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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, 1998
 
                                               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 31,
1999:       282,000
 
                      DOCUMENTS INCORPORATED BY REFERENCE:
 
                                      NONE
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                             COGENTRIX ENERGY, INC.
 
                      INDEX TO ANNUAL REPORT ON FORM 10-K
 
<TABLE>
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                                                                         PAGE
                                                                         ----
<S>        <C>                                                           <C>
PART I
Item 1:    Business....................................................    1
Item 2:    Properties..................................................   21
Item 3:    Legal Proceedings...........................................   21
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.........................................   23
Item 6:    Selected Consolidated Financial Data........................   24
Item 7:    Management's Discussion and Analysis of Financial Condition
           and Results of Operations...................................   25
Item 8:    Financial Statements and Supplementary Data.................   37
Item 9:    Changes in and Disagreements with Accountants on Accounting
           and Financial Disclosure....................................   69
 
PART III
Item 10:   Directors and Executive Officers of the Registrant..........   69
Item 11:   Executive Compensation......................................   72
Item 12:   Security Ownership of Certain Beneficial Owners and
           Management..................................................   76
Item 13:   Certain Relationships and Related Transactions..............   76
 
PART IV
Item 14:   Exhibits, Financial Statement Schedules and Reports on Form
           8-K.........................................................   78
           Signatures..................................................   86
</TABLE>
 
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<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, principally under long-term power purchase
agreements, to regulated electric utilities. 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 plants 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 3.3% to approximately 74%, our net ownership interests in
the total production capability of our 25 electric generating plants is
approximately 1,690 megawatts. We developed, constructed and currently operate
10 of our plants, which, with one exception, are located in either North
Carolina or Virginia.
 
     When our plant currently under construction in Batesville, Mississippi
begins operation, we will have ownership interests in a total of 26 domestic
electric generating plants that are designed with a total production capability
of 4,800 megawatts. Our net equity interest in the total production capability
of those 26 facilities will be approximately 2,110 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 "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
industry trends and 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. These suppliers will include 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 requirements 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. Even when not required to do so by
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 additional investment opportunities for us. In
connection with acquiring -- entirely or in
 
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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.
 
  Passage of the Energy Policy Act has Expanded Our Options
 
     The passage of the Energy Policy Act by the United States Congress in 1992
significantly expanded the options available to independent power producers,
particularly with respect to siting a generating facility. Among other things,
this law 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
plant 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 selected 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:
 
     - 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 facilities using natural gas as fuel
 
     Acquiring Interests in Existing Domestic Electric Generating Plants.  Our
candidates for future acquisitions will generally already have 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 would expect
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 Customers.  Many
large, industrial customers 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 technology that many of these
industrial companies currently operate themselves. We 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.
 
     Developing New Electric Generating Plants.  We intend to pursue domestic
development of new, highly-efficient, low-cost plants, concentrating on
mid-sized facilities that use natural gas as fuel. We expect to have long-term
contractual arrangements for these plants in place 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 accepting the risks associated with
energy price fluctuations. We also intend to pursue international project
development opportunities on a highly
 
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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.
 
     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 plants 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 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
 
     We also intend whenever practicable to reduce the risks associated with the
development of any new projects by developing them on a joint venture basis with
one or more strategic partners instead of doing so on our own.
 
OUR RECENT ACQUISITIONS OF INTERESTS IN ELECTRIC GENERATING PLANTS
 
     A key part of our business strategy is to acquire interests in domestic
electric generating assets. We completed three material acquisitions in 1998
that expanded our operations from four to nine states in the eastern U.S. and
into two states in the upper Midwest. These recent acquisitions strengthen our
competitive position and diversify our operations with regard to fuel source and
dependence on any single project or customer.
 
     - October 1998.  The "Bechtel Acquisition" resulted in our acquiring
       ownership interests ranging from 3.3% to 49% in 12 domestic electric
       generating plants and a natural gas pipeline from Bechtel Generating
       Company, Inc. Nine of these electric generating facilities were developed
       and are managed by U.S. Generating Company, LLC, an indirect,
       wholly-owned subsidiary of PG&E Corporation, and are owned in part by its
       affiliates. The acquisition of these interests gives us an aggregate net
       equity interest of approximately 365 megawatts in a diverse portfolio of
       electric generating plants that comprises approximately 2,400 megawatts
       in total production capability. The plants are located in New Jersey, New
       York, Pennsylvania, West Virginia, Massachusetts and Florida. The
       aggregate purchase price was approximately $189.7 million, including
       related acquisition costs. We have accounted for this acquisition using
       the purchase method of accounting. We account for our ownership interests
       in eight of these generating facilities using the equity method of
       accounting, and the cost method of accounting for the other four
       generating facilities.
 
     - August 1998.  The "Batesville Acquisition" resulted in our acquiring an
       approximate 52% interest in an 800-megawatt, gas-fired electric
       generating plant under construction in Batesville, Mississippi. We have
       committed to provide an equity contribution to the project subsidiary of
       approximately $54 million. The equity commitment is supported by a $54
       million letter of credit provided under our corporate credit facility. We
       expect this generating plant, which we will operate when construction is
       completed, will begin operation in June 2000. Two electric utilities have
       agreed to purchase the electricity produced at this plant under long-term
       power purchase agreements. Both utilities have senior, unsecured debt
       outstanding that nationally-recognized credit rating agencies have rated
       investment grade. We account for our interest in this generating facility
       using the equity method of accounting, because we anticipate that our
       ownership will be less than 50% when the plant begins operation.
 
     - March 1998.  The "Whitewater/Cottage Grove Acquisition" resulted in our
       acquiring approximate 74% interests in each of two electric generating
       plants located in Whitewater, Wisconsin and Cottage Grove, Minnesota. The
       aggregate purchase price for the plants was $158.0 million. Each facility
       is a 245-megawatt, gas-fired plant. Commercial operations began at both
       facilities in the last six months of
 
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<PAGE>   6
 
       1997. The plant in Cottage Grove has a 30-year power purchase agreement
       with Northern States Power Company. The plant in Whitewater has a 25-year
       power purchase agreement with Wisconsin Electric Power Company. We have
       accounted for this acquisition using the purchase method of accounting.
       We account for our ownership interests in these generating facilities
       using the consolidation method.
 
PROJECT UNDER DEVELOPMENT
 
     Rathdrum, Idaho Project.  Cogentrix is developing jointly with Avista
Power, Inc. a 270 megawatt electric generating facility to be located in
Rathdrum, Idaho. Avista Energy, Avista Power, Inc.'s national energy trading and
marketing affiliate, will deliver natural gas to the plant and purchase the
electrical output of the facility under a long term power purchase agreement.
Avista Power and Cogentrix will share ownership in the facility. Cogentrix will
have the lead role for the development, construction and operation of the
facility.
 
PROJECT AGREEMENTS, FINANCING AND OPERATING ARRANGEMENTS FOR OUR FACILITIES
 
  Project Agreements
 
     Our facilities sell electricity primarily to electric utilities under
long-term power sales agreements. 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 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 purchasing utility.
 
     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 utility
purchasing its electricity. It is generally less than 100% of the facility's
design production capability dictated by its equipment and design
specifications. Fixed payments are based either on a facility's net electrical
output and paid on a kilowatt-hour basis or on the facility's declared
production capability and can be adjusted if actual production capability varies
significantly from declared production capability.
 
     Many power sales agreements permit the purchasing utility to direct the
facility to deliver a variable amount of electrical output within limited
parameters. This means the utility may within those parameters direct the
facility to reduce or suspend the delivery of electricity to the utility. The
power sales agreements of substantially all our facilities provide the
purchasing utilities 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 to generate electricity, are received only
for each kilowatt hour delivered.
 
     With few 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.
 
     Each of the 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
 
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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.
 
     These 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.
 
     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 certain industrial steam customers or utilities 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 by Cogentrix Energy to satisfy these obligations. To the
extent of these obligations, the lenders to a project have recourse to Cogentrix
Energy and the distributions to Cogentrix Energy from other projects. 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."
 
     The indentures under which Cogentrix Energy has senior debt outstanding
permit the incurrence of debt, guarantees and liens jointly by any future
project subsidiaries or joint ventures with respect to the future development of
electric generating facilities. To the extent we take advantage of these
provisions of the indentures, the project lenders will have recourse to several
of our facilities instead of having their recourse limited to the facility or
facilities owned by a single project subsidiary.
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<PAGE>   8
 
     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, our project subsidiary
employs directly the persons required to operate the facility. We invest in
training our operating personnel and structure our plant bonus program to reward
efficient and cost-effective operation of the facilities. Our management meets
several times a year with the facilities' managers and conducts on-site facility
performance reviews with each facility manager.
 
     We have established a strong record of efficiency and reliability in
operating our electric generating plants, which 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 10 plants we currently operate for
the periods indicated.
 
<TABLE>
<CAPTION>
PERIOD                                                        AVERAGE AVAILABILITY
------                                                        --------------------
<S>                                                           <C>
Year ended December 31, 1998................................         96.4%
Year ended December 31, 1997................................         97.2%
Year ended December 31, 1996................................         96.6%
</TABLE>
 
     We provide to 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.
 
     In addition, we serve as a third-party operator for the generating facility
we developed for Public Utility District Number 1 of Clark County, Washington,
under the terms of a two-year operations and maintenance agreement, which
expires in 1999.
 
  Ash Removal
 
     Project subsidiaries owning eight of our coal-fired plants contract with
our subsidiary, ReUse Technology, to remove coal ash generated by such
facilities. As an alternative to disposing of coal ash in landfills, ReUse
Technology has developed the use of coal ash as structural fill material and in
the manufacturing and production of various ash derived products for resale.
 
FACILITY UNDER CONSTRUCTION IN BATESVILLE, MISSISSIPPI
 
     In August 1998, we acquired an approximate 52% interest in an 800-megawatt,
gas-fired facility under construction in Batesville, Mississippi. We expect this
plant, which we will operate, to begin operation in June 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.
 
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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, 1998, two
regulated utility customers accounted for approximately 69% 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 the acquisitions we made in
1998, 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         49.0         106.8      Atlantic City Electric
Northampton................  Northampton County,      Waste coal     110         49.0          53.9      Metropolitan Edison
                             PA
Indiantown.................  Martin County, FL        Coal           380         10.0          38.0      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.................  Scrubgrass Township, 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          3.3           8.5      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      62         15.0           9.3      Monongahela Power
                                                      Coal
Iroquois Gas Transmission    Long Island, NY to       --                                                 --
  System...................  Waddington, NY                           --          0.5            --
</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. Under the amended terms, the power
 
                                        7
<PAGE>   10
 
sales agreements for the Elizabethtown and Lumberton facilities each has an
initial term expiring 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 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. This
penalty does not apply in the event of an early termination by our project
subsidiary that is the result of a material breach by the utility. When it does
apply, 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. Another subsidiary,
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.
 
                                        8
<PAGE>   11
 
     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 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 Clariant Corporation.
 
     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 made 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
                                        9
<PAGE>   12
 
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.
 
  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, failure of our subsidiary that
owns and operates the plant 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 $23 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 an unaffiliated
company -- Keystone Village Farms, Inc. 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.
 
     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, our 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 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
 
                                       10
<PAGE>   13
 
refinancing of the Richmond facility after payment of senior and subordinated
project financing debt and expenses.
 
  Birchwood, Virginia Facility
 
     Through an indirect, wholly-owned subsidiary we have a 50% interest in a
partnership that owns a 240-megawatt coal-fired cogeneration plant 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 operates and maintains
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.
 
                                       11
<PAGE>   14
 
     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. Westinghouse Operating Services Company, Inc.
operates the Cottage Grove facility.
 
     On March 16, 1999, the partnership which owns the Cottage Grove facility
exercised an option under its O&M Agreement to terminate the O&M Agreement with
Westinghouse Operating Services, Inc. effective April 15, 1999. In connection
with the exercise of such option, Cottage Grove will make a payment to
Westinghouse Operating Services, Inc. pursuant to its O&M Agreement in an amount
equal to $320,000. Each O&M Agreement will be replaced with a similar agreement,
in all material respects identical to the applicable O&M Agreement, executed
with an indirect subsidiary of Cogentrix Energy.
 
  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.
                                       12
<PAGE>   15
 
     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. Westinghouse Operating Services Company,
Inc. operates the Whitewater facility.
 
     On March 16, 1999, the partnership which owns the Whitewater facility
exercised an option under its O&M Agreement to terminate the O&M Agreement with
Westinghouse Operating Services, Inc. effective April 15, 1999. In connection
with the exercise of such option, Whitewater will make a payment to Westinghouse
Operating Services, Inc. pursuant to its O&M Agreement in an amount equal to
$320,000. Each O&M Agreement will be replaced with a similar agreement, in all
material respects identical to the applicable O&M Agreement, executed with an
indirect subsidiary of Cogentrix Energy.
 
  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 49% general partnership interest in each of the
first limited partnership and each of the partners of the second limited
partnership. The remaining 1% interest is held by an indirect subsidiary of
Bechtel Generating Company, Inc. as a limited partnership interest. Pursuant to
a put agreement, Bechtel Generating Company, Inc. has the right to require us to
purchase, at fair market value, the 1% limited partnership interest within the
30-day period following November 20, 1999. If Bechtel Generating Company, Inc.
exercises such put right, the 1% limited partnership interest will automatically
convert to a general partnership interest upon transfer to us. An indirect,
wholly-owned subsidiary of 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
200 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 U.S. Generating Company operates the Logan facility
pursuant to an operation and maintenance agreement with an initial term expiring
in 2004. U.S. Generating Company 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 49% general partnership
interest in this partnership. The remaining 1% interest is held by an indirect
subsidiary of Bechtel Generating Company, Inc. as a limited partnership
interest. Pursuant to a put agreement, Bechtel Generating Company, Inc. has the
right to require us to purchase, at fair market value, the 1% limited
partnership interest within the 30-day period following November 20, 1999. If
Bechtel Generating Company, Inc. exercises such put right, the 1% limited
partnership interest will automatically convert to a general partnership
interest upon transfer to our subsidiary. 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.
 
                                       13
<PAGE>   16
 
     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". The Northampton facility produces
and sells steam to Ponderosa Fibers, but steam sales are not required in order
to maintain the Northampton facility's regulatory status.
 
     An affiliate of U.S. Generating Company operates and maintains the
Northampton facility pursuant to an operation and maintenance agreement with an
initial term expiring in 2020. U.S. Generating Company, LLC provides management
and administration services for the Northampton facility pursuant to a
management services agreement with an initial term expiring in 2020.
 
     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. In connection with the Bechtel Acquisition,
Cogentrix provided 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 indirect,
wholly-owned subsidiary of PG&E owns a 50% general partnership interest in the
partnership, an indirect, wholly-owned subsidiary of General Electric Capital
Corporation owns a 40% limited partnership interest in the partnership, and we
own a 10% 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
                                       14
<PAGE>   17
 
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 U.S. Generating Company provides operation and maintenance
services for the Indiantown facility pursuant to an operating agreement which
expires in 2025. U.S. Generating Company 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 U.S.
Generating Company. 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.
 
     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 U.S. Generating Company operates the Carneys Point facility
under an operation and maintenance agreement with an initial term expiring in
2004. U.S. Generating Company 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
revenue for the fiscal years ended December 31, 1998, 1997 and 1996 were as
follows:
 
<TABLE>
<CAPTION>
                                                                 FISCAL YEAR ENDED
                                                                    DECEMBER 31,
                                                                --------------------
                                                                1998    1997    1996
                                                                ----    ----    ----
<S>                                                             <C>     <C>     <C>
CP&L........................................................     19%     22%     30%
Virginia Power..............................................     50      64      56
</TABLE>
 
     As a result of the acquisitions we completed in 1998, 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
with utilities, types of fuel utilized, the type of energy produced and power
 
                                       15
<PAGE>   18
 
plant ownership. State regulatory commissions must 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.
 
     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
would 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" 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.  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
                                       16
<PAGE>   19
 
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
our facilities are dually certified as QFs and eligible facilities of 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.
 
     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 has filed its rates with the
FERC and obtained authorization to sell all of its power pursuant to those
rates.
 
     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
 
                                       17
<PAGE>   20
 
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.
 
     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.
 
     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.
 
     Although a number of major environmental statutes are scheduled for
reauthorization, we expect that environmental regulations will continue to
become more stringent as environmental regulations previously passed become
implemented. 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.
                                       18
<PAGE>   21
 
     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 perform at levels better than federal performance
standards mandated for such facilities under the Clean Air Act. 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.
 
     The 1990 Amendments also require states to impose annual operating permit
fees. While such permit fees may be substantial and will be greater for
coal-fired projects than for those burning gas or certain other fuels, such fees
are not expected to significantly increase our costs at the plants we operate.
 
     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 newly designated nonattainment areas which has not submitted a
complete air permit application before November 15, 1992 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. Three
studies of the emissions from such facilities are, however, in progress. Until
all of these studies are completed and 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 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 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
 
                                       19
<PAGE>   22
 
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 goes 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. The State of
North Carolina -- where six of the plants we operate are located -- has,
however, proposed to the EPA an alternative NO(x) reduction plan that does not
include any of those plants.
 
     The 1990 Amendments expand the enforcement authority of the federal
government by increasing the range of civil and criminal penalties for
violations of the Clean Air Act, enhancing administrative civil penalties, and
adding a citizen suit provision. These enforcement provisions also include
enhanced monitoring, recordkeeping and reporting requirements for existing and
new facilities. On February 13, 1997, the EPA issued a regulation providing for
the use of "any credible evidence or information" in lieu of, or in addition to,
the test methods prescribed by regulation to determine the compliance status of
permitted sources of air pollution. This rule may effectively make emission
limits previously established for many air pollution sources, including 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.
 
     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 will
be required to complete a toxic chemical inventory release form for each listed
toxic chemical manufactured, processed or otherwise used in excess of threshold
levels for the 1998 reporting year. 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.
 
  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.
 
     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
                                       20
<PAGE>   23
 
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, 1998, we employed 463 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; Portland, Oregon;
Bangalore, India; Mangalore, India; and New Delhi, India.
 
     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
 
     Under the terms of the amended power sales agreements for our
Elizabethtown, Lumberton, Kenansville, Roxboro and Southport facilities, the
purchasing utility has exercised its right to suspend or reduce purchases of
energy resulting in significantly reduced fuel requirements at each of these
facilities. Coal is supplied to the Elizabethtown, Lumberton and Kenansville
facilities by James River Coal Sales, Inc. and one of its affiliates. Coal was
supplied to the Southport facility until November 1997 when the contract term
expired by Coastal Coal Sales, Inc. The coal sales agreements for the
Elizabethtown, Lumberton and Kenansville facilities provide for the sale and
purchase of the coal requirements of those facilities through September 2001.
 
     Under the amended power sales agreement for our Portsmouth facility,
Virginia Power has from time to time since December 1997 exercised its right to
suspend or reduce purchases of energy resulting in significantly reduced fuel
requirements at the facility. Coal is supplied to the Portsmouth facility by
Arch Coal Sales Company, Inc. The coal sales agreement provides for the sale and
purchase of the coal requirements of the Portsmouth facility through April 2003.
 
     As a result of the purchasing utility exercising its right to suspend or
reduce purchases of energy from these facilities and the consequent reduction in
fuel requirements, our project subsidiaries operating these facilities are
purchasing significantly less coal. The suppliers are seeking to recover damages
and, in some cases, seeking injunctive relief. A summary of each of these
pending disputes is set forth below.
 
DISPUTE WITH JAMES RIVER COAL (ELIZABETHTOWN, LUMBERTON AND KENANSVILLE
FACILITIES)
 
     In November 1996, James River Coal instituted an action against our project
subsidiary in the United States District Court for the Eastern District of
Kentucky claiming breach of contract and fraud in the inducement based on the
reduction in coal requirements. In this complaint, James River Coal sought
specific
 
                                       21
<PAGE>   24
 
performance and, in the alternative, an unspecified amount of damages. In April
1998, after the case was transferred to the United States District Court for the
Western District of North Carolina, the fraud in the inducement claim was
dismissed by the court with prejudice.
 
     The contract with James River Coal contains an arbitration provision
requiring contract disputes to be submitted to arbitration in Charlotte, North
Carolina. After we filed a motion to compel arbitration of the contract claim,
James River Coal consented to, and filed a demand for, arbitration of the claim.
In March 1999, the dispute was submitted to arbitration before a three-member
panel of arbitrators. With one member of the panel dissenting, the arbitrators
ruled in favor of James River, awarding damages in the amount of approximately
$8 million payable in 1999. Approximately $3 million of this award relates to
the reduction in the 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 the project subsidiary. The amount of damages awarded, even
when combined with the amounts which may become payable under the preliminary
settlement agreement we have entered into with the coal supplier to our
Portsmouth facility that is described below, will not materially reduce the
projected amount of cash flow to Cogentrix Energy for the current fiscal year.
The payment of this award should not, therefore, have a material adverse effect
on Cogentrix Energy's ability to service its outstanding debt.
 
DISPUTE WITH COASTAL COAL SALES (SUPPLIER TO SOUTHPORT FACILITY)
 
     In October 1996, Coastal Coal Sales initiated an arbitration proceeding
against our project subsidiary through the American Arbitration Association in
Charlotte, North Carolina. The notice of arbitration alleged breach of contract
based on the reduction in coal requirements at our Southport facility. In
October 1997, a three-member panel of arbitrators ruled in our favor, denying
any recovery to the coal supplier.
 
     The successor company to Coastal Coal Sales subsequently challenged the
arbitrator's ruling in the United States District Court for the Western District
of North Carolina on grounds of arbitrator partiality. In April 1998, the court
issued an order vacating the ruling of the arbitration panel and directing that
a new arbitration be conducted. We appealed the court's decision to the United
States Court of Appeals for the Fourth Circuit and await the decision of that
court.
 
DISPUTE WITH ARCH COAL SALES (SUPPLIER TO OUR PORTSMOUTH FACILITY)
 
     In February 1998, this coal supplier filed a complaint against our project
subsidiary in the United States District Court for the Southern District of West
Virginia alleging breach of contract and seeking a determination that the
subsidiary is obligated to purchase approximately 360,000 tons of coal per year,
breached the coal sales agreement by wrongfully reducing its requirements of
coal, and violated a duty of good faith and fair dealing owed to the coal
supplier. In the alternative, this coal supplier seeks damages for the
subsidiary's failure to purchase such quantities of coal. This agreement also
contains an arbitration clause that requires any disputes between the parties to
be resolved by arbitration in Charlotte, North Carolina. In June 1998, the
District Court issued an order staying the litigation proceeding pending
arbitration of the issues raised in the complaint.
 
     On March 11, 1999, our project subsidiary entered into a comprehensive
settlement agreement with this coal supplier, which is subject to the approval
of their and our board of directors and to the approval of the lenders to our
project subsidiary. The agreement also reflects that we have not yet reached
final agreement with the coal supplier on the potential impact of the provisions
of our steam sales agreements at the Portsmouth Facility on the settlement
agreement's payment terms. If we reach final agreement on that issue and the
required board consents and lender approvals are obtained, the settlement
agreement will obligate our project subsidiary to take stated minimum quantities
of coal each year and failing such purchases to make an agreed upon payment for
quantities not purchased over the next five years. Given projected levels of
coal requirements over that five year period, we believe such payments should
not have a material adverse effect on the projected aggregate amount of cash
flow to Cogentrix Energy from its project subsidiaries and
 
                                       22
<PAGE>   25
 
unconsolidated affiliates. The payments we expect to make under this settlement
agreement should not, therefore, have a material adverse impact on Cogentrix
Energy's ability to service its outstanding debt.
 
OTHER LITIGATION
 
     In addition to the litigation described above, we experience other
litigation in the normal course of business. Several of our indirect,
wholly-owned subsidiaries are parties 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 these subsidiaries in their 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, we experience other routine litigation in the normal course of
our business. Our management is of the opinion that none of this routine
litigation should have a material adverse effect on our financial position or
results of operation.
 
ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
 
     None.
 
                                    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 six-month period ended December 31, 1997, our
board of directors declared a dividend on our outstanding common stock of $2.1
million, which was paid in March 1998. 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.
 
                                       23
<PAGE>   26
 
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, 1998, 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, 1998 set forth below has
been derived from our consolidated financial statements.
 
<TABLE>
<CAPTION>
                                                      YEARS ENDED DECEMBER 31,
                                 ------------------------------------------------------------------
                                   1998         1997         1996           1995           1994
                                 --------     --------     --------      -----------    -----------
                                                         (DOLLARS IN     (UNAUDITED)    (UNAUDITED)
                                                          THOUSANDS)
<S>                              <C>          <C>          <C>           <C>            <C>
Operating revenue:
  Electric.....................  $293,083     $307,104     $340,681       $361,694       $352,894
  Steam........................    25,043       26,123       28,987         23,328         24,113
  Lease........................    34,715           --           --             --             --
  Service revenue under capital
     leases....................    34,470           --           --             --             --
  Income from unconsolidated
     investments in power
     projects..................     6,474        1,412        3,408             --             --
  Other........................    17,672       15,275       15,769         12,655          1,201
                                 --------     --------     --------       --------       --------
          Total operating
            revenue............   411,457      349,914      388,845        397,677        378,208
                                 --------     --------     --------       --------       --------
Operating expenses:
  Operating costs..............   188,331      190,098      232,199        238,261        238,536
  General, administrative and
     development...............    36,490       41,650       31,245         28,853         31,240
  Depreciation and
     amortization..............    42,535       41,844       37,455         38,848         34,939
  Loss on impairment and cost
     of removal of cogeneration
     facilities................        --           --       65,628             --             --
                                 --------     --------     --------       --------       --------
          Total operating
            expenses...........   267,356      273,592      366,527        305,962        304,715
                                 --------     --------     --------       --------       --------
Operating income...............   144,101       76,322       22,318         91,715         73,493
Other income (expense):
  Interest expense.............   (74,949)     (53,864)     (56,950)       (59,362)       (53,753)
  Investment and other
     income....................     9,226        9,789       10,942          8,232          6,583
  Equity in net income (loss)
     of affiliates, net........    (3,274)      (1,538)      (2,135)           109          9,144
Minority interest in income of
  joint venture................   (12,458)      (4,672)      (5,621)        (3,558)        (3,205)
                                 --------     --------     --------       --------       --------
Income (loss) before income
  taxes and Extraordinary gain
  (loss).......................    62,646       26,037      (31,446)        37,136         32,262
Benefit (provision) for income
  taxes........................   (24,914)      (9,754)      11,273        (13,783)       (13,015)
                                 --------     --------     --------       --------       --------
Income (loss) before
  extraordinary gain (loss)....    37,732       16,283      (20,173)        23,353         19,247
Extraordinary gain (loss) on
  early extinguishment of debt,
  net..........................      (743)      (1,502)        (703)            --          3,055
                                 --------     --------     --------       --------       --------
Net income (loss)..............  $ 36,989     $ 14,781     $(20,876)      $ 23,353       $ 22,302
                                 ========     ========     ========       ========       ========
</TABLE>
 
                                       24
<PAGE>   27
 
<TABLE>
<CAPTION>
                                                     AS OF DECEMBER 31,
                            --------------------------------------------------------------------
                               1998          1997         1996           1995           1994
                            ----------     --------     --------      -----------    -----------
                                                      (DOLLARS IN     (UNAUDITED)    (UNAUDITED)
                                                       THOUSANDS)
<S>                         <C>            <C>          <C>           <C>            <C>
BALANCE SHEET DATA:
Total Assets..............  $1,499,851     $822,974     $865,941       $914,136       $926,130
                            ==========     ========     ========       ========       ========
Project financing debt
  (1).....................  $  877,653     $567,705     $620,885       $639,823       $680,918
                            ==========     ========     ========       ========       ========
Parent debt (2)...........  $  355,000     $100,000     $100,000       $100,000       $100,000
                            ==========     ========     ========       ========       ========
Total shareholders'
  equity..................  $   87,863     $ 58,298     $ 50,631       $ 75,891       $ 56,147
                            ==========     ========     ========       ========       ========
</TABLE>
 
---------------
 
(1) Project financing debt with respect to each of our facilities is
    "non-recourse" to Cogentrix Energy and its other project subsidiaries. For a
    discussion of the term "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 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 developed ourselves originally
sold electricity under long-term contracts that obligated the electric utility
to purchase all electricity generated by the facility. During the last three
years, we 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.
 
     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
 
                                       25
<PAGE>   28
 
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 for the electric utilities and Cogentrix. 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 for
electricity generated by our facilities had the power purchase agreements not
been restructured.
 
     In response to the reduction in fuel requirements at some of the facilities
at which we have restructured the power sales agreements, the facilities coal
suppliers have instituted various legal proceedings against Cogentrix seeking to
recover damages. The ultimate disposition of those proceedings, in the judgement
of our management, should not have a material adverse effect on our consolidated
results of operations or financial position or on the cash flow Cogentrix Energy
requires to service its outstanding debt. See "Legal Proceedings", herein for a
more detailed discussion of these matters.
 
  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 after 2002 will be eliminated or
significantly reduced. We believe, 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 the 2004
notes and the 2008 notes, 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 and Changes in our Portfolio of Generating Plants
 
     The Whitewater/Cottage Grove and Bechtel Acquisitions, have substantially
increased our electric production capability. As a result, our financial
condition, and results of operations should be significantly impacted in the
coming years. The power purchase agreements for the Cottage Grove and Whitewater
facilities 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, Cottage Grove's and Whitewater's
power purchase agreements were accounted for as "sales-type" capital leases in
accordance with Statement of Financial Accounting Standards (SFAS) No. 13,
"Accounting for Leases". As a result, the Whitewater/Cottage Grove project
subsidiaries recognize lease and service revenues, as well as cost of services
under sales type leases. The Bechtel Acquisition should significantly impact the
income from unconsolidated power projects. Both acquisitions were financed with
debt, and, as a result, will impact our interest expense reported in our results
of operations.
 
                                       26
<PAGE>   29
 
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, 1998, 1997 and 1996.
 
<TABLE>
<CAPTION>
                                                            YEAR ENDED DECEMBER 31,
                                                ------------------------------------------------
                                                     1998             1997             1996
                                                --------------   --------------   --------------
                                                             (DOLLARS IN THOUSANDS)
<S>                                             <C>        <C>   <C>        <C>   <C>        <C>
Total operating revenues......................  $411,457   100%  $349,914   100%  $388,845   100%
Operating costs...............................   188,331    46    190,098    54    232,199    59
General, administrative and development.......    36,490     9     41,650    12     31,245     8
Depreciation and amortization.................    42,535    10     41,844    12     37,455    10
Impairment and cost of removal................        --    --         --    --     65,628    17
                                                --------   ---   --------   ---   --------   ---
Operating income..............................  $144,101    35%  $ 76,322    22%  $ 22,318     6%
                                                ========   ===   ========   ===   ========   ===
</TABLE>
 
 Fiscal Year Ended December 31, 1998 as compared to Fiscal Year Ended December
 31, 1997
 
     Total operating revenues increased 17.6% to $411.5 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. The increase in operating revenues was
also related to a $4.3 million construction management fee received in August
1998 which related to cost savings realized on the completion of construction of
an electric generating facility for Public Utility District Number 1 of Clark
County, Washington. Operating revenues were also impacted by an increase in
income from unconsolidated investments in power projects. The increase was
primarily the result of the October 1998 Bechtel Acquisition, in which we
acquired ownership interests in 12 electric generating plants. 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 was
primarily the result of a $14.3 million decrease in electric revenue from the
Portsmouth facility and a $6.3 million decrease in electric revenue from the
Hopewell facility resulting from the restructuring of their power sales
agreements to give the purchasing utility the right to suspend or reduce
purchases of energy from the facilities. The decrease in electric revenues was
partially offset by an increase in electric revenue at the Richmond, Rocky Mount
and Southport facilities due to an increase in megawatt hours sold to the
purchasing utilities.
 
     Our operating costs decreased 1.0% to $188.3 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 $23.9
million reduction in fuel expense at the Portsmouth facility and a $14.4 million
reduction in fuel expense at the Hopewell facility, in each case associated with
the restructuring of the power sales agreements. The decrease was also a result
of a decrease in operating costs incurred by ReUse Technology, a wholly-owned
subsidiary of Cogentrix Energy, 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, in which we acquired our approximate
74% interests in March 1998. Operating expenses were also impacted by the
increases in fuel expense at the Rocky Mount and Richmond facilities associated
with an increase in megawatt hours sold and an increase in routine maintenance
expenses at the Rocky Mount facility.
 
     General, administrative and development expenses for the year ended
December 31, 1998 decreased 12.4% 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 terminating 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
 
                                       27
<PAGE>   30
 
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 weighted 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 weighted 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 were related
to the inclusion of the project finance debt of the Cottage Grove and Whitewater
facilities acquired in March 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 our 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 related 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 statement of
operations. We may recognize an additional gain of approximately $11.6 million
as the payment of a note received as consideration in this transaction becomes
assured.
 
     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.
 
  Fiscal Year Ended December 31, 1997 as compared to the Fiscal Year Ended
December 31, 1996
 
     Total operating revenues decreased 10.0% to $349.9 million for the year
ended December 31, 1997 as compared to $388.8 million for the year ended
December 31, 1996. This decrease was primarily attributable to the significant
decrease in electric revenues resulting from the amendment in September 1996 of
our power sales agreements with Carolina Power & Light Company on the
Elizabethtown, Lumberton, Kenansville, Roxboro, and Southport facilities. The
decrease in operating revenues was also due to a decrease in steam revenues at
the Hopewell and Southport facilities resulting from reduced demand for steam by
the facilities' steam customers. These decreases in operating revenues were
partially offset by a $4.5 million construction management fee we earned in
December 1997, related to the construction of the Clark facility, as well as a
$6.9 million increase in electric revenues at the Rocky Mount, Hopewell and
Portsmouth facilities. The increase in electric revenues at the Rocky Mount
facility was due to an increase in on-peak megawatt hours provided to the
purchasing utility, while the increase in electric revenues at the Portsmouth
facility was mainly attributable to the restructured power sales agreement with
the purchasing utility eliminating Portsmouth's accrued obligation to return
previously disallowed fixed payments to the purchasing utility. The decreases in
operating revenues were also impacted by a $2.0 million decrease in income from
unconsolidated investments in power projects that was primarily the result of
decreased earnings generated by our investment in Bolivian Power Company
Limited, in which we sold our interest in December 1996. We recognized $3.5
million in income from our investment in Bolivian Power Company Limited during
the fiscal year ended December 31, 1996.
 
     Operating costs decreased 18.1% to $190.0 million for the year ended
December 31, 1997 as compared to $232.2 million for the year ended December 31,
1996. This decrease resulted primarily from the decrease in
                                       28
<PAGE>   31
 
fuel expense of approximately $37.6 million at the Elizabethtown, Lumberton,
Kenansville, Roxboro, and Southport facilities resulting from their reduced
sales of electricity to Carolina Power & Light Company as well as a decrease in
fuel expense of approximately $4.3 million at the Richmond facility associated
with a decrease in megawatt hours sold. The decrease in operating costs was also
due to a reduction in maintenance costs of approximately $6.3 million at the
Rocky Mount and Hopewell facilities, at which facilities we performed routine
maintenance during the year ended December 31, 1996. The decrease in operating
costs was also related to severance costs incurred by the Lumberton,
Elizabethtown, Kenansville, Roxboro, and Southport facilities in the year ended
December 31, 1996 associated with the reduction of the workforce at those
facilities due to the amendment of their power sales agreements. These decreases
were partially offset by an increase in operating costs incurred by ReUse of
approximately $6.0 million related to an increase in third-party ash services
activity during the year ended December 31, 1997 and an increase in maintenance
costs at the Southport facility of approximately $2.2 million related to routine
maintenance performed during the year ended December 31, 1997.
 
     General, administrative and development expenses increased 33.3% to $41.7
million for the year ended December 31, 1997 as compared to $31.2 million for
the year ended December 31, 1996. The increase in general, administrative and
development expenses related primarily to $10.7 million of expense recognized in
the year ended December 31, 1997 related to the restructuring or terminating of
incentive compensation arrangements for certain employees, as well as expenses
incurred related to severance payments to certain executive officers. The
increase was also attributable to incentive compensation expense incurred in
December 1997 related to the successful completion of the Clark facility and
severance costs incurred related to the reduction of the workforce at the
corporate office. The increase was partially offset by a general reduction in
expenses related to projects under development, and consulting expenses related
to development.
 
     During fiscal 1996, we undertook an analysis of the projected operating
results for all of our facilities in light of the dramatic market changes in the
electric generating industry. The analysis included assumptions regarding future
levels of operations, operating costs and market prices for equivalent
generation available from other sources. As a part of this analysis, in
accordance with the Statement of Financial Accounting Standards No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed of," we assessed whether any impairment of our facilities had
occurred. This assessment included a comparison of the projected future cash
flows to be provided by these assets to the net book value of such assets. Based
on this assessment, we determined that an impairment loss had occurred on the
Elizabethtown, Lumberton, Kenansville and Ringgold facilities. This loss on
impairment of cogenerating facilities of $57.3 million represented the excess of
the net book value of these cogenerating facilities over their current fair
value, determined by discounting to present value the projected future cash
flows to be provided by such assets. We believe that the projections of future
cash flows are based upon reasonable assumptions about the future performance of
these assets. Because of the risks and uncertainties associated with any
projections, there can be no assurances, however, that actual events will be
consistent with the assumptions made, and future cash flows may be greater or
less than those projected.
 
     Our analysis of the projected operating results for all of our facilities
also resulted in the recognition of an $8.3 million liability related to
estimated cost of removal obligations under the land leases for the
Elizabethtown, Lumberton and Kenansville facilities. The total impairment loss
and cost of removal of $65.6 million has been reflected in the statement of
operations for the year ended December 31, 1996. Also in connection with the
overall assessment of the projected operating results for its cogenerating
facilities, we concluded that, effective January 1, 1997, the Lumberton,
Elizabethtown, Kenansville, Roxboro and Southport facilities would be
depreciated over the remaining term of these facilities' power sales agreements.
The 11.7% increase in depreciation and amortization expense in fiscal 1997 as
compared to fiscal 1996 related primarily to this change in the estimated useful
lives of these facilities.
 
     Annual depreciation expense, in the aggregate, is expected to increase
approximately $6.1 million per year as a result of the changes in estimated
useful lives of the Lumberton, Elizabethtown, Kenansville, Roxboro and Southport
facilities, as well as the impairment loss recognized during fiscal 1996 at the
Lumberton, Elizabethtown, Kenansville and Ringgold facilities.
 
                                       29
<PAGE>   32
 
     Interest expense decreased 5.4% to $53.9 million for the year ended
December 31, 1997 as compared to $57.0 million for the year ended December 31,
1996. The decrease in interest expense was primarily attributable to a decrease
in the weighted average debt outstanding from $730 million for the year ended
December 31, 1996 to $697 million for the year ended December 31, 1997. The
decrease in weighted average debt outstanding related to regularly scheduled
repayments of principal on our project financing debt.
 
     Equity in net loss of affiliates decreased to $1.5 million for the year
ended December 31, 1997 as compared to $2.1 million for the year ended December
31, 1996. The decrease in equity in net loss was primarily attributable to a
reduction in development costs associated with the termination in December 1996
of funding for a partnership pursuing development opportunities in Latin
America. The decrease was partially offset by the recognition of our share of
losses from our investments in greenhouse facilities in Texas, Pennsylvania and
New York during the year ended December 31, 1997. During the year ended December
31, 1996, these greenhouse facilities were either (a) not yet in commercial
operation, (b) had just started commercial operation or (c) we had not yet made
our investment.
 
     The decrease in minority interest in income of joint venture for the year
December 31, 1997 as compared to the year ended December 31, 1996 related to a
decrease in the net income of the Hopewell facility. The decrease in net income
of the Hopewell facility resulted primarily from the non-recurring revenue
recognized in the year ended December 31, 1996 of $7.5 million related to a
contract buydown received from the utility purchasing the electrical output of
the Hopewell facility. The decrease was partially offset by an increase in
maintenance costs incurred at the Hopewell facility during the year ended
December 31, 1997.
 
     The extraordinary loss on early extinguishment of debt for the year ended
December 31, 1997 related to the refinancing of the Portsmouth facility's
project debt in December 1997. The loss consisted of a write-off of the deferred
financing costs on the Portsmouth facility's original project debt and net swap
termination fees on interest rate swap agreements hedging the original project
debt. The extraordinary loss on early extinguishment of debt for the year ended
December 31, 1996 related to the write-off of the deferred financing costs on
the Elizabethtown, Lumberton, and Kenansville facilities' original project debt,
which was refinanced in September 1996.
 
     The provision for income taxes for the year ended December 31, 1997
represented an effective rate of 37.3% of income before income taxes as compared
to an effective rate of 35.8% of loss before benefit for income taxes for the
year ended December 31, 1996. The increase in effective rate for the year ended
December 31, 1997 related to a reduced recognition of losses for state income
tax purposes. A more complete discussion of income taxes is included in Note 9
of "Notes to Consolidated Financial Statements."
 
LIQUIDITY AND CAPITAL RESOURCES
 
     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 $10.1
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 $12.7 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.
 
     The principal components of operating cash flow for the year ended December
31, 1997 were generated by net income of $14.8 million, increases due to
adjustments for depreciation and amortization of $41.8 million, deferred income
taxes of $1.7 million, a write-off of deferred financing costs of $1.4 million,
minority interest in income of joint venture of $1.9 million, distributions from
and equity in net loss of unconsolidated
                                       30
<PAGE>   33
 
affiliates of $15.5 million and a net $5.5 million of cash provided by changes
in other working capital assets and liabilities. Cash flow provided by operating
activities of $82.6 million, proceeds from project finance borrowings of $65.2
million, $1.5 million of cash escrows released, proceeds from marketable
securities of $21.6, and $17.3 million of cash on hand at the beginning of the
year were primarily used to purchase property, plant and equipment additions of
$2.4 million, to make investments in affiliates of $61.1 million, to pay
deferred financing costs of $0.9 million, to repay project finance borrowings of
$118.8 million and to pay a dividend to common shareholders of $5.0 million.
 
     The principal components of cash flow provided by operating activities for
fiscal year ended December 31, 1996 were generated by net loss of $20.9 million,
increases due to adjustments for depreciation and amortization of $36.7 million,
loss on impairment of cogeneration facilities of $65.6 million, a write-off of
deferred financing costs of $1.2 million, and a net of $10.3 million source of
cash reflecting changes in other working capital assets and liabilities which
were partially offset by deferred income taxes of $21.6 million, minority
interest in net income, net of dividends of $4.9 million, gain on sale of
investments in affiliates of $3.2 million and distributions from and equity in
income of unconsolidated affiliates of $0.6 million. Cash flow provided by
operating activities of $62.6 million, proceeds from project finance borrowings
of $210.2 million, proceeds from sale of investment in affiliate of $25.5
million, proceeds from sale of marketable securities of $0.4 and $6.0 million of
cash escrows released were primarily used to purchase property, plant and
equipment of $1.5 million, to make investments in affiliates of $6.1 million, to
repay project finance borrowings of $229.7 million, to pay a dividend to common
shareholders of $4.8 million and to pay deferred financing costs of $2.6
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 project subsidiary. This type of
financing is generally referred to as "project financing." The project financing
debt of our subsidiaries and joint ventures (aggregating $877.7 million as of
December 31, 1998) 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 three project subsidiaries
to fund cash deficits the projects may experience as a result of incurring
certain costs, subject to an aggregate cap of $51.9 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 project subsidiaries to pay dividends and management
fees periodically to Cogentrix Energy is subject to certain limitations in their
respective project credit documents. Such limitations generally
 
                                       31
<PAGE>   34
 
require that: (a) project debt service payments be current, (b) project debt
service coverage ratios be met, (c) all project debt service and other reserve
accounts be funded at required levels and (d) there be no default or event of
default under the relevant project credit documents. There are also additional
limitations that are adapted to the particular characteristics of each project
subsidiary. Management does not believe that such restrictions or limitations
will adversely affect its ability to meet its debt obligations.
 
     As of December 31, 1998, we had long-term debt (including the current
portion thereof) of approximately $1.2 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 $54.7
million to $86.3 million in the five-year period ending December 31, 2003. 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.
 
     For the year ended December 31, 1998, the ratio of Parent EBITDA to Parent
Fixed Charges was 3.07x. 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.
 
     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 $60 million of the credit availability under the
corporate credit facility for letters of credit issued in connection with the
Bechtel Acquisition and the Batesville Acquisition. 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.
 
     In December 1997, we substantially completed construction of the Clark
facility and earned a construction management fee of $4.5 million. In August
1998, we earned an additional $4.3 million, which represents an additional
construction management fee of $0.5 million and our share ($3.8 million) of cost
savings in constructing the Clark facility.
 
     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. In
March 1998, the project subsidiary borrowed $20 million under the revolving
credit facility and distributed such amount to Cogentrix Energy for purposes of
funding a portion of the purchase price related to the Whitewater/Cottage Grove
Acquisition. In July 1998, the project subsidiary borrowed an additional $20.5
million under the revolving credit facility and distributed such amount to
Cogentrix Energy for purposes of paying down the outstanding balance under the
corporate credit facility. In November 1998, we utilized a portion of the
proceeds from the sale of the outstanding notes together with corporate cash
balances to pay down the outstanding balance under the Portsmouth facility's
revolving credit facility.
 
                                       32
<PAGE>   35
 
     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 will receive a distribution of the remaining
$1.0 million in 1999. The purchase price was ultimately funded with a portion of
the proceeds from the sale of the 2008 Note 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
and (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
June 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.
 
     As a result of a March 1999 arbitration award related to a contract dispute
with a coal supplier, we are 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 will not materially reduce
the projected amount of cash flow to Cogentrix Energy for the current fiscal
year and should not, therefore, have a material adverse impact on Cogentrix
Energy's ability to service its outstanding debt.
 
     For the fiscal year ended December 31, 1998, our board of directors
declared a dividend on the outstanding common stock of $7.4 million, which was
paid in March 1999. 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.
                                       33
<PAGE>   36
 
     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 its 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.
 
     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, 1998. 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, 1998.
Future interest rates are likely to vary from those disclosed in the table.
 
<TABLE>
<CAPTION>
                                          EXPECTED MATURITY DATE
                            ---------------------------------------------------
                             1999       2000       2001       2002       2003      THEREAFTER      TOTAL
                            -------    -------    -------    -------    -------    ----------    ----------
                                              (IN THOUSANDS)
<S>                         <C>        <C>        <C>        <C>        <C>        <C>           <C>
Long-term Debt
  Fixed Rate..............  $ 3,929    $ 6,257    $28,544    $29,790    $32,396     $455,646     $  556,562
    Weighted average
      interest rate.......     8.00%      7.45%      7.48%      7.47%      7.46%        7.75%
  Variable Rate...........  $82,325    $83,728    $59,347    $48,321    $22,317     $359,064        655,102
    Weighted average
      interest rate.......     6.39%      6.41%      6.40%      6.48%      6.72%        8.16%
                                                                                                 ----------
                                                                                                 $1,211,664
                                                                                                 ==========
</TABLE>
 
                                       34
<PAGE>   37
 
     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, 1998 was
$343,112,000. 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 6.48% to a weighted average effective rate
of 6.76% at December 31, 1998.
 
            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>
$ 7,000,000      8/30/90    8/30/00    9.503%    5.555%     $  (477,903)
 36,700,000      1/14/98    6/30/02    5.555%    5.048%        (315,527)
 67,000,000      2/12/98   12/31/02   5.6875%    5.591%        (812,501)
 20,000,000      7/31/00    7/31/02    6.995%       --         (635,016)
 58,163,000     12/20/95    7/31/06    6.078%    5.470%      (2,402,250)
 43,128,981     11/15/98     3/7/01    5.585%    5.591%        (271,852)
                                                            -----------
                                                            $(4,915,049)
                                                            ===========
</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>
$14,420,000      12/31/96    3/31/01    7.500%      6.05%    $  (164,810)
 36,700,000       2/20/97    6/28/02    6.500%      6.05%       (236,695)
 80,000,000       10/7/92    9/18/99     9.00%      6.70%             --
 80,000,000       9/18/99    7/31/00    9.000%        --        (478,371)
 31,000,000       7/31/00    7/31/02    9.000%        --        (291,495)
                                                             -----------
                                                             $(1,171,371)
                                                             ===========
</TABLE>
 
---------------
 
(1) The "variable rate receive" and "actual interest rate" are based on the
    interest rates in effect as of December 31, 1998. Interest rates in the
    future are likely to vary from those disclosed in the tables above.
 
YEAR 2000 COMPLIANCE
 
     The Year 2000 issue exists because many computer systems and applications,
including those embedded in equipment and facilities, use two digit rather than
four digit date fields to designate an applicable year. As a result, the systems
and applications may not properly recognize the year 2000 or process data which
includes such date, potentially causing data miscalculations or inaccuracies or
operational malfunctions or failures. Cogentrix initiated assessments in 1997 to
identify the issues required to be resolved to assure business critical systems
successfully operate upon and beyond the turn of the century. The assessments
include reviewing information technology and systems utilizing embedded
technology. Plans for achieving Year 2000 compliance were finalized during 1998
and remediation work is underway. We have identified the following systems and
applications on which to focus our efforts to ensure Year 2000 compliance:
 
     - corporate applications, which include core business systems;
     - embedded technology systems, which include the plants' operating and
       control systems and
     - business partner and vendor systems.
 
Non-compliance in the embedded technology systems or business partner and vendor
systems could result in temporary shutdown of the facilities, and potential
equipment damage.
 
                                       35
<PAGE>   38
 
     Replacement of our core financial systems which included corporate
applications such as purchasing, accounts payable and general ledger, with Year
2000 compliant client-server software is virtually complete. We expect to
complete the updating of the human resources and internal payroll systems by
June 30, 1999. We do not expect any disruptions in corporate applications as a
result of the Year 2000 issue.
 
     Investigation, analysis, remediation and contingency planning for embedded
technology such as plant operating control systems, telecommunications and
facilities-based equipment at all of our power generation facilities have been
completed. The investigation and analysis have identified no significant Year
2000 issues. For those insignificant issues that have been identified as
non-compliant, we have established a remediation plan to address the areas of
non-compliance. The remediation of these systems is expected to be completed by
June 30, 1999. The costs to replace our core financial systems, update our human
resources and internal payroll systems and bring the operating systems at the
plant facilities fully compliant with Year 2000 are currently expected to be
approximately $2.8 million, of which $2.4 million has already been incurred.
 
     We are communicating with critical suppliers, vendors, joint venture
partners and major customers verbally, in writing and through other
representations made by the organizations to assess their compliance efforts and
our exposure resulting from Year 2000 issues. Of major concern to us are the
fuel suppliers and transporters, and the electric and steam customers. We
produce revenue by selling the power we produce to major utilities. We depend on
fuel suppliers and transporters to deliver our fuel to power the generating
facilities. We also rely on transmission and distribution facilities to deliver
our power to the electric and steam customers. At this time, based on our review
of responses we have received, we do not expect a major impact from
non-compliant Year 2000 suppliers, vendors, joint venture partners or major
customers. However, an incomplete or incorrect assessment of the Year 2000
issues by the suppliers and transporters, transmission and distribution
facilities, as well as the utility customers, could adversely effect our
financial results and operations.
 
     We have developed contingency plans for the critical systems. We developed
these plans to address our most likely worst case scenario, the inability of our
plants to produce and distribute power. The contingency plans include turning
back the date on all date critical systems at the plants to ensure the
continuous operation of the generating facilities. These plans have been tested
and appear to be adequate.
 
     We expect that our business critical systems will be Year 2000 compliant by
December 31, 1999, and we do not anticipate costs associated with the Year 2000
issue to have a material impact on our consolidated results of operations or
financial position. Currently, we have not entered into any material contracts
with external contractors to complete the Year 2000 compliance projects. We have
dedicated two headquarters level employees to oversee, develop and test systems
to ensure Year 2000 readiness. Managers at each plant location are also
responsible for various components of the Year 2000 testing. Despite
management's current expectations, there can be no assurances that there will
not be interruptions or other limitations of financial and operating systems
functionality or that we will not ultimately incur significant unplanned costs
to avoid such interruptions or limitations.
 
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 following calendar year. We
have restated our consolidated financial statements for the 1997 and 1996 fiscal
years to a calendar basis.
 
                                       36
<PAGE>   39
 
ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
                                     INDEX
 
<TABLE>
<CAPTION>
                                                              PAGE
                                                              ----
<S>                                                           <C>
Reports of Independent Public Accountants...................   38
Consolidated Financial Statements:
  Consolidated Balance Sheets at December 31, 1998 and
     1997...................................................   40
  Consolidated Statements of Operations For the Years Ended
     December 31, 1998, 1997 and 1996.......................   41
  Consolidated Statements of Changes in Shareholders' Equity
     For the Years Ended December 31, 1998, 1997 and 1996...   42
  Consolidated Statements of Cash Flows For the Years Ended
     December 31, 1998, 1997 and 1996.......................   43
Notes to Consolidated Financial Statements..................   44
Financial Statement Schedules:
Schedule I -- Condensed Financial Information of the
  Registrant................................................   64
</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>   40
 
                    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, 1998 and 1997, 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, 1998. 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. The summarized
financial data for Bolivian Power Company Limited contained in Note 5 are based
on the financial statements of Bolivian Power Company Limited which were audited
by other auditors. Their report has been furnished to us and our opinion,
insofar as it relates to the data in Note 5, is based solely on the report of
the other auditors.
 
     We conducted our audits in accordance with generally accepted auditing
standards. 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, based on our audits and the report of other auditors, 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, 1998 and 1997 and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 1998, in
conformity with generally accepted accounting principles.
 
     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 19, 1999
 
                                       38
<PAGE>   41
 
                    REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
 
TO THE BOARD OF DIRECTORS AND SHAREHOLDERS:
Compania Boliviana de Energia Electrica S.A. -- Bolivian Power Company Limited
 
     We have audited the consolidated financial statements of Compania Boliviana
de Energia Electrica S.A. -- Bolivian Power Company Limited and its subsidiaries
as of December 31, 1996 and 1995, and the related consolidated statements of
income of cash flows and of shareholders' equity for each of the three years in
the period ended December 31, 1996 (not presented separately herein). 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 of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
 
     In our opinion, the consolidated financial statements audited by us present
fairly, in all material respects, the financial position of Compania Boliviana
de Energia Electrica S.A. -- Bolivian Power Company Limited and its subsidiaries
at December 31, 1996 and 1995, and the results of their operations and their
cash flows for each of the three years in the period ended December 31, 1996, in
conformity with accounting principles generally accepted in the United States of
America.
 
                                          PRICEWATERHOUSECOOPERS LLP
 
La Paz, Bolivia
February 28, 1997
 
                                       39
<PAGE>   42
 
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES
 
                          CONSOLIDATED BALANCE SHEETS
                           DECEMBER 31, 1998 AND 1997
                             (DOLLARS IN THOUSANDS)
 
<TABLE>
<CAPTION>
                                                                 1998        1997
                                                              ----------   --------
<S>                                                           <C>          <C>
                                      ASSETS
CURRENT ASSETS:
  Cash and cash equivalents.................................  $   48,207   $ 71,833
  Restricted cash...........................................      40,604     27,742
  Marketable securities.....................................          --     42,118
  Accounts receivable.......................................      66,586     49,781
  Inventories...............................................      18,697     15,210
  Other current assets......................................       4,061      2,465
                                                              ----------   --------
          Total current assets..............................     178,155    209,149
NET INVESTMENT IN LEASES....................................     498,614         --
PROPERTY, PLANT AND EQUIPMENT, net of accumulated
  depreciation of $225,928 and $188,227, respectively.......     473,065    496,589
LAND AND IMPROVEMENTS.......................................       3,981      2,540
DEFERRED FINANCING COSTS, net of accumulated amortization of
  $15,557 and $16,952, respectively.........................      37,007     21,085
NATURAL GAS RESERVES........................................       1,557      2,384
INVESTMENTS IN AFFILIATES...................................     251,312     79,072
OTHER ASSETS................................................      56,160     12,155
                                                              ----------   --------
                                                              $1,499,851   $822,974
                                                              ==========   ========
                       LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
  Current portion of long-term debt.........................  $   86,255   $ 74,680
  Accounts payable..........................................      25,511     13,755
  Accrued compensation......................................       8,096      4,923
  Accrued interest payable..................................       7,729      2,935
  Accrued dividends payable.................................       7,398      2,140
  Other accrued liabilities.................................      13,492      8,182
                                                              ----------   --------
          Total current liabilities.........................     148,481    106,615
LONG-TERM DEBT..............................................   1,127,184    595,112
DEFERRED INCOME TAXES.......................................      52,306     25,872
MINORITY INTERESTS..........................................      61,167     15,131
OTHER LONG-TERM LIABILITIES.................................      22,850     21,946
                                                              ----------   --------
                                                               1,411,988    764,676
                                                              ----------   --------
COMMITMENTS AND CONTINGENCIES (NOTES 10 AND 12)
SHAREHOLDERS' EQUITY:
  Common stock, no par value, 300,000 shares authorized;
     282,000 shares issued and outstanding..................         130        130
  Net unrealized gain on available for sale securities......          --         26
  Accumulated earnings......................................      87,733     58,142
                                                              ----------   --------
                                                                  87,863     58,298
                                                              ----------   --------
                                                              $1,499,851   $822,974
                                                              ==========   ========
</TABLE>
 
          The accompanying notes to consolidated financial statements
           are an integral part of these consolidated balance sheets.
 
                                       40
<PAGE>   43
 
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES
 
                     CONSOLIDATED STATEMENTS OF OPERATIONS
              FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
      (DOLLARS IN THOUSANDS, EXCEPT FOR EARNINGS (LOSS) PER COMMON SHARE)
 
<TABLE>
<CAPTION>
                                                                1998       1997       1996
                                                              --------   --------   --------
<S>                                                           <C>        <C>        <C>
OPERATING REVENUE:
  Electric..................................................  $293,083   $307,104   $340,681
  Steam.....................................................    25,043     26,123     28,987
  Lease.....................................................    34,715         --         --
  Service revenue under capital leases......................    34,470         --         --
  Income from unconsolidated investments in power
     projects...............................................     6,474      1,412      3,408
  Other.....................................................    17,672     15,275     15,769
                                                              --------   --------   --------
                                                               411,457    349,914    388,845
                                                              --------   --------   --------
OPERATING EXPENSES:
  Fuel expense..............................................    77,847    118,731    157,743
  Cost of services under capital leases.....................    39,376         --         --
  Operations and maintenance................................    71,108     71,367     74,456
  General, administrative and development expenses..........    36,490     41,650     31,245
  Depreciation and amortization.............................    42,535     41,844     37,455
  Loss on impairment and cost of removal of cogeneration
     facilities.............................................        --         --     65,628
                                                              --------   --------   --------
                                                               267,356    273,592    366,527
                                                              --------   --------   --------
OPERATING INCOME............................................   144,101     76,322     22,318
OTHER INCOME (EXPENSE):
  Interest expense..........................................   (74,949)   (53,864)   (56,950)
  Investment and other income...............................     9,226      9,789     10,942
  Equity in net loss of affiliates, net.....................    (3,274)    (1,538)    (2,135)
                                                              --------   --------   --------
INCOME (LOSS) BEFORE MINORITY INTERESTS IN INCOME, INCOME
  TAXES AND EXTRAORDINARY LOSS..............................    75,104     30,709    (25,825)
MINORITY INTERESTS IN INCOME................................   (12,458)    (4,672)    (5,621)
                                                              --------   --------   --------
INCOME (LOSS) BEFORE INCOME TAXES AND EXTRAORDINARY LOSS....    62,646     26,037    (31,446)
BENEFIT (PROVISION) FOR INCOME TAXES........................   (24,914)    (9,754)    11,273
                                                              --------   --------   --------
INCOME (LOSS) BEFORE EXTRAORDINARY LOSS.....................    37,732     16,283    (20,173)
EXTRAORDINARY LOSS ON EARLY EXTINGUISHMENT OF DEBT, net of
  minority interest and income tax benefit..................      (743)    (1,502)      (703)
                                                              --------   --------   --------
NET INCOME (LOSS)...........................................  $ 36,989   $ 14,781   $(20,876)
                                                              ========   ========   ========
EARNINGS (LOSS) PER COMMON SHARE:
  Income (loss) before extraordinary loss...................  $ 133.80   $  57.74   $ (71.54)
  Extraordinary loss........................................     (2.63)     (5.33)     (2.49)
                                                              --------   --------   --------
                                                              $ 131.17   $  52.41   $ (74.03)
                                                              ========   ========   ========
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.
 
                                       41
<PAGE>   44
 
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES
 
           CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY
              FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
         (DOLLARS IN THOUSANDS, EXCEPT FOR DIVIDENDS PER COMMON SHARE)
 
<TABLE>
<CAPTION>
                                                             NET UNREALIZED
                                                             GAIN (LOSS) ON
                                                    COMMON    AVAILABLE FOR    ACCUMULATED
                                                    STOCK    SALE SECURITIES    EARNINGS      TOTAL
                                                    ------   ---------------   -----------   --------
<S>                                                 <C>      <C>               <C>           <C>
Balance, December 31, 1995........................   $130         $(375)        $ 76,136     $ 75,891
Net unrealized gain on available for sale
  securities, net of deferred income taxes........     --           375               --          375
Net loss..........................................     --            --          (20,876)     (20,876)
Common stock dividends ($16.88 per common
  share)..........................................     --            --           (4,759)      (4,759)
                                                     ----         -----         --------     --------
Balance, December 31, 1996........................    130            --           50,501       50,631
Net unrealized gain on available for sale
  securities, net of deferred income taxes........     --            26               --           26
Net income........................................     --            --           14,781       14,781
Common stock dividends ($25.32 per common
  share)..........................................     --            --           (7,140)      (7,140)
                                                     ----         -----         --------     --------
Balance, December 31, 1997........................    130            26           58,142       58,298
Net unrealized loss on available for sale
  securities, net of deferred income taxes........     --           (26)              --          (26)
Net income........................................     --            --           36,989       36,989
Common stock dividends ($26.23 per common
  share)..........................................     --            --           (7,398)      (7,398)
                                                     ----         -----         --------     --------
Balance, December 31, 1998........................   $130         $  --         $ 87,733     $ 87,863
                                                     ====         =====         ========     ========
</TABLE>
 
          The accompanying notes to consolidated financial statements
             are an integral part of these consolidated statements.
 
                                       42
<PAGE>   45
 
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES
 
                     CONSOLIDATED STATEMENTS OF CASH FLOWS
              FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
                             (DOLLARS IN THOUSANDS)
 
<TABLE>
<CAPTION>
                                                                1998        1997        1996
                                                              ---------   ---------   --------
<S>                                                           <C>         <C>         <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
  Net income (loss).........................................  $  36,989   $  14,781   $(20,876)
  Adjustments to reconcile net income (loss) to net cash
     provided by operating activities:
     Depreciation and amortization..........................     42,535      41,844     37,455
     Loss on impairment and cost of removal of cogeneration
       facilities...........................................         --          --     65,628
     Deferred income taxes..................................     14,182       4,927    (18,098)
     Extraordinary loss on early extinguishment of debt.....      2,172       2,458      1,173
     Minority interests in income, net of dividends.........    (14,494)      1,935     (4,889)
     Gain on sale of investment in Bolivian Power...........         --          --     (3,243)
     Gain on sale of investment in affiliate................     (2,063)         --         --
     Equity in net (income) loss of unconsolidated
       affiliates...........................................     (3,200)        126     (1,273)
     Dividends received from unconsolidated affiliates......     13,362      15,354        633
     Minimum lease payments received........................     31,500          --         --
     Amortization of unearned lease income..................    (33,473)         --         --
     Decrease (increase) in accounts receivable.............     (7,278)      3,437     (2,172)
     Decrease (increase) in inventories.....................     (1,029)      4,385        720
     Increase (decrease) in accounts payable................     (4,212)     (9,490)     8,413
     Increase in accrued liabilities........................      5,179         499      6,249
     Decrease (increase) in other...........................     (5,425)      2,320     (6,451)
                                                              ---------   ---------   --------
          Net cash flows provided by operating activities...     74,745      82,576     63,269
                                                              ---------   ---------   --------
CASH FLOWS FROM INVESTING ACTIVITIES:
  Property, plant and equipment additions...................     (7,391)     (2,449)    (2,296)
  Decrease in marketable securities.........................     42,118      21,577        380
  Investments in unconsolidated affiliates..................   (180,292)    (61,063)    (6,142)
  Acquisition of facilities, net of cash acquired...........   (155,324)         --         --
  Proceeds from sale of investment in Bolivian Power, net...         --          --     25,504
  Decrease in restricted cash...............................     22,952       1,532      5,953
                                                              ---------   ---------   --------
          Net cash flows provided by (used in) investing
            activities......................................   (277,937)    (40,403)    23,399
                                                              ---------   ---------   --------
CASH FLOWS FROM FINANCING ACTIVITIES:
  Proceeds from corporate credit facility, notes payable and
     long-term debt.........................................    384,104      65,171    210,188
  Repayments of corporate credit facility, notes payable and
     long-term debt.........................................   (193,812)   (118,778)  (229,553)
  Payment of deferred financing costs.......................     (8,586)       (921)    (2,584)
  Common stock dividends paid...............................     (2,140)     (5,000)    (4,759)
                                                              ---------   ---------   --------
          Net cash flows provided by (used in) financing
            activities......................................    179,566     (59,528)   (26,708)
                                                              ---------   ---------   --------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS........    (23,626)    (17,355)    59,960
CASH AND CASH EQUIVALENTS, beginning of year................     71,833      89,188     29,228
                                                              ---------   ---------   --------
CASH AND CASH EQUIVALENTS, end of year......................  $  48,207   $  71,833   $ 89,188
                                                              =========   =========   ========
</TABLE>
 
          The accompanying notes to consolidated financial statements
             are an integral part of these consolidated statements.
 
                                       43
<PAGE>   46
 
                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, 1998, the
Company owned or had interests in 25 Facilities 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 3.3% to approximately 74%, the Company's net equity
interest in the total production capability of the 25 Facilities is
approximately 1,690 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.
 
     Marketable Securities -- Marketable securities include commercial paper,
corporate obligations, government securities, and certificates of deposit with
maturity dates in excess of three months from their date of purchase. All
investments in debt securities held by the Company are classified as available
for sale securities and are reported at fair value. Realized gains or losses are
determined on the specific identification method and are reflected in income.
Unrealized gains and losses are reported net of taxes as a separate component of
shareholders' equity, except those unrealized losses that are deemed to be other
than temporary, which are reflected in income.
 
     Construction Agreement -- In December 1994, the Company executed an
engineering, procurement and construction agreement (the "Construction
Agreement") with Public Utility District No. 1 of Clark County, Washington
("Clark"). Under this Construction Agreement, the Company engineered, procured
equipment for and constructed a 248 megawatt combined-cycle, gas-fired electric
generation facility (the "Clark Facility"). Construction of the facility was
substantially complete, and the facility commenced commercial operations in
December 1997. The Company accounted for the construction under the
completed-contract method, and, as such, all third-party construction costs and
reimbursements were deferred until the contract was completed. See Note 12 for
further discussion.
 
                                       44
<PAGE>   47
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
     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 for
a Facility that is 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, 1998 and 1997,
fuel and spare parts inventories are comprised of the following (dollars in
thousands):
 
<TABLE>
<CAPTION>
                                                                DECEMBER 31,
                                                              -----------------
                                                               1998      1997
                                                              -------   -------
<S>                                                           <C>       <C>
Coal........................................................  $ 8,028   $ 8,230
Natural gas.................................................    2,773       700
Spare parts.................................................    7,377     6,280
Fuel oil....................................................      519        --
                                                              -------   -------
                                                              $18,697   $15,210
                                                              =======   =======
</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 $305,000 and $427,000 less than the cost of these
inventories on a FIFO basis as of December 31, 1998 and 1997, 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 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.
 
     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, investments in unconsolidated entities which own and
operate greenhouses, 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 greenhouses and development joint venture entities is
included in other income (expense) in the accompanying consolidated statements
of operations.
 
     Project Development Costs -- Project development costs represent costs
incurred after executing a power sales contract or obtaining a viable project
site or signing a letter of intent and prior to obtaining project financing and
starting physical construction. These costs represent amounts incurred for
professional services, salaries, permits, options and other direct and
incremental costs and are included in construction in progress when project
financing is obtained or expensed at the time the Company determines the project
will not be developed.
 
     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 50%
and 19%
 
                                       45
<PAGE>   48
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
of revenues in the year ended December 31, 1998, 64% and 22% of revenues in the
year ended December 31, 1997 and 56% and 30% of revenues in the year ended
December 31, 1996.
 
     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.
 
     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.
 
     New Accounting Pronouncements -- In June 1998, the Financial Accounting
Standards Board 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
must formally document, designate, and assess the effectiveness of transactions
that receive hedge accounting.
 
     SFAS No. 133 is effective for fiscal years beginning after June 15, 1999.
Early adoption is allowed. SFAS No. 133 must be applied to derivative
instruments and certain derivative instruments embedded in hybrid contracts that
were issued, acquired, or substantially modified after December 31, 1997.
 
     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.
 
     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 will adopt SOP No. 98-5 as of January 1, 1999.
The Company has determined that SOP No. 98-5 will not have a material impact on
the financial statements.
 
     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
 
                                       46
<PAGE>   49
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
each July 1, concluding on June 30 of the following calendar year. The Company
has restated its consolidated financial statements for the 1997 and 1996 fiscal
years to a calendar year basis.
 
3. RECENT 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 8).
 
     The aggregate acquisition price for the equity interests in the Cottage
Grove and Whitewater Facilities acquired by the Company was $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 will receive a distribution of 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 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 sheet as of December 31,
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 sheet as of December 31, 1998. The accompanying
consolidated statement of operations for the twelve months ended December 31,
1998 includes the results of operations of the acquired facilities since the
closing date of the LS Power Acquisition (March 20, 1998).
 
     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,
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 June 2000. Electricity generated by the Batesville Facility will be
sold under long-term power purchase agreements with two investment-grade
utilities.
 
                                       47
<PAGE>   50
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
     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 (see Note 7).
 
     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 will
use the equity method of accounting to account for its ownership interests in
eight of these facilities (see Note 5) and will use the cost method of
accounting for its ownership interests in the other four facilities.
 
     The following unaudited pro forma consolidated results for the Company for
the years ended December 31, 1998 and December 31, 1997 give effect to the LS
Power Acquisition and the BGCI Acquisition as if these transactions had occurred
on January 1, 1998 and January 1, 1997, respectively (dollars in thousands,
except per share amount).
 
<TABLE>
<CAPTION>
                                                           PRO FORMA           PRO FORMA
                                                          YEAR ENDED          YEAR ENDED
                                                       DECEMBER 31, 1998   DECEMBER 31, 1997
                                                       -----------------   -----------------
<S>                                                    <C>                 <C>
Revenues.............................................      $447,788            $391,595
Net Income...........................................      $ 36,587            $  7,861
Earnings per Share...................................      $ 129.75            $  27.88
</TABLE>
 
4. INVESTMENT IN DEBT SECURITIES
 
     At December 31, 1997, investments in debt securities included in marketable
securities in the accompanying consolidated balance sheet consisted of
government securities and corporate obligations. The Company's net unrealized
gain of $40,000 on its investment in debt securities is reported in the
accompanying consolidated statements of changes in shareholders' equity, net of
$14,000 in deferred income taxes. The Company had no investments in debt
securities at December 31, 1998.
 
5. INVESTMENTS IN UNCONSOLIDATED POWER PROJECTS
 
BIRCHWOOD POWER PARTNERS, L.P.
 
     In December 1994, the Company acquired a 50% interest in Birchwood Power
Partners, L.P. ("Birchwood Power"), a partnership formed to construct and own a
220-megawatt coal-fired cogeneration facility (the "Birchwood Facility") in King
George County, Virginia, from two indirect wholly-owned subsidiaries of The
Southern Company. The Company initially paid $29.5 million for its 50% interest
in Birchwood Power. In addition, pursuant to the equity funding obligation under
Birchwood Power's project financing arrangements, the Company provided an equity
contribution to Birchwood Power of approximately $43.7 million in March 1997.
The initial distribution of $6.9 million received by the Company from Birchwood
Power in April 1997 was also subsequently paid to a subsidiary of The Southern
Company in accordance with the terms of the original transaction agreement and
was treated as part of the purchase price of the Company's interest in Birchwood
Power.
 
     The Birchwood Facility, which commenced commercial operations in November
1996, 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
 
                                       48
<PAGE>   51
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
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 $3,714,000, $1,412,000 and ($79,000) in income (loss) from
unconsolidated investments in power projects, net of premium amortization, in
the accompanying consolidated statements of operations for the years ended
December 31, 1998, 1997 and 1996, respectively, related to its investment in
Birchwood Power. The following table presents summarized financial information
for Birchwood Power as of December 31, 1998 and 1997 and for the years ended
December 31, 1998, 1997 and 1996 (dollars in thousands):
 
<TABLE>
<CAPTION>
                                                                1998       1997
                                                              --------   --------
<S>                                                           <C>        <C>
BALANCE SHEET DATA:
  Current assets............................................  $ 48,416   $ 30,577
  Noncurrent assets.........................................   344,374    374,560
                                                              --------   --------
          Total assets......................................  $392,790   $405,137
                                                              ========   ========
  Current liabilities.......................................  $  7,952   $  6,818
  Noncurrent liabilities....................................   329,428    335,134
  Partners' capital.........................................    55,410     63,185
                                                              --------   --------
                                                              $392,790   $405,137
                                                              ========   ========
</TABLE>
 
<TABLE>
<CAPTION>
                                                              1998      1997      1996
                                                             -------   -------   ------
<S>                                                          <C>       <C>       <C>
INCOME STATEMENT DATA:
  Operating revenues.......................................  $71,908   $69,275   $9,745
  Operating income.........................................   36,863    35,087    4,527
  Net income...............................................    9,747     6,451       26
</TABLE>
 
BGCI ASSETS
 
     The Company acquired interests in 12 electric generating facilities from
BGCI on October 20, 1998 (see Note 3). The Company's ownership interests in the
following projects acquired from BGCI 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        10.0            38.0
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>
 
                                       49
<PAGE>   52
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
     The Company recognized approximately $2,760,000 in income from
unconsolidated investments in power projects in the accompanying consolidated
statement of operations for the year ended December 31, 1998 related to its
investment in the projects acquired from BGCI. The following table presents
summarized combined financial data for the unconsolidated power projects
acquired from BGCI being accounted for under the equity method as of December
31, 1998 and for the period from October 20, 1998 to December 31, 1998 (dollars
in thousands):
 
<TABLE>
<CAPTION>
                                                              DECEMBER 31, 1998
                                                              -----------------
<S>                                                           <C>
BALANCE SHEET DATA:
  Current assets............................................     $  147,838
  Noncurrent assets.........................................      3,086,657
                                                                 ----------
          Total assets......................................     $3,234,495
                                                                 ==========
  Current liabilities.......................................     $  176,206
  Noncurrent liabilities....................................      2,627,848
  Partner's Capital.........................................        430,441
                                                                 ----------
                                                                 $3,234,495
                                                                 ==========
</TABLE>
 
<TABLE>
<CAPTION>
                                                               FOR THE PERIOD
                                                              OCTOBER 20, 1998
                                                                     TO
                                                              DECEMBER 31, 1998
                                                              -----------------
<S>                                                           <C>
INCOME STATEMENT DATA:
  Operating revenues........................................       $96,622
  Operating income..........................................        51,948
  Net income................................................        15,071
</TABLE>
 
BOLIVIAN POWER COMPANY LIMITED
 
     In November 1994, the Company acquired 719,206 shares of common stock of
Bolivian Power Company Limited ("Bolivian Power"), representing approximately
17.1% of Bolivian Power's issued and outstanding shares of common stock, for a
purchase price of approximately $18 million. In conjunction with the
transaction, three executive officers of the Company were elected to the
seven-member board of directors of Bolivian Power. In addition, the Company was
providing to Bolivian Power general administrative and management services, as
well as significant advisory services with respect to financial, regulatory and
governmental matters, pursuant to a management agreement. The investment in
Bolivian Power was accounted for using the equity method, because the Company
had the ability to exercise significant influence over Bolivian Power's
operating and financial policies.
 
     In January 1996, Bolivian Power closed the sale of its distribution
subsidiaries, realizing an after-tax gain of approximately $13.5 million. The
Company's share of this gain was approximately $2.3 million. In December 1996,
the Company sold its investment in Bolivian Power pursuant to a cash tender
offer made for all of the outstanding common stock of Bolivian Power at a price
of $43 per share. The Company received proceeds from the sale of $25.5 million,
net of transaction costs, which included payments to certain unaffiliated
individuals who performed development activities for Bolivian Power. The
resulting book gain of $3.2 million is included in investment and other income
in the accompanying consolidated statement of operations for the year ended
December 31, 1996. The Company recognized approximately $3.5 million in income
from unconsolidated investments in power projects in the accompanying
consolidated statements of operations for the year ended December 31, 1996
related to its investment in Bolivian Power. The following
 
                                       50
<PAGE>   53
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
table presents summarized financial information for Bolivian Power as of and for
the year ended December 31, 1996 (dollars in thousands):
 
<TABLE>
<CAPTION>
                                                                1996
                                                              --------
<S>                                                           <C>
BALANCE SHEET DATA:
  Current assets............................................  $ 72,550
  Noncurrent assets.........................................    81,211
                                                              --------
          Total assets......................................  $153,761
                                                              ========
  Current liabilities.......................................  $ 12,818
  Noncurrent liabilities....................................    15,036
  Shareholders' equity......................................   125,907
                                                              --------
                                                              $153,761
                                                              ========
INCOME STATEMENT DATA:
  Operating revenues........................................  $ 20,009
  Operating loss............................................    (4,159)
  Net income................................................     8,434
</TABLE>
 
6. 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 $307,000, $471,000,
and $1,936,000 in equity losses for the years ended December 31, 1998, 1997 and
1996, respectively, related to its 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. The Company,
accounting for its investment in these partnerships under the equity method,
recognized approximately $2,967,000, $1,066,000 and $200,000 in equity losses in
the accompanying consolidated statements of operations for the years ended
December 31, 1998, 1997 and 1996, respectively.
 
     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 in
the amount of approximately $20.6 million. EcoScience is required to register
the 1,000,000 shares of their common stock paid as consideration no later than
June 15, 1999. The note receivable from EcoScience accrues interest at 11.25%
per annum with principal and interest due on March 15, 1999 (see below), and is
secured by a pledge of all of the outstanding stock of Agro.
 
     As of December 31, 1998, the Company recognized a gain of $2.1 million
related to the sale of the greenhouse partnerships. This gain is included in
investment and other income in the accompanying consolidated statements of
operations for the year ended December 31, 1998. The Company may recognize an
additional gain of up to $11.6 million as the payment of the note becomes
assured. On March 15, 1999, the Company agreed to extend the due date for
principal and interest on the 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.
 
                                       51
<PAGE>   54
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
7. LONG-TERM DEBT
 
     The following long-term debt was outstanding as of December 31, 1998 and
1997, respectively (dollars in thousands):
 
<TABLE>
<CAPTION>
                                                              DECEMBER 31,   DECEMBER 31,
                                                                  1998           1997
                                                              ------------   ------------
<S>                                                           <C>            <C>
PROJECT FINANCING DEBT:
  HOPEWELL FACILITY:
     Note payable to banks..................................   $   67,000      $ 45,417
  PORTSMOUTH FACILITY:
     Note payable to banks..................................       43,129        61,489
  ROCKY MOUNT FACILITY:
     Note payable to financial institution..................      123,422       125,761
  RINGGOLD FACILITY:
     Note payable to banks..................................       13,440        15,737
  RICHMOND FACILITY:
     Commercial paper notes payable, net of unamortized
       issue discount of $350 and $365, respectively, and
       tax-exempt bonds.....................................      185,814       198,113
  ELIZABETHTOWN, LUMBERTON AND KENANSVILLE FACILITIES:
     Notes payable to banks.................................       16,964        26,716
  ROXBORO AND SOUTHPORT FACILITIES:
     Note payable to banks..................................       73,400        93,036
  COTTAGE GROVE AND WHITEWATER FACILITIES:
     Bonds payable, due 2010 and 2016, including unamortized
       fair market value adjustment related to purchase of
       facilities of $21,345................................      353,345            --
OTHER.......................................................        1,139         1,436
                                                               ----------      --------
          Total Project Financing Debt......................      877,653       567,705
SENIOR NOTES (including net unamortized gain (loss) on hedge
  transactions of $(20,048) and $2,087, respectively and net
  bond issuance premium of $835 and $0, respectively).......      335,786       102,087
                                                               ----------      --------
          Total Long-Term Debt..............................    1,213,439       669,792
Less: Current portion.......................................      (86,255)      (74,680)
                                                               ----------      --------
          Long-term portion.................................   $1,127,184      $595,112
                                                               ==========      ========
</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 .875% through February 1998 and 1.00% thereafter
     (6.47% at December 31, 1998). 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.
 
                                       52
<PAGE>   55
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
          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, 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, 1998, there were no outstanding balances under this 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 .875% through December 1998 and
     1.0% thereafter (6.59% at December 31, 1998). 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 statements of
     operations.
 
     Rocky Mount Facility:
 
          The note payable to financial institution consists of a $123,422,000
     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 $13,440,000 senior loan which
     accrues interest at an annual rate equal to the applicable LIBOR rate, as
     chosen by the Company, plus .95% to 1.35% per annum (6.70% at December 31,
     1998). 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.
 
     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 $138,165,000 as of December 31, 1998. 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 6.72% at December 31, 1998) 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 a Facility ($48.0 million outstanding at
 
                                       53
<PAGE>   56
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
     December 31, 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 (5.5% at December 31, 1998). 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, which consisted of a senior loan with a syndicate of banks and
     a subordinated credit facility with a financial institution, was refinanced
     in September 1996 with the proceeds of a $39 million senior credit facility
     and a $5.5 million capital contribution by the Company. The senior credit
     facility accrues interest at an annual rate equal to the applicable LIBOR
     rate, as chosen by the Company, plus .875% through September 1997 and 1%
     thereafter (6.05% at December 31, 1998). 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.
 
          An extraordinary loss of $1.2 million was recorded in the year ended
     December 31, 1996 related to the write-off of unamortized deferred
     financing costs from the original senior loan and subordinated credit
     facility. This extraordinary loss is shown net of a tax benefit of
     approximately $500,000 in the accompanying consolidated statements of
     operations.
 
     Roxboro and Southport Facilities:
 
          The project debt agreement for the Roxboro and Southport Facilities
     was amended in September 1996, resulting in an $18.4 million increase in
     the amount of outstanding indebtedness. The revised senior credit facility
     accrues interest at an annual rate equal to the applicable LIBOR rate, as
     chosen by the Company, plus .875% through September 1997, 1% thereafter
     through September 2001 and 1.125% thereafter (6.05% at December 31, 1998).
     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. Cogentrix Energy,
     Inc. has indemnified the lenders of the senior credit facility for any cash
     deficits the Roxboro and Southport Facilities could experience as a result
     of incurring certain costs, subject to a cap of $11.3 million.
 
     Cottage Grove and Whitewater Facilities:
 
          The project debt of the Cottage Grove and Whitewater Facilities
     consist of the following senior secured bonds:
 
<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.
 
          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 available in a form of the
     issuance of letters of credit
 
                                       54
<PAGE>   57
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
     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. The revolving credit expires, unless extended, in December
     1999. At expiration, the outstanding balance is payable over four years in
     16 equal quarterly repayments.
 
     Interest Rate Protection Agreements:
 
          The Company has entered into interest rate cap and interest rate swap
     agreements (Note 14) 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, 1998 and 1997 were $343,111,981 and
     $259,191,000, respectively. The agreements effectively change the interest
     rate on the portion of debt covered by the notional amounts from a weighted
     average variable rate of 6.48% at December 31, 1998 to a weighted average
     effective rate of 6.76% at December 31, 1998. 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
     8.75% senior notes due 2008 in a Rule 144A offering (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 resulting in an
     effective rate of approximately 7.95%. Cogentrix Energy, Inc. anticipates
     completing an exchange offer in April 1999 for the notes issued in the Rule
     144A offering for exchange notes registered under the Securities Act of
     1933, as amended.
 
          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.
 
     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, 1998, the Company has used this credit
     facility to issue
 
                                       55
<PAGE>   58
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
     $60 million of letters of credit in connection with investments made in
     electric-generating plants, and one plant under construction.
 
          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 project subsidiaries to pay dividends and
     management fees periodically to the Company (as parent) is subject to
     certain limitations in their respective project credit documents. Such
     limitations generally require that: (i) project debt service payments be
     current, (ii) project debt service coverage ratios be met, (iii) all
     project debt service and other reserve accounts be funded at required
     levels, and (iv) there be no default or event of default under the relevant
     project 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 a $7.4 million dividend
     to the Company's shareholders for the year ended December 31, 1998.
 
          Future maturities of long-term debt at December 31, 1998, net of
     unamortized issue discounts on commercial paper notes, the net unamortized
     premium on senior notes and excluding the unamortized balance of the
     deferred gains and losses on hedge transactions, are as follows (dollars in
     thousands):
 
<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31,
------------
<S>                                                       <C>
1999....................................................   $   86,255
2000....................................................       89,985
2001....................................................       87,891
2002....................................................       78,111
2003....................................................       54,713
Thereafter..............................................      814,709
                                                           ----------
                                                           $1,211,664
                                                           ==========
</TABLE>
 
          Cash paid for interest on the Company's long-term debt amounted to
     $76,358,000, $55,339,000 and $56,039,000 for the years ended December 31,
     1998, 1997 and 1996, respectively.
 
8. 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".
 
                                       56
<PAGE>   59
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
     The components of the net investment in the leases at December 31, 1998 are
as follows (dollars in thousands):
 
<TABLE>
<S>                                                           <C>
Gross Investment in Leases..................................  $1,140,909
Unearned Income on Leases...................................    (642,295)
                                                              ----------
          Net Investment in Leases..........................  $  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.
 
     Estimated minimum lease payments over the remaining term of the power
purchase agreements as of December 31, 1998 are as follows (dollars in
thousands):
 
<TABLE>
<S>                                                           <C>
1999........................................................  $   43,116
2000........................................................      45,180
2001........................................................      45,192
2002........................................................      47,244
2003........................................................      49,056
Thereafter..................................................     911,121
                                                              ----------
          Total.............................................  $1,140,909
                                                              ==========
</TABLE>
 
9. INCOME TAXES
 
     The provision (benefit) for income taxes for the years ended December 31,
1998, 1997 and 1996, consists of the following (dollars in thousands):
 
<TABLE>
<CAPTION>
                                                             YEARS ENDED DECEMBER 31,
                                                            ---------------------------
                                                             1998      1997      1996
                                                            -------   ------   --------
<S>                                                         <C>       <C>      <C>
Current
  Federal.................................................  $ 6,561   $3,619   $  5,929
  State...................................................    3,698      252        426
                                                            -------   ------   --------
                                                             10,259    3,871      6,355
                                                            -------   ------   --------
Deferred
  Federal.................................................   13,565    3,942    (13,530)
  State...................................................      617      985     (4,568)
                                                            -------   ------   --------
                                                             14,182    4,927    (18,098)
                                                            -------   ------   --------
                                                            $24,441   $8,798   $(11,743)
                                                            =======   ======   ========
Statements of Operations Captions
  Tax effect of extraordinary loss........................  $  (473)  $ (956)  $   (470)
  Provision (benefit) for income taxes....................   24,914    9,754    (11,273)
                                                            -------   ------   --------
                                                            $24,441   $8,798   $(11,743)
                                                            =======   ======   ========
</TABLE>
 
                                       57
<PAGE>   60
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
     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,
                                                                ------------------------
                                                                1998     1997      1996
                                                                -----    -----    ------
<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................................................     3.4      3.4      (5.0)
Other.......................................................     1.4     (1.1)      4.2
                                                                ----     ----     -----
Effective tax rate..........................................    39.8%    37.3%    (35.8)%
                                                                ====     ====     =====
</TABLE>
 
     The net current and noncurrent components of deferred income taxes
reflected in the accompanying consolidated balance sheets as of December 31,
1998 and 1997 are as follows (dollars in thousands):
 
<TABLE>
<CAPTION>
                                                                DECEMBER 31,
                                                              -----------------
                                                               1998      1997
                                                              -------   -------
<S>                                                           <C>       <C>
Net current deferred tax (asset) liability..................  $(2,269)  $(1,615)
Net noncurrent deferred tax liability.......................   52,306    25,872
                                                              -------   -------
Net deferred tax liability..................................  $50,037   $24,257
                                                              =======   =======
</TABLE>
 
     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, 1998 and 1997 are as
follows (dollars in thousands):
 
<TABLE>
<CAPTION>
                                                                DECEMBER 31,
                                                              -----------------
                                                               1998      1997
                                                              -------   -------
<S>                                                           <C>       <C>
Deferred tax liabilities:
  Depreciation/amortization and book/tax basis
     differences............................................  $59,435   $60,072
  Book/tax timing differences on joint venture interest.....   34,043    11,727
  Other.....................................................   10,124     5,323
                                                              -------   -------
                                                              103,602    77,122
                                                              -------   -------
Deferred tax assets:
  Depreciation/amortization and book/tax basis
     differences............................................   13,463    11,626
  Operating loss carryforwards..............................    3,852     2,726
  Accrued expenses not currently deductible.................    7,211     7,066
  Investment tax credit carryforwards.......................       --     2,291
  Alternative minimum tax credit carryforwards..............   22,867    23,537
  Other.....................................................    6,172     5,619
                                                              -------   -------
                                                               53,565    52,865
                                                              -------   -------
          Net deferred tax liability........................  $50,037   $24,257
                                                              =======   =======
</TABLE>
 
     At December 31, 1998, the Company had alternative minimum tax credit
carryforwards of approximately $22,867,000 with no expiration date available to
reduce its future federal income tax liabilities.
 
     Cash paid for income taxes amounted to $11,367,000, $12,127,000 and
$7,877,000 for the years ended December 31, 1998, 1997 and 1996, respectively.
 
                                       58
<PAGE>   61
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
10. 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 7 years and 50 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, 1998 are as follows (dollars in thousands):
 
<TABLE>
<CAPTION>
                                                                        OTHER
YEAR ENDED                                                            EQUIPMENT
DECEMBER 31,                                                  ELP     PROVIDERS   TOTAL
------------                                                 ------   ---------   ------
<S>                                                          <C>      <C>         <C>
1999.......................................................  $1,561     $321      $1,882
2000.......................................................   1,554      257       1,811
2001.......................................................   1,354       93       1,447
2002.......................................................   1,327       --       1,327
2003.......................................................   1,097       --       1,097
Thereafter.................................................   5,000       --       5,000
</TABLE>
 
11. LOSS ON IMPAIRMENT AND COST OF REMOVAL OF COGENERATION FACILITIES
 
     During the fiscal year ended December 31, 1996, the Company undertook an
analysis of the post-contract operating environment for all of its operating
facilities in light of the dramatic market changes that are taking place in the
power generation industry. The analysis included assumptions regarding future
levels of operations, operating costs and market prices for equivalent
generation available from other sources. As a part of this analysis, in
accordance with the Statement of Financial Accounting Standards No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed of," the Company assessed whether any impairment of the Company's
Facilities had occurred. This assessment included comparing the projected future
cash flows to be provided by these assets to the net book value of such assets.
Based on this assessment, the Company determined that an impairment loss had
occurred on the Elizabethtown, Lumberton, Kenansville and Ringgold Facilities.
This loss on impairment of cogeneration facilities of $57.3 million represents
the excess of the net book value of these cogeneration facilities over their
current fair value, determined by discounting to present value projected future
cash flows to be provided by such assets. The Company believes that its
projections of future cash flows are based upon reasonable assumptions about the
future performance of these assets. Because of the risks and uncertainties
associated with any projections, there can be no assurances, however, that
actual events will be consistent with the assumptions made, and future cash
flows may be greater or less than those projected. The analysis also resulted in
the recognition of an $8.3 million liability related to the Company's estimated
cost of removal obligations under the land leases for the Elizabethtown,
Lumberton and Kenansville Facilities. The total impairment loss and cost of
removal of $65.6 million has been reflected in the accompanying consolidated
statement of operations for the year ended December 31, 1996.
 
     Also in connection with the overall assessment of the post-contract
operating environment for its cogeneration facilities, the Company concluded
that the estimated useful lives of the Elizabethtown, Lumberton, Kenansville,
Roxboro and Southport Facilities should be adjusted to reflect the economic
lives of the plants as determined by the remaining terms of their respective
power purchase agreements. The annual depreciation expense for these five
facilities, in aggregate, increased approximately $6.1 million per year as a
result of the changes in estimated useful lives and the impairment loss
recognized during the fiscal year ended December 31, 1996.
 
                                       59
<PAGE>   62
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
12. 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
25 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 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 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 terms of contracts with one Utility, the Company is obligated to pay
up to $8,850,000 in liquidated damages to the Utility if two of the Company's
Facilities do not demonstrate certain operating and reliability standards. A
bank has issued letters of credit in favor of the Utility which secure the
Company's obligations to the Utility 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.
 
     Construction Agreement -- In October 1995, the Company delivered to Clark a
$20 million letter of credit, provided by a bank, which was collateralized with
a pledge of marketable securities. This letter of credit supported certain
contingent obligations of the Company under the Construction Agreement. In
December 1997, the Company substantially completed construction of the Clark
Facility and earned a construction fee of $4.5 million, which is included in
other operating revenue in the accompanying consolidated statement of operations
for the year ended December 31, 1997. The $20 million letter of credit was also
released to the Company at this time. During 1998, the Company completed
construction of the Clark Facility resulting in an additional $500,000
construction fee and received $3.8 million representing its 50% share of the
amount equal to the excess of the contract amount over the costs and expenses
incurred in constructing the Clark Facility.
 
                                       60
<PAGE>   63
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
Both of these amounts are included in other operating revenue in the
accompanying consolidated statement of operations for the year ended December
31, 1998.
 
     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 $5,758,000, $9,123,000 and $4,247,000 for the
fiscal years ended December 31, 1998, 1997 and 1996, 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.
 
     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 $1,435,000, $1,483,000 and $1,573,000 for the fiscal years ended
December 31, 1998, 1997 and 1996, 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 $4,853,000 and
$2,685,000 at December 31, 1998 and 1997, 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 $51.9 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 2001, 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.
 
     Pending Claims and Litigation -- Effective September 1996, the Company
amended the power sales agreements on its Elizabethtown, Lumberton, Kenansville,
Roxboro, and Southport Facilities. Under the amended terms of these power sales
agreements, the purchasing utility has exercised its right of economic dispatch
resulting in significant reductions in fuel requirements at each of these
facilities. In response to this reduction in fuel requirements, one of the coal
suppliers for these facilities initiated an arbitration proceeding and another
filed a civil action against certain subsidiaries of the Company. The
arbitration proceeding was completed in October 1997, with the arbitration panel
denying any recovery to the coal supplier. The coal supplier subsequently
challenged the arbitration panel's ruling on grounds of partiality by the
neutral arbitrator. On April 15, 1998, the federal district court issued an
order vacating the arbitration award and directing a new arbitration be
conducted. The Company has appealed this decision to the United States Court of
Appeals for the Fourth Circuit. The Company believes that the district court
action was in error, that the
 
                                       61
<PAGE>   64
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
arbitration award is valid and should be upheld on appeal. With respect to the
civil action filed by the other coal supplier, the Company filed a motion to
compel arbitration of the contract claim, consented to, and filed a demand for,
arbitration of the claim. In March 1999, the dispute was submitted to
arbitration before a three-member panel of arbitrators. With one member of the
panel dissenting, the arbitrators ruled in favor of the coal supplier, awarding
approximately $8 million payable in 1999. Approximately $3 million of this award
relates to the reduction in purchase quantities for prior periods, and
approximately $5 million relates to a 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 the project subsidiary.
 
     Effective December 1997, the Company amended the power sales agreement on
its Portsmouth Facility. Under the amended terms, the purchasing utility has
exercised its right to economic dispatch which has led to significant reductions
in that facility's fuel requirements. In response to the reduced fuel
requirements, the coal supplier for the Portsmouth Facility filed a civil action
in federal district court against a subsidiary of the Company. Upon motion by
the Company, the court has stayed the action pending arbitration of the claims
in Charlotte, North Carolina. On March 11, 1999, a project subsidiary of the
Company entered into a comprehensive settlement agreement with this coal
supplier, which is subject to the approval of the Company's and coal supplier's
board of directors and to the approval of the lenders to the project subsidiary.
 
     The Company has established reserves which management believes to be
adequate to cover any expense resulting from these matters. Management believes
that the resolution of these disputes should not have a material adverse effect
on the consolidated financial position, results of operations or cash flows of
the Company.
 
     Indirect, wholly-owned subsidiaries of Cogentrix Energy are also parties 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
these subsidiaries in their defense of such claims -- that the ultimate
resolution of these claims should not have a material adverse effect on the
Company's consolidated financial position or results of operations or Cogentrix
Energy's ability to generate sufficient cash flow to service its outstanding
debt.
 
     In addition, the Company experiences other routine litigation in the normal
course of its business. Management is of the opinion that none of this routine
litigation should have a material adverse effect on its consolidated financial
position or results of operations.
 
     Termination Agreement for Power Purchase Agreement -- In January 1998, the
Company signed an agreement with Pennsylvania Electric Company ("Penelec") to
terminate the Ringgold Facility's power purchase agreement. This termination
agreement was the result of a request for proposals to buy-back or restructure
power sales agreements issued to all operating IPP projects in Penelec's
territory in April 1997. The termination agreement with Penelec provides for a
payment to the Company of approximately $23 million which will be sufficient to
retire all of Cogentrix of Pennsylvania, Inc.'s ("CPA") outstanding project
debt. The buy-back of the power purchase agreement is subject to the issuance of
an order by the Pennsylvania Public Utility Commission granting Penelec the
authority to fully recover from its customers the consideration paid to CPA
under the buyout agreement. Management does not expect this event to have an
adverse impact on the Company's consolidated results of operations or financial
position.
 
13. 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
 
                                       62
<PAGE>   65
                COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES
 
           NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
 
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 $56,637,000 and $42,170,000 at December 31,
1998 and 1997, 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.
 
14. 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, 1998 and 1997, approximate the fair values for cash and
cash equivalents and variable-rate long-term debt. Investments in debt
securities and certificates of deposit included in restricted cash, marketable
securities and restricted investments are also reported at fair market value,
which approximates cost, at December 31, 1998, and 1997 (Note 4). The fair value
of the Company's fixed-rate borrowings at December 31, 1998 and 1997 is
$69,561,000 and $8,376,000 greater than the historical carrying value of
$810,422,000 and $225,761,000, 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 7). The Company does not obtain collateral or other security to
support such agreements but continually monitors its positions with, and the
credit quality of, the counterparties to such agreements. As of December 31,
1998 and 1997, the gross unrealized loss on the interest rate protection
agreements was $6,086,000 and $2,670,000, respectively.
 
15. RELATED PARTY TRANSACTIONS
 
     The Company has notes receivable and advances due from shareholders and an
affiliated entity of approximately $405,000, and $118,000 as of December 31,
1998 and 1997, 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 $1,694,000, $1,851,000 and $2,057,000, for
the years ended December 31, 1998, 1997 and 1996, respectively.
 
     In September 1991, 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 agreement provided for monthly
payments of $12,500 through December 1995 and monthly payments of $8,333
thereafter through December 1996. In addition, the shareholder was a participant
in management incentive compensation plans (Note 12) 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
$278,000, $324,000 and $417,000 for the years ended December 31, 1998, 1997 and
1996, respectively.
 
     Three shareholders, who are also employees of the Company, terminated their
participation in certain management incentive compensation plans during the
fiscal year ended December 31, 1997 (Note 12). The Company recognized $3.5
million of expense related to the termination of the shareholders' participation
in these plans.
 
                                       63
<PAGE>   66
 
                                                                      SCHEDULE I
 
                             COGENTRIX ENERGY, INC.
 
                     CONDENSED BALANCE SHEETS OF REGISTRANT
                           DECEMBER 31, 1998 AND 1997
                             (DOLLARS IN THOUSANDS)
 
<TABLE>
<CAPTION>
                                                                1998       1997
                                                              --------   --------
<S>                                                           <C>        <C>
                                     ASSETS
CURRENT ASSETS:
  Cash and cash equivalents.................................  $ 14,884   $  8,264
  Restricted cash...........................................     7,351      2,411
  Accounts receivable.......................................     1,313      1,343
  Accounts receivable from affiliates.......................    23,523      9,038
  Other current assets......................................       200        143
                                                              --------   --------
          Total current assets..............................    47,271     21,199
                                                              --------   --------
INVESTMENT IN SUBSIDIARIES (ON THE EQUITY METHOD)...........   408,780    154,321
                                                              --------   --------
EQUIPMENT, net of accumulated depreciation..................     2,661        918
                                                              --------   --------
OTHER ASSETS:
  Restricted investments....................................        --        250
  Income tax benefit........................................    59,020     49,765
  Deferred financing costs, net of accumulated
     amortization...........................................     8,547      2,086
  Notes receivable from affiliates..........................     5,801      7,126
  Other.....................................................     5,934      4,316
                                                              --------   --------
          Total other assets................................    79,302     63,543
                                                              --------   --------
Total Assets................................................  $538,014   $239,981
                                                              ========   ========
                      LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
  Accounts payable..........................................  $  7,452   $  2,472
  Accounts payable to affiliate.............................     2,526      1,857
  Accrued liabilities.......................................    25,346     15,513
  Accrued dividends.........................................     7,398      2,140
                                                              --------   --------
          Total current liabilities.........................    42,722     21,982
                                                              --------   --------
LONG-TERM LIABILITIES:
  Notes payable to affiliates...............................    54,528     44,405
  Long-term debt............................................   335,787    102,087
  Other.....................................................    17,114     13,235
                                                              --------   --------
          Total long-term liabilities.......................   407,429    159,727
                                                              --------   --------
          Total liabilities.................................   450,151    181,709
                                                              --------   --------
SHAREHOLDERS' EQUITY:
  Common stock..............................................       130        130
  Accumulated earnings......................................    87,733     58,142
                                                              --------   --------
          Total shareholders' equity........................    87,863     58,272
                                                              --------   --------
Total Liabilities and Shareholders' Equity..................  $538,014   $239,981
                                                              ========   ========
</TABLE>
 
 The accompanying notes are an integral part of these condensed balance sheets.
 
                                       64
<PAGE>   67
 
                                                                      SCHEDULE I
 
                             COGENTRIX ENERGY, INC.
 
                CONDENSED STATEMENTS OF OPERATIONS OF REGISTRANT
              FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
                             (DOLLARS IN THOUSANDS)
 
<TABLE>
<CAPTION>
                                                                1998       1997       1996
                                                              --------   --------   ---------
<S>                                                           <C>        <C>        <C>
INCOME:
  Development and construction management fees..............  $  4,471   $  5,329   $   1,215
  Operating management fees.................................    22,836     20,002      16,205
                                                              --------   --------   ---------
          Total income......................................    27,307     25,331      17,420
                                                              --------   --------   ---------
OPERATING EXPENSES:
  General, administrative and development expenses..........    34,310     40,765      30,399
  Depreciation and amortization.............................     1,467      1,304       1,251
                                                              --------   --------   ---------
          Total operating expenses..........................    35,777     42,069      31,650
                                                              --------   --------   ---------
OPERATING LOSS..............................................    (8,470)   (16,738)    (14,230)
                                                              --------   --------   ---------
OTHER INCOME (EXPENSE):
  Interest expense..........................................   (15,018)   (10,635)     (9,279)
  Investment and other income...............................       236      2,137       2,186
                                                              --------   --------   ---------
          Total other expense...............................   (14,782)    (8,498)     (7,093)
                                                              --------   --------   ---------
LOSS BEFORE INCOME TAXES....................................   (23,252)   (25,236)    (21,323)
INCOME TAX BENEFIT..........................................     9,255      9,413       7,634
EQUITY IN EARNINGS (LOSS) OF SUBSIDIARIES...................    50,986     30,604      (7,187)
                                                              --------   --------   ---------
NET INCOME (LOSS)...........................................  $ 36,989   $ 14,781   $ (20,876)
                                                              ========   ========   =========
</TABLE>
 
    The accompanying notes are an integral part of these condensed financial
                                   statements
 
                                       65
<PAGE>   68
 
                                                                      SCHEDULE I
 
                             COGENTRIX ENERGY, INC.
 
                CONDENSED STATEMENTS OF CASH FLOWS OF REGISTRANT
              FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
                             (DOLLARS IN THOUSANDS)
 
<TABLE>
<CAPTION>
                                                                1998        1997       1996
                                                              ---------   --------   --------
<S>                                                           <C>         <C>        <C>
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES.............  $  78,803   $ 36,860   $ 41,252
                                                              ---------   --------   --------
CASH FLOWS FROM INVESTING ACTIVITIES:
  Decrease in restricted investments........................        250     19,750         --
  Property, plant and equipment additions...................     (2,485)      (201)      (267)
  Investments in subsidiaries...............................   (301,077)   (46,239)   (50,494)
                                                              ---------   --------   --------
  Net cash flows used in investing activities...............   (303,312)   (26,690)   (50,761)
                                                              ---------   --------   --------
CASH FLOWS FROM FINANCING ACTIVITIES:
  Proceeds (repayment) from notes payable to affiliate,
     net....................................................     10,123    (10,878)     5,547
  Increase in restricted cash...............................     (4,940)       (22)       (13)
  Proceeds from issuance of long term debt, net.............    233,705         --         --
  Decrease (increase) in notes receivable from affiliates...      1,325     (3,612)    24,418
  Increase in deferred financing costs......................     (6,944)      (661)      (486)
  Dividends paid............................................     (2,140)    (5,000)    (8,619)
                                                              ---------   --------   --------
  Net cash flows provided by (used in) financing
     activities.............................................    231,129    (20,173)    20,847
                                                              ---------   --------   --------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS:.......      6,620    (10,003)    11,338
CASH AND CASH EQUIVALENTS, beginning of year................      8,264     18,267      6,929
                                                              ---------   --------   --------
CASH AND CASH EQUIVALENTS, end of year......................  $  14,884   $  8,264   $ 18,267
                                                              =========   ========   ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
  CASH DIVIDENDS RECEIVED...................................  $  97,605   $ 59,291   $ 57,271
                                                              =========   ========   ========
</TABLE>
 
    The accompanying notes are an integral part of these condensed financial
                                  statements.
 
                                       66
<PAGE>   69
 
                                                                      SCHEDULE I
 
                             COGENTRIX ENERGY, INC.
 
             NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT
 
1. SIGNIFICANT ACCOUNTING POLICIES
 
     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, Inc.
has restated its financial statements for the 1997 and 1996 fiscal years 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 condensed 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.
 
     On October 20, 1998, Cogentrix Energy, Inc. issued $220 million of 8.75%
unsecured senior notes due 2008 in a Rule 144A offering (the "2008 Notes").
These notes were issued at a discount resulting in an effective rate of
approximately 8.824%. On November 25, 1998, Cogentrix Energy, Inc. issued an
additional $35 million of the 2008 Notes at a premium resulting in an effective
rate of approximately 7.95%. Cogentrix Energy, Inc. anticipates completing an
exchange offer in April 1999 for the notes issued in the Rule 144A offering for
notes registered under the Securities Act of 1933, as amended.
 
     In March 1998, in anticipation of the offering of the 2008 Notes, Cogentrix
Energy, Inc. 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.
 
     Future maturities of long-term debt at December 31, 1998, 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>
1999.................................................  $     --
2000.................................................        --
2001.................................................    20,000
2002.................................................    20,000
2003.................................................    20,000
Thereafter...........................................   295,000
                                                       --------
                                                       $355,000
                                                       ========
</TABLE>
 
                                       67
<PAGE>   70
                             COGENTRIX ENERGY, INC.
 
      NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT -- (CONTINUED)
 
CORPORATE CREDIT FACILITY
 
     In May 1997, Cogentrix Energy, Inc. entered into a credit agreement with
Australia and New Zealand Banking Group Limited, as agent for a group of lending
banks. In October 1998, Cogentrix Energy, Inc. 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,
Inc.'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,
1998, Cogentrix Energy had used this credit facility to issue $60 million of
letters of credit in connection with investments made in electric-generating
plants, and one plant under construction.
 
     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 2001, 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.
 
                                       68
<PAGE>   71
 
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.......................  71    Chairman Emeritus
David J. Lewis............................  42    Chairman of the Board, Chief Executive Officer and
                                                    Director
Mark F. Miller............................  44    President, Chief Operating Officer and Director
James E. Lewis............................  35    Vice Chairman and Director
Dennis W. Alexander.......................  52    Group Senior Vice President, General Counsel,
                                                  Secretary and Director
James R. Pagano...........................  39    Group Senior Vice President -- Development, Mergers
                                                  & Acquisitions
Bruno R. Dunn.............................  48    Group Senior Vice President -- Operations
Betty G. Lewis............................  69    Director
Robert W. Lewis...........................  45    Director
W. E. "Bill" Garrett......................  68    Director
John A. Tillinghast.......................  71    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.
 
     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
 
                                       69
<PAGE>   72
 
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 congeneration 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.
 
     Betty G. Lewis has been a Director of Cogentrix Energy since September
1994. Betty Lewis is the spouse of George T. Lewis, Jr.
 
     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
                                       70
<PAGE>   73
 
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, and Partners for
Livable Communities.
 
     John A. Tillinghast was elected a Director of Cogentrix Energy on March 19,
1998, filling a position left vacant since the death of former board member T.
Louis Austin, Jr. in 1997. 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 Great Bay Power
Corporation, 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 a holds two U.S. and
seven foreign patents.
 
                                       71
<PAGE>   74
 
ITEM 11.  EXECUTIVE COMPENSATION
 
     The following table sets forth information for the calendar years ended
December 31, 1998, and December 31, 1997 and for the fiscal year ended June 30,
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,
1998 and (2) the four most highly compensated executive officers of Cogentrix
incumbent at December 31, 1998, 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, 1998   $633,428    $1,117,302   $1,750,730      $62,010        $      0
  Vice Chairman and         December 31, 1997    613,960       841,239    1,455,199       58,157         862,329
  Chief Executive Officer   June 30, 1997        565,317       695,824    1,261,141       67,657         862,329
Mark F. Miller............  December 31, 1998    386,412       779,057    1,165,469      127,989               0
  President and Chief       December 31, 1997    249,164       173,046      422,210      193,243               0
  Operating Officer         June 30, 1997         58,334             0       58,334       25,211               0
James E. Lewis............  December 31, 1998    378,788       679,642    1,058,430       32,570               0
  Executive Vice President  December 31, 1997    364,524       415,163      779,687       25,831         884,692
                            June 30, 1997        360,347       345,124      705,471       44,191         884,692
James R. Pagano...........  December 31, 1998    291,118       660,227      951,345       29,169               0
  Group Senior Vice         December 31, 1997    223,532       345,033      568,565       28,412               0
 President -- Development,  June 30, 1997        164,498       180,000      344,498       28,912               0
  Mergers & Acquisitions
Dennis W. Alexander.......  December 31, 1998    295,328       635,227      930,555       27,922               0
  Group Senior Vice         December 31, 1997    284,086       175,033      459,119       21,845               0
  President and             June 30, 1997        272,068        70,000      342,068       21,472               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 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 33
    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 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."
 
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
 
                                       72
<PAGE>   75
 
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, 1998, David J. Lewis earned $694,150, Mark F. Miller earned
$485,905, James E. Lewis earned $416,490, and James R. Pagano and Dennis W.
Alexander each earned $347,075 under our profit sharing plan.
 
     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 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, 1998,
each of the Named Executive Officers earned $213,152 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, respectively.
 
EMPLOYMENT AGREEMENTS WITH NAMED EXECUTIVE OFFICERS
 
  David J. Lewis
 
     In March 1999, the board of directors appointed David J. Lewis Chairman of
the Board and Chief Executive Officer. Prior to March 1999, David J. Lewis was
Vice Chairman of the Board and Chief Executive Officer since August 1995. 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.
 
     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
 
                                       73
<PAGE>   76
 
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.
 
                                       74
<PAGE>   77
 
  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 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, 1998, there were nine 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 August 1995, we entered into a five-year employment and noncompetition
agreement with George T. Lewis, Jr., a shareholder and 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 $662,000 for the year ended December 31,
1998.
 
     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.
                                       75
<PAGE>   78
 
  Robert W. Lewis
 
     While Robert W. Lewis was employed as an executive officer, Cogentrix
entered into a non-qualified incentive compensation agreement with him similar
to the agreements described above under "-- Facility Cash Flow Incentive
Compensation Agreements" providing for him to receive incentive compensation
annually equal to a designated percentage of the net cash flow for the fiscal
year of two of our facilities. Our obligation to make such annual payments to
him continues through June 30, 2007. We have agreed to pay him an annual minimum
payment of $200,000 regardless of whether his actual annual distribution would
yield such amount. Robert W. Lewis must repay to Cogentrix, on or before January
31, 2008, an amount equal to the aggregate amount of minimum payments made in
excess of the actual annual distributions which he was entitled to receive. The
actual amount of the distribution Mr. Lewis received pursuant to his facility
cash flow compensation agreement for the year ended December 31, 1998 was
$278,118.
 
     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.
 
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 by George T. Lewis, Jr., Betty G. Lewis and their
three sons: David J. Lewis, James E. Lewis and Robert W. Lewis. The number of
shares and the percentage of the total number of shares beneficially owned by
each are shown below.
 
<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.
 
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.
 
                                       76
<PAGE>   79
 
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, James E.
Lewis and George T. Lewis, Jr. are also executive officers of Cogentrix. Total
rent paid by us to ELP under such equipment leases was $726,000, $896,000 and
$1,120,000 for the years ended December 31, 1998, 1997 and 1996, 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 $856,000, $843,000 and $825,000 for the years ended December 31,
1998, 1997 and 1996, 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 $112,000 for each of the years ended
December 31, 1998, 1997 and 1996, 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, three of whom are executive officers of the
Cogentrix (the fourth being a former executive officer) and each of whom is 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 year ended December 31, 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.
 
                                       77
<PAGE>   80
 
                                    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 36.
 
       (2) Financial Statement Schedules -- See index on page 36.
 
         (3) Index to Exhibits.
 
<TABLE>
<CAPTION>
DESIGNATION OF
   EXHIBIT            DESCRIPTION OF EXHIBIT
--------------        ----------------------
<C>              <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").
                      (20)
      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>
 
                                       78
<PAGE>   81
 
<TABLE>
<CAPTION>
DESIGNATION OF
   EXHIBIT            DESCRIPTION OF EXHIBIT
--------------        ----------------------
<C>              <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)
     10.9         --  Coal Sales Agreement, dated as of October 1, 1989, among
                      AgipCoal 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. (**)
    10.11         --  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>
 
                                       79
<PAGE>   82
 
<TABLE>
<CAPTION>
DESIGNATION OF
   EXHIBIT            DESCRIPTION OF EXHIBIT
--------------        ----------------------
<C>              <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).
    10.15         --  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)
    10.18         --  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>
 
                                       80
<PAGE>   83
 
<TABLE>
<CAPTION>
DESIGNATION OF
   EXHIBIT            DESCRIPTION OF EXHIBIT
--------------        ----------------------
<C>              <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         --  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)
    10.19(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)
    10.19(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)
    10.19(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)
    10.19(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)
    10.20         --  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)
    10.21         --  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)
    10.22         --  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)
    10.23         --  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)
    10.24         --  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)
    10.24(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>
 
                                       81
<PAGE>   84
 
<TABLE>
<CAPTION>
DESIGNATION OF
   EXHIBIT            DESCRIPTION OF EXHIBIT
--------------        ----------------------
<C>              <C>  <S>
    10.25         --  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)
    10.26         --  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)
    10.27         --  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)
    10.28         --  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)
    10.29         --  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)
    10.30         --  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)
    10.31         --  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)
    10.32         --  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)
    10.33         --  Consulting Agreement, dated as of September 30, 1993,
                      between Cogentrix, Inc. and C&L Account Ten Inc. (assigned
                      to and assumed by Cogentrix Energy, Inc.) (10.101). (1)
    10.34         --  Form of Profit-Sharing Plan(I) (10.102). (1)
    10.35         --  Form of Profit-Sharing Plan(II) (10.103). (1)
    10.36         --  Executive Incentive Bonus Plan (10.104). (2)
    10.37         --  Facility Cash Flow Incentive Compensation Agreement with
                      Robert W. Lewis (10.105). (1)
    10.38         --  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)
    10.39         --  Employment Agreement, dated as of June 24, 1994, between
                      David J. Lewis and Cogentrix Energy, Inc. (10.115). (3)
    10.40         --  Employment Agreement, dated as of May 1, 1997, between Mark
                      F. Miller and Cogentrix Energy, Inc. (10.109). (10)
    10.41         --  Employment Agreement, dated as of January 1, 1994, between
                      Dennis W. Alexander and Cogentrix Energy, Inc. (10.110).
                      (11)
    10.42         --  Executive Employment Agreement, dated as of January 1, 1999,
                      between Cogentrix Energy, Inc. and James R. Pagano.
    10.43         --  Supplemental Retirement Savings Plan (10.132) (5)
</TABLE>
 
                                       82
<PAGE>   85
 
<TABLE>
<CAPTION>
DESIGNATION OF
   EXHIBIT            DESCRIPTION OF EXHIBIT
--------------        ----------------------
<C>              <C>  <S>
    10.44         --  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)
    10.45         --  Consulting and Noncompetition Employment Agreement, dated as
                      of August 11, 1995, between Cogentrix Energy, Inc. and
                      George T. Lewis, Jr. (10.135). (5)
    10.46         --  Support Agreement, dated as of July 14, 1995, from Cogentrix
                      Energy, Inc. to Malconna Company Limited (10.137). (5)
    10.47         --  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         --  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         --  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. (16)
    10.49(a)      --  Amendment #1 to the Cottage Grove Partnership Agreement.
                      (17)
    10.49(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. (19)
    10.49(c)      --  Third Amendment, dated December 11, 1998, to the Amended and
                      Restated Limited Partnership Agreement of LSP-Cottage Grove,
                      L.P. (21)
    10.50         --  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. (16)
    10.50(a)      --  Consent, Waiver and Amendment No. 1, dated March 20, 1998,
                      to the Amended and Restated Limited Partnership Agreement of
                      LSP-Whitewater Limited Partnership. (19)
    10.50(b)      --  Second Amendment, dated December 11, 1998, to the Amended
                      and Restated Limited Partnership Agreement of LSP-Whitewater
                      Limited Partnership. (21)
    10.51         --  Power Purchase Agreement, dated as of May 9, 1994, between
                      Northern States Power Company and LSP-Cottage Grove, L.P.
                      (16)
    10.52         --  Power Purchase Agreement, dated as of December 21, 1993,
                      between Wisconsin Electric Power Company and LSP-Whitewater
                      Limited Partnership. (16)
    10.52(a)      --  Amendment to Power Purchase Agreement, dated as of February
                      10, 1994, between Wisconsin Electric Power Company and
                      LSP-Whitewater Limited Partnership. (16)
    10.52(b)      --  Second Amendment to Power Purchase Agreement, dated as of
                      October 5, 1994, between Wisconsin Electric Power Company
                      and LSP-Whitewater Limited Partnership. (16)
    10.52(c)      --  Third Amendment to Power Purchase Agreement, dated as of May
                      5, 1995, between Wisconsin Electric Power Company and
                      LSP-Whitewater Limited Partnership. (16)
    10.52(d)      --  Fourth Amendment to Power Purchase Agreement, dated March
                      18, 1997, between Wisconsin Electric Power Company and
                      LSP-Whitewater Limited Partnership. (18)
    10.52(e)      --  Fifth Amendment to Power Purchase Agreement, dated February
                      26, 1998, between Wisconsin Electric Power Company and
                      LSP-Whitewater Limited Partnership. (19)
     21.1         --  Direct and Indirect Subsidiaries of Cogentrix Energy, Inc.
</TABLE>
 
                                       83
<PAGE>   86
 
<TABLE>
<CAPTION>
DESIGNATION OF
   EXHIBIT            DESCRIPTION OF EXHIBIT
--------------        ----------------------
<C>              <C>  <S>
     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 these exhibits have been omitted pursuant to previously
     approved requests for confidential treatment.
(**) Certain portions of this exhibit have been deleted pursuant to a request
     for confidential treatment filed with the Securities and Exchange
     Commission pursuant to Rule 24b-2 under the Securities Exchange Act of
     1934, as amended.
 (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.
 (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.
 
                                       84
<PAGE>   87
 
(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 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.
(17) 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.
(18) 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.
(19) 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.
(20) 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.
(21) 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.
 
                                       85
<PAGE>   88
 
                                   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)
 
                                          By:      /s/ DAVID J. LEWIS
                                            ------------------------------------
                                                       David J. Lewis
                                                   Chairman of the Board,
                                            Chief Executive Officer and Director
                                               (Principal Executive Officer)
 
Date: March 31, 1999
 
     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                March 31, 1999
-----------------------------------------------------
                George T. Lewis, Jr.
 
                 /s/ DAVID J. LEWIS                    Chairman of the Board, Chief     March 31, 1999
-----------------------------------------------------    Executive Officer and
                   David J. Lewis                        Director
 
                 /s/ MARK F. MILLER                    President, Chief Operating       March 31, 1999
-----------------------------------------------------    Officer and Director
                   Mark F. Miller
 
                 /s/ BETTY G. LEWIS                    Director                         March 31, 1999
-----------------------------------------------------
                   Betty G. Lewis
 
                 /s/ JAMES E. LEWIS                    Vice Chairman and Director       March 31, 1999
-----------------------------------------------------
                   James E. Lewis
 
                                                       Director                         March 31, 1999
-----------------------------------------------------
                   Robert W. Lewis
 
               /s/ DENNIS W. ALEXANDER                 Group Senior Vice President,     March 31, 1999
-----------------------------------------------------    General Counsel, Secretary
                 Dennis W. Alexander                     and Director
 
                  /s/ W. E. GARRETT                    Director                         March 31, 1999
-----------------------------------------------------
                    W. E. Garrett
 
               /s/ JOHN A. TILLINGHAST                 Director                         March 31, 1999
-----------------------------------------------------
                 John A. Tillinghast
 
               /s/ THOMAS F. SCHWARTZ                  Senior Vice                      March 31, 1999
-----------------------------------------------------    President -- Finance and
                 Thomas F. Schwartz                      Treasurer (Principal
                                                         Financial and Accounting
                                                         Officer)
</TABLE>
 
                                       86