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                UNITED STATES SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                                    FORM 10-K

                  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
                     OF THE SECURITIES EXCHANGE ACT OF 1934

                     FOR THE FISCAL YEAR ENDED JUNE 30, 1997

                        Commission File Number: 33-74254

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


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


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

       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
September 29, 1997:       282,000

DOCUMENTS INCORPORATED BY REFERENCE:  NONE


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                             COGENTRIX ENERGY, INC.
                       INDEX TO ANNUAL REPORT ON FORM 10-K

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<S>          <C>                                                                                      <C>
PART I

Item 1:      Business                                                                                  3

Item 2:      Properties                                                                               31

Item 3:      Legal Proceedings                                                                        31

Item 4:      Submission of Matters to a Vote of Security Holders                                      32


PART II

Item 5:      Market for the Registrant's Common Stock and Related Shareholder Matters                 33

Item 6:      Selected Consolidated Financial Data                                                     34

Item 7:      Management's Discussion and Analysis of Financial Condition and Results of Operations    36

Item 8:      Financial Statements and Supplementary Data                                              45

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                                       70

Item 11:     Executive Compensation                                                                   73

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                                                                                            91

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                                     PART I

ITEM 1.  BUSINESS

INTRODUCTION

         Cogentrix Energy, Inc., through its direct and indirect subsidiaries
(the "Company") is principally engaged in the business of acquiring, developing,
owning and operating independent (i.e., non-utility) electric power generation
facilities. The Company was one of the early participants in the market for
independently generated electric power which developed in the United States as a
result of the enactment of the Public Utility Regulatory Policies Act ("PURPA").
Based on net ownership of total project megawatts in operation, the Company is
among the larger independent power producers in the United States.

         Unless the context requires otherwise, references herein to the
"Company" mean Cogentrix Energy, Inc. and its direct and indirect subsidiaries.
The former parent company, Cogentrix, Inc., which as the result of a
restructuring completed in December 1993 is now one of the Company's principal
subsidiaries, is referred to herein as "Cogentrix." The Company's subsidiaries
engaged in the development, ownership or operation of cogeneration facilities
are sometimes referred to individually as a "project subsidiary" and
collectively as the Company's "project subsidiaries."

         All of the Company's plants are cogeneration facilities and all but 
one of the plants are coal-fired. See "Facilities in Operation" herein.
Cogeneration is a power generation process that produces two or more useful
forms of energy, such as electricity and steam, from a single primary fuel
source, such as coal or natural gas. Each of the Company's projects sells
electricity to a major utility and thermal energy (typically in the form of
steam) to an industrial or other user under long-term agreements.

         The construction of the Company's first facility began in September
1984. The Company has developed and constructed and is now operating a total of
ten facilities, all of which are in the United States. The ten facilities had an
aggregate project cost of approximately $796.8 million and have an installed
capacity of approximately 900 megawatts. The Company also holds a 50% ownership
interest in a 220 megawatt coal-fired facility, which is operated by an
affiliate of the Company's partner in this facility. These facilities are
financed primarily through eight project financing transactions which are
substantially non-recourse to the Company and its other project subsidiaries,
except for the financings related to the Company's facility in Portsmouth,
Virginia and facilities in Roxboro and Southport, North Carolina where Cogentrix
Energy, Inc. or Cogentrix has agreed to certain limited guarantees or other
obligations with respect to the facilities. For a discussion of the terms
"project financing" and "substantially non-recourse," see "Description of the
Company's Facilities -- Project Financing" herein. For a description of the
limited guarantees and other obligations with respect to the facilities, see
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources."

THE INDEPENDENT POWER MARKET

         The United States independent power industry expanded rapidly in the
1980s following the enactment of PURPA in 1978. Prior to PURPA, the demand for
power in the United States had traditionally been met by utilities constructing
large-scale electric generating plants under cost-of-service based regulation.
PURPA removed most regulatory constraints relating to the production and sale of
electric energy by certain non-utility generators and required electric
utilities to buy electricity from "qualifying facilities" ("QFs") at the
utilities' avoided cost, thereby encouraging companies other than electric
utilities to enter the electric power production market. Concurrently, due in
part to regulatory disallowance of many large utility construction project
costs, there has been a general decline in the construction of generating plants
by electric utilities. As a result, a significant market for electric power
produced by independent power producers (such as the Company) has developed in
the United States since the enactment of PURPA.

         The future market for independently produced power in the United States
will be determined primarily by the need for new electric generation capacity.
Regulated utilities are making more efficient use of their existing resources by
improving plant availability, extending plant lives, repowering older facilities
and taking advantage of attractive bulk power purchases. Partly in response to
regulatory pressures, many regulated utilities have also initiated demand side
management programs designed to reduce the need for new electric generating
capacity.


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         In addition, over the past decade, obtaining a power sales agreement
with a domestic utility has become progressively more difficult, expensive and
competitive. As a result of this trend and other factors, consolidation of
companies involved in the independent power industry has accelerated. Many state
regulatory commissions now require or have policies that encourage power sales
agreements to be awarded by competitive bidding, which increases the costs and
decreases the chances of obtaining such agreements. The Company's strategy is to
negotiate power sales agreements whenever possible and to participate only
selectively in competitive bidding situations.

         The passage of the Energy Policy Act of 1992 (the "Energy Policy Act")
significantly expanded the options available to independent power producers,
particularly with respect to siting a generating facility. Among other things,
it enables independent power producers to obtain an order from the Federal
Energy Regulatory Commission ("FERC") requiring an intermediary utility to give
access to its transmission lines to transmit, or wheel, electric power from a
project to its utility purchaser. The availability of wholesale transmission
wheeling could be an important aspect in the development of new projects. For
example, the Company 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 such utility to a second utility or another wholesale
purchaser. The Energy Policy Act also created a new class of generator, Exempt
Wholesale Generator ("EWGs"), that, unlike QFs, are not required to use
alternative or renewable fuels or to have useful thermal energy output. See
"Regulation -- Energy Regulations" herein.

         Also, recent developments in the power generation industry indicate a
trend toward the disposition of power generation facilities by utilities,
independent power producers and industrials. Several large domestic utilities
have announced intentions to sell such assets. The Company believes that this
trend will create investment opportunities for companies such as Cogentrix
Energy, Inc. that have integrated power service capabilities.

         Because the projected need for base-load generating capacity additions
in developing countries over the next ten to fifteen years significantly exceeds
that in the United States, independent power producers have in recent years
expanded from the United States to a global market. Many foreign markets
(including Latin America, China, India and Southeast Asia) have adopted policies
and are experiencing economic growth rates that the Company believes provide
greater opportunities than most markets existing in the United States today. An
important part of the Company's business strategy is to participate in
competitive generation markets worldwide. See "Project Development Strategy"
herein.

         The Company believes that knowledge gained from developing and
operating power plants in the United States can be applied to take advantage of
opportunities in these developing markets. To this end, the Company is actively
exploring development of projects outside of the United States, principally in
Asia and in Latin America. Development of power generation projects in
non-United States markets is, however, more difficult and expensive than in the
United States, and some competitors in these foreign markets have greater
capital resources than the Company.

         Most independent power projects in the United States have been fueled
by natural gas or coal. Various forecasting studies project natural gas and coal
to be the dominant fuel sources for new power generation projects in the United
States. The Company believes that plants fueled by these two fuels will continue
to represent a significant portion of the successful independent power projects
in the United States and that coal will have a significantly larger market share
outside the United States than is currently forecasted for the United States.
Although requests for proposals recently issued by United States electric
utilities have been more heavily oriented toward peaking capacity, which is
typically provided by natural gas-fired facilities, than base-load needs, the
Company believes that the development of coal-fired, base-load projects will
continue to be an important market niche for independent power producers in the
future, particularly in the international market.

PROJECT DEVELOPMENT STRATEGY

         The Company intends to remain among the leaders in the independent
power industry by developing and constructing or acquiring electric power
generation facilities in the United States and in selected foreign countries
where the political climate is conducive to increased foreign investment. The
Company's overall goal in pursuing this strategy is to capitalize on its
reputation as an efficient and reliable energy provider.

         The Company's overall project development strategy is to concentrate on
those segments of the market for independent power, in both the domestic and
international sectors, requiring smaller generating facilities, ranging from 60
to 250 megawatts using coal as fuel and up to 240 megawatts using natural gas as
fuel. When opportunities become available to develop larger projects, management
believes this strategy can be adapted by constructing facilities comprised of
several 



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of the Company's standard design units. The Company believes that historically
it has been able to construct its coal-fired facilities at a lower total cost
per kilowatt than most of its competitors. For example, the Company's 240
megawatt facility in Richmond, Virginia was completed in 17 months from
groundbreaking at a total installed cost of less than $1,000 per kilowatt. The
Company has been able to achieve time and cost savings primarily by using
standard plant designs that incorporate proven technology and modular, as
opposed to custom, construction. As a result, financing, construction and
start-up of such facilities generally proceed more quickly than is the case with
larger generating facilities, some of which have included unproven technology.

         In developing future projects, the Company anticipates that it will
increasingly do so on a joint venture basis with various partners, including
non-regulated subsidiaries of electric utilities, other independent power
producers, financial institutions, equipment manufacturers, large construction
companies and fuel suppliers. By doing so, the Company expects to gain a number
of advantages, including technical expertise possessed by others, greater
knowledge of and experience with the political and social conditions of the
region or country where the project is being developed and the ability to
leverage the Company's human and financial resources. The Company also expects
such joint ventures will enable it to share the risks associated with
development of larger projects and build a larger and more diversified
portfolio of projects. The Company anticipates that it will share control over
the development and construction of such projects with its joint venture
partners and will seek to operate the facility itself whenever possible.

         The Company has identified three market segments in which it intends to
focus its future development activities. These targeted market segments are
United States electric utilities, United States and foreign industrial companies
and international project development, primarily in Asia and Latin America.

         UNITED STATES ELECTRIC UTILITIES. Although demand for new and
replacement power in the United States is expected to grow, the Company does not
view the domestic electric utility market as providing as many opportunities for
project development during the next several years as it did during the 1980s.
With the exception of the Southeast and the Pacific Northwest, most regions of
the United States appear to be oversupplied in terms of generating capacity for
the next five years. Over the next ten years, however, the projected need for
increased generating capacity in the United States, coupled with a growing trend
toward consolidation and strategic alliances in the independent power industry,
is expected to create more attractive project development opportunities in this
market for the Company. Although electric utilities will construct some
additional generating capacity during this period, the Company expects
independent power producers will maintain or increase their share of new
capacity additions. The Company believes that independent power producers are
generally able to make better use of leverage, achieve lower costs in operating
power plants than do utilities, and tend to have lower general and
administrative costs than electric utilities.

         In order to remain an effective participant in this market, the
Company's development team is continuing to engage in a variety of marketing
activities designed to maintain the Company's profile and develop new
relationships with potential utility customers. Company personnel focusing on
the industrial market also seek to identify industrial concerns with which the
Company can respond jointly to a request for proposals by an electric utility
needing additional or replacement generating capacity.

         Because the Company is generally more competitive in the development
and construction of smaller facilities, the Company expects to concentrate its
development efforts in the United States electric utility market on identifying
utilities that potentially have a need for one or more such facilities. The
standard designs the Company has developed for coal-fired units ranging in plant
output size from 60 to 250 megawatts, as well as for natural gas-fired units
with plant output as high as 240 megawatts, will enable the Company to bid more
effectively in competitive bid situations and pursue negotiated transactions
when available. The Company believes that its chances of obtaining a power
purchase agreement for such smaller facilities from an electric utility will be
greater than for larger facilities which tend to attract a greater number of
qualified bidders.

         The Company's smaller units also are marketed to municipally-owned
electric distribution utilities, which traditionally have purchased electric
energy. The development of such a facility would provide the municipality not
only with a cost-effective alternative to such energy purchases, but also with a
greater degree of control over the power generation process.


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         UNITED STATES AND FOREIGN INDUSTRIAL COMPANIES. With opportunities for
development in the United States electric utility market diminishing, the
Company is increasing its focus on the industrial market for new domestic, as
well as international, project development opportunities. Management believes
that establishing relationships with large United States multinational
industrial corporations will also help serve as an indirect route to the
development of projects in the international market.

         The Company believes that a potential market for future project
development, using one or more of its standard designs, exists among many large
industrial consumers of electricity. Many of these industrial companies, both
domestic and international, are currently operating their own "inside the fence"
cogeneration facilities to produce both electricity and thermal energy, which
employ older technology, produce energy inefficiently and generally are managed
as an adjunct to the industrial company's primary manufacturing objectives. The
cost of their energy supply is a major component of these industrial companies'
product cost. The Clean Air Act Amendments of 1990 also pose challenges for many
industrial companies which must retrofit existing facilities to comply with the
new law. The Company believes that its smaller, standard design units could be
readily employed to replace or, in certain circumstances, upgrade existing
"inside the fence" cogeneration facilities.

         The Company has established a joint venture with AEP Resources, Inc., a
non-regulated subsidiary of American Electric Power Company, Inc. ("AEP") for
the purpose of seeking large industrial steam and power projects in major United
States and Canadian energy-intensive industries including steel, pulp and paper,
refining and chemical. The purpose of the joint venture is to upgrade, expand,
replace, own and, in most cases, operate new and existing power generation
facilities, steam plants, refrigeration plants, compressed air facilities and
related energy distribution assets.

         Most state regulatory authorities have not yet resolved the issue of
whether an independent power producer may lawfully sell power directly to one or
more retail customers, and, if so, whether such producer becomes subject to
regulation as a public utility. Even if regulatory authorities permit the
Company and others to develop such facilities for the retail sale of
electricity, electric utilities may decide to mount legal challenges to such
developments. To avoid such regulatory and legal challenges, the Company may
structure the ownership of projects such that the industrial corporation retains
a controlling interest in the project or may use other acceptable alternative
structures.

         INTERNATIONAL PROJECT DEVELOPMENT. The Company believes the knowledge
and experience it has gained in developing ten facilities in the United States
using its standard design approach can be effectively employed in selected
situations to develop projects outside the United States where demand for
generating capacity is projected to grow rapidly. In pursuing international
development projects, the Company intends to focus primarily on the segment of
the international market for coal-fired plants in the 60 to 250 megawatt range
and gas-fired facilities up to 240 megawatts. By concentrating on the
development of smaller facilities, the Company believes it can successfully
export its proven core business, obtain a greater portion of construction
financing utilizing host country capital markets, spread the Company's equity
investment over a larger number of projects and obtain proportionately greater
political risk insurance coverage. The Company believes this development
strategy can be adapted, when necessary, to larger projects by constructing a
facility comprised of several units of the Company's standard design.

         Because they are inherently riskier, more difficult to finance and
generally require a greater equity commitment than those in the United States,
the Company expects to develop most international projects on a joint venture
basis. Whenever possible, the Company expects to include a host country partner
whose participation in the project will assist in obtaining financing from host
country capital markets as well as in building political and community support
for the project. Potential joint venture partners for international development
projects include utilities, large construction firms, financial institutions and
equipment suppliers who can contribute not only equity capital but also many
years of experience in international project development.

         The primary international markets where the Company has been and
expects to be active in pursuing project development opportunities are Asia and
Latin America.

         Asia. Rapid economic growth, increasing demand for electricity and
growing receptiveness by governments in Asia to foreign investment have combined
to create significant project development opportunities. To position itself
better to capitalize on development opportunities in India, where the Company
has a project under development (see "Projects Under Development" herein),
China, Thailand, Australia, Indonesia and other countries in the region, the
Company has established regional marketing offices in Singapore and India which
are staffed by development professionals.



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         The Company has formed a joint venture with Sargent & Lundy, L.L.C. 
and a Chinese chemical company for the purpose of constructing two 24
megawatt coal-fired electric generating units to sell electric and thermal
energy to the chemical company and excess electric and thermal energy to other
Chinese industrials. The joint venture is currently negotiating a power sales
agreement with the Chinese chemical company.

         Latin America. The Company considers Latin America to hold selective
opportunities for development of new projects in the next several years. The
Company is actively investigating possible development opportunities in Mexico
and Brazil, principally cogeneration projects with large industrial companies
that would purchase electricity and thermal energy generated by the projects.
For further discussion of the opportunities for such projects, see "Project
Development Strategy -- United States and Foreign Industrial Companies" herein.

PROJECTS UNDER DEVELOPMENT

         In November 1994, the Company formed a partnership with BTU Energy,
Inc. for the purpose of developing a 240 megawatt natural gas-fired electric
power generating facility in Rathdrum, Idaho. In October 1995, the Company
purchased all of BTU Energy, Inc.'s interest in the partnership for
approximately $1.2 million. The Company has the right to acquire 108 acres of
land in Rathdrum, Idaho, which is currently permitted for the proposed facility
and is strategically located for natural gas transmission. The Company is
continuing to negotiate with utilities in the Pacific Northwest in efforts to
procure a power sales agreement for the proposed facility.

         In May 1993, the Government of India ("GOI") approved in principle,
subject to certain conditions, the Company's proposal to develop a coal-fired
power generation facility with a total gross electrical generating capacity of
approximately 1,000 megawatts. The project was designated by the GOI as one of
eight projects under development which would receive the support of a partial
guaranty by the GOI of the payment obligations of the related State Government.
The proposed site for the facility near Mangalore in the State of Karnataka has
already received in-principle clearance related to the environmental permitting
process. The Company has executed a power sales agreement with the Karnataka
State Electricity Board and has received approval in principle of the Government
of Karnataka guaranty of the full financial obligation of the Karnataka State
Electricity Board. The Company is currently negotiating with the Central
government on revision to the power sales agreement, which the Company's
management believes will lead to issuance of the GOI partial counter-guaranty of
the Government of Karnataka guaranty.

         In July 1995, the Company executed a joint development agreement with a
subsidiary of China Light & Power Company, Limited ("CLP") (the "Joint Venture")
which provides for the Company and CLP to co-develop the India project and to
share equally in the direct development expenses related to the project.
Additionally, the Company expects to secure one or more other partners for the 
purpose of making equity investments in the project. If the Company is
successful in obtaining the necessary governmental approvals and guarantees of
the power sales agreement and construction financing, the Company intends to
further participate by overseeing construction of the project and managing
under a long-term agreement the operation of the facility by a third party.

         The Company has formed a joint venture with Sargent & Lundy, L.L.C. 
and a Chinese chemical company for the purpose of constructing two 24 megawatt
coal-fired electric generating units to sell electric and thermal energy to the
chemical company and excess electric and thermal energy to other Chinese
industrials. The joint venture is currently negotiating a power sales agreement
with the Chinese chemical company.

         The projects the Company is seeking to develop are often large and
complex and the completion of any such project is subject to substantial risks.
There can be no assurance that the Company will be able to obtain new power
sales agreements, the necessary site agreements, steam sales agreements,
licenses and certifications, environmental and other permits and financing
necessary for the successful development of new projects. These, and other
risks, may result in the Company abandoning projects under development.

PROJECTS UNDER CONSTRUCTION

         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 is engineering, procuring equipment for and constructing
a 248 megawatt combined-cycle, gas-fired electric generation facility (the
"Clark Facility"). Upon completion of the Clark Facility, the Company will 



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earn a construction fee of $5 million. The Company will also share in 50% of the
amount, if any, equal to the excess of the contract amount over the costs and
expenses incurred in constructing the Clark Facility. Cogentrix of Vancouver,
Inc. ("CVC"), an indirect wholly-owned subsidiary of the Company, performed the
development and preliminary engineering on the Clark Facility and received a
development fee of $5 million in October 1995. Upon commencing commercial
operations, which is anticipated to be late calendar 1997, CVC will operate and
maintain the Clark Facility pursuant to a two-year operations and maintenance
agreement.

POWER MARKETING

         Increased competition in the wholesale electric power market, and
improved access to that market through wheeling, has prompted hundreds of
companies to enter the market as non-generating wholesale power marketers. Such
companies purchase and resell electric power, often packaging available electric
power from several different sources to meet the unique needs of particular
wholesale purchasers.

         The Company's power marketing subsidiary, Cogentrix Energy Power
Marketing, Inc. ("CEPM"), has entered into agreements with The Washington Water
Power Company to purchase up to 222 megawatts of electric capacity and energy
and to schedule transmission for up to 397 megawatts of electric energy. CEPM
has also entered into power sales and transmission scheduling agreements with a
major industrial company to provide capacity and energy to its production
facilities in the Pacific Northwest. CEPM currently matches its contracts to
purchase capacity and energy with corresponding contracts to sell equivalent
capacity and energy, thus CEPM is not subject to losses resulting from price
fluctuations in the wholesale electric power market.

GREENHOUSE OPERATIONS

         The Company has entered into an agreement with Agro Power Development,
Inc., a developer and operator of greenhouse facilities, giving the Company a
right of first refusal to make investments in partnerships which develop,
construct and operate greenhouses which produce tomatoes. The Company has made
investments in partnerships which currently operate greenhouses with an
aggregate 50 acres of production capacity and has made additional investments in
partnerships which currently have greenhouses under construction with an
aggregate 57 acres of production capacity. These greenhouses are located in
Texas, Pennsylvania and New York.

DESCRIPTION OF THE COMPANY'S FACILITIES IN OPERATION

         The Company's project subsidiaries currently own 100% of nine
cogeneration power facilities in operation. The Company's other two facilities
in operation are held by partnerships in each of which a Company subsidiary is a
50% general partner. Ten of these eleven facilities are currently operated and
managed by the Company. The eleventh facility is operated and managed by an
affiliate of the Company's partner in the partnership that owns the facility.
Each facility is located on a site which is owned or leased on a long-term basis
by a project subsidiary, which ownership or leasehold interest is mortgaged to
secure the subsidiary's project financing obligations, and, in certain
instances, to secure the Company's project subsidiaries' obligations under their
power sales agreements.

         PROJECT AGREEMENTS. Each of the Company's project subsidiaries sells
electricity to a utility under long-term power sales agreements. A plant's
revenue from a power sales agreement usually consists of two components: energy
payments and capacity payments. Energy payments, which are generally intended to
cover the variable costs of electric generation (such as fuel costs and variable
operation and maintenance expense), are based on a facility's net electrical
output measured in kilowatt hours, with payment rates either fixed or indexed to
the fuel costs of the purchasing utility. Capacity payments, which are intended
to compensate for the fixed costs incurred by the project subsidiary (such as
debt service on the project financing), are more complex and are calculated
based on a declared capacity of a facility. Declared capacity is the electric
generating capacity in megawatts that the Company's project subsidiary agrees in
a power sales agreement to make available to the utility purchasing its
electricity and is a percentage of the facility's design capacity dictated by
its equipment and design specifications. Capacity payments are based either on a
plant's net electrical output and paid on a kilowatt hour basis or on the
plant's declared capacity and can be adjusted if actual capacity varies
significantly from declared capacity.

         Many power sales agreements (including the Company's) permit the
purchasing utility to dispatch the facility (i.e., direct the plant to deliver a
variable amount of electrical output) within limited parameters or permit the
purchasing utility to suspend for a limited number of hours per year the
delivery of electrical output. The power sales agreements for eight of the



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Company's facilities are of a type typically called "fully dispatchable,"
providing the utility with greater dispatching rights whenever it determines
that it can obtain lower cost power either from the utility's in-system
generation or from bulk purchases. The power sales agreements for these
facilities are structured in a manner such that when the amount of electrical
output is reduced, the plant continues to receive capacity payments (which
provide substantially all of the project subsidiary's profits). Energy payments
(which cover the variable operating, maintenance and fuel costs) are received
for each kilowatt hour delivered. In February 1994, the Company received
notification from Virginia Electric and Power Company ("Virginia Power")
invoking a provision contained in the power sales agreements with respect to the
Company's Hopewell and Portsmouth facilities which requires the Company to
negotiate in good faith to enter into a separate agreement for the dispatch of
all of the Company's cogeneration facilities located in the Virginia Power
service area. The agreements executed by Virginia Power in connection with the
financing of the Company's Hopewell and Portsmouth facilities provide that
without the consent of the project lenders to such facilities, Virginia Power
will not enter into any agreement with the Company which would permit Virginia
Power to increase the aggregate annual number of kilowatt hours that such
facility could be dispatched downward. The Company and Virginia Power have
conducted initial discussions on such a proposal and will continue these
negotiations going forward. At this time, it is impossible to predict the
ultimate outcome of these discussions. The Company believes that any future
agreement that may be negotiated with Virginia Power with respect to the
dispatching of these facilities will not have a material adverse economic impact
on any of these facilities.

         With the exception of two facilities, which produce thermal energy in
the form of hot water for use by commercial greenhouses, all of the Company's
plants produce steam ("process steam") for use by an industrial host. These
industrial hosts, which include textile manufacturing companies, pharmaceutical
manufacturing companies, chemical producers and synthetic fiber plants, use the
process steam in their manufacturing processes. The Company's steam sales
contracts with these industrial hosts generally are long-term contracts that
provide payment on a per thousand pound basis for steam delivered and a minimum
annual payment if the industrial host's plant is shut down. All contracts
require steam purchases during their initial terms adequate to allow maintenance
of QF status. See "Regulation -- Energy Regulations" herein.

         Each of the Company's project subsidiaries purchases fuel under
long-term supply agreements. Ten of the Company's projects are fueled with
low-sulfur coal and one with natural gas. The coal is transported by rail to
each project or to a terminal point near a project. The coal supply and rail
transportation contracts with respect to each of the Company's coal-fired
projects are structured so that the fuel cost escalations are generally matched
by increases in the energy payments received by the Company for electricity
under the corresponding power sales agreement. This matching is typically
effected by having the coal prices escalate as a function of the solid fuel
index of the purchasing utility, which reflects changes in the utility's cost of
fuel to operate its plants or by contracting for scheduled increases in energy
payments designed to offset scheduled increases in coal and rail prices. The
Company is generally required to purchase all of its fuel requirements for a
particular plant under the coal sales agreement relating to that particular
plant. Each fuel supplier may service the contract from a list of approved mines
identified in the agreement. Each of the Company's projects fueled with coal
maintains fuel inventories at the project site which ordinarily vary from 15 to
30 days' supply. The Company believes that such inventories are adequate and has
developed contingency plans to deal with shortages of coal due to coal or rail
strikes or force majeure events impacting coal deliveries.

         The fuel transportation requirements of each coal-fired facility are
satisfied in accordance with a rail transportation agreement entered into
between the project subsidiary and a railway company. These agreements provide
that the railway company will transport all of the facility's fuel from the mine
to a point near the project subsidiary's facility. The railway company is paid a
specified price per ton for these services, which adjusts annually through the
term of the agreements.

         The power sales agreements and the steam sales agreements provide
substantially all of the revenue stream of the Company's facilities. Excluding
the non-recurring loss on impairment and cost of removal of cogeneration
facilities recognized in fiscal 1997, costs incurred under the fuel supply
agreements and transportation agreements accounted for approximately 46.3% of
the Company's operating expenses.

         PROJECT FINANCING. The Company has financed each facility through
project subsidiaries primarily under financing arrangements and related
documents which, except as noted herein, 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
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 set forth in the financing documents to assure that, to the 

                                       9
<PAGE>   10

extent available, they are used first to pay operating expenses, senior debt
service and taxes and to fund reserve accounts. Thereafter, subject to
satisfying debt service coverage ratios and certain other conditions, amounts
may be disbursed to the Company for management fees or dividends or, where there
are subordinated lenders, to the payment of subordinated debt service.

         As with the Company's existing facilities, future projects are expected
to be financed using a high proportion of debt to equity. Leveraged financing
permits the development of 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
have security interests covering certain aspects of the project, including the
plant, related facility support agreements, the stock or partnership interest of
certain of the Company's project subsidiaries, licenses and permits necessary to
operate the plant and the cash flow derived from the plant. In the event of a
foreclosure after a default, the Company 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 the
Company's 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, the
Company's ability to transfer or sell its interest in certain projects is
restricted by a purchase option to a steam purchaser and certain rights of first
refusal in favor of its power and steam purchasers. See "Facilities in
Operation" herein.

         The lenders under these project financing structures cannot look to the
Company or its other projects for repayment (that is, they are "non-recourse" to
the Company and its other project subsidiaries), unless the Company or another
project subsidiary expressly agrees to undertake liability. The Company has
agreed to undertake limited financial support for certain of its project
subsidiaries in the form of certain limited obligations and contingent
liabilities. These obligations and contingent liabilities take the form of
guarantees, indemnities, capital infusions and agreements to pay certain debt
service deficiencies. To the extent the Company becomes liable under such
guarantees and other agreements with respect to a particular project,
distributions received by the Company from other projects may be used by the
Company to satisfy these obligations. To the extent of these obligations, the
lenders to a project have recourse to the Company and the distributions to the
Company from other projects. The aggregate contractual liability of the Company
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 "substantially non-recourse" to the Company and
its other projects. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations."

         The Indenture under which the Senior Notes were issued permits the
incurrence of debt, guarantees and liens jointly by the Company's two project
subsidiaries that own and operate the Company's five facilities located in North
Carolina that sell electricity to Carolina Power & Light Company ("CP&L")
(Elizabethtown, Lumberton, Kenansville, Roxboro and Southport). This provision
of the Indenture permits the Company to refinance the project financings for
these five facilities and give a new project lender (or lenders) a security
interest covering all five facilities, the related facility support agreements,
the shares of stock the Company owns of these two project subsidiaries, the
licenses and permits necessary to operate the facilities and the cash flow
derived from each of the five facilities. The Indenture also permits the
incurrence of debt, guarantees and liens jointly by (i) the project subsidiaries
that own and operate the Company's facilities located at Portsmouth and
Hopewell, Virginia and (ii) any future project subsidiaries or joint ventures
with respect to the future development of power generation facilities. To the
extent the Company takes advantage of these provisions of the Indenture, the
project lender (or lenders) will have recourse to several of the Company's
facilities instead of having its (or their) recourse limited to the facility (or
facilities) owned by a single project subsidiary.

         The Company's plants 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 (at replacement cost) and business interruption.

         OPERATING ARRANGEMENTS. Unlike many independent power producers who
contract with third party operators, the Company operates ten of its eleven
facilities. Each project subsidiary employs directly the persons required to
operate the facility it owns or leases. The Company hires its general plant
managers early in the construction phase of the plants, invests in the training
of operating personnel and structures its plant bonus program to reward
efficient and cost effective operation of the plants. Executive management of
the Company meets several times a year with the plant managers and conducts
on-site plant performance reviews with each plant manager.


                                       10
<PAGE>   11

         The ten plants which the Company operates had average availability of
96.83% in fiscal 1997, 96.51% in fiscal 1996 and 97.02% in fiscal 1995. In
calculating plant availability, the Company has adapted the utility industry's
definition of "equivalent availability factor" to the independent power
industry. The "equivalent availability factor" is defined as the percentage of
time that a plant is available for operation in a given period (usually a year),
where each hour of availability is pro rated if the plant is only partially
available. For an independent power producer like the Company, full capacity is
generally defined as contracted-for electric generating capacity (in megawatts).
For plants that sell process steam to an industrial host, full capacity also
includes contracted-for steam usage, in megawatt-equivalents.

         The Company provides to the plants it operates certain 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 certain covenants under the project financing agreements
and may be subordinated to the payment of obligations under those agreements.
The Company has earned and will continue to earn incentive compensation from the
Hopewell Facility, in which the Company holds a 50% general partnership interest
and is the managing general partner, if the facility achieves certain net income
levels.

         ASH REMOVAL. Project subsidiaries owning seven of the Company's
facilities contract with ReUse Technology, Inc. ("ReUse"), a wholly-owned
subsidiary of the Company operated as an autonomous business unit, to remove
coal ash generated by such plants. A third party removes and handles coal ash at
the other coal-fired plants. As an alternative to disposing of coal ash in
landfills, ReUse has developed the use of coal ash as structural fill material
and in the manufacturing and production of various ash derived products for
resale. Most of the coal ash removed from the Company's plants by ReUse is
hauled to land located in a nearby industrial/commercial area, which is owned or
leased by ReUse. The coal ash is utilized as structural fill on the tract to
raise the existing grade to a higher level and thereby make the site more
suitable for commercial development. Industrial warehouse facilities have been
constructed on two sites that had been filled with coal ash removed from the
Company's plants. It is anticipated that some of the sites owned by ReUse will
be sold at some future date for industrial or commercial development.

         The remaining coal ash removed from the Company's plants by ReUse is
incorporated into various products for resale. Examples of such products include
concrete blocks, concrete pavers, land plaster for peanut crops and potting
soil. At one site, which was developed by utilizing coal ash as structural fill
material for several years, ReUse has now established a composting operation to
mix coal ash with wood by-products and cotton gin waste to make potting soil,
which ReUse then sells in bulk to nurseries and other end users.

         ReUse also provides ash services for cogeneration facilities owned and
operated by unaffiliated independent power producers. In connection with the
provision by ReUse of such services under a contract for one of these
facilities, Cogentrix has agreed to take all action necessary (including making
loans and equity contributions) to ensure that ReUse has adequate financial
resources to perform its obligations under its agreement with the facility's
owner up to a maximum aggregate liability of $1.5 million.


                                       11
<PAGE>   12


FACILITIES IN OPERATION

         Set forth in the table and the text below are descriptions of the
Company's eleven plants currently in operation. In each case, the Company
developed the plant (except for the Ringgold facility that the Company purchased
immediately prior to construction and the Birchwood facility in which the
Company purchased its 50% interest during construction), which included siting,
permitting and financing activities. Revenues are currently being realized from
the sale of electricity and thermal energy generated by each of these
facilities.

         Each of the Company's facilities relies on a power sales agreement with
a single customer for the majority of its revenues over the life of the power
sales agreement. During the fiscal year ended June 30, 1997, two regulated
utilities, CP&L and Virginia Power, accounted for approximately 87% of the
Company's consolidated revenues. The failure of either of these utility
customers to fulfill its contractual obligations for a prolonged period of time
would have a substantial negative impact on the Company's primary source of
revenues. Both CP&L and Virginia Power's senior debt securities are rated
investment grade by Standard & Poor's Corporation and Moody's Investors Service,
Inc.

<TABLE>
<CAPTION>
------------------------------------------------------------------------------------------------------------------------------------
                       ACTUAL       DESIGN                                                            DATE OF
                       PROJECT    CAPACITY OF                                                      COMMENCEMENT      COMPANY'S
    LOCATION OF        COST(1)    ELECTRICITY            POWER               THERMAL ENERGY        OF COMMERCIAL     OWNERSHIP
    FACILITIES           (IN      (MEGAWATTS)     PURCHASING UTILITY         PURCHASER/USER          OPERATION        INTEREST
                      MILLIONS)
------------------------------------------------------------------------------------------------------------------------------------
<S>                    <C>            <C>          <C>                    <C>                    <C>                    <C>
 ELIZABETHTOWN, NC     $ 30.3          35                CP&L             Alamac Knit Fabrics,     December 1985        100%
                                                                                  Inc.
------------------------------------------------------------------------------------------------------------------------------------
   LUMBERTON, NC       $ 30.5          35                CP&L             Alamac Knit Fabrics,     December 1985        100%
                                                                                  Inc.
------------------------------------------------------------------------------------------------------------------------------------
  KENANSVILLE, NC      $ 32.8          35                CP&L             Guilford Mills, Inc.      April 1986          100%
------------------------------------------------------------------------------------------------------------------------------------
    ROXBORO, NC        $ 44.9          60                CP&L               Collins & Aikman        August 1987         100%
                                                                               Corporation
------------------------------------------------------------------------------------------------------------------------------------
   SOUTHPORT, NC       $ 82.9         120                CP&L                Archer-Daniels-      September 1987        100%
                                                                             Midland Company
------------------------------------------------------------------------------------------------------------------------------------
   HOPEWELL, VA        $ 97.8         120           Virginia Power            Allied-Signal        December 1987         50%
                                                                               Corporation
------------------------------------------------------------------------------------------------------------------------------------
  PORTSMOUTH, VA       $ 94.7         120           Virginia Power          Hoechst-Celanese         June 1988          100%
                                                                               Corporation
------------------------------------------------------------------------------------------------------------------------------------
  ROCKY MOUNT, NC      $107.2         120           Virginia Power         Abbott Laboratories     October 1990         100%
                                                 d/b/a North Carolina
                                                     Power Company
------------------------------------------------------------------------------------------------------------------------------------
   RINGGOLD, PA        $ 32.0        15.5        Pennsylvania Electric      Keystone Village        April 1991          100%
                                                        Company                Farms, Inc.
------------------------------------------------------------------------------------------------------------------------------------
   RICHMOND, VA        $243.7         240           Virginia Power           E.I. Du Pont de     Unit I May 1992;       100%
                                                                            Nemours & Company     Unit II August
                                                                                                       1992
------------------------------------------------------------------------------------------------------------------------------------
  KING GEORGE, VA      $364.0         220           Virginia Power           Greenhost, Inc.       November 1996         50%
    (BIRCHWOOD
     FACILITY)
------------------------------------------------------------------------------------------------------------------------------------
</TABLE>

(1) Actual project cost includes all costs directly associated with the
    construction of the facility, related improvements and land
    acquisition, together with costs incurred to obtain construction and
    permanent financing and other costs associated with the formation of
    each project entity and the start-up of the facility.

         ELIZABETHTOWN, LUMBERTON AND KENANSVILLE FACILITIES. Cogentrix Eastern
Carolina Corporation, a North Carolina corporation ("CECC"), owns and operates
three 35 megawatt stoker coal-fired cogeneration plants in Elizabethtown,
Lumberton and Kenansville, North Carolina (collectively, the "ELK Facilities"
and individually an "ELK Facility"). The ELK Facilities were the first
cogeneration facilities developed by the Company and are presently financed
under a single project financing credit facility. The Elizabethtown and
Lumberton plants commenced commercial operation in December 1985 with the
Kenansville plant following in April 1986.

         The ELK Facilities sell electricity to CP&L under separate power sales
agreements, which were amended effective in September 1996. Under the amended
terms, the power sales agreements for the Elizabethtown and Lumberton Facilities
each have 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 power sales agreements has automatic renewals for one-year
renewal terms unless either party terminates the agreement prior to the
commencement of a renewal term. The purchase price for electricity during such
renewal term would continue to be the rate set forth in the power sales
agreements. Annual increases in energy prices under the power sales agreement
are designed to offset annual increases in coal and rail transportation prices.


                                       12
<PAGE>   13

         In addition to CP&L's right to dispatch or suspend delivery of
electricity from the ELK Facilities for maintenance and emergencies, the ELK
Facilities are also subject to economic dispatch by CP&L. This right allows CP&L
to suspend or reduce purchases of energy from the ELK Facilities if CP&L
determines that it can operate its system for a designated period more
economically. The power sales agreement is structured so that CECC will continue
to receive capacity payments during any period of economic dispatch. Capacity
payments cover project debt service, fixed operating costs and constitute a
substantial portion of the profit component of the power sales agreement. Energy
payments, which would be reduced (or possibly eliminated) as a result of an
economic dispatch, primarily cover variable operating, maintenance, coal and
rail transportation costs associated with operating at different levels.

         In the event CECC decides to dispose of an ELK Facility, it must first
offer the facility to the respective steam purchaser, and if the steam purchaser
does not exercise its right, CECC must then offer the facility to CP&L at fair
market value.

         Each of the power sales agreements provides that in the event of
termination (other than for a material breach by CP&L) prior to the expiration
of the initial term of the power sales agreements, CECC must pay CP&L a
termination charge equal to the excess paid for capacity and energy over what
would have been paid to CECC under the North Carolina Utilities Commission
("NCUC") published capacity credit and variable energy rates plus interest.

         If the average capacity made available in the peak period or average
energy generated or made available in peak or off-peak periods during any
12-month period falls below 80% of the established contract capacity level or
the contract peak or off-peak energy level, as the case may be, CP&L may
establish a new contract capacity level or contract energy level. If a reduction
in the contract capacity level is invoked, a special charge will be imposed by
CP&L equal to a percentage of the termination charge described above. If a
reduction in the contract energy level is invoked, a special reduction in the
contract energy charge will also be imposed. In addition, if CECC desires to
terminate the power sales agreement prior to its expiration and a substitute
operator satisfactory to CP&L is not secured, CECC must pay to CP&L the
termination charge described above plus an amount equal to the depreciated
installed cost of the interconnection facilities relating to the plant (using a
20-year useful life). Cogentrix has guaranteed the performance of CECC under the
CP&L 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 expiring in December 2000, each of which
contains renewal options. Guilford Mills, Inc. ("Guilford") purchases steam from
the Kenansville Facility for use in its textile manufacturing plant under a
steam sales agreement expiring in July 2001, which contains renewal options.

         Each of the ELK Facilities uses low-sulfur stoker coal mined in
Kentucky supplied under a single coal sales agreement with James River Coal
Sales, Inc. ("James River") and its affiliate, Bell County Coal Corporation. The
coal sales agreement provides that CECC will purchase and James River will
provide all of CECC's coal requirements through September 2001. If the ELK
Facilities do not purchase an average of 320,000 tons per fiscal year (as
appropriately reduced due to force majeure events), the contract will be
extended if during any subsequent period the ELK Facilities are selling
electricity to CP&L until CECC purchases such short-fall amount.

         The coal purchased for the ELK Facilities is transported by CSX
Transportation, Inc. ("CSX") under separate rail transportation contracts each
having a term through September 2001 to rail unloading facilities owned by CECC.
Coal is then hauled by truck to each of the plants by independent contractors,
and ash is removed from each of the plants by ReUse, under separate long-term
coal hauling and ash disposal agreements.

         The ELK Facilities were financed pursuant to a senior term loan and a
subordinated credit facility, each entered into in December 1991, the proceeds
of which were used to purchase the facilities from General Electric Capital
Corporation. In September 1996, CECC refinanced both the senior term loan and
subordinated credit facility with the proceeds of a senior credit facility and a
$5.5 million capital contribution from the Company. The senior credit facility
provides for a $39 million term loan and a $3.3 million letter of credit to
secure the obligations of CECC to pay debt service.

         Cogentrix has pledged the stock of CECC to secure the obligations of
CECC under the senior credit facility, but Cogentrix is not liable for any
deficiency if the proceeds of any sale or disposition of the collateral are
insufficient to pay the secured obligations.


                                       13
<PAGE>   14

         The ELK Facilities generated $35.7 million of revenues in fiscal 1997,
$53.9 million of revenues in fiscal 1996 and $52.4 million of revenues in fiscal
1995.

         ROXBORO AND SOUTHPORT FACILITIES. Cogentrix of North Carolina, Inc., a
North Carolina corporation ("CNC"), operates two stoker coal-fired cogeneration
plants in Roxboro and Southport, North Carolina (individually, the "Roxboro
Facility" and "Southport Facility"; collectively, the "Roxboro and Southport
Facilities"), which are owned by another wholly-owned subsidiary of the Company,
Cogentrix of North Carolina Holdings, Inc. The Roxboro and Southport Facilities
are financed under a single project financing credit facility. The 60 megawatt
Roxboro Facility, which commenced commercial operation in August 1987, may
operate at a declared capacity of up to 56 megawatts. The 120 megawatt Southport
Facility, which may operate at a declared capacity of up to 107 megawatts,
commenced commercial operation in September 1987.

         The Roxboro and Southport Facilities sell electricity to CP&L under
separate power sales agreements, each having an initial term expiring in
December 2002 with automatic renewals for two-year renewal terms unless either
party terminates the agreement prior to the commencement of a renewal term. The
purchase price for electricity during such renewal term would continue to be the
rate for 2002 set forth in the power sales agreements. These power sales
agreements were amended effective in September 1996 to provide CP&L economic
dispatch rights on the facilities and to eliminate options CP&L had to purchase
these facilities. Under the amended power sales agreements, CP&L has a right of
first refusal on either or both facilities.

         The power sales agreements provide for scheduled annual increases in
energy payments through 1997, which the Company believes are sufficient to
offset scheduled annual increases in coal and rail transportation prices. Energy
payments from 1998 through 2002 under the power sales agreements are designed to
offset annual fluctuations in coal and rail transportation prices.

         In addition to CP&L's right to dispatch or suspend delivery of
electricity from the Roxboro and Southport Facilities for maintenance and
emergencies, the Roxboro and Southport Facilities are also subject to economic
dispatch by CP&L. This right allows CP&L to suspend or reduce purchases of
energy from the Roxboro and Southport Facilities if CP&L determines that it can
operate its system for a designated period more economically. The power sales
agreements are structured so that CNC will continue to receive capacity payments
during any period of economic dispatch. Capacity payments cover project debt
service, fixed operating costs and constitute a substantial portion of the
profit component of the power sales agreements. Energy payments, which would be
reduced (or possibly eliminated) as a result of an economic dispatch, primarily
cover variable operating, maintenance, coal and rail transportation costs
associated with operating at different levels.

         Each of the power sales agreements provides that in the event CNC
desires to terminate the power sales agreement or abandons the Roxboro or
Southport Facility, CNC must pay CP&L a termination charge. Such termination
charge will be equal to the sum of (i) the depreciated installed cost of the
interconnection facilities relating to the plant (using a 20-year useful life),
plus (ii) for terminations occurring prior to December 15, 1997, an amount equal
to the excess paid for energy delivered prior to September 26, 1996 and capacity
made available after September 26, 1996 over what would have been paid to CNC
under the published NCUC approved cogeneration small power variable rate
applicable at the time the energy was delivered or the capacity was made
available or, for terminations occurring on or after December 15, 1997, the cost
incurred by CP&L to replace the capacity provided by the Roxboro or Southport
Facility in excess of the capacity payments which would have been made to CNC
for the Roxboro or Southport Facility, plus (iii) a carrying charge equal to the
overall pretax cost of capital allowed to CP&L by the NCUC retail rate order in
effect during the time the energy credits were received.

         If the average energy generated or made available in peak or off-peak
periods during any 12-month period occurring prior to December 15, 1997 falls
below 80% of the established contract peak or off-peak energy level, CP&L may
establish a new contract energy level for peak or off-peak periods,
respectively, and, as a result, a special charge plus interest would then become
payable by CNC.

         Cogentrix has guaranteed the performance of CNC under the CP&L power
sales agreements.


                                       14
<PAGE>   15

         Collins & Aikman Corporation ("C&A") purchases process steam for its
textile manufacturing facility from the Roxboro Facility under a 15-year steam
sales agreement (of which approximately five years remain) that is renewable by
C&A for an additional five-year term upon one year's prior written notice.
During the initial term of the steam sales agreement, C&A is obligated to
purchase and use a minimum of five percent of the Roxboro Facility's total
energy output so that the facility will remain a QF under PURPA.

         Archer-Daniels-Midland Company ("ADM") purchases steam for its
pharmaceutical and chemical manufacturing company from the Southport Facility
under a 15-year steam sales agreement (of which approximately five years remain)
that is renewable by ADM for an additional five-year term upon one year's prior
written notice. During the initial term of the steam sales agreement, ADM is
obligated to purchase and use a minimum of five percent of the Southport
Facility's total energy output so that the facility will remain a QF under
PURPA.

         Coal for the Roxboro Facility is supplied from Kentucky by Martiki Coal
Corporation under a coal sales agreement ending in November 1997. CNC is
obligated to purchase and Martiki is obligated to sell, subject to a limit of
235,000 tons per year, all of the coal requirements for the Roxboro Facility.
Coal for the Southport Facility is supplied from Kentucky by Coastal Coal Sales,
Inc. ("Coastal") under a coal sales agreement ending in November 1997. Coastal
has agreed to supply and CNC has agreed to purchase all of the coal requirements
for the Southport Facility. CNC has executed replacement long-term coal sales
agreements for both the Roxboro and Southport Facilities with subsidiaries of
Alliance Coal Corporation. The terms of these replacement contracts correspond
with the terms of each Facility's power sales agreement.

         Norfolk Southern Railway Company transports coal to the Roxboro
Facility under a rail transportation contract ending in 2002. The coal for the
Southport Facility is transported by CSX, under a rail transportation contract
ending in 2002, to a rail side track located approximately six miles from the
Southport Facility and is then hauled by a CNC operated locomotive to the plant
site.

         Ash hauling services are provided for the Roxboro Facility by First
Piedmont Corporation under a ten-year agreement (expiring in December 1997) with
three five-year renewal options. Ash disposal services for the Southport
Facility are provided by KBK Enterprises, Inc. under a ten-year contract
(expiring in December 1997) with two ten-year renewal options. In addition,
ReUse has entered into backup ash disposal agreements for both facilities in the
event the existing agreements are terminated or the existing ash haulers are
unable to perform.

         The Southport and Roxboro Facilities were financed pursuant to a senior
term loan and a subordinated credit facility, each entered into in March 1993,
the proceeds of which were used to purchase the facilities from General Electric
Capital Corporation. In September 1996, CNC refinanced the senior term loan and
subordinated credit facility with the proceeds of a $122 million senior credit
facility. The senior credit facility provides for a $115.5 million term loan and
a $6.5 million letter of credit facility to secure the obligations of CNC to pay
debt service. In connection with the refinancing, the Company entered into an
agreement for the benefit of the project lenders to fund cash deficits CNC could
experience as a result of incurring certain costs, subject to a cap of $11.3
million.

         Certain of the Company's subsidiaries have pledged their respective
ownership interests in the Roxboro and Southport Facilities as collateral
security for the senior credit facility, but Cogentrix Energy, Inc. is not
liable for any deficiency if the proceeds of any sale or disposition of the
collateral are insufficient to pay the secured obligations.

         The steam sales agreement for the Southport Facility provides that upon
at least 12 months' prior notice, CNC will sell to ADM up to an additional
100,000 pounds of steam per hour. The power sales agreement further provides
that if upon a sale of the Southport Facility CP&L exercises its right of first
refusal and a package boiler to meet ADM's increased steam demands has not been
installed, CNC must deposit into an escrow account at such time an amount
sufficient to provide a package boiler to meet such increased steam demands.
Management anticipates such a boiler could be provided at a cost of
approximately $2,500,000.

         The Roxboro and Southport Facilities generated $58.2 million of
revenues in 1997, $86.9 million of revenues in fiscal 1996 and $84.4 million of
revenues in fiscal 1995.


                                       15
<PAGE>   16

         HOPEWELL FACILITY. The Company's Hopewell facility (the "Hopewell
Facility"), located in Hopewell, Virginia, is a 120 megawatt stoker coal-fired
cogeneration facility owned by James River Cogeneration Company ("JRCC"). JRCC
is a North Carolina general partnership, in which a 50% general partnership
interest is owned by Cogentrix of Virginia, Inc., a Virginia corporation
("CVA"), which is a wholly-owned subsidiary of the Company. The remaining 50% is
owned by Capistrano Cogeneration Company, a subsidiary of Edison Mission Energy.
Commercial operation of the Hopewell Facility commenced in December 1987.

         CVA, as managing general partner, has complete responsibility for the
operation, maintenance and management of the Hopewell Facility under a 20-year
operations, maintenance and management agreement with JRCC (expiring in December
2008). JRCC is governed by a partnership agreement which provides that certain
significant business decisions regarding the partnership must be approved by
representatives of both partners. The operations, maintenance and management
agreement provides for CVA to receive base compensation as well as incentive
compensation if the facility achieves certain levels of net income.

         The Hopewell Facility provides electricity to Virginia Power under a
power sales agreement, which was amended in March 1996, having an initial
20-year term (of which approximately 10 years remain) with an automatic ten-year
extension unless either party notifies the other prior to the expiration of the
initial term of its desire to terminate the agreement. The capacity purchase
price for any such renewal term would be based on the avoided cost schedule then
in effect. In connection with the March 1996 amendment of the power sales
agreement, JRCC received a $7.5 million payment from Virginia Power in exchange
for a reduction of the Hopewell Facility's declared capacity from 100 to 88.5
megawatts. Under the amended terms of the power sales agreement, Virginia Power
is not obligated to purchase energy from the Hopewell Facility in excess of
375,000 on-peak megawatt hours and 330,000 off-peak megawatt hours during each
calendar year through the year 2000 and 350,000 on-peak megawatt hours and
330,000 off-peak megawatt hours from 2001 through the end of the term of the
agreement.

         Annual increases in energy prices under the power sales agreement are
designed to offset annual increases in coal and rail transportation prices. In
addition to having the right to suspend delivery of electricity from the
Hopewell Facility for maintenance and emergencies, Virginia Power has the right
to suspend delivery from the facility to a level of not less than 25 megawatts
for up to 450 hours per year. Such suspensions of delivery have no material
impact on the aggregate amount of annual energy or capacity payments received by
the Hopewell Facility. In February 1994, the Company received a notice from
Virginia Power invoking a provision in the power sales agreement which requires
the Company to negotiate in good faith to enter into a separate agreement for
the dispatch of all of the Company's cogeneration facilities located in the
Virginia Power service area. See "Description of the Company's Facilities --
Project Agreements" herein.

         Currently, Virginia Power is permitted recovery from its customers of
payments made to JRCC under the power sales agreement. The power sales agreement
provides, however, that if at any time after commercial operation commences the
Virginia regulatory authorities prohibit Virginia Power from recovering from its
customers payments made under the agreement, the purchase price of electricity
will be adjusted to the greater of the following: 80% of the energy and capacity
prices that would have been payable under the power sales agreement absent such
disallowance or the rates which the regulatory authorities allow Virginia Power
to recover from its customers. Notwithstanding any such occurrence, Virginia
Power has agreed to pay the contracted prices for the first 15 years of the
agreement (until December 2002), provided that within four months following the
end of the 15th year, JRCC must repay Virginia Power any excess amounts so paid
by Virginia Power for energy and capacity with interest. In addition, if the
agreement is terminated prior to the end of its initial or any subsequent term
other than due to a default by Virginia Power, JRCC must pay Virginia Power the
difference between payments for capacity under the contract and those that would
have been allowable under the applicable avoided cost schedules plus interest.

         If the Hopewell Facility has a forced outage rate with respect to the
number of on-peak kilowatt hours generated in any calendar year of greater than
ten percent but less than or equal to twenty-five percent, capacity payments
will be reduced by four percent for each percent that the forced outage rate
exceeds ten percent. If the forced outage rate is greater than twenty-five
percent for any calendar year, no capacity payments will be due for such year.
The forced outage rate is a percentage derived by dividing the number of on-peak
kilowatt hours generated in a calendar year by an amount equal to the rated
capacity of the facility multiplied by the number of available on-peak hours
during such year excluding outages for scheduled maintenance, emergencies,
contractually permitted suspensions of delivery of electricity or force majeure.


                                       16
<PAGE>   17


         The power sales agreement for the Hopewell Facility provides that after
December 31, 2002, JRCC will be paid for energy at the rates specified in the
applicable avoided cost schedule published by the Virginia State Corporation
Commission (increased, if necessary, to include certain line loss and variable
operation and maintenance expense adjustments). If at any time after such date,
the Virginia regulatory authorities do not promulgate such a schedule, the power
sales agreement provides that JRCC and Virginia Power will negotiate, in good
faith, a mutually agreeable price for energy. The power sales agreement grants
to Virginia Power a right of first refusal to purchase the Hopewell Facility at
fair market value provided that such amount will not exceed JRCC's net
investment in the Hopewell Facility.

         Allied-Signal Corporation ("ASC") purchases steam from the Hopewell
Facility under a 20-year steam sales agreement (of which approximately 10 years
remain). ASC is obligated to purchase and use a minimum of five percent of the
Hopewell Facility's total energy output in a manner such that the facility will
remain a QF under PURPA.

         Coal for the Hopewell Facility is supplied from mines in Kentucky by
Pontiki Coal Corporation ("Pontiki") under a 15-year coal sales agreement (of
which approximately five years remain), which requires Pontiki to sell and JRCC
to purchase all of the Hopewell Facility's requirements for coal. Historically,
under the coal sales agreement, Pontiki has supplied and the facility has
required approximately 430,000 tons of coal per year. The agreement provides,
however, that Pontiki is not obligated to supply more than 400,000 tons of coal
per year. JRCC has no reason to believe that Pontiki will not continue to supply
the excess amount of coal required, but if it does not, the Company believes
that JRCC could purchase coal from other sources. Because the term of the coal
sales agreement for the Hopewell Facility expires at the end of 2002, JRCC will
need to assure itself of a supply of coal for the remaining term of its power
sales agreement. JRCC's current plans are to negotiate a replacement long-term
coal sales agreement. However, if JRCC is unable to enter into agreements
acceptable to it, JRCC currently believes it would be able to purchase its
requirements on the short-term spot market at prices that are presently
significantly below the present contract rates. The coal is transported by
Norfolk Southern Railroad Company under a 15-year rail transportation agreement
(of which approximately five years remain).

         Ash generated by the Hopewell Facility is removed and disposed of by
ReUse under an ash removal agreement having a term expiring in 2005.

         The Hopewell Facility was financed pursuant to an $81,990,000 term loan
and letter of credit facility. The letter of credit supported the issuance of
commercial paper notes by JRCC. In July 1996, JRCC refinanced the term loan and
letter of credit facility with the proceeds of a $55,490,000 senior term loan.

         Cogentrix has pledged the stock of CVA as security for the obligations
of JRCC under this credit facility, but Cogentrix is not liable for any
deficiency if the proceeds of any sale or disposition of the pledged stock are
insufficient to pay all secured obligations.

         The Hopewell Facility generated $51.2 million of revenues in fiscal
1997, $57.4 million in revenues in fiscal 1996 and $54.9 million in revenues in
fiscal 1995.

         PORTSMOUTH FACILITY. The Company's Portsmouth Facility (the "Portsmouth
Facility") located in Portsmouth, Virginia is a 120 megawatt stoker coal-fired
cogeneration facility owned by Cogentrix Virginia Leasing Corporation, a North
Carolina corporation ("CVLC"). Commercial operation of the Portsmouth Facility
commenced in June 1988.

         Under a power sales agreement with Virginia Power, the Portsmouth
Facility provides 115 megawatts of declared capacity of electricity for an
initial 20-year term (of which approximately 11 years remain) with an automatic
ten-year extension unless either party notifies the other prior to the
expiration of the initial term of its desire to terminate the agreement. The
capacity purchase price for any such renewal term would be based on the avoided
cost schedule then in effect.

         Annual increases in energy prices under the power sales agreement are
designed to offset annual increases in coal and rail transportation prices. In
addition to having the right to suspend delivery of electricity from the
Portsmouth Facility for maintenance and emergencies, Virginia Power also has the
right to suspend delivery from the facility to a level of not less than 25
megawatts for up to 450 hours per year. Such suspensions of delivery have no
material impact on the aggregate amount of annual capacity payments received by
the Portsmouth Facility. In February 1994, the Company received a notice from
Virginia Power invoking a provision in the power sales agreement which requires
the Company to negotiate in good 



                                       17
<PAGE>   18

faith to enter into a separate agreement for the dispatch of all of the
Company's cogeneration facilities located in the Virginia Power service area.
See "Description of the Company's Facilities -- Project Agreements" herein.

         Except to the limited extent set forth below, Virginia Power is
permitted recovery from its customers of payments made to CVLC under the power
sales agreement. The power sales agreement provides that if at any time after
commercial operation commences the Virginia regulatory authorities prohibit
Virginia Power from recovering from its customers payments made under the
agreement, the purchase price of electricity will be adjusted to the greater of
the following: 80% of the energy and capacity prices that would have been
payable under the power sales agreement absent such disallowance or the rates
which the regulatory authorities allow Virginia Power to recover from its
customers. Notwithstanding any such occurrence, Virginia Power has agreed to pay
the contracted prices for the first 15 years of the agreement (until June 2003),
provided that within four months following the end of the 15th year, CVLC must
repay Virginia Power any excess amounts so paid by Virginia Power for energy and
capacity with interest. In addition, 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, CVLC must pay Virginia Power the difference between
payments for capacity under the contract and those that would have been
allowable under the applicable avoided cost schedules plus interest.

         In February 1994, the Virginia State Corporation Commission, in a 
Virginia Power rate case, disallowed recovery from Virginia Power's customers a
portion of the capacity payments paid to certain independent power producers,
including CVLC, under their respective power sales agreements. This
disallowance was based on an alleged error in the calculation of Virginia
Power's avoided cost used in calculating the amount of the capacity payments
contained in such power sales agreements. In the case of CVLC, the order, which
during 1996 became final after all appeals were exhausted, disallows recovery
by Virginia Power from its customers of approximately $250,000 annually from
the capacity payments paid to CVLC. Pursuant to the security deposit agreement
between CVLC and its project lenders, CVLC is funding a reserve account in an
amount equal to the accrued liability for such regulatory disallowance.

         If the Portsmouth Facility has a forced outage rate with respect to the
number of on-peak kilowatt hours generated in any calendar year of greater than
ten percent but less than or equal to twenty-five percent, capacity payments
will be reduced by four percent for each percent that the forced outage rate
exceeds ten percent. If the forced outage rate is greater than twenty-five
percent for any calendar year, no capacity payments will be due for such year.
The forced outage rate is a percentage derived from the relationship of the
number of on-peak kilowatt hours generated in a calendar year divided by an
amount equal to the rated capacity of the facility multiplied by the number of
available on-peak hours during such year excluding outages for scheduled
maintenance, emergencies, contractually permitted suspensions of delivery of
electricity or force majeure.

         The power sales agreement for the Portsmouth Facility provides that
after December 31, 2002, CVLC will be paid for energy at the rates specified in
the applicable avoided cost schedule published by the Virginia State Corporation
Commission (adjusted, if necessary, to include certain line loss and variable
operation and maintenance expense adjustments). If at any time after such date,
the Virginia regulatory authorities do not promulgate such a schedule, the power
sales agreement provides that CVLC and Virginia Power will negotiate, in good
faith, a mutually agreeable price for energy. The power sales agreement grants
to Virginia Power a right of first refusal to purchase the Portsmouth Facility
at fair market value provided that such amount will not exceed CVLC's net
investment in the Portsmouth Facility.

         The Portsmouth Facility supplies process steam to Hoechst Celanese
Corporation ("Hoechst Celanese") pursuant to a 20-year steam sales agreement (of
which approximately 11 years remain) which renews automatically for successive
two-year periods unless either party gives two years' notice of cancellation.
Hoechst Celanese is obligated to purchase and use a minimum of five percent of
the Portsmouth Facility's total energy output (except in the case of force
majeure) so that the facility will remain a QF under PURPA.

         Coal for the Portsmouth Facility is supplied from mines in Kentucky by
Arch Coal Sales Company ("ACS") pursuant to a 15-year coal sales agreement (of
which approximately six years remain), which requires ACS to sell and CVLC to
purchase all of the Portsmouth Facility's requirements for coal. Historically,
under the coal sales agreement, ACS has supplied and the facility has required
approximately 430,000 tons of coal per year. The agreement provides, however,
that ACS is not obligated to supply more than 400,000 tons of coal per year.
CVLC has no reason to believe that ACS will not continue to supply the excess
amount of coal required, but if it does not, the Company believes that CVLC
could purchase coal from other sources.


                                       18
<PAGE>   19

         Coal for the Portsmouth Facility is transported by rail and barge. CVLC
has a 15-year rail transportation contract (of which approximately six years
remain) with Norfolk Southern Railway Company. From the rail unloading facility
in Norfolk, Virginia, the coal is then transported by a barge owned by CVLC to
the Portsmouth Facility under a barge transportation contract having a term
expiring December 31, 2002 with an unrelated party that provides tugboat and
supervisory services for the loading and unloading of the coal.

         Ash generated by the Portsmouth Facility is managed by ReUse under an
ash removal agreement having a term expiring December 31, 2005, subject to two
five-year renewal options.

         As one of many monitoring requirements of the National Pollutant
Discharge Elimination System ("NPDES") Permits for all of its facilities in
Virginia, including the Portsmouth Facility, CVLC is required to conduct a
bio-assay test on a semiannual basis as an indicator of the toxicity of the
facility's wastewater discharge. The results of a bio-assay test, which is
conducted by growing sensitive living organisms, e.g., mysid shrimp, in
undiluted wastewater, can be influenced by numerous factors in addition to the
toxicity of the wastewater, and a 75% success rate is generally considered
acceptable. In response to negative results on some of the bio-assay tests
conducted at the Portsmouth Facility in prior years, which may or may not be a
result of the toxicity of the wastewater, CVLC reached agreement in September
1993 with the Virginia Department of Environmental Quality ("VDEQ") to perform,
over a four-year period, a toxicity reduction evaluation. Prior to the deadline
for completing the evaluation, VDEQ approved a modification to CVLC's NPDES
Permit. Under the requirements of the modified NPDES Permit, CVLC is in full
compliance, and current operations at the Portsmouth Facility are unaffected.

         The Portsmouth Facility is financed pursuant to a $90 million term loan
credit facility. Cogentrix has agreed that if the funds on deposit in the
revenue account are insufficient to pay the principal of and interest on the
term loans then due (without using any funds deposited in the debt protection
account), Cogentrix will pay the amount of such deficiency. The aggregate amount
that Cogentrix is obligated to pay under this provision is limited to $4,000,000
until June 1, 1998. Thereafter, as long as no default occurs and the debt
protection account is funded to the required levels, Cogentrix's obligation
reduces by an amount equal to $1,000,000 per year plus the aggregate amount of
payments previously made under this provision. If, however, Cogentrix fails to
make any required payment in respect of such a deficiency as described above
within seven business days after notice, Cogentrix is then obligated to prepay
the term loans in an amount equal to the recourse limit then in effect (and not
merely to pay the amount of such deficiency). In addition, as collateral
security for its obligations to make such prepayments, Cogentrix has pledged
cash collateral to one of the lenders under the credit facility in an amount
equal to $1,777,778.

         Cogentrix has pledged the stock of CVLC to secure the obligations of
CVLC under the credit facility, but Cogentrix is not liable for any deficiency
if the proceeds of any sale or disposition of the collateral are insufficient to
pay the secured obligations.

         Cogentrix has agreed to indemnify the lenders under the credit facility
for losses and damages, up to an aggregate amount of $2,500,000, arising from
any failure by ReUse to comply with any governmental actions or requirements of
law or any default by ReUse under its agreement for ash removal services with
CVLC.

         Certain transfers, dispositions or pledges by the Company or any
subsidiary thereof of a majority of its interest in any of the Company's
existing plants constitutes a default under the CVLC credit facility.

         The Portsmouth Facility generated $61.0 million in revenues in fiscal
1997, $58.9 million in revenues in fiscal 1996 and $57.4 million in revenues in
fiscal 1995.

         ROCKY MOUNT FACILITY. The Company's Rocky Mount Facility located near
Rocky Mount, North Carolina is a 120 megawatt stoker coal-fired cogeneration
facility (the "Rocky Mount Facility") owned by Cogentrix of Rocky Mount, Inc., a
North Carolina corporation ("CRM"). Commercial operation of the Rocky Mount
Facility commenced in October 1990. Under a power sales agreement with North
Carolina Power Company ("NC Power"), a division of Virginia Power, the Rocky
Mount Facility provides a declared capacity of 115.5 megawatts of electricity
for an initial 25-year term (of which approximately 18 years remain) with two
renewal terms of up to five years each. Annual changes in energy prices under
the power sales agreement are designed to offset annual fluctuations in coal and
rail transportation prices. NC Power has a right of first refusal to purchase
the Rocky Mount Facility.


                                       19
<PAGE>   20

         In addition to NC Power's right to dispatch or suspend delivery of
electricity from the Rocky Mount Facility for maintenance and emergencies, the
facility is also subject to economic dispatch by NC Power. This right allows NC
Power to suspend or reduce purchases of energy from the Rocky Mount Facility if
NC Power determines that it can operate its system for a designated period more
economically. The power sales agreement is structured so that CRM will continue
to receive capacity payments during any period of economic dispatch. Capacity
payments constitute a substantial portion of the profit component of the power
sales agreement. Energy payments, which would be reduced (or possibly
eliminated) as a result of an economic dispatch, primarily cover variable
operating, maintenance, coal and rail transportation costs associated with
operating at different levels. In February 1994, the Company received a notice
from Virginia Power invoking a provision in the power sales agreement relating
to the Hopewell and Portsmouth facilities which requires the Company to
negotiate in good faith to enter into a separate agreement for the dispatch of
all of the Company's cogeneration facilities located in the Virginia Power
service area. See "Description of the Company's Facilities --Project Agreements"
herein.

         Currently, NC Power is permitted full recovery from its customers of
payments to CRM under the power sales agreement. The power sales agreement
provides, however, that if an applicable legislative or regulatory authority
should take action which would have the effect of disallowing NC Power from
recovering from its customers all or a portion of the payments for capacity in
excess of a certain amount during the first 18 years following the commencement
of commercial operation of the facility (until October 2008), NC Power will
continue to pay for capacity at the contract price through the first 18 years
and may thereafter withhold up to 75% of the payments for capacity for the
following three years to the extent necessary to repay the disallowance to NC
Power with interest. In the event such withholdings do not fully repay such
disallowance, CRM must repay the difference at the end of the 21st year.
Aggregate payments for capacity after the 18th anniversary of the commercial
operation date are not permitted to exceed the amount that NC Power is allowed
to recover from its customers.

         In light of this regulatory disallowance provision in the power sales
agreement, the project lender for the Rocky Mount Facility has established a
regulatory disallowance reserve account, which is required to be funded at any
time a regulatory disallowance occurs or, from and after January 1, 2004, any
filing with a regulatory authority, which is deemed meritorious in the judgment
of the lender in consultation with counsel, is made challenging the pass-through
of payments under the power sales agreement (each a "Regulatory Disallowance
Event"). If a Regulatory Disallowance Event occurs during the period from 1994
through 2002, 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 Regulatory Disallowance Event
occurs during the period from 2003 through 2013, 100% of the 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. The
amount required to be funded in such account is an amount equal to the lesser of
(i) projected reduction in cash flows from 2009 through 2013 as a result of the
disallowance, and (ii) the amount of the debt outstanding at September 30, 2008.

         If the Rocky Mount Facility has forced outage days in any year with
respect to more than the greater of 25 days or ten percent of the total number
of days the facility was required by NC Power to operate, capacity payments for
such period will be reduced by four percent for each such excess forced outage
day.

         In the event capacity testing indicates that the Rocky Mount 
Facility's dependable capacity is less than 90% of the declared capacity, CRM
will be obligated to pay annual liquidated damages to NC Power. A letter of
credit has been posted by CRM in favor of NC Power to secure its obligations to
perform under the power sales agreement.

         Steam from the Rocky Mount Facility is sold to Abbott Laboratories
("Abbott") pursuant to a 25-year steam sales agreement (of which approximately
18 years remain) which may be extended for an additional five-year term upon one
year's prior written notice by Abbott. Abbott is obligated to purchase and use a
minimum of five percent of the total energy output so that the facility will
remain a QF under PURPA. The steam sales agreement provides that if CRM does not
deliver steam in accordance with the agreement under certain circumstances,
Abbott is entitled to receive certain quantities of steam in the future at
substantially reduced prices.

         Coal for the Rocky Mount Facility is supplied from mines in West
Virginia under a 23-year coal sales agreement (of which approximately 16 years
remain) with Laurel Creek Co., Inc. and ACS Coal Sales Company ("ACS Coal
Sales"), which requires ACS Coal Sales to sell and CRM to purchase all of the
Rocky Mount Facility's requirements for coal. The contract price for coal
includes a base price which is modified based upon changes in a fuel and
transportation index that equals the fluctuation in rates payable by Virginia
Power for energy under the power sales agreement adjusted by 



                                       20
<PAGE>   21

fluctuations in pricing under CRM's rail transportation contract. CRM purchases
the lime required by the plant's pollution control equipment from APG Lime Corp.
under a five-year agreement expiring in December 2000.

         CSX transports the coal for the Rocky Mount Facility pursuant to a
23-year rail transportation contract (of which approximately 16 years remain)
with pricing indexed to parallel increases in rates under CSX's transportation
agreements with Virginia Power.

         Ash generated by the Rocky Mount Facility is managed by ReUse under an
ash removal agreement having a term expiring in 2013.

         The Rocky Mount Facility was originally financed pursuant to a
$113,946,966 project financing. In December 1993, CRM renegotiated this
financing and, in connection therewith, increased outstanding borrowings to
$129,650,000. In addition, CRM has a cash collateralized letter of credit in a
face amount equal to $3,150,000 issued in favor of NC Power in support of CRM's
obligations under the power sales agreement with NC Power.

         The Rocky Mount Facility generated $48.5 million in revenues in fiscal
1997, $47.5 million in revenues in fiscal 1996 and $45.3 million in revenues in
fiscal 1995.

         RINGGOLD FACILITY. The Company's Ringgold facility (the "Ringgold
Facility"), located in Ringgold, Pennsylvania, is a 15.5 megawatt gas-fired
cogeneration facility using an internal combustion engine fueled primarily by
natural gas. The Ringgold Facility is owned by Cogentrix of Pennsylvania, Inc.,
a Delaware corporation ("CPA"). The Ringgold Facility commenced commercial
operation in April 1991.

         Pennsylvania Electric Company ("Penelec") purchases energy from the
Ringgold Facility under a 20-year power sales agreement (of which approximately
13 and one-half years remain). Under the power sales agreement, failure of CPA
to generate and sell electricity throughout the term of the agreement (other
than due to force majeure) 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 which may be offset against
amounts payable by Penelec for energy.

         Thermal energy (in the form of hot water) from the Ringgold Facility is
provided to a 10-acre greenhouse owned by CPA which is leased to and operated by
Keystone Village Farms, Inc. ("Keystone"), a subsidiary of Agro Power
Development, Inc. (see "Greenhouse Operations" herein), under a lease with a 
ten-year term, which may be extended with the consent of the Company. Keystone
harvests tomatoes from the greenhouse which are then sold to wholesalers for
resale to grocery store chains.

         Natural gas for the facility is supplied pursuant to two gas supply
contracts. One of these contracts is with JC Enterprises ("JCE") under an
agreement pursuant to which CPA has agreed to purchase two-thirds of its
requirements for gas. The price for gas under the agreement with JCE is a fixed
price which escalates by a fixed percentage monthly. JCE is responsible for
delivering the gas to CPA's property from its gas wells located in close
proximity to the plant. The term of this contract is 15 years (of which
approximately eight and one-half years remain) or until a specified volume of
gas is purchased, whichever is earlier. CPA also purchases gas under a gas
purchase agreement with Eastern Marketing Corporation ("Eastern") pursuant to
which it has prepaid for the quantity of gas contracted for thereunder. Eastern
is responsible for transporting the gas to CPA's property. The term of the
Eastern contract is ten years (of which approximately five and one-half years
remain).

         The Ringgold Facility is financed pursuant to a $24,500,000 senior
credit facility and an $8,000,000 subordinated credit facility. Cogentrix has
granted a lien on the stock of CPA to the senior lenders. In April 1994,
Cogentrix Delaware Holdings, Inc. (a wholly owned subsidiary of Cogentrix
Energy, Inc.) purchased for $3,000,000 the entire $7.4 million outstanding
principal balance of the subordinated note and the related receivable
representing approximately $490,000 of accrued interest from the financial
institution holding the subordinated note.

         When this project was initially developed, CPA entered into a
consulting agreement which provided for certain payments to be made annually to
the original developer of the Ringgold Facility. In September 1994, the Company
purchased the developer's interest in the consulting agreement with CPA and
acquired all outstanding shares of junior preferred stock of CPA held by him.


                                       21
<PAGE>   22

         As a result primarily of higher than anticipated construction costs,
the failure and subsequent replacement of certain equipment and higher than
anticipated maintenance and operation expenses, the Ringgold Facility has failed
to produce sufficient revenue to cover the debt service requirements of the
subordinated credit facility and to cover completely the debt service
requirements of the senior credit facility. Since the date of commencement of
construction through June 30, 1997, the Company has made approximately $18.8
million in equity contributions to CPA in order to cover construction costs and
permit CPA to make required payments of principal and interest. The Company is
presently attempting to restructure certain of the project's agreements to
improve the project's financial results. Given the current restructuring
efforts, the Company intends to continue to provide funds to CPA, if necessary,
for debt service.

         The Ringgold Facility generated $8.4 million in revenues in fiscal
1997, $7.8 million in revenues in fiscal 1996 and $7.6 million in revenues in
fiscal 1995.

         RICHMOND FACILITY. Cogentrix of Richmond, Inc., a North Carolina
corporation ("CR"), owns and operates a 240 megawatt stoker coal-fired
cogeneration plant in Richmond, Virginia (the "Richmond Facility"). Commercial
operation of the Richmond Facility was commenced in two phases: Unit I in May
1992 and Unit II in August 1992.

         The Richmond Facility provides 209 megawatts of declared capacity
electricity to Virginia Power under two 25-year power sales agreements (of which
approximately 20 years remain) each of which may be extended for an additional
five-year term provided that two years prior to the end of the initial term the
parties agree to such extension. Annual changes in energy prices under the power
sales agreements are designed to offset annual fluctuations in coal and rail
transportation prices. Virginia Power has a right of first refusal to purchase
the Richmond Facility subject to the prior exercise of any such right by the
steam purchaser.

         Currently, Virginia Power is permitted full recovery from its customers
of payments made to CR under the power sales agreements. The power sales
agreements provide, however, that if an applicable legislative or regulatory
authority should take action which would have the effect of disallowing Virginia
Power from recovering from its customers all or a portion of the payments for
capacity in excess of a certain amount during the first 18 years following the
commencement of commercial operation of the facility, Virginia Power will
continue to pay for capacity at the contract price through the first 18 years
and may thereafter withhold up to 75% of the payments for capacity for the
following three years to the extent necessary to repay the disallowance to
Virginia Power with interest. In the event such withholdings do not fully repay
such disallowance, CR will repay the difference at the end of the 21st year.
Aggregate payments for capacity after the 18th anniversary of the commercial
operation date are not permitted to exceed the amount that Virginia Power is
allowed to recover from its customers.

         If the Richmond Facility has forced outage days in any year with
respect to 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, capacity
payments for such period will be reduced by four percent for each such excess
forced outage day. In addition to Virginia Power's right to dispatch or suspend
delivery of electricity from the Richmond Facility for maintenance and
emergencies, the facility is also subject to economic dispatch by Virginia
Power. This right allows Virginia Power to suspend or reduce purchases of energy
from the Richmond Facility if Virginia Power determines that it can operate its
system for a designated period more economically. The power sales agreements are
structured so that CR will continue to receive capacity payments during any
period of economic dispatch. Capacity payments constitute a substantial portion
of the profit component of the power sales agreement. Energy payments, which
would be reduced (or possibly eliminated) as a result of an economic dispatch,
primarily cover variable operating, maintenance, coal and rail transportation
costs associated with operating at different levels. In February 1994, the
Company received a notice from Virginia Power invoking a provision in the power
sales agreement relating to the Hopewell and Portsmouth Facilities which
requires the Company to negotiate in good faith to enter into a separate
agreement for the dispatch of all of the Company's cogeneration facilities
located in the Virginia Power service area. See "Description of the Company's
Facilities --Project Agreements" herein.

         In the event capacity testing indicates that the Richmond Facility's 
dependable capacity is less than 90% of the declared capacity, CR will be
obligated to pay annual liquidated damages to Virginia Power. Letters of credit
have been posted by CR in favor of Virginia Power to secure its obligations to
perform under the power sales agreements.

         The Richmond Facility provides steam to E. I. Du Pont de Nemours &
Company ("DuPont") for its Spruance plant located in Chesterfield County,
Virginia, under a long-term steam sales agreement. DuPont is obligated to
purchase and use a minimum of five percent of the Richmond Facility's total
energy output in a manner such that the Facility will remain a QF 



                                       22
<PAGE>   23

under PURPA. If CR is unable to operate the Richmond Facility to comply with the
steam sales agreement, DuPont has a qualified right to operate the facility.
DuPont also has the right to purchase the Richmond Facility upon the termination
of the steam sales agreement for a price equal to fair market value of the
facility at the time of exercise.

         Coal for the Richmond Facility is purchased under two separate coal
sales agreements. Under a 20-year agreement (of which approximately 15 years
remain), Electric Fuels Corporation ("Electric Fuels") provides coal mined in
Kentucky for Unit I of the Richmond Facility. Coastal provides the coal
requirements for Unit II from mines in Kentucky under a separate 15-year
agreement (of which approximately 10 years remain). The coal sales agreements
require the coal providers to sell and CR to purchase all of the requirements
for the respective unit of the Richmond Facility, subject to certain maximum and
minimum requirements. The contract price for coal includes a base price which is
modified based upon a fuel and transportation index that parallels the
fluctuation in rates payable by Virginia Power for energy under the power sales
agreement adjusted by fluctuations in pricing under CR's rail transportation
contracts. CSX transports the coal for both units of the Richmond Facility
pursuant to two separate rail transportation contracts each having a 20-year
term expiring in 2012.

         Ash generated by the Richmond Facility is managed by ReUse under an ash
removal agreement having a term expiring in 2008.

         The Richmond Facility is financed pursuant to a construction and term
loan credit facility, which includes (i) a letter of credit in an original face
amount equal to $196,825,000 issued to support commercial paper notes of CR
issued from time to time; (ii) letters of credit issued to support certain
revenue bonds issued by the Industrial Development Authority of the City of
Richmond, Virginia in an aggregate principal amount equal to $48,000,000; and
(iii) letters of credit in an original aggregate face amount equal to $5,700,000
issued in support of CR's obligations to Virginia Power under the power sales
agreements.

         CR purchased one of the power sales agreements relating to the Richmond
Facility from WV Hydro, Inc. ("WV"). In connection with such purchase and in
consideration of certain consulting arrangements, CR has continuing obligations
to make payments to Clover Development Company ("Clover"), an affiliate of WV,
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, CR is obligated to pay to Clover an amount ranging from 3 to
3.5 percent of the net proceeds payable to CR upon any sale, disposition or
refinancing of the Richmond Facility after payment of senior and subordinated
project financing debt and expenses.

         The Richmond Facility generated $79.5 million in revenues in fiscal
1997, $80.9 million in revenues in fiscal 1996 and $79.2 million in revenues in
fiscal 1995.

         BIRCHWOOD FACILITY. Birchwood Power Partners, L.P. ("Birchwood"), a
Delaware limited partnership, owns the Birchwood Facility, which is located in
King George, Virginia. Cogentrix/Birchwood Two, L.P., an indirect, wholly-owned
subsidiary of the Company, owns a 50% interest in Birchwood. An indirect,
wholly-owned subsidiary of The Southern Company owns the remaining 50% of
Birchwood. The Birchwood Facility commenced commercial operation in November
1996.

         The Birchwood Facility provides up to 202 megawatts of declared
capacity electricity to Virginia Power under a 25-year power sales agreement (of
which approximately 24 years remain) which may be extended for an additional
five-year term provided that two years prior to the end of the initial term the
parties agree to such extension. Annual changes in energy prices under the power
sales agreement are designed to offset annual fluctuations in coal and rail
transportation prices. Virginia Power has a right of first refusal to purchase
the Birchwood Facility. In addition, Virginia Power has an option to purchase
the Birchwood Facility at the end of the term of the power sales agreement.

         Currently, Virginia Power is permitted full recovery from its customers
of payments made to Birchwood under the power sales agreement. The power sales
agreement provides, however, that if an applicable legislative or regulatory
authority should take action which would have the effect of disallowing Virginia
Power from recovering from its customers all or a portion of the payments for
capacity in excess of a certain amount during the first 20 years following the
commencement of commercial operation of the facility, Virginia Power will
continue to pay for capacity at the contract price through the first 20 years
and may thereafter withhold up to 75% of the payments for capacity for the
following year to the extent necessary to repay the disallowance to Virginia
Power with interest. In the event such withholdings do not fully repay 


                                       23
<PAGE>   24

such disallowance, Birchwood will repay the difference at the end of the 21st
year. Aggregate payments for capacity after the 20th anniversary of the
commercial operation date are not permitted to exceed the amount that Virginia
Power is allowed to recover from its customers.

         If the Birchwood Facility is unable to operate within the dispatch
parameters established by Virginia Power under the power sales agreement, the
capacity payments for such period are subject to reduction. In addition to
Virginia Power's right to dispatch or suspend delivery of electricity from the
Birchwood Facility for maintenance and emergencies, the facility is also subject
to economic dispatch by Virginia Power. This right allows Virginia Power to
suspend or reduce purchases of energy from the Birchwood Facility if Virginia
Power determines that it can operate its system for a designated period more
economically. The power sales agreement is structured so that Birchwood will
continue to receive capacity payments during any period of economic dispatch.
Capacity payments constitute a substantial portion of the profit component of
the power sales agreement. Energy payments, which would be reduced (or possibly
eliminated) as a result of an economic dispatch, primarily cover variable
operating, maintenance, coal and rail transportation costs associated with
operating at different levels.

         In the event capacity testing indicates that the Birchwood Facility's 
dependable capacity is less than 90% of the declared capacity, Birchwood will
be obligated to pay annual liquidated damages to Virginia Power. A letter of
credit has been posted by Birchwood in favor of Virginia Power to secure its
obligations to perform under the power sales agreement.

         The 36-acre greenhouse located adjacent to the Facility, which is
jointly owned and operated by the partners of Birchwood, uses steam from the
Facility.

         Birchwood has a 25-year coal supply agreement for the requirements of
the Facility with Laurel Creek Co., Inc. ("Laurel"), Rockspring Development,
Inc. ("Rockspring"), Neweagle Industries, Inc. (as assignee of AgipCoal Holding
USA, Inc.) and Neweagle Coal Sales Corp. (as assignee of AgipCoal Sales USA,
Inc.) (collectively, "Neweagle"). Birchwood also has a back-up coal supply
letter agreement with Arch Mineral Corp. ("Arch") and two of its subsidiaries,
ACSC Coal Sales, Inc. ("ACSC") and Cumberland River Coal Company ("CRCC"),
whereby Arch guarantees that ACSC and CRCC will supply coal to the Facility in
the event of default by Neweagle under the coal supply agreement.

         ER&L Birchwood, Inc. ("ER&LB"), a subsidiary of Energy Resources and
Logistics, Inc. ("Energy Resources"), and an indirect subsidiary of CSX,
provides transportation of the coal from the coal seller's mines in West
Virginia to the Facility. ER&LB will use CSX's rail lines and equipment to meet
its obligations under the 25-year coal transportation agreement. CSX by separate
agreement assures full and complete performance of all of ER&LB's obligations
under the coal transportation agreement.

         The combined fuel and transportation cost under the coal supply
agreement and the coal transportation agreement is approximately equal to the
fuel compensation price that Birchwood receives under the power purchase
agreement. Furthermore, Neweagle and ER&LB have agreed to the same price
adjustment mechanism and redetermination formula included in the power purchase
agreement for the fuel compensation price. In effect, this passes the fuel and
transportation cost escalation risks from Birchwood through to the suppliers.

         JTM Industries, Inc. ("JTM") removes and disposes of the ash generated
by the Birchwood Facility under an ash removal contract that expires in 2021.
JTM will attempt to identify viable markets to maximize the quantity of ash
being used. JTM and Birchwood will develop a revenue sharing program in
connection with the marketing of the ash.

         The Birchwood Facility was financed pursuant to a debt facility which
includes a $155 million bank credit facility, a $135 million institutional debt
facility and $50 million of tax exempt debt. Cogentrix/Birchwood Two, L.P. has
pledged its ownership interests in Birchwood and the greenhouse located adjacent
to the Birchwood Facility as collateral security for the debt facility, however
Cogentrix Energy, Inc. is not liable for any deficiency if the proceeds of any
sale or disposition of the collateral are insufficient to pay the secured
obligations.


                                       24
<PAGE>   25

PRINCIPAL CUSTOMERS

         Electric utility customers accounting for more than ten percent of the
Company's revenue in each of the last three fiscal years were as follows:

<TABLE>
<CAPTION>
                                                                 FISCAL YEAR ENDED JUNE 30,
                                                          -----------------------------------------
                                                            1997           1996            1995
                                                          ----------     ----------     -----------

<S>                                                           <C>          <C>              <C>
              CP&L                                            25%          33%              34%
              Virginia Power (including NC Power)             62           55               57
</TABLE>

COMPETITION

         The demand for power in the United States traditionally has been met by
utilities constructing large-scale electric generating plants under
cost-of-service based regulation. The enactment of PURPA in 1978 spawned the
growth of the independent power industry which expanded rapidly in the 1980s.
The electric power industry is now in the midst of fundamental change, in terms
of both who the participants are and how they operate and are regulated. The
initial independent power producers to enter the market were an entrepreneurial
group of cogenerators and small power producers who recognized the business
opportunities offered by PURPA. This initial group of independent power
producers, which included the Company, was later joined by larger,
better-capitalized companies, such as subsidiaries of fuel supply companies,
utility affiliates, engineering companies, equipment manufacturers and
affiliates of other industrial companies. In addition, a number of regulated
utilities created subsidiaries which compete with the independent power
producers. Some independent power producers specialize in market niches, such as
a specific technology or fuel (e.g., gas-fired cogeneration, waste-to-energy,
hydroelectric, geothermal, wind, solar, wood, coal and conservation) or a
specific region of the country where they believe they have a market advantage.
The Company presently conducts its operations primarily in the southeastern
United States and has in the past concentrated primarily on standardized design
coal-fired facilities.

         Based on net ownership of total project megawatts in operation, the
Company is among the larger independent power producers in the United States.
Although the Company is an established leader in the independent power industry,
other independent power producers and utility affiliates, including, among
others, Enron Power Corp., Calpine Corporation, CalEnergy, The AES Corporation,
Edison Mission Energy and U.S. Generating Company, have significantly larger
capital resources available to them than the Company.

         Over the past decade, obtaining a power sales agreement with a utility
has become a progressively more difficult, expensive and competitive process.
The Company and its competitors now must put a significant amount of financial
resources at risk in order to develop a proposal or bid to a utility. Many
states and utilities now have policies that require or encourage power sales
agreements to be awarded by competitive bidding, which both increases the costs
and decreases the chances of obtaining such agreements.

         Amendments to the Public Utility Holding Company Act of 1935 ("PUHCA")
enacted in the Energy Policy Act of 1992 have increased the number of the
Company's competitors by reducing certain restrictions on the ownership of
projects which are not QFs under PURPA. On the other hand, the Energy Policy Act
has also made it simpler for developers to develop certain types of larger
generation projects without the necessity of locating a steam host or developing
a complex ownership structure to avoid PUHCA restrictions.

REGULATION

         The Company is subject to federal, state and local energy and
environmental laws and regulations applicable to the development, ownership and
operation of its United States plants. Federal laws and regulations govern
transactions with utilities, types of fuel utilized, the type of energy produced
and power plant ownership. State regulatory commissions must approve the rates
and, in some instances, other terms under which utilities purchase electricity
from independent producers. Under certain circumstances, such state commissions
may have broad jurisdiction over non-utility power plants. Power projects 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 



                                       25
<PAGE>   26

plant commences and that the facility operate in compliance therewith. The
Company strives to comply with all environmental laws, regulations, permits and
licenses but, despite such efforts, at times has been in non-compliance. No such
instance of non-compliance has resulted in significant fines or revocation of
any permit or license.

ENERGY REGULATIONS

QFs under PURPA.

         Each of the Company's current operating facilities is a QF. 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 power
generation 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 certain proportions to the facility's
total useful energy output. A QF utilizing oil or natural gas as fuel also must
meet certain energy efficiency standards. 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 PUHCA, most provisions of the Federal Power Act
(the "FPA") and, except under certain limited circumstances, state rate and
financial regulations. These exemptions are important to the Company and its
competitors.

         In the absence of a power sales agreement, FERC regulations 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 thereof from QFs, such 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.

         The Company endeavors to minimize the risk of its facilities losing
their QF status. The occurrence of events outside the Company's 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 such action would
be practicable or economic.

         If one of the Company's facilities were to lose its status as a QF, the
subsidiary would lose its exemptions from PUHCA and the FPA (and certain state
laws and regulations). This could subject the subsidiary to regulation under the
FPA and, in such event, would result in the Company inadvertently becoming a
public utility holding company. The Company's other facilities could in turn
lose their QF status. Moreover, loss of QF status could result in certain
utility customers terminating their power sales agreement with the nonqualifying
facility. If loss of QF status were threatened for a facility, the Company could
avoid holding company status (and thereby protect the QF status of its other
facilities) by applying to the FERC to obtain 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 in lieu of) QF status, an independent
power producer 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.
Birchwood, the owner of the Birchwood Facility, which is a QF, has also been 
determined to be an EWG. See "Facilities Under Development."


                                       26
<PAGE>   27

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 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 Commission and regulation under PUHCA,
unless eligible for an exemption. Under the 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 generation
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 and create some pressure on profit
margins. The Company believes that it is 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 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, the Company's 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.

State Regulation.

         PUCs regulate retail rates of electric utilities and in certain cases
power sales agreements from independent power producers. In addition, states
have been delegated the authority to determine utilities' avoided costs under
PURPA. PUCs often will pre-approve agreements with prices that do not exceed
avoided costs, because such contracts often have been acquired through a
competitive or market-based process. Recognizing the competitive nature of the
acquisition process, many PUCs will permit utilities to "pass through" expenses
associated with a power sales agreement with an independent power producer. In
addition, retail sales of electricity or steam by an independent power producer
may be subject to PUC regulation, depending on state law.

         EWGs are subject to broad regulation by PUCs, ranging from the
requirement of certificates of public convenience and necessity to regulation of
organizational, accounting, financial and other corporate matters. In addition,
states may assert jurisdiction over the siting and construction of EWGs (as well
as QFs), and over the issuance of securities and the sale or other transfer of
assets by these facilities. Many state utility commissions and state
legislatures are actively seeking ways to lower electric power costs at the
retail level, including options that would permit or compel competition at the
retail level. Federal legislation that would require states to permit retail
competition is also being given serious consideration. An opening of the retail
market would create tremendous opportunities for companies that have until now
been limited to the wholesale market. At the same time, state commissions are
pressuring the utilities they regulate to cut purchased power costs through
strict enforcement of existing contracts with QFs and EWGs, many of which are
considered to be overpriced. Because the Company is in compliance with its QF
contracts, it is not threatened by these pressures. State commissions are also
encouraging efforts by utilities to buy out or buy down such contracts.


                                       27
<PAGE>   28

Proposed Legislation.

         In addition to federal legislative initiatives, the state commissions
or state legislatures of many states (for example, California, Illinois,
Michigan, Massachusetts, and Pennsylvania) are considering, or have considered,
whether to open the retail electric power market to competition (so-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 (i.e., the delivery of electric power
to retail customers through its local distribution lines) from its transmission
and generation service.

         The competitive pricing 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 the Company with additional
opportunities to provide power from the Company's projects to industrial users
or power marketers. In addition, in light of the states' approaches to
"stranded investment" costs, the Company does not believe retail access programs
will have a material adverse effect on the Company's existing contracts.

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 Policy Act. Currently, none of the
Company's facilities requires the wheeling of electricity over power lines owned
by others. Except when market factors (such as an exceptional site or power
sales opportunity) warrant it, the Company generally attempts to site its
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 the Company.

         In April 1996, the FERC issued a rulemaking order under the FPA, 
Order 888, requiring all jurisdictional public utilities to file "open access"
transmission tariffs. Compliance with Order 888 has been virtually universal.
However, many utilities are seeking permission from the FERC to recover for
"stranded investment" through add-ons to their transmission rates. To the
extent that the FERC permits such charges, the cost of transmission may be too
high on some systems to be of practical use to wholesale sellers like the
Company. Therefore, the full value of Order 888 remains to be determined.

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

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 the Company 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 the Company's
facilities are not grandfathered, extensive modifications to project
technologies and facilities could be required.


                                       28
<PAGE>   29

         Although a number of major environmental statutes are scheduled for
reauthorization, the Company expects that environmental regulations will
continue to become more stringent as environmental regulations previously passed
become implemented. Accordingly, the Company plans to continue a strong emphasis
on implementation of environmental standards and procedures at its operating
plants to minimize the environmental impact of its energy generation.

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 Company's
facilities 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 ("SO2") "allowance." All non-exempt facilities over 25 megawatts that
emit SO2 (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
SO2. The 1990 Amendments exempt from the SO2 allowance provisions all
independent power projects which were operating, under construction or with
power sales agreements (or letters of intent therefor) as of November 15, 1990,
as well as facilities outside the contiguous 48 states. As a result, all of the
Company's current operating facilities are exempt. In the future, the facilities
the Company expects to develop will continue to rely on "clean (low sulfur)
coal," with flue gas desulfurization technology or natural gas technology. In
addition, under the 1990 Amendments, the Company will have the ability to
generate significant allowances from its existing facilities for use in future
projects, and, accordingly, the Company believes that the additional costs of
obtaining the number of allowances needed for future projects should not
materially affect the Company's ability to develop such projects. There has also
been an oversupply of allowances in the market resulting in a significant
decrease in allowance prices.

         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 the Company's plant operating costs.

         The 1990 Amendments also contain other provisions that could affect the
Company's 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 Company's projects should uniformly meet or exceed
RACT for all such 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 existing Company facilities were permitted under the Prevention of
Significant Deterioration New Source Review Process, the permitting impact to
the Company under the 1990 Amendments 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 the Company's 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 the Company's
facilities and other electric steam generating facilities, will remain 
uncertain.


                                       29
<PAGE>   30

         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 the Company's plants 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 NOx emission reductions that go beyond current federal
standards. These recommendations include reductions from utility and industrial
boilers. If more stringent NOx emission standards are adopted by the EPA and/or
certain states as a result of these recommendations, the Company could be
required to install additional NOx emission control technologies and/or obtain
allowances from other emitters.

         The Company does not believe that any of the potential additional
requirements discussed above will have a material adverse effect on the
operations or financial position of the Company.

         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 and enhancing administrative civil penalties and
adding a citizen suit provision. These enforcement provisions also include
enhanced monitoring, recordkeeping and reporting requirements for existing and
new facilities. On February 13, 1997, the EPA issued a regulation providing for
the use of "any credible evidence or information" in lieu of, or in addition to,
the test methods prescribed by regulation to determine the compliance status of
permitted sources of air pollution. This rule may effectively make emission
limits previously established for many air pollution sources, including the
Company's, more stringent. On March 10, 1997, a number of utilities filed a
petition for review of the EPA regulations in the U.S. Court of Appeals for the
District of Columbia Circuit.

Clean Water Act.

         The Company's existing 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 NPDES 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 Company's
facilities have either recently gone through permit renewal or will be renewed
within the next few years. Based upon recent renewals, the Company does not
anticipate more stringent monitoring requirements.

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 ("TRI") under Section 313 of the Emergency
Planning and Community Right-to-Know Act ("EPCRA") to include electric 
utilities. The Company's operating plants 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
power generation 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 foreign independent power
projects often conduct environmental impact assessments of proposed projects
pursuant to existing legislative requirements. Certain 



                                       30
<PAGE>   31

lenders to international development projects may impose their own requirements
relating to the protection of the environment.

         The Company believes that the level of environmental awareness and
enforcement is growing in most countries, including most of the countries in
which the Company intends 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, the Company
believes that the nature and level of environmental regulation that it is
subject to will become increasingly stringent, whether the Company undertakes
new projects in foreign countries or in the United States.

EMPLOYEES

         At June 30, 1997, the Company employed 405 people, approximately 307 of
whom are involved in facility operations. No employees are covered by a
collective bargaining agreement.

ITEM 2.  PROPERTIES

         In addition to the Company's properties listed under Item 1. "Business
-- Description of the Company's Facilities," the Company leases its principal
executive office, a single 61,024 square foot building, located at 9405
Arrowpoint Boulevard in Charlotte, North Carolina. The Company leases the
building and related land from a partnership comprised of four of the Company's
shareholders. 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 Transactions."

         The Company also leases office space in Prince George, Virginia;
Portland, Oregon; Singapore; Bangalore, India; Mangalore, India and New Delhi,
India, none of which leases or leased premises are material.

         The Company believes that its facilities and properties have been
satisfactorily maintained, are in good condition, and are suitable for the
Company's operations.

ITEM 3.  LEGAL PROCEEDINGS

         Under the amended terms of the power sales agreements for the
Elizabethtown, Lumberton, Kenansville, Roxboro and Southport Facilities, the
purchasing utility, CP&L, has exercised its right of economic dispatch resulting
in significantly reduced fuel requirements at each of these facilities. Coal is
supplied to the ELK Facilities by James River and its affiliate, Bell County
Coal Corporation. The coal sales agreement for the ELK Facilities provides that
the Company's subsidiary operating the ELK Facilities will purchase, and James
River will provide, all of such subsidiary's coal requirements through the end
of the contract term. In November 1996, James River and its affiliate instituted
an action against CECC claiming breach of contract and fraud in the inducement
based on the reduction in fuel requirements at the ELK Facilities as a
consequence of the recent amendments to the power sales agreements. James River
and its affiliate seek specific performance and, in the alternative, an
unspecified amount of damages. The lawsuit is pending in the United States
District Court for the Eastern District of Kentucky. The coal sales agreement
for the ELK Facilities contains an arbitration provision requiring disputes to
be submitted to arbitration in North Carolina, which CECC intends to seek to
enforce with respect to these claims.

         In October 1996, Coastal, the coal supplier to the Southport Facility
under a similar requirements contract, initiated an arbitration proceeding
against CNC through the American Arbitration Association in Charlotte, North
Carolina. The notice of arbitration alleges breach of contract based on the
reduction in fuel requirements at the Southport Facility as a consequence of the
recent amendment to the power sales agreement. The arbitration panel has been 
selected and the proceedings are scheduled for September 30 - October 3, 1997.

         Management believes that in some instances there is no basis for these
claims, and, as to the others, there are meritorious defenses. The Company
intends to defend the lawsuit and arbitration proceeding vigorously. The Company
has established reserves which management believes will be adequate to cover any
costs resulting from these matters. In the opinion of management, the ultimate
outcome of the litigation, or any arbitration proceeding relating to these
claims, will not have a material adverse effect on the Company's consolidated
results of operations or financial position.


                                       31
<PAGE>   32


         In addition, the Company experiences routine litigation in the normal
course of business. Management is of the opinion that none of this routine
litigation will have a material adverse effect on the consolidated financial
position or results of operations of the Company.

ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

         None.


                                       32
<PAGE>   33

                                     PART II

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

(a)      Market Information - There is no established market for the Company's
         common stock, which is closely held.

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

(c)      Dividends - In fiscal 1996, the Company's board of directors declared a
         dividend on its outstanding common stock of $4.8 million, which was
         paid in fiscal 1997. The Company's board of directors declared a
         dividend on its outstanding common stock of $5.0 million for the fiscal
         year ended June 30, 1997, which was paid in September 1997. 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 the
         Company's net income for the immediately preceding fiscal year. While
         the dividend declared in fiscal 1997 represents a departure from the
         board's policy due to non-recurring items, the board of directors
         intends to adhere to the policy in future years. In addition, under the
         terms of the Indenture of the Senior Notes and a revolving credit
         facility agreement, the Company's ability to pay dividends and make
         other distributions to its shareholders is restricted.


                                       33
<PAGE>   34

ITEM 6.  SELECTED CONSOLIDATED FINANCIAL DATA

         The following table sets forth certain selected consolidated financial
data as of and for the five years ended June 30, 1997, which should be read in
conjunction with the Company's 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 June 30, 1997 set forth
below has been derived from the consolidated financial statements of the
Company, which were audited by Arthur Andersen LLP, independent public
accountants.

<TABLE>
<CAPTION>
                                                                       FISCAL YEARS ENDED JUNE 30,
                                                     ----------------------------------------------------------------
                                                       1997          1996          1995          1994          1993
                                                    ---------     ---------     ---------     ---------     ---------
                                                                         (DOLLARS IN THOUSANDS)

<S>                                                 <C>           <C>           <C>           <C>           <C>      
STATEMENT OF OPERATIONS DATA:

  Operating revenue:
    Electric                                        $ 315,203     $ 356,459     $ 357,674     $ 351,892     $ 338,645
    Steam                                              26,686        27,703        23,320        22,254        22,637
    Other                                              10,343        22,522         2,992         1,939         1,037
                                                    ---------     ---------     ---------     ---------     ---------
      Total operating revenue                         352,232       406,684       383,986       376,085       362,319
                                                    ---------     ---------     ---------     ---------     ---------

  Operating expenses:
    Operating costs                                   204,446       245,582       235,006       239,225       236,568
    General, administrative and development            39,425        29,983        30,499        26,664        25,116
    Depreciation and amortization                      40,047        37,842        37,642        36,290        28,851
    Loss on impairment and cost of removal of
      cogeneration facilities                          65,628             0             0             0             0
                                                    ---------     ---------     ---------     ---------     ---------
      Total operating expenses                        349,546       313,407       303,147       302,179       290,535
                                                    ---------     ---------     ---------     ---------     ---------

  Operating income                                      2,686        93,277        80,839        73,906        71,784

  Other income (expense):
    Interest expense                                  (56,328)      (58,354)      (59,621)      (50,736)      (45,479)
    Investment and other income                        13,184         7,478         8,269         4,335         4,110
    Equity in net income (loss)
      of affiliates, net                                 (239)        2,104         9,812          (650)            0


  Minority interest in income of joint venture         (4,013)       (4,749)       (4,789)       (3,089)       (2,514)
                                                    ---------     ---------     ---------     ---------     ---------

  Income (loss) before income taxes,
    extraordinary gain (loss) and cumulative
    effect of change in accounting principle          (44,710)       39,756        34,510        23,766        27,901

  Benefit (provision) for income taxes                 17,112       (15,961)      (13,337)       (9,307)      (11,508)
                                                    ---------     ---------     ---------     ---------     ---------

  Income (loss) before extraordinary gain (loss)
    and cumulative effect of change in
    accounting principle                              (27,598)       23,795        21,173        14,459        16,393


  Extraordinary gain (loss) on early
    extinguishment of debt, net                          (703)            0             0         3,055             0


  Cumulative effect of change in method of
    accounting for income taxes                             0             0             0          (875)            0
                                                    ---------     ---------     ---------     ---------     ---------

  Net income (loss)                                 $ (28,301)    $  23,795     $  21,173     $  16,639     $  16,393
                                                    =========     =========     =========     =========     =========
</TABLE>



                                       34
<PAGE>   35

<TABLE>
<CAPTION>
                                                          As of June 30,
                                    --------------------------------------------------------
                                      1997        1996        1995        1994        1993
                                    --------    --------    --------    --------    --------
                                                          (Dollars in thousands)
<S>                                     <C>         <C>         <C>         <C>         <C>     
Balance Sheet Data:

  Total assets                      $859,828    $921,641    $930,733    $944,185    $868,369
                                    ========    ========    ========    ========    ========
  Project financing debt (1)        $591,694    $616,588    $661,891    $702,736    $723,435
                                    ========    ========    ========    ========    ========
  Parent debt (2)                   $100,000    $100,000    $100,000    $100,000    $ 32,037
                                    ========    ========    ========    ========    ========
      Total shareholders' equity    $ 49,709    $ 83,010    $ 63,618    $ 46,560    $ 33,725
                                    ========    ========    ========    ========    ========
</TABLE>



(1)      Project financing debt with respect to each of the Company's facilities
         is "substantially non-recourse" to Cogentrix Energy, Inc. and its other
         project subsidiaries. For a discussion of the term "substantially
         non-recourse," see "Business -- Description of the Company's Facilities
         -- Project Financing" herein.

(2)      Parent debt represents obligations of Cogentrix Energy, Inc. only and
         does not include non-recourse obligations of the Company's project
         subsidiaries.


                                       35
<PAGE>   36

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
        RESULTS OF OPERATIONS

         In addition to discussing and analyzing the Company's 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 the Company 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 Company's actual results to differ
materially from the forward-looking statements. See cautionary statements
appearing above, under "Item 1. Business" and elsewhere in this Form 10-K for a
discussion of the important factors affecting the realization of those results.

GENERAL

         The Company acquires, develops, owns and operates power generation
facilities and sells electricity and steam in the United States. The Company
owns or has interests in 11 power generation facilities having an aggregate
capacity of 1,120 megawatts. The Company's consolidated revenues are derived and
costs are incurred primarily from the generation and sale of electricity and, to
a lesser extent, from the production and sale of thermal energy (primarily
steam) and other commodities related to its cogeneration operations. Other
revenues and costs arise from fees earned and costs incurred in connection with
development activities, ash disposal and environmental consulting services. Each
of the Company's facilities relies on a power sales agreement with a single
customer for the majority of its revenues over the life of the power sales
agreement. During the fiscal year ended June 30, 1997, two regulated utilities,
CP&L and Virginia Power, accounted for approximately 87% of the Company's
consolidated revenues.

         Nine of the eleven cogeneration facilities in which the Company has 
an interest are wholly owned by the Company. The Company has only a 50%
ownership interest in the Hopewell and Birchwood Facilities. The Company's
consolidated financial statements include the accounts of the Hopewell Facility
over which the Company has effective control of the management through majority
representation on the board of directors of the managing general partner. The
"minority interest in income of joint venture" on the Company's consolidated
statements of operations reflects the interest of the Company's joint venture
partner in the income of the Hopewell Facility. The Company accounts for its 
investment in the Birchwood Facility, which is operated by a subsidiary of the
Company's joint venture partner, under the equity method.

         Effective in September 1996, the Company amended the power sales
agreements with CP&L on the Elizabethtown, Lumberton, Kenansville, Roxboro and
Southport Facilities. Under the amended terms, the power sales agreements are
dispatchable contracts which provide the utility the ability to suspend or
reduce purchases of energy from the facilities if CP&L determines it can operate
its system for a designated period more economically. In addition to providing
CP&L additional dispatch rights, the amendments eliminated the purchase options
which CP&L had on the Roxboro and Southport Facilities. The amended power sales
agreements are structured so that the Company continues to receive capacity
payments during any period of economic dispatch, which cover project debt
service, fixed operating costs and constitute a substantial portion of the
profit component of the power sales agreement. Energy payments, which are
reduced (or possibly eliminated) as a result of economic dispatch, primarily
cover variable operating and maintenance costs as well as coal and rail
transportation costs. The impact of the amendment to these power sales
agreements has been a significant reduction in the Company's electric revenues,
which has been offset by reduced fuel costs and operations and maintenance
expense at these facilities. In response to the reduction in fuel requirements
at these five facilities resulting from the exercise by CP&L of its economic
dispatch rights, certain of the Company's coal suppliers for these facilities
have instituted various legal proceedings against the Company seeking to recover
damages. See "Legal Proceedings" herein.

         In future years, the Company's revenues will or could be impacted by
one or more of the following events and uncertainties. First, the Company is
engaged in ongoing negotiations with Virginia Power regarding the restructuring
of the power sales agreements with respect to the Company's cogeneration
facilities located in that utility's service area. These negotiations could
result in amendments to the Company's power sales agreements for these
facilities granting Virginia Power additional dispatch rights for certain
facilities, which, if exercised, would lead to a reduction in the Company's
electric revenues from these facilities. Second, certain of the Company's power
sales agreements either terminate in years 2000 through 2002 or provide that
the rates for energy paid under such agreements after 2002 will be the rates
then specified in the applicable avoided cost schedule published by the
Virginia State Corporation Commission. The rates specified in the current
edition of the applicable avoided cost schedule are significantly lower than
the rates currently being paid by Virginia Power for energy 



                                       36
<PAGE>   37

under the contracts. And third, the Company is likely to develop future projects
with one or more partners as opposed to developing them on its own, in which
event the Company's ownership percentage will potentially be less than 51%. 
Any such jointly developed projects would likely be accounted for under the
equity method with the Company recognizing only equity in net income of the
project based on its ownership percentage. Many of these same events and
uncertainties, if they occur, will also result in a corresponding decrease in
the Company's operating expenses.

         Unusual weather conditions, reduced demand for steam by a facility's
steam host and the needs of each facility to perform routine or unanticipated
facility maintenance may have an effect on financial results. In addition, power
sales agreements at eight of the Company's facilities permit the utility
customer to significantly dispatch the related plant (i.e., direct the plant to
deliver a reduced amount of electrical output). However, even when dispatched,
such facilities' capacity payments, which are structured to cover fixed
operating costs and debt service and account for most of the profits of these
facilities, are not reduced.

         The activities of the Company are subject to stringent environmental
regulations by federal, state, local and (for future non-U.S. projects) foreign
governmental authorities. The Clean Air Act Amendments of 1990 require states to
impose permit fees on certain emissions, and Congress may consider proposals to
restrict or tax certain emissions, which proposals, if adopted, could impose
additional costs on the operation of the Company's facilities. There can be no
assurance that the Company's business and financial condition would not be
materially and adversely affected by the cost of compliance with future changes
in domestic or foreign environmental laws and regulations or additional
requirements for reduction or control of emissions imposed by regulatory
authorities in connection with renewals of required permits. The Company
maintains a comprehensive program to monitor its project subsidiaries'
compliance with all applicable environmental laws, regulations, permits and
licenses.

         In 1996, the Company began making investments in partnerships formed to
develop, construct and operate greenhouses to produce tomatoes. Two of these
partnerships are operating greenhouses with a combined total of 50 acres of
production capacity. Two additional partnerships in which the Company has
invested are constructing greenhouses, with a combined total of 57 acres of
production capacity. The Company has a 50% interest in each of these
partnerships and accounts for these investments under the equity method.

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 three fiscal years ended June 30, 1997.

<TABLE>
<CAPTION>
                                                               Fiscal Years Ended June 30,
                                     -----------------------------------------------------------------------------
                                              1997                          1996                       1995
                                     ---------------------       ---------------------       ---------------------
                                                                   (Dollars in thousands)
<S>                                  <C>              <C>        <C>              <C>        <C>              <C> 
Total operating revenues             $  352,232       100%       $  406,684       100%       $  383,986       100%
Operating costs                         204,446        58           245,582        61           235,006        61
General, administrative and
  development                            39,425        11            29,983         7            30,499         8
Depreciation and amortization            40,047        11            37,842         9            37,642        10
Impairment and cost of removal           65,628        19              --          --              --          --
                                     ----------       ---        ----------       ---        ----------       ---
Operating income                     $    2,686         1        $   93,277        23%       $   80,839        21%
                                     ==========       ===        ==========       ===        ==========       ===
Megawatt hours sold                   3,532,201                   5,175,922                   5,356,253         
                                     ==========                  ==========                  ==========       
</TABLE>

                                       37
<PAGE>   38


Fiscal 1997 as compared to Fiscal 1996

         Total operating revenues decreased 13.4% to $352.2 million for fiscal
1997 as compared to $406.7 million for fiscal 1996. This decrease was primarily
attributable to the significant decreases in electric revenues resulting from
economic dispatch of, and consequently reduced energy payments from, the
Elizabethtown, Lumberton, Kenansville, Roxboro and Southport Facilities. The
decrease in operating revenues is also attributable to the absence of revenue in
fiscal 1997 comparable to (i) the payment received in fiscal 1996 upon the
execution of a joint development agreement with CLP related to the development
of the Company's India project, (ii) the $5 million fee earned by the Company in
fiscal 1996 related to the pre-construction development phase of an electric
generation facility for Clark and (iii) the $7.5 million capacity buydown
payment received in fiscal 1996 from the utility purchasing the electrical
output of the Hopewell Facility. To a lesser extent, the decrease in operating
revenues was also attributable to a $1.5 million decrease in steam revenues at
the Hopewell, Kenansville and Richmond Facilities resulting from a decrease in
demand for steam by these facilities' steam hosts and a $2.7 million decrease in
electric revenue at the Richmond and Rocky Mount Facilities resulting from a
decrease in megawatt hours sold to the purchasing utility. These decreases in
operating revenues were partially offset by a $4.6 million increase in electric
revenues at the Hopewell and Portsmouth Facilities due to an increase in on-peak
megawatt hours provided to the purchasing utility, as well as
escalation/inflation adjustment provisions in certain power sales agreements.

         Operating costs decreased 16.8% to $204.4 million for fiscal 1997 as
compared to $245.6 million for fiscal 1996. This decrease resulted primarily
from the significant decrease in operating expenses at the Elizabethtown,
Lumberton, Kenansville, Roxboro and Southport Facilities resulting from their
economic dispatch by CP&L, as well as a decrease in fuel expense at the Richmond
and Rocky Mount Facilities associated with a decrease in megawatt hours sold.
The decrease in operating expense is also due to reductions in maintenance costs
at the Hopewell, Portsmouth and Southport Facilities, at which facilities the
Company performed routine maintenance during fiscal 1996. These decreases were
partially offset by an increase in maintenance costs at the Richmond Facility
associated with routine maintenance performed in fiscal 1997 and an increase in
operating costs incurred by ReUse related to third-party agreements and expense
associated with a payment due to a deceased officer's beneficiary in fiscal
1997.

         General, administrative and development expenses increased 31.5% to
$39.4 million for fiscal 1997 as compared to $29.9 million for fiscal 1996. The
increase is primarily the result of $10.7 million of payments made in connection
with restructuring or terminating incentive compensation arrangements for
certain employees, an increase in performance bonuses paid and severance
payments made to certain executive officers in fiscal 1997. These increases were
partially offset by a reduction in payments made under the profit-sharing plan,
due to a net loss before tax, a reduction in development expenses incurred on a
project the Company is developing in Idaho, as well as a general reduction in
consulting expenses related to development.

         During fiscal 1997, 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, recorded in fiscal 1997,
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 Company's analysis of the post-contract operating environment 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 statement of
operations for the year ended June 30, 1997. Also in connection with the overall
assessment of the post-contract operating environment for its cogeneration
facilities, the Company concluded that, effective January 1, 1997, the
Lumberton, Elizabethtown, Kenansville, Roxboro and Southport Facilities would be
depreciated over the remaining term of these facilities' 



                                       38
<PAGE>   39

power sales agreements. The 5.8% increase in depreciation and amortization
expense in fiscal 1997 as compared to fiscal 1996 relates primarily to this
change in the estimated useful lives of these facilities.

         The 3.5% decrease in interest expense is a result of the decrease in
the weighted average debt outstanding from $739 million in fiscal 1996 to $704
million in fiscal 1997. The decrease in weighted average debt outstanding, which
relates to scheduled maturities of the Company's project finance debt and the
repayment of the subordinated debt at the Elizabethtown, Lumberton and
Kenansville Facilities, was partially offset by an increase in project debt
outstanding at the Hopewell Facility and the Roxboro and Southport Facilities,
which related to refinancings completed during fiscal 1997.

         Investment income increased 76.3% to $13.2 million for fiscal 1997 as
compared to fiscal 1996. The increase in investment income is related to larger
cash and investment balances maintained by the Company during fiscal 1997 as
compared to fiscal 1996, the recognition of a net loss on the sale of marketable
securities of approximately $900,000 during fiscal 1996 and the $3.1 million
gain on the sale (discussed below) of an investment during fiscal 1997.

         In December 1996, the Company sold its investment in Bolivian Power
Company Limited ("Bolivian Power") to NRG Generating Holdings (No. 9), B.V., a
wholly owned subsidiary of NRG Energy, Inc. ("Holdings"), pursuant to a cash
tender offer which Holdings made for all the outstanding common stock of
Bolivian Power at a price of $43 per share. The Company recognized a $3.1
million gain on the sale of its investment in Bolivian Power, net of transaction
costs, which included payments made to certain unaffiliated individuals who
performed development activities for Bolivian Power.

         The equity in net loss of affiliates of $200,000 for fiscal 1997 as
compared to the equity in net income of affiliates of $2.1 million for fiscal
1996 is primarily attributable to the Company selling its investment in Bolivian
Power in December 1996. The Company recognized approximately $3.9 million in
equity in net income of affiliates in fiscal 1996 related to Bolivian Power,
which included the Company's share of a one-time gain recognized by Bolivian
Power on the sale of its distribution assets. This decrease in equity in net
income of affiliates was partially offset by earnings generated by the Company's
investment in a greenhouse facility in Texas, which commenced commercial
operation in late calendar 1996, earnings generated by the Company's investment
in the Birchwood Facility, which commenced commercial operations in November
1996, and 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 in minority interest in income of joint venture in fiscal
1997 as compared to fiscal 1996 related to the decrease in net income of the
Hopewell Facility. The decrease in net income of the Hopewell Facility in turn
resulted primarily from the absence of revenue in fiscal 1997 comparable to the
$7.5 million capacity buydown payment received in fiscal 1996 from the utility
purchasing the electrical output of the Hopewell Facility. This decrease was
partially offset by a reduction in maintenance costs incurred at the Hopewell
Facility in fiscal 1997 as compared to fiscal 1996.

         The benefit for income taxes for fiscal 1997 represents an effective
rate of 38.3% of loss before benefit for income taxes as compared to an
effective rate of 40.1% of income before income taxes for fiscal 1996. The
decrease in the effective rate in fiscal 1997 relates to the reduced recognition
of current year losses for state income tax purposes. A more complete discussion
of income taxes is included in Note 7 of Notes to Consolidated Financial
Statements.

         The extraordinary loss on early extinguishment of debt in fiscal 1997
relates 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.

Fiscal 1996 as compared to Fiscal 1995

         Total operating revenues increased $22.7 million (5.9%) in fiscal 1996
as compared to fiscal 1995. This increase in operating revenues was primarily
attributable to the $7.5 million payment received from the utility purchasing
the electrical output of the Hopewell Facility in connection with such utility's
buydown of the Hopewell Facility's declared capacity from 100 to 88.5 megawatts,
the $5 million fee earned by the Company related to the pre-construction
development phase of an electric generation facility for Clark and the payment
received by the Company upon the execution in July 1995 of the joint development
agreement with CLP related to the development of the Company's India project.
The increase in operating revenues for fiscal 1996 was also related to the
increase in megawatt hours sold by the Elizabethtown, Kenansville, Richmond and
Rocky Mount Facilities, the 168% increase in steam revenue at the Hopewell
Facility associated with an increase in steam demand by the industrial host and
the escalation/inflation adjustment provisions in certain power sales




                                       39
<PAGE>   40

agreements. The increase in revenues for fiscal 1996 was partially offset by a
$10.2 million decrease in electric revenues at the Hopewell Facility related to
the significant, unscheduled maintenance performed at the facility which
resulted in a decrease in megawatt hours delivered to the purchasing utility in
fiscal 1996.

         Operating costs for fiscal 1996 increased 4.5% to $245.6 million as
compared to $235 million in fiscal 1995. This increase relates primarily to a
significant increase in maintenance costs at the Hopewell Facility related to
the unscheduled boiler outages associated with replacing the tubing in all of
the facility's boilers. The increase in operating costs also relates to routine
turbine and boiler maintenance performed at the Rocky Mount and Richmond
Facilities. The increases in operating costs were partially offset by
significant decreases in fiscal 1996 in routine maintenance costs at the
Portsmouth, Lumberton and Kenansville Facilities, at which facilities the
Company performed routine turbine and boiler maintenance during fiscal 1995.

         General, administrative and development expenses decreased 1.7% to
$30.0 million in fiscal 1996 as compared to $30.5 million in fiscal 1995. The
decrease for fiscal 1996 relates primarily to a decrease in performance bonuses
paid in fiscal 1996, severance payments accrued in fiscal 1995 related to
certain former participants in the Company's incentive compensation plan and to
a buyout of an unrelated consultant in fiscal 1995 of a long term consulting
agreement under which the consultant provided services to the Ringgold Facility.
The decrease in general, administrative and development expenses for fiscal 1996
also relates to a general decrease in outside consulting expenses associated
with the Company's international development efforts, which is partially
attributable to the direct development expenses related to the India project
being shared equally with CLP commencing in July 1995. These decreases were
partially offset by an increase in the incentive compensation accrual for fiscal
1996 due to an increase in net income before taxes, expenses associated with the
Company's deferred compensation plan, which commenced in January 1995, and
development expenses incurred on the Rathdrum Project which commenced
development in December 1994.

         The 2.1% decrease in interest expense is a result of the decrease in
the weighted average debt outstanding from $782 million in fiscal 1995 to $739
million in fiscal 1996. The decrease in weighted average debt outstanding
relates primarily to regularly scheduled repayments of principal on the
Company's project finance debt. The decrease in interest expense was partially
offset by an increase in interest expense associated with an increase in the
weighted average interest rate from 7.62% in fiscal 1995 to 7.89% for fiscal
1996. This increase in the weighted average interest rate relates primarily to a
new interest rate swap agreement on the Portsmouth Facility project debt and an
increase in the interest rate floor on a certain interest rate hedge agreement
on the Richmond Facility project debt.

         Investment income decreased 9.6% to $7.5 million for fiscal 1996 as
compared to fiscal 1995. This decrease relates primarily to a net loss in the
sale of marketable securities of approximately $900,000 during fiscal 1996. This
decrease in investment income was partially offset by increases in investment
income associated with larger cash and investment balances maintained by the
Company during fiscal 1996 as compared to fiscal 1995.

         The decrease in equity in net income of affiliates is related to the
$10.7 million gain recognized during fiscal 1995 on the termination of the power
sales agreement between Consumers Power Company and Michigan Cogeneration
Partners Limited Partnership, a joint venture between the Company and Wolverine
Energy, Inc. This decrease in equity in net income of affiliates was partially
offset by an increase in the equity in net income of affiliates associated with
the equity in net income of the Company's investment in Bolivian Power, which
was acquired in November 1994. The Company recognized approximately $3.9 million
in equity in net income of affiliates during fiscal 1996 related to Bolivian
Power, $2.3 million of which was associated with the gain recognized by Bolivian
Power on the sale of its distribution subsidiaries.

         The minority interest in income of joint venture for fiscal 1996 was
similar to that recognized for the same period of fiscal 1995. However, during
fiscal 1996 the Hopewell Facility recognized a significant increase in operating
costs from the unscheduled outages associated with the boiler retubing
maintenance and from the related routine maintenance performed during these
outages. This significant increase in operating costs during fiscal 1996 was
offset by a decrease in fuel expense associated with the Hopewell Facility
operating at lower levels in fiscal 1996 and an increase in revenues associated
with the $7.5 million capacity buydown payment received from the utility
purchasing the electrical output of the Hopewell Facility in fiscal 1996.

         The provision for income taxes in fiscal 1996 represents an effective
rate of 40.1% of income before income taxes as compared to an effective rate of
38.6% of income before income taxes in fiscal 1995. This increase in the
effective tax rate relates to the reduced recognition of state net operating
loss carryforwards calculated under the apportionment method in 



                                       40
<PAGE>   41

fiscal 1996. A more complete discussion of income taxes is included in Note 7 of
Notes to Consolidated Financial Statements.

LIQUIDITY AND CAPITAL RESOURCES

         The principal components of operating cash flow for the fiscal year
ended June 30, 1997 were generated by a net loss of $28.3 million, increases due
to adjustments for depreciation and amortization of $40 million, loss on
impairment and cost of removal of cogeneration facilities of $65.6 million,
extraordinary loss on early extinguishment of debt of $1.2 million,
distributions from and equity in net loss of unconsolidated affiliates of $7.4
million and a net $16.5 million source of cash reflecting changes in other
working capital assets and liabilities, which were partially offset by deferred
taxes of $27.6 million, gain on the sale of the investment in Bolivian Power of
$3.1 million and minority interest in income of joint venture, net of dividends,
of $7.7 million. Cash flow provided by operating activities of $64 million, net
of proceeds from the sale of the investment in Bolivian Power of $25.4 million,
proceeds from project finance borrowings of $70.7 million, and $55 million of
cash escrows and restricted marketable securities released were primarily used
to purchase equipment of $3.0 million, to make investments in marketable
securities of $21.5 million, to make investments in affiliates of $58.2 million,
to repay project finance borrowings of $95.5 million, to pay deferred financing
costs of $2.9 million and to pay common stock dividends of $4.8 million.

         The principal components of cash flow provided by operating activities
for fiscal year ended June 30, 1996 were generated by net income of $23.8
million, increases due to adjustments for depreciation and amortization of $37.8
million, deferred income taxes of $8.6 million, minority interest in income of
joint venture of $3.4 million, net of dividends, loss on the sale of securities,
net of $0.9 million, and a net $5.5 million source of cash reflecting changes in
other working capital assets and liabilities which were partially offset by $1.5
million of equity in net income of affiliates net of dividends received from
unconsolidated affiliates. Cash flow provided by operating activities of $78.5
million and proceeds from project finance borrowings of $0.4 million were
primarily used to purchase property, plant and equipment of $1.6 million, to
purchase marketable securities of $12.5 million, to make investments in
affiliates of $6.5 million, to repay project finance borrowings of $46.6
million, to fund cash escrows of $7.5 million and to pay a dividend to common
shareholders of $4.2 million.

         Historically, the Company has 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 that project subsidiary. This type of financing is generally
referred to as "project financing." The project financing debt of the Company's
subsidiaries (aggregating $591.7 million as of June 30, 1997) is substantially
non-recourse to the Company and its other project subsidiaries, except in
connection with certain transactions where Cogentrix Energy, Inc. or Cogentrix
has agreed to certain limited guarantees and other obligations with respect to
such projects. These limited guarantees and other obligations include (i) an
agreement for the benefit of the Roxboro and Southport project lenders to fund
cash deficits the project may experience as a result of incurring certain costs,
subject to a cap of $11.3 million, (ii) guarantees to fund a reserve account in
connection with the financing of a project subsidiary in an aggregate amount of
up to approximately $4.0 million and (iii) guarantees of obligations and
liabilities of the Company's ReUse subsidiary limited in an aggregate amount of
up to $2.5 million. In addition, Cogentrix has guaranteed certain project
subsidiaries' obligations to the utility under power sales agreements and
obligations of up to $1.5 million of ReUse under an ash disposal agreement with
an unrelated third party. Because certain of these limited guarantees and other
obligations do not by their terms stipulate a maximum dollar amount of
liability, the aggregate amount of the Company's potential exposure under these
guarantees cannot be quantified. The aggregate contractual liability of the
Company to its subsidiaries' project lenders is, in each case, a small portion
of the aggregate project debt. If, however, the Company were required to satisfy
all these guarantees and other obligations or even one or more of the
significant ones, such event could have a material adverse impact on the
Company's financial condition.

         As of June 30, 1997, the Company had long-term debt (including the
current portion thereof) of approximately $691.7 million. With the exception of
the $100 million of Senior Notes issued in March, 1994, substantially all of
such indebtedness is project financing debt. Future annual maturities of
long-term debt range from $62.4 million to $90.4 million in the five-year period
ending June 30, 2002. The Company believes that its project subsidiaries 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, Inc. periodically in sufficient amounts to allow Cogentrix
Energy, Inc. to pay all required debt service on the Senior Notes, fund a
significant portion of its development activities and meet its other
obligations. If, as a result of 



                                       41
<PAGE>   42

unanticipated events, the Company's ability to generate cash from operating
activities is significantly impaired, the Company could be required to curtail
its development activities to meet its debt service obligations.

         On March 15, 1994, the Company issued $100 million of registered,
unsecured Senior Notes due 2004. The Senior Notes were priced at par to yield
8.10%. Of the net proceeds to the Company from the issuance of the Senior Notes,
$23.5 million was used in March 1994 to repay the outstanding balance due under
a corporate credit facility, $3 million was used in April 1994 to purchase the
subordinated note of CPA (project subsidiary operating the Ringgold Facility),
$18 million was used in November 1994 to purchase 17.1% of the common stock of
Bolivian Power, $29.5 million was used in December 1994 to purchase a 50%
interest in Birchwood, $4.6 was used in February 1996 to purchase a 50%
interest in a tomato greenhouse in Texas, and the balance was used to fund a
portion of the Company's equity investment in Birchwood.

         In May 1997, the Company entered into a credit agreement with Australia
and New Zealand Banking Group Limited, as Agent, which provides for a $50
million revolving credit facility ("Credit Facility") with a term of three years
("Revolving Term"). The Credit Facility provides for one-year extensions of the
Revolving Term, subject to lender consent. The Company can utilize the Credit
Facility in the form of direct advances or the issuance of unsecured letters of
credit. The outstanding balance of the Credit Facility at the end of the
Revolving Term is payable over two years in four equal semiannual repayments of
direct advances or collateralization of letters of credit. As of June 30, 1997,
the Company had no advances or letters of credit outstanding under the Credit
Facility.

         Any projects the Company develops in the future, and those independent
power projects it may seek to acquire, are likely to require substantial capital
investment. The Company's ability to arrange financing on a substantially
non-recourse basis and the cost of such capital are dependent on numerous
factors. In order to access capital on a substantially non-recourse basis in the
future, the Company may have to make larger equity investments in, or provide
more financial support for, the project entity.

         The ability of the Company's project subsidiaries to pay dividends and
management fees periodically to Cogentrix Energy, Inc. 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. There
are also additional limitations that are adapted to the particular
characteristics of each project subsidiary. See "Business -- Description of the
Company's Facilities," and " -- Facilities in Operation" herein.

         In December 1994, the Company acquired a 50% interest in Birchwood, a 
partnership formed to 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 purchase price of the
50% interest in Birchwood Power was approximately $29.5 million and was funded
with a portion of the net proceeds of the Company's Senior Note offering. The
Company also provided an equity contribution to Birchwood Power of
approximately $43.7 million in March 1997, which was funded with the remaining
proceeds of the Company's Senior Note offering and corporate cash balances.
Birchwood, which commenced commercial operations in November 1996, sells
electricity to Virginia Power and provides thermal energy to a 36-acre
greenhouse under long-term contracts.

         In December 1994, the Company executed an engineering, procurement and
construction agreement (the "Construction Agreement") with Clark. Under this
Construction Agreement, the Company is currently engineering, procuring
equipment for and constructing a 248 megawatt combined-cycle, gas-fired electric
generation facility (the "Clark Facility"). In October 1995, the Company
delivered to Clark a $20 million letter of credit, provided by a bank, which is
collateralized by a pledge of marketable securities. This letter of credit will
support the Company's contingent obligations under certain performance
guarantees and late construction completion payments under the Construction
Agreement. The Company is also obligated to pay 50% of costs and expenses, if
any, incurred in constructing the facility in excess of the contract amount.
Pursuant to the Construction Agreement, the contract amount of $117 million may
be adjusted as a result of a force majeure event, scope change, certain delays
in schedule or change in law. The Company will earn a construction fee of $5
million upon completion of the Clark Facility. The Company will also share in
50% of the amount, if any, equal to the excess of the contract amount over the
costs and expenses in constructing the Clark Facility. Cogentrix of Vancouver,
Inc. ("CVC"), an indirect wholly-owned subsidiary of Cogentrix Energy, Inc.,
performed the development and preliminary engineering of the Clark Facility and
received a development fee of $5 million in October 1995. The Company
anticipates that construction on the Clark Facility will be completed in late
calendar 1997. Upon commencing commercial operations, CVC will operate and
maintain the Clark Facility pursuant to a two-year operations and maintenance
agreement.


                                       42
<PAGE>   43

         In July 1995, the Company executed a joint development agreement with a
subsidiary of CLP (the "Joint Venture") which provides for the Company and CLP
to co-develop a 1,000 megawatt coal-fired facility in India and to share equally
in the direct development expenses related to the project. Additionally, the
Company expects to secure one or more other partners for the purpose of making 
equity investments in the project. The Company currently anticipates requiring
funds, in addition to amounts payable by CLP to the Company at financial
closing of the project, in an amount ranging from $60 to $65 million for the
purpose of making its equity investment in the India project. The Company
expects to fund this equity commitment from corporate cash balances.

         In July 1996, the Company renegotiated the project financing
arrangements for its Hopewell Facility, in which it owns a 50% interest. The
amended agreements resulted in a $13 million increase in the amount of
indebtedness of JRCC outstanding and extended the final maturity date of the
loan by 21 months. JRCC transferred substantially all of the additional funds
borrowed (net of transaction costs) to its partners. The distribution received
by Cogentrix Energy, Inc. related to the refinancing was approximately $6.1
million which will be used by the Company for general corporate purposes.

         In September 1996, the Company renegotiated the project financing
arrangements for its Roxboro and Southport Facilities. The amended agreements
resulted in an approximate $18.4 million increase in the amount of indebtedness
outstanding and extended the final maturity date of the loan by 7 months. The
Company's project subsidiary operating the Roxboro and Southport Facilities
transferred substantially all of the additional funds borrowed (net of
transaction costs) to Cogentrix Energy, Inc., which utilized $5.5 million to
make a capital contribution to the project subsidiary operating the ELK
Facilities in connection with the refinancing of its project debt in September
1996. The remainder of the proceeds will be used by the Company for general
corporate purposes.

         In December 1996, the Company sold its investment in Bolivian Power
pursuant to a cash tender offer received for all of the outstanding common stock
of Bolivian Power at a price of $43 per share. The Company received proceeds of
$25.4 million from the sale of its investment in Bolivian Power, net of
transaction costs, which included payments made to certain unaffiliated
individuals who performed development activities for Bolivian Power. See
"Results of Operations" for the financial reporting impact of the sale of the
investment in Bolivian Power.

         In September 1997, the Company's board of directors declared a $5.0
million dividend for the fiscal year ended June 30, 1997 payable to the common
shareholders of the Company, which was paid in September 1997. 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 the Company's net
income for the immediately preceding fiscal year. While the dividend declared
for fiscal 1997 represents a departure from the policy due to non-recurring
items, the board of directors intends to adhere to the policy in future years.
Under the terms of the Indenture for the Senior Notes and the Credit Facility,
the Company's ability to pay dividends and make other distributions to the
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
economic conditions generally and tend to fluctuate significantly. Through
various hedging mechanisms, the Company has 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 the Company's
project subsidiaries receive from the utility purchasing the electricity
generated by the facility.

         Under the power sales agreements for two of the Company's facilities, 
energy payments are indexed, subject to certain caps, to reflect the purchasing
utility's solid fuel cost of producing electricity. The Company's other power
sales agreements 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 the
Company. 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, the Company has substantially hedged 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. As of June
30, 1997, approximately 



                                       43
<PAGE>   44

87.6% of the Company's project financing debt was hedged, with 30.4% being
hedged with interest rate caps which were above the prevailing market rate at
June 30, 1997 and therefore subject to interest rate volatility.

         Although hedged to a significant extent, the Company's 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 the Company is dependent, in part, on each counterparty's ability
to perform in accordance with the provisions of the relevant contracts. The
Company has sought to reduce the risk by entering into contracts with
creditworthy organizations.

CHANGE OF CORPORATE FISCAL YEAR

         On September 18, 1997, the Company's board of directors authorized
management to take the necessary actions and secure the required approvals to
change the fiscal year end of the Company from June 30 to December 31, effective
December 31, 1997. Management believes it is preferable for the Company to
report on a calendar year basis for reasons including, but not limited to, the
following: (1) the majority of corporations (the Company's peer group) in the
independent power industry report on a calendar year basis, (2) the majority of
the Company's joint ventures formed with third parties report on a calendar 
year basis, and (3) a calendar year reporting period more closely approximates
the Company's business cycle under its long-term contracts.


                                       44
<PAGE>   45

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA



                                      INDEX


                                                                          Page
                                                                          ----

Reports of Independent Public Accountants                                  46

Consolidated Financial Statements:

         Consolidated Balance Sheets at June 30, 1997 and 1996             48

         Consolidated Statements of Operations For the Years Ended
             June 30, 1997, 1996 and 1995                                  49

         Consolidated Statements of Changes in Shareholders' Equity
             For the Years Ended June 30, 1997, 1996 and 1995              50

         Consolidated Statements of Cash Flows
           For the Years Ended June 30, 1997, 1996 and 1995                51

Notes to Consolidated Financial Statements                                 52

Financial Statement Schedules:

         Schedule I - Condensed Financial Information of the Registrant    65




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.


                                       45
<PAGE>   46


                    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 June 30, 1997 and 1996, and the related consolidated statements of
operations, changes in shareholders' equity and cash flows for each of the three
years in the period ended June 30, 1997. 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 4 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 4, 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 June 30, 1997 and 1996, and the results of their operations and
their cash flows for each of the three years in the period ended June 30, 1997,
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,
         September 12, 1997


                                       46
<PAGE>   47

                    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 shareholders' equity and of cash flows for each of the
three years in the period ended December 31, 1996. 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.

                                         PRICE WATERHOUSE
                                         Moreno, Munoz y
                                         Cia.



                                         La Paz, Bolivia
                                         February 28, 1997



                                       47
<PAGE>   48


                 COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES

                           CONSOLIDATED BALANCE SHEETS

                             JUNE 30, 1997 AND 1996
                             (DOLLARS IN THOUSANDS)

<TABLE>
<CAPTION>
                                                                         1997             1996
                                                                       --------         --------

                                     ASSETS

<S>                                                                    <C>              <C>     
CURRENT ASSETS:
  Cash and cash equivalents                                            $ 62,596         $ 33,351
  Restricted cash                                                        30,888           42,203
  Marketable securities                                                  21,494                0
  Restricted investments                                                 20,000                0
  Accounts receivable                                                    57,880           57,331
  Inventories                                                            15,723           19,086
  Other current assets                                                    5,779            2,883
                                                                       --------         --------

    Total current assets                                                214,360          154,854

PROPERTY, PLANT AND EQUIPMENT,
  Net of accumulated depreciation:  1997, $169,761; 1996, $156,215      514,449          604,491

LAND AND IMPROVEMENTS                                                     2,540            2,424

DEFERRED FINANCING, START-UP AND ORGANIZATION COSTS,
    Net of accumulated amortization:  1997, $16,373; 1996, $19,653       22,601           25,105

RESTRICTED INVESTMENTS                                                        0           63,695

NATURAL GAS RESERVES                                                      2,829            3,611

INVESTMENTS IN AFFILIATES                                                84,599           56,028

OTHER ASSETS                                                             18,450           11,433
                                                                       --------         --------

                                                                       $859,828         $921,641
                                                                       ========         ========

                      LIABILITIES AND SHAREHOLDERS' EQUITY

CURRENT LIABILITIES:
  Current portion of long-term debt                                    $ 62,370         $ 48,416
  Accounts payable                                                       22,147           21,453
  Accrued compensation                                                   12,290            4,393
  Accrued interest payable                                                3,308            4,063
  Accrued dividends payable                                               5,000            4,759
  Other accrued liabilities                                              13,040            8,816
                                                                       --------         --------

    Total current liabilities                                           118,155           91,900

LONG-TERM DEBT                                                          631,624          670,900

DEFERRED INCOME TAXES                                                    23,074           46,971

MINORITY INTEREST IN JOINT VENTURE                                       14,354           22,044

OTHER LONG-TERM LIABILITIES                                              22,912            6,816
                                                                       --------         --------

                                                                        810,119          838,631
                                                                       --------         --------

COMMITMENTS AND CONTINGENCIES (NOTES 8 AND 10)
SHAREHOLDERS' EQUITY:
  Common stock, no par value, 300,000 shares authorized;
    282,000 shares issued and outstanding                                   130              130
  Accumulated earnings                                                   49,579           82,880
                                                                       --------         --------
                                                                         49,709           83,010
                                                                       --------         --------
                                                                       $859,828         $921,641
                                                                       ========         ========
</TABLE>

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


                                       48
<PAGE>   49

                 COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES
                      CONSOLIDATED STATEMENTS OF OPERATIONS

                     FOR THE YEARS ENDED JUNE 30, 1997, 1996
                   AND 1995 (DOLLARS IN THOUSANDS, EXCEPT FOR
                        EARNINGS (LOSS) PER COMMON SHARE)


<TABLE>
<CAPTION>
                                                                                   1997               1996               1995
                                                                                 ---------          ---------          ---------

<S>                                                                              <C>                <C>                <C>      
OPERATING REVENUE:
  Electric                                                                       $ 315,203          $ 356,459          $ 357,674
  Steam                                                                             26,686             27,703             23,320
  Other                                                                             10,343             22,522              2,992
                                                                                 ---------          ---------          ---------
                                                                                   352,232            406,684            383,986
                                                                                 ---------          ---------          ---------

OPERATING EXPENSES:
  Fuel expense                                                                     131,405            171,310            168,184
  Operations and maintenance                                                        73,041             74,272             66,822
  General, administrative and development expenses                                  39,425             29,983             30,499
  Depreciation and amortization                                                     40,047             37,842             37,642
  Loss on impairment and cost of removal of cogeneration facilities                 65,628                  0                  0
                                                                                 ---------          ---------          ---------
                                                                                   349,546            313,407            303,147
                                                                                 ---------          ---------          ---------

OPERATING INCOME                                                                     2,686             93,277             80,839

OTHER INCOME (EXPENSE):
  Interest expense                                                                 (56,328)           (58,354)           (59,621)
  Investment and other income                                                       13,184              7,478              8,269
  Equity in net income (loss) of affiliates, net                                      (239)             2,104              9,812
                                                                                 ---------          ---------          ---------

INCOME (LOSS) BEFORE MINORITY INTEREST IN INCOME OF
  JOINT VENTURE, INCOME TAXES AND EXTRAORDINARY LOSS                               (40,697)            44,505             39,299

MINORITY INTEREST IN INCOME OF JOINT VENTURE                                        (4,013)            (4,749)            (4,789)
                                                                                 ---------          ---------          ---------

INCOME (LOSS) BEFORE INCOME TAXES AND EXTRAORDINARY LOSS                           (44,710)            39,756             34,510

BENEFIT (PROVISION) FOR INCOME TAXES                                                17,112            (15,961)           (13,337)
                                                                                 ---------          ---------          ---------

INCOME (LOSS) BEFORE EXTRAORDINARY LOSS                                            (27,598)            23,795             21,173

EXTRAORDINARY LOSS ON EARLY EXTINGUISHMENT OF DEBT,
  NET OF INCOME TAX BENEFIT OF $470                                                   (703)                 0                  0
                                                                                 ---------          ---------          ---------

NET INCOME (LOSS)                                                                ($ 28,301)         $  23,795          $  21,173
                                                                                 =========          =========          =========

EARNINGS (LOSS) PER COMMON SHARE:
  Income (loss) before extraordinary loss                                        ($  97.87)         $   84.38          $   75.08
  Extraordinary loss                                                                 (2.49)              0.00               0.00
                                                                                 ---------          ---------          ---------
                                                                                 ($ 100.36)         $   84.38          $   75.08
                                                                                 =========          =========          =========
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.



                                       49
<PAGE>   50

                 COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES

           CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY

                FOR THE YEARS ENDED JUNE 30, 1997, 1996 AND 1995
          (DOLLARS IN THOUSANDS, EXCEPT FOR DIVIDENDS PER COMMON SHARE)




<TABLE>
<CAPTION>
                                                       NET UNREALIZED
                                                          LOSS ON
                                          COMMON       AVAILABLE FOR       ACCUMULATED
                                           STOCK       SALE SECURITIES       EARNINGS                TOTAL
                                           -----       ---------------       --------                -----

<S>                                         <C>             <C>               <C>                  <C>     
Balance, June 30, 1994                      $130            ($476)            $ 46,906             $ 46,560

Net unrealized loss on available
    for sale securities, net of
    deferred income tax benefit
    of $34                                     0              120                    0                  120

Net income                                     0                0               21,173               21,173

Common stock dividends
    ($15.01 per common share)                  0                0               (4,235)              (4,235)
                                            ----            -----             --------             --------

Balance, June 30, 1995                       130             (356)              63,844               63,618

Net unrealized gain on available
    for sale securities, net of
    deferred income tax
    provision of $256                          0              356                    0                  356

Net income                                     0                0               23,795               23,795

Common stock dividends
    ($16.88 per common share)                  0                0               (4,759)              (4,759)
                                            ----            -----             --------             --------

Balance, June 30, 1996                       130                0               82,880               83,010

Net loss                                       0                0              (28,301)             (28,301)

Common stock dividends
    ($17.73 per common share)                  0                0               (5,000)              (5,000)
                                            ----            -----             --------             --------

Balance, June 30, 1997                      $130            $   0             $ 49,579             $ 49,709
                                            ====            =====             ========             ========
</TABLE>




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


                                       50
<PAGE>   51

                 COGENTRIX ENERGY, INC. AND SUBSIDIARY COMPANIES
                      CONSOLIDATED STATEMENTS OF CASH FLOWS
                FOR THE YEARS ENDED JUNE 30, 1997, 1996 AND 1995
                             (DOLLARS IN THOUSANDS)



<TABLE>
<CAPTION>
                                                                                   1997                 1996                 1995
                                                                                 --------             --------             --------
<S>                                                                              <C>                  <C>                  <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
  Net income (loss)                                                              ($28,301)            $ 23,795             $ 21,173
  Adjustments to reconcile net income (loss) to net cash
    provided by operating activities:
    Depreciation and amortization                                                  40,047               37,842               37,642
    Loss on impairment and cost of removal of cogeneration facilities              65,628                    0                    0
    Deferred income taxes                                                         (27,585)               8,569                7,718
    Extraordinary loss on early extinguishment of debt                              1,173                    0                    0
    Minority interest in income of joint venture, net of dividends                 (7,690)               3,407                3,680
    Gain on sale of investment in Bolivian Power                                   (3,137)                   0                    0
    Equity in net (income) loss of unconsolidated affiliates                          239               (2,104)             (11,057)
    Dividends received from unconsolidated affiliates                               7,152                  617               14,853
    Loss on sale of securities, net                                                     0                  890                    0
    Increase in accounts receivable                                                  (549)                (795)              (1,313)
    Decrease in inventories                                                         4,145                  667                  317
    Increase (decrease) in accounts payable                                           (61)               1,628               (2,708)
    Increase in accrued liabilities                                                12,121                3,809                  585
    Decrease in other                                                                 866                  141                  564
                                                                                 --------             --------             --------
  Net cash flows provided by operating activities                                  64,048               78,466               71,454
                                                                                 --------             --------             --------

 CASH FLOWS FROM INVESTING ACTIVITIES:
    Property, plant and equipment additions                                        (2,956)              (1,555)              (8,171)
    Decrease (increase) in marketable securities                                   22,201              (12,456)               1,506
    Investments in affiliates                                                     (58,222)              (6,516)             (48,323)
    Proceeds from sale of investment in Bolivian Power, net                        25,398                    0                    0
    Decrease (increase) in restricted cash                                         11,315               (8,190)              (4,157)
                                                                                 --------             --------             --------
  Net cash flows used in investing activities                                      (2,264)             (28,717)             (59,145)
                                                                                 --------             --------             --------

CASH FLOWS FROM FINANCING ACTIVITIES:
    Proceeds of notes payable and long-term debt                                   70,661                  406                1,622
    Repayments of notes payable and long-term debt                                (95,552)             (46,642)             (42,513)
    Increase in deferred financing costs                                           (2,889)                   0                  (93)
    Common stock dividends paid                                                    (4,759)              (4,235)              (3,328)
                                                                                 --------             --------             --------
  Net cash flows used in financing activities                                     (32,539)             (50,471)             (44,312)
                                                                                 --------             --------             --------

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS                               29,245                 (722)             (32,003)
CASH AND CASH EQUIVALENTS, beginning of year                                       33,351               34,073               66,076
                                                                                 --------             --------             --------
CASH AND CASH EQUIVALENTS, end of year                                           $ 62,596             $ 33,351             $ 34,073
                                                                                 ========             ========             ========

SUPPLEMENTAL CASH FLOW INFORMATION:
    Interest paid                                                                $ 54,458             $ 58,253             $ 58,952
                                                                                 ========             ========             ========
    Income taxes paid                                                            $  8,271             $  7,023             $  4,664
                                                                                 ========             ========             ========
</TABLE>




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




                                       51



<PAGE>   52



                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 June 30, 1997, the Company
owned or had interests in eleven Facilities in the United States with an
aggregate installed capacity of approximately 1,120 megawatts. Two of the eleven
Facilities are owned 50% by the Company and 50% by other independent power
producers. 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., its subsidiary companies and 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. Investments in other affiliates in
which the Company has a 20% to 50% interest and/or the ability to exercise
significant influence over operating and financial policies are accounted for on
the equity method. All material intercompany transactions and balances among
Cogentrix Energy, Inc. and its subsidiary companies and its consolidated joint
venture 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 is engineering,
procuring equipment for and constructing a 248 megawatt combined-cycle,
gas-fired electric generation facility (the "Clark Facility"). The Company is
accounting for the construction under the completed-contract method, and, as
such, all third-party construction costs and reimbursements are deferred until
the contract is completed. Costs incurred as of June 30, 1997 and 1996 of
$104,960,000 and $37,117,000, respectively, are netted against the related
reimbursed costs of $99,552,000 and $35,572,000, respectively, and the
difference is included in accounts receivable on the accompanying consolidated
balance sheets.

         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 June
30, 1997 and 1996, fuel and spare parts inventories are comprised of the
following (dollars in thousands):



                                       52
<PAGE>   53




<TABLE>
<CAPTION>
                                  1997            1996
                                -------         -------

<S>                             <C>             <C>    
            Coal                $ 8,274         $11,951
            Natural gas             700             700
            Spare parts           6,749           6,435
                                -------         -------
                                $15,723         $19,086
                                =======         =======
</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 $900,000, $1,458,000 and $1,162,000 less than the cost of these
inventories on a FIFO basis as of June 30, 1997, 1996 and 1995, 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.

         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.

         Deferred Financing, Start-up and Organization Costs -- Financing costs,
consisting primarily of legal and other direct costs incurred to obtain
financing for the Facilities, are deferred and amortized over the permanent
financing term. Start-up and organization costs include payroll costs and fees
paid to consultants, technicians and vendors associated with the formation of
each entity and the start-up of the Facilities. All start-up costs were fully
amortized as of June 30, 1997.

         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 62% and 25% of revenues in 1997, 55% and 33% of revenues in 1996
and 57% and 34% of revenues in 1995.

         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 variable-rate, 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 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.





                                       53
<PAGE>   54

         Reclassifications -- Certain amounts included in the accompanying
consolidated financial statements for fiscal year 1996 have been reclassified
from their original presentation to conform with the current year's
presentation.

3.  INVESTMENT IN DEBT SECURITIES

         At June 30, 1997, investments in debt securities included in restricted
cash and marketable securities in the accompanying balance sheet consisted of
government securities and corporate obligations. These securities are recorded
at their fair market value which approximates cost. Restricted investments
consist of an investment in a certificate of deposit which collateralizes the
Company's obligation under a letter of credit (Note 10).

         At June 30, 1996, there were no debt securities held in restricted cash
or marketable securities. Restricted investments consisted of investments in
certificates of deposit which collateralized the Company's obligations under
certain letters of credit.

         At June 30, 1995, the Company's net unrealized loss of $834,000 on its
investment in debt securities is reported in the accompanying consolidated
statement of changes in shareholders' equity, net of $222,000 allocated to
minority interest in joint venture and net of $256,000 in deferred income taxes.

4.  INVESTMENT IN POWER PROJECTS

Michigan Cogeneration Partners

         In partnership with Wolverine Energy, Inc., an indirect subsidiary of
Northern States Power Company, a Minnesota-based investor-owned electric
utility, the Company pursued the development of a 65 megawatt cogeneration power
facility in Michigan. Development of this project began in September 1993 when
the Company and its joint venture partner (the "Michigan Partnership") purchased
from another developer a power sales agreement with Consumers Power Company
providing for the sale of up to 65 megawatts of electric power. In July 1994,
the Michigan Partnership joined with Consumers Power Company to terminate the
power sales agreement pursuant to terms under which the Partnership received
$29.9 million. The Company, which owned a 50% interest in the Michigan
Partnership, recognized its share of the Michigan Partnership's net income of
$22.9 million for the year ended June 30, 1995, which was comprised solely of
the proceeds received from this transaction net of project development costs.
The Company recorded the $10.2 million gain from this transaction, which
consisted of the Company's share of the net income of the Michigan Partnership
net of corporate incentive compensation costs related to the transaction, as
equity in net income of affiliates in the accompanying consolidated statement of
operations for the year ended June 30, 1995. The Michigan Partnership was
dissolved in June 1996.

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 $25.4 million,
net of transaction costs, which included payments to certain unaffiliated
individuals who performed development activities for Bolivian Power. The
resulting book gain of $3.1 million is included in investment and other income
in the accompanying consolidated statement of operations for the year ended June
30, 1997. The Company recognized approximately $0.4 million, $3.9 million and
$1.1 million in equity in net income of affiliates in the accompanying
consolidated statements of operations for the years ended June 30, 1997, 1996
and 1995, respectively, related to its investment in Bolivian Power. The



                                       54
<PAGE>   55



following table presents summarized financial information for Bolivian Power as
of December 31, 1996 and 1995 and for the three years ended December 31, 1996
(dollars in thousands):

<TABLE>
<CAPTION>
                                            1996             1995
                                          --------         --------
<S>                                       <C>              <C>             
         BALANCE SHEET DATA:
           Current assets                 $ 72,550         $ 54,686
           Noncurrent assets                81,211           93,849
                                          --------         --------        
             Total assets                 $153,761         $148,535
                                          ========         ========

           Current liabilities            $ 12,818         $ 12,237
           Noncurrent liabilities           15,036           20,138
           Shareholders' equity            125,907          116,160
                                          --------         --------        
                                          $153,761         $148,535
                                          ========         ========
</TABLE>


<TABLE>
<CAPTION>
                                            1996             1995            1994
                                          --------         --------        --------
<S>                                       <C>              <C>             <C>    
         INCOME STATEMENT DATA:
           Operating revenues             $ 20,009         $ 52,874        $ 45,969
           Operating income (loss)          (4,159)           6,929           5,848
           Net income                        8,434            7,963           7,712
                                          ========         ========        ========
</TABLE>

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 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 also 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 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 $147,000 in equity in net income
of affiliates in the accompanying consolidated statement of operations for the
year ended June 30, 1997, related to its investment in Birchwood Power. The
following table presents summarized financial information for Birchwood Power as
of and for the years ended December 31, 1996 and 1995 (dollars in thousands):





                                       55
<PAGE>   56

<TABLE>
<CAPTION>

                                             1996             1995
                                          --------         --------
<S>                                       <C>              <C>     
         BALANCE SHEET DATA:
           Current assets                 $ 25,701         $  1,234
           Noncurrent assets               385,171          313,402
                                          --------         --------
             Total assets                 $410,872         $314,636
                                          ========         ========

           Current liabilities            $ 89,599         $ 92,968
           Noncurrent liabilities          321,247          221,668
           Shareholders' equity                 26                0
                                          --------         --------
                                          $410,872         $314,636
                                          ========         ========

         INCOME STATEMENT DATA:
           Operating revenues             $  9,745         $      0
           Operating income                  4,527                0
           Net income                           26                0
                                          ========         ========
</TABLE>

5.  INVESTMENT IN GREENHOUSES

         The Company has entered into an agreement with Agro Power Development,
Inc., a developer and operator of greenhouse facilities, giving the Company a
right of first refusal to make investments in partnerships which develop,
construct and operate greenhouses which produce tomatoes. As of June 30, 1997,
the Company held a 50% interest in two limited partnerships which had a
combined 50 acres of production capacity in operation and an additional two
limited partnerships which had a combined 57 acres of production capacity under
construction. The Company is accounting for its investment in these
partnerships under the equity method. The Company recognized approximately
$444,000 in equity in net income of affiliates in the accompanying consolidated
statement of operations for the year ended June 30, 1997, related to its
investments in these partnerships.





                                       56
<PAGE>   57




6.  LONG-TERM DEBT

         The following long-term debt was outstanding as of June 30, 1997 and
1996, respectively (dollars in thousands):


<TABLE>
<CAPTION>

                                                                                     1997               1996
                                                                                  ---------          ---------
<S>                                                                               <C>                <C>      
PROJECT FINANCING DEBT:
HOPEWELL FACILITY:
     1997 - Note payable to banks; 1996 - commercial paper notes payable,
       net of unamortized issue discount of $87                                   $  49,513          $  42,403
PORTSMOUTH FACILITY:
     Note payable to financial institutions                                          60,500             68,250
ROCKY MOUNT FACILITY:
     Note payable to financial institutions                                         126,409            127,576
RINGGOLD FACILITY:
     Note payable to banks                                                           16,900             18,799
RICHMOND FACILITY:
     Commercial paper notes payable, net of unamortized issue discount of
       $409 and $319, respectively, and tax-exempt bonds                            203,651            214,379
ELIZABETHTOWN, LUMBERTON AND KENANSVILLE FACILITIES:
     Notes payable to banks                                                          31,688             44,464
ROXBORO AND SOUTHPORT FACILITIES:
     Note payable to banks                                                          102,074             99,750
OTHER                                                                                   959                967
                                                                                  ---------          ---------
Total Project Financing Debt                                                        591,694            616,588
SENIOR NOTES (including unamortized gain on hedge transaction of $2,300
  and $2,728, respectively)                                                         102,300            102,728
                                                                                  ---------          ---------
Total Long-Term Debt                                                                693,994            719,316
Less: Current Portion                                                               (62,370)           (48,416)
                                                                                  ---------          ---------
Long-term portion                                                                 $ 631,624          $ 670,900
                                                                                  =========          =========
</TABLE>

         Information related to each of these borrowings is as follows:

HOPEWELL FACILITY:
         In July 1996, the Hopewell Facility's project debt agreement was
     amended, which effectively replaced the commercial paper notes with a note
     payable to banks and resulted in a $13,000,000 increase in the amount of
     outstanding indebtedness. The amended project debt accrues interest at an
     annual rate equal to the applicable London Interbank Offering Rate
     ("LIBOR") as chosen by the Company, plus a .875% per annum through July
     1999 and 1.125% thereafter (6.56% at June 30, 1997). Principal is payable
     quarterly with interest payable the earlier of the maturity of the
     applicable LIBOR term or quarterly through June 2002.

PORTSMOUTH FACILITY:
         The note payable to financial institutions consists of a $60,500,000
     senior loan which accrues interest at an annual rate equal to the
     applicable LIBOR rate, as chosen by the Company, plus 1% through May 1997
     and 1.125% thereafter (6.91% at June 30, 1997). Principal is payable
     quarterly with interest payable the earlier of the maturity of the
     applicable LIBOR term or quarterly through September 2002.

ROCKY MOUNT FACILITY:
         The note payable to financial institution consists of a $126,409,000
     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 $16,900,000 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 (6.9% at June 30,
     1997). Interest is payable 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.




                                       57
<PAGE>   58


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 $156,060,000 as of June 30, 1997. 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 6.95% at June 30, 1997) 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 ($48,000,000 outstanding at June 30,
     1997). 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
     (5.95% at June 30, 1997) paid to the Banks. 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 $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 (6.59% at June 30, 1997). 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 fiscal year 1997 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
     $470,000 in the accompanying consolidated statement 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 (6.59% at June 30, 1997).
     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.

INTEREST RATE PROTECTION AGREEMENTS:
         The Company has entered into interest rate cap, interest rate collar
     and interest rate swap agreements (Note 12) to manage its interest rate
     risk on its variable-rate project financing debt. The notional amounts of
     debt covered by these agreements as of June 30, 1997 and 1996 are
     $391,371,000 and $427,287,000, 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 6.79% to a weighted
     average effective rate of 7.52% at June 30, 1997. These agreements expire
     at various dates through July 2006.

SENIOR NOTES:
         On March 15, 1994, the Company issued $100 million of registered,
     unsecured senior notes due 2004 (the "Senior Notes") in a public debt
     offering. The Senior Notes were priced at par to yield 8.10%. In February
     1994, the Company 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 Senior Notes offering.
     This hedge transaction resulted in the recognition of a gain which has been
     deferred and included as part of the Senior Notes on the accompanying
     consolidated balance sheets. This deferred gain will be recognized over the
     term of the Senior Notes, reducing the effective rate of interest on the
     Senior Notes to 7.5%. The Senior 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.





                                       58
<PAGE>   59

         Corporate Credit Facility -- In May 1997, the Company entered into a 
credit agreement with Australia and New Zealand Banking Group Limited, as
Agent, which provides for a $50,000,000 revolving credit facility (the "Credit
Facility") with an initial term of three years (the "Revolving Term"). The
Credit Facility provides for one-year extensions of the Revolving Term, subject
to lender consent. The Credit Facility allows for direct advances or the
issuance of letters of credit. The outstanding balance at the end of the
Revolving Term is payable over two years in four equal semiannual repayments of
direct advances or collateralization of letters of credit. Borrowings bear
interest at LIBOR plus an applicable margin based on the credit rating on the
Company's Senior Notes. Commitment fees related to the Credit Facility are
currently 30 basis points per annum, payable each quarter on the outstanding
unused portion of the Credit Facility. As of June 30, 1997, the Company had no
borrowings or letters of credit outstanding.

         The project financing debt is substantially non-recourse to the Company
(as parent). The project financing agreements of the Company's subsidiaries, the
Indenture for the Senior Notes and the 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 Indenture for the Senior Notes and the
Credit Facility. These covenants did not restrict the Company's ability to
declare a $5.0 million dividend to the Company's shareholders for the year
ended June 30, 1997.

         Future maturities of long-term debt at June 30, 1997 excluding
unamortized issue discounts and the unamortized balance of the deferred gain on
the Senior Notes hedge transaction are as follows (dollars in thousands):

<TABLE>
<CAPTION>
                        YEAR ENDED
                          JUNE 30
                        ----------
<S>                        <C>                   <C>     
                           1998                  $ 62,370
                           1999                    67,083
                           2000                    72,238
                           2001                    90,030
                           2002                    90,430
                        Thereafter                311,843
                                                 --------
                                                 $693,994
                                                 ========
</TABLE>





                                       59
<PAGE>   60




7.  INCOME TAXES

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

<TABLE>
<CAPTION>
                                                  1997             1996            1995
                                               --------          -------         -------
<S>                                            <C>               <C>             <C>    
Current
  Federal                                      $  9,025          $ 6,893         $ 5,264
  State                                             978              499             355
                                               --------          -------         -------
                                                 10,003            7,392           5,619
                                               --------          -------         -------
Deferred
  Federal                                       (23,085)           6,406           6,191
  State                                          (4,500)           2,163           1,527
                                               --------          -------         -------
                                                (27,585)           8,569           7,718
                                               --------          -------         -------                   
                                               $(17,582)         $15,961         $13,337
                                               ========          =======         =======

Statements of Operations Captions
  Tax effect of extraordinary loss             $   (470)         $     0         $     0
  Provision (benefit) for income taxes          (17,112)          15,961          13,337
                                               --------          -------         -------
                                               $(17,582)         $15,961         $13,337
                                               ========          =======         =======
</TABLE>

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

<TABLE>
<CAPTION>
                                                       1997             1996            1995
                                                      ------           ------          ------

<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                               (5.0)             4.6             4.2
Other                                                   1.7               .5             (.6)
                                                      -----            -----           -----           
Effective tax rate                                    (38.3)%           40.1%           38.6%
                                                      =====            =====           =====
</TABLE>

         The net current and noncurrent components of deferred income taxes
reflected in the accompanying consolidated balance sheets as of June 30, 1997
and 1996 are as follows (dollars in thousands):

<TABLE>
<CAPTION>
                                                     1997              1996
                                                   -------           -------
<S>                                                <C>               <C>    
Net current deferred tax (asset) liability         $(3,460)          $   228
Net noncurrent deferred tax liability               23,074            46,971
                                                   -------           -------
Net deferred tax liability                         $19,614           $47,199
                                                   =======           =======
</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 June 30, 1997 and 1996 are as follows
(dollars in thousands):




                                       60
<PAGE>   61
\




<TABLE>
<CAPTION>
                                                                                  1997             1996
                                                                               --------         --------
<S>                                                                            <C>              <C>     
         Deferred tax liabilities:
              Depreciation/amortization and book/tax basis differences         $ 60,575         $ 86,246
              Book/tax timing differences on joint venture interest               8,528            8,656
              Other                                                               5,592            6,554
                                                                               --------         --------
                                                                                 74,695          101,456
                                                                               --------         --------

         Deferred tax assets:
              Depreciation/amortization and book/tax basis differences           10,873            6,697
              Operating loss carryforwards                                        2,194           16,762
              Accrued expenses not currently deductible                           8,721            3,005
              Investment tax credit carryforwards                                   749            5,127
              Alternative minimum tax credit carryforwards                       25,537           17,227
              Other                                                               7,007            5,439
                                                                               --------         --------
                                                                                 55,081           54,257
                                                                               --------         --------

              Net deferred tax liability                                       $ 19,614         $ 47,199
                                                                               ========         ========
</TABLE>

         At June 30, 1997, the Company had federal investment tax carryforwards
of approximately $749,000 expiring in 2006 and alternative minimum tax credit
carryforwards of approximately $25,537,000 with no expiration date available to
reduce its future federal income tax liabilities.

8.  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 June 30,
1997 are as follows (dollars in thousands):

<TABLE>
<CAPTION>
                                                          OTHER
                        YEAR ENDED                      EQUIPMENT
                         JUNE 30            ELP         PROVIDERS          TOTAL
                      ---------------    ----------    -------------     ----------
<S>                        <C>             <C>            <C>             <C>    
                           1998            $ 1,598        $ 340           $ 1,938
                           1999              1,395          194             1,589
                           2000              1,218          149             1,367
                           2001              1,210          108             1,318
                           2002              1,199           15             1,214
                        Thereafter           6,457            0             6,457
</TABLE>

9.  LOSS ON IMPAIRMENT AND COST OF REMOVAL OF COGENERATION FACILITIES

         During fiscal year 1997, 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


                                       61
<PAGE>   62

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 statement of operations for
the year ended June 30, 1997.

         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, will increase approximately $6.1 million per year as a
result of the changes in estimated useful lives and the impairment loss
recognized during fiscal 1997.

10.  COMMITMENTS AND CONTINGENCIES

         Long-Term Contracts -- The Company has several long-term contractual
commitments that comprise a significant portion of its financial obligations.
These contractual commitments with original terms varying in length from 10 to
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.

         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 contracts with one Utility, the Utility is permitted,
subsequent to the maturity date of the original project financing debt, to
reduce future payments or recover certain payments previously made in the event
that a state utility commission prohibits the Utility from recovering such
payments made under a power sales agreement. As of June 30, 1997, the Company
has accrued $1,323,000 in other long-term liabilities in the accompanying
consolidated balance sheet for the estimated disallowance of a portion of a
Facility's capacity payment and the related accrued interest.

         Construction Agreement -- In October 1995, the Company delivered to
Clark a $20 million letter of credit, provided by a bank, which is
collateralized by a pledge of marketable securities. This letter of credit
supports certain contingent obligations of the Company under the Construction
Agreement. The Company is also obligated to pay 50% of any costs and expenses,
if any, incurred in constructing the facility in excess of the contract amount.
Pursuant to the Construction Agreement, the contract amount of $117 million may
be adjusted as a result of a force majeure event, scope change, certain delays
in schedule or change in law. The Company will earn a construction fee of $5
million upon completion of the Clark 


                                       62
<PAGE>   63

Facility. The Company will also share in 50% of the amount, if any, equal to the
excess of the contract amount over the costs and expenses incurred in
constructing the Clark Facility. Construction on the Clark Facility commenced in
March 1996 and is anticipated to be completed in late calendar 1997.

         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 $3,710,000 in 1996 and $3,950,000 in 1995. During
fiscal year 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 $1,618,000 in 1997, $1,629,000 in 1996 and $1,612,000 in 1995.

         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 $2,318,000 at June
30, 1997) 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 substantially 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 certain subsidiaries'
obligations aggregating $8 million and certain subsidiaries' performance under
their contracts with one Utility. In addition, Cogentrix Energy, Inc. has
indemnified the project lenders of a certain subsidiary for any cash deficits
such subsidiary could experience as a result of incurring certain costs, subject
to a cap of $11.3 million.

         Pending Claims and Litigation -- Under the amended terms of the power 
sales agreements for the Elizabethtown, Lumberton, Kenansville, Roxboro and
Southport Facilities, 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,
certain of the coal suppliers for these Facilities have initiated litigation
and arbitration proceedings against certain subsidiaries of the Company. The
Company intends to defend itself in the litigation and the arbitration
proceeding vigorously. The Company has established reserves which management
believes to be adequate to cover any costs resulting from these matters.
Management believes that the resolution of these matters will not have a
material adverse effect on the consolidated financial position or results of
operations of the Company.

11.  FUNDS HELD BY TRUSTEES

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

         Funds held by the Trustees were $49,187,000 and $59,287,000 at June 30,
1997 and 1996, 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.





                                       63
<PAGE>   64


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

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

         The carrying values reflected in the accompanying consolidated balance
sheets at June 30, 1997 and 1996 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 June 30, 1997 and 1996 (Note 3). The fair value of the
Company's fixed-rate borrowings at June 30, 1997 is $1,759,000 lower than the
historical carrying value of $226,409,000. At June 30, 1996, the fair value of
the Company's fixed-rate borrowings was $3,631,000 lower than the historical
carrying value of $238,018,000. In making such calculations, the Company
utilized credit reviews, quoted market prices and discounted cash flow analyses,
as appropriate.

         The Company is exposed to credit-related losses in the event of
non-performance by counterparties to the Company's interest rate protection
agreements (Note 6). The Company does not obtain collateral or other security to
support such agreements but continually monitors its positions with, and the
credit quality of, the counterparties to such agreements. As of June 30, 1997,
the gross unrealized gains and losses on the interest rate protection agreements
are $3,130,000 and $2,102,000, respectively, resulting in an estimated net
unrealized gain of $1,028,000. As of June 30, 1996, the gross unrealized gains
and losses on the Company's interest rate protection agreements were $4,984,000
and $4,185,000, respectively, resulting in an estimated net unrealized gain of
$799,000.

13.  RELATED PARTY TRANSACTIONS

         The Company has notes receivable and advances due from shareholders and
an affiliated entity of approximately $450,000 and $678,000 as of June 30, 1997
and 1996, 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 $1,967,545, $2,041,000 and $2,158,000 for
the years ended June 30, 1997, 1996 and 1995, 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 10) while employed as an
executive officer of the Company and continues to receive incentive compensation
annually pursuant to such plans equal to a percentage of net cash flow, as
defined, of certain subsidiaries. Total compensation to the shareholder under
the consulting agreement and incentive compensation plans was approximately
$374,000, $442,000 and $510,000 for the years ended June 30, 1997, 1996 and
1995, respectively.

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




                                       64
<PAGE>   65

                                                                     SCHEDULE I

                            COGENTRIX ENERGY, INC.

                    CONDENSED BALANCE SHEETS OF REGISTRANT

                            (dollars in thousands)

<TABLE>
<CAPTION>
                                                                                       June 30,
                                                                               -----------------------
                                                                                 1997           1996  
                                                                               --------       --------
                                    ASSETS

<S>                                                                            <C>            <C>
CURRENT ASSETS:
  Cash and cash equivalents                                                    $ 10,028       $  9,268
  Restricted cash                                                                 1,688          1,716
  Accounts receivable                                                             6,160          4,029
  Accounts receivable from affiliates                                             8,671          4,459
  Restricted investments                                                         20,000              0
  Other current assets                                                              309            405
                                                                               --------       --------
    Total current assets                                                         46,856         19,877
                                                                               --------       --------

INVESTMENT IN SUBSIDIARIES (ON THE EQUITY METHOD)                               174,711        200,055
                                                                               --------       --------

EQUIPMENT, net of accumulated depreciation of $2,748
    and $2,287, respectively                                                      1,038          1,213
                                                                               --------       --------

OTHER ASSETS:
  Restricted investments                                                              0         20,000
  Income tax benefit                                                             26,416         16,369
  Deferred financing costs, net of accumulated amortization of
    $1,027 and $713, respectively                                                 2,259          2,398
  Notes receivable from affiliates                                                  921          1,001
  Other                                                                           2,453          2,288
                                                                               --------       --------
    Total other assets                                                           32,049         42,056
                                                                               --------       --------

Total Assets                                                                   $254,654       $263,201
                                                                               ========       ========

                     LIABILITIES AND SHAREHOLDERS' EQUITY

CURRENT LIABILITIES:
  Accounts payable                                                             $  8,808       $  4,298
  Accounts payable to affiliate                                                      20             50
  Accrued liabilities                                                            21,261         14,445
  Accrued dividends                                                               5,000          4,759
                                                                               --------       --------
    Total current liabilities                                                    35,089         23,552
                                                                               --------       --------

LONG-TERM LIABILITIES:
  Notes payable to affiliates                                                    56,513         46,176
  Long-term debt                                                                102,300        102,728
  Other                                                                          11,043          7,735
                                                                               --------       --------
    Total long-term liabilities                                                 169,856        156,639
                                                                               --------       --------
      Total liabilities                                                         204,945        180,191
                                                                               --------       --------

SHAREHOLDERS' EQUITY:
  Common stock                                                                      130            130
  Accumulated earnings                                                           49,579         82,880
                                                                               --------       --------
    Total shareholders' equity                                                   49,709         83,010
                                                                               --------       --------

Total Liabilities and Shareholders' Equity                                     $254,654       $263,201
                                                                               ========       ========
</TABLE>

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

                                      65
<PAGE>   66

                                                                      SCHEDULE I

                            COGENTRIX ENERGY, INC.

                  CONDENSED STATEMENTS OF INCOME REGISTRANT

                            (DOLLARS IN THOUSANDS)


<TABLE>
<CAPTION>
                                                                 FOR THE YEARS ENDED JUNE 30,
                                                              ----------------------------------
                                                                1997         1996         1995
                                                              --------     --------     --------

<S>                                                           <C>          <C>          <C>
INCOME:
  Development and construction management fees                $  1,105     $    672     $    197
  Operating management fees                                     20,238       12,206       10,814
                                                              --------     --------     --------

    Total Income                                                21,343       12,878       11,011
                                                              --------     --------     --------

OPERATING EXPENSES:
  General, administrative and development expenses              38,211       27,452       28,419
  Depreciation and amortization                                  1,253        1,302        1,221
                                                              --------     --------     --------

    Total operating expenses                                    39,464       28,754       29,640
                                                              --------     --------     --------

OPERATING LOSS                                                 (18,121)     (15,876)     (18,629)
                                                              --------     --------     --------

OTHER INCOME (EXPENSE):
  Interest expense                                             (10,634)      (8,735)      (7,723)
  Investment and other income                                    2,523        1,769          690
                                                              --------     --------     --------

    Total other expense                                         (8,111)      (6,966)      (7,033)
                                                              --------     --------     --------

LOSS BEFORE INCOME TAXES                                       (26,232)     (22,842)     (25,662)

INCOME TAX BENEFIT                                              10,047        9,160        9,906

EQUITY IN EARNINGS (LOSS) OF SUBSIDIARIES                      (12,116)      37,477       36,929
                                                              --------     --------     --------

NET INCOME (LOSS)                                             $(28,301)    $ 23,795     $ 21,173
                                                              ========     ========     ========
</TABLE>

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


                                      66
<PAGE>   67

                                                                     SCHEDULE I


                            COGENTRIX ENERGY, INC.

               CONDENSED STATEMENTS OF CASH FLOWS OF REGISTRANT

                            (DOLLARS IN THOUSANDS)

<TABLE>
<CAPTION>
                                                                                  FOR THE YEARS ENDED JUNE 30,   
                                                                               ----------------------------------
                                                                                 1997         1996         1995  
                                                                               --------     --------     --------
                                                                                                                 
<S>                                                                            <C>          <C>          <C>     
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES                                $ 38,921     $ 21,638     $ 12,119
                                                                               --------     --------     --------
                                                                                                                 
CASH FLOWS FROM INVESTING ACTIVITIES:                                                                            
  Increase in restricted investments                                                  0      (20,000)           0
  Property, plant and equipment additions                                          (286)        (232)        (532)
  Investments in subsidiaries                                                   (43,386)     (14,239)      (5,403)
                                                                               --------     --------     --------
  Net cash flows used in investing activities                                   (43,672)     (34,471)      (5,935)
                                                                               --------     --------     --------
                                                                                                                 
CASH FLOWS FROM FINANCING ACTIVITIES:                                                                            
  Proceeds from notes payable to affiliate                                       10,944       18,500            0
  Decrease (increase) in restricted cash                                             28          660         (681)
  Decrease in notes receivable from affiliates                                       80            0            0
  Increase in deferred financing costs                                             (175)           0          (93)
  Repayment of long-term notes payable to affiliates                               (607)      (3,560)      (1,500)
  Dividends paid                                                                 (4,759)      (4,235)      (3,328)
                                                                               --------     --------     --------
  Net cash flows provided by (used in) financing activities                       5,511       11,365       (5,602)
                                                                               --------     --------     --------
                                                                                                                 
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS                                760       (1,468)         582
                                                                                                                 
CASH AND CASH EQUIVALENTS, Beginning of Year                                      9,268       10,736       10,154
                                                                               --------     --------     --------
                                                                                                                 
CASH AND CASH EQUIVALENTS, End of Year                                         $ 10,028     $  9,268     $ 10,736
                                                                               ========     ========     ========
                                                                                                                 
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION --                                                              
  CASH DIVIDENDS RECEIVED                                                      $ 56,614     $ 44,133     $ 37,952
                                                                               ========     ========     ========
</TABLE>

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

                                      67
<PAGE>   68

                                                                     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 provision (benefit) for income taxes has been computed
based on Cogentrix Energy, Inc.'s consolidated effective income tax rate.

    Reclassification -- Certain amounts included in the condensed financial
statements for fiscal years 1996 and 1995 have been reclassified from their
original presentation to conform with the current year's presentation.

2.  LONG-TERM DEBT

Senior Notes

    On March 15, 1994, Cogentrix Energy, Inc. issued $100 million of
registered, unsecured senior notes due 2004 (the "Senior Notes") in a public
debt offering. The Senior Notes were priced at par to yield 8.10%. In February
1994, the Company 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 Senior Notes offering. This hedge
transaction resulted in the recognition of a gain which has been deferred and
included as part of the Long-term debt on the accompanying condensed balance
sheets. This deferred gain will be recognized over the term of the Senior
Notes, reducing the effective rate of interest on the Senior Notes to 7.5%. The
Senior Notes require annual sinking fund payments beginning in March 2001.

    Future maturities of long-term debt at June 30, 1997, excluding the
unamortized balance of the deferred hedge gain, are as follows (dollars in
thousands):



<TABLE>
<CAPTION>
                                      YEAR ENDED
                                       JUNE 30,
                                   ------------------

                                   <S>                             <C>
                                         1998                      $        0
                                         1999                               0
                                         2000                               0
                                         2001                          20,000
                                         2002                          20,000
                                      Thereafter                       60,000
                                                                   -----------
                                                                     $100,000
                                                                   ===========
</TABLE>

Corporate Credit Facility

    In May 1997, Cogentrix Energy, Inc. entered into a credit agreement with
Australia and New Zealand Banking Group Limited, as Agent, which provides for a
$50,000,000 revolving credit facility (the "Credit Facility") with an initial
term of three years (the "Revolving Term"). The Credit Facility provides for
one-year extensions of the Revolving Term, subject to lender consent. The
Credit Facility allows for direct advances or the issuance of letters of
credit. The outstanding balance at the end of the Revolving Term is payable
over two years in four equal semiannual repayments of direct advances or
collateralization of letters of credit. Borrowings bear interest at LIBOR plus
an applicable margin based on the credit rating on the Senior Notes. Commitment
fees related to the Credit Facility are currently 30 basis points per annum,
payable each quarter on the outstanding unused portion of the Credit Facility.
As of June 30, 1997, Cogentrix Energy, Inc. had no borrowings or letters of
credit outstanding.


                                      68
<PAGE>   69


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

        None.





                                       69
<PAGE>   70

                                    PART III

ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

         The directors and executive officers of the Company are as set forth
below.

<TABLE>
<CAPTION>

NAME                                AGE     POSITION
----                                ---     --------
<S>                                 <C>     <C>                                  
George T. Lewis, Jr.                69      Chairman of the Board and Director
David J. Lewis                      41      Vice Chairman, Chief Executive Officer and Director
Mark F. Miller                      43      President, Chief Operating Officer and Director
Betty G. Lewis                      68      Director
James E. Lewis                      34      Executive Vice President and Director
Robert W. Lewis                     44      Director
Dennis W. Alexander                 50      Group Senior Vice President, General Counsel, Secretary and Director
T. Louis Austin, Jr.                78      Director (Deceased: September 16, 1997)
W. E. Bill Garrett                  67      Director
James R. Pagano                     37      Group Senior Vice President -- Chief Financial Officer
B. Yamin Afshar                     53      Senior Vice President -- Business Development
William C. Campbell, III            45      Senior Vice President -- Business Development
Kartar B. Singh                     56      Senior Vice President -- Estimating and Cost Scheduling

</TABLE>

         GEORGE T. LEWIS, JR., the founder of Cogentrix, has been Chairman of
the Board and a Director of the Company since its formation in 1993 and Chief
Executive Officer of the Company from December 1993 to August 1995, prior to
which he was Chief Executive Officer and a Director of Cogentrix from 1983 to
1995, Chairman of the Board of Cogentrix since 1990 and President of Cogentrix
from 1983 to 1989. Mr. Lewis previously served for over 18 years with Chas T.
Main, Inc. ("Main"), an engineering firm headquartered in Boston. In 1971, he
became a Senior Vice President responsible for that company's work with the
utility industry. From 1978 through 1980, he headed Main's Southern District
office located in Charlotte, North Carolina and directed Main's 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. In this capacity, he
became convinced that cogeneration projects would become an emerging market and
left Main to form Cogentrix.

         DAVID J. LEWIS has been a Director of the Company since its formation
and was appointed Vice Chairman of the Board and Chief Executive Officer in
August 1995. Prior to August 1995, Mr. Lewis was Executive Vice President
--Marketing and Development and a Director since the Company's formation, Chief
Executive Officer -- Elect since June 1994, Group Senior Vice President --
Marketing and Development with Cogentrix since September 1993 and a Director of
Cogentrix 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. From 1987 to 1989, he was
Vice President --Administration of Cogentrix, from 1986 to 1987, he was Resident
Construction Manager and from 1985 to 1986, he was Assistant Construction
Manager. Prior to joining Cogentrix in 1985, he was Operations Manager -- Export
Management and Marketing Representative -- Export Management 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 the Company in May 1997. Prior to joining the Company, Mr. Miller
was Vice President - Business Management, Electronics and Systems Integration
Division for Northrop Grumman in Bethpage, New York. He joined Northrop Grumman
in 1982 where he held positions in the material, law and contracts departments
before his promotion in 1994 to the position held at his departure. From 1980 to
1982, he was an Associate with the law firm of Dolack, Hansler.

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

         JAMES E. LEWIS has been Executive Vice President and a Director of the
Company since its formation, prior to which he was Executive Vice President of
Cogentrix since November 1992 and a Director of Cogentrix since 1988. From 1991
to 1992, he was Senior Vice President of Operations responsible for the daily
operations of the Company's facilities. 


                                       70
<PAGE>   71

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 Company's Portsmouth Facility.
James Lewis is a son of George T. Lewis, Jr. and Betty G. Lewis.

         ROBERT W. LEWIS has been a Director of the Company since its formation,
prior to which he was a Director of Cogentrix since 1988. In April 1991, Mr.
Lewis resigned from his positions of Vice Chairman and Secretary of Cogentrix
which he had held since March 1991. Since his resignation as an officer, Mr.
Lewis has served as a consultant to the Company. 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's development
efforts. From March 1987 to March 1988, Mr. Lewis was Senior Vice President --
Administration and Secretary. From September 1983 to March 1987, Mr. Lewis was
Vice President -- Administration and Secretary. Mr. Lewis joined Cogentrix in
April 1983 and served as Secretary through September 1983. Robert 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 the Company in February 1994.
Immediately prior to joining the Company, 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.

         T. LOUIS AUSTIN, JR. has been a Director of the Company since its
formation and became a Director of Cogentrix in September 1993. Mr. Austin, who
is currently retired, formerly served as CEO and a Director of Texas Utilities
Company, an investor-owned parent of an electric public utility, CEO and a
Director of Brown & Root, Inc., an engineering and construction management firm
headquartered in Houston, Texas, and as a Director of Halliburton Company, a
worldwide oilfield services company headquartered in Dallas, Texas. He is
currently a director of Guardian Savings and Loan Association in Houston, Texas.
He is a former Director of the Electric Power Research Institute and the
National Coal Association. The Company acknowledges with great sadness the
passing of Mr. T. Louis Austin, Jr. on September 16, 1997, and expresses much
gratitude for his many years of dedicated service as a Director of the Company.
Mr. Austin's seat on the Company's board of directors remains vacant at this
time.

         W. E. BILL GARRETT has been a Director of the Company since its
formation and became a Director of Cogentrix 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. Both Mexico and Guatemala have honored
him with prestigious awards for his work in the region. He also currently serves
on the national Board of Governors of The Nature Conservancy, the Boards of the
American Land Conservancy and Partners for Livable Communities, as well as the
Advisory Board of the Corbis Corporation.

         JAMES R. PAGANO has been Group Senior Vice President -- Chief Financial
Officer of the Company since May 1997, prior to which he was Senior Vice
President -- Project Finance since February 1995 and Vice President -- Project
Finance since the Company's formation. Previously, Mr. Pagano was Vice President
-- Project Finance of Cogentrix 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. Prior to
joining Cogentrix, 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.

         B. YAMIN AFSHAR was appointed Senior Vice President -- Business
Development of the Company in September 1997, prior to which he was Senior Vice
President -- International Development since joining the Company in 1995. Mr.
Afshar is responsible for identifying and managing the development of
independent power opportunities for the Company. Prior to joining the Company,
Mr. Afshar was employed by Parsons Main International, Inc. for more than 20
years. His 


                                       71
<PAGE>   72

experience includes extensive work in Asia, Latin America and the Middle East,
developing and successfully negotiating contracts with suppliers and contractors
relating to power projects abroad.

         WILLIAM C. CAMPBELL, III was appointed Senior Vice President --
Business Development of the Company in September 1995. Mr. Campbell had been
Senior Vice President -- Environmental Affairs of the Company since its
formation, prior to which he held the same position with Cogentrix since July
1992. From 1990 to 1992, Mr. Campbell was Vice President --Environmental
Relations of Cogentrix and from 1988 to 1990, he was Vice President -- Project
Development and Environmental Affairs. From 1984 to 1988, Mr. Campbell was a
Project Manager with Cogentrix. Prior to joining Cogentrix, he spent seven years
with Main.

         KARTAR B. SINGH has been Senior Vice President -- Estimating and Cost
Scheduling of the Company since its formation, prior to which he held the same
position of Cogentrix since 1988 and also the positions of Assistant to
President from 1987 to 1991 and Assistant to Chairman from 1991. From 1983 to
1984, he was Chief Estimator and Project Manager. From 1984 to 1988, Mr. Singh
was Chief Estimator and Chief Planning and Scheduling Engineer with Main. Mr.
Singh has 31 years' experience in engineering, estimating, planning and
scheduling and construction in the utility and industrial sector.





                                       72
<PAGE>   73


ITEM 11.  EXECUTIVE COMPENSATION

         The following table sets forth information for the three fiscal years
ended June 30, 1997 concerning the annual compensation paid or accrued by the
Company to or for the account of each of the following: (i) the only person who
served as the chief executive officer of the Company during the fiscal year
ended June 30, 1997; (ii) the four most highly compensated executive officers of
the Company incumbent at June 30, 1997, other than the chief executive officer,
for the fiscal year then ended; and (iii) one former executive officer of the
Company who would have been included among the group described in clause (ii)
but for the fact that he was not an executive officer of the Company at June 30,
1997 (collectively, the "Named Executive Officers").

                           SUMMARY COMPENSATION TABLE

<TABLE>
<CAPTION>
                                                                               ANNUAL COMPENSATION
                                                                  --------------------------------------------
                  NAME AND                                                                                          ALL OTHER
             PRINCIPAL POSITION                  FISCAL YEAR         SALARY (1)       BONUS (2)        TOTAL    COMPENSATION (3)
             ------------------                  -----------         ----------       ---------        -----    ----------------
<S>                                                 <C>              <C>              <C>         <C>           <C>        
George T. Lewis, Jr.                                1997             $ 666,647        $ 332,080   $   998,727   $   994,992
Chairman of the Board                               1996               649,100          381,810     1,030,910        60,960
                                                    1995               634,500          371,560     1,006,060        18,870

David J. Lewis                                      1997               565,317          695,824     1,261,141       929,829
Vice Chairman and Chief Executive Officer           1996               351,720          359,500       711,220        45,040
                                                    1995               345,780          409,350       755,130        10,759

James E. Lewis                                      1997               360,347          345,124       705,471       928,883
Executive Vice President                            1996               349,720          279,950       629,670        37,380
                                                    1995               345,780          331,030       676,810        14,085

James R. Pagano                                     1997               194,498          180,000       374,498        28,912
Group Senior Vice President                         1996               155,243          137,367       292,610        17,570
and Chief Financial Officer                         1995               150,000          155,351       305,351         9,780

Dennis W. Alexander                                 1997               272,068           70,000       342,068        21,472
Group Senior Vice President                         1996               220,946          198,840       419,786        15,332
and General Counsel                                 1995               219,000          237,701       456,701        15,645

Frank J. Benner                                     1997               398,904           70,000       468,904     1,072,719
Former President and Chief Operating Officer        1996               267,659          424,310       691,969        38,855
                                                    1995               265,128          399,928       665,056         9,079
</TABLE>

(1)      Amounts listed in this column include all fees for service on the
         Company's board of directors.

(2)      Amounts listed in this column reflect annual performance bonuses
         and annual distributions under the 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 (i) the Company's matching
         contributions on behalf of the Named Executive Officers to the
         Company's 401(k) savings plan in which all Company employees are
         eligible to participate and to a non-qualified Supplemental Retirement
         Savings Plan in which approximately 37 employees, including all of the
         Named Executive Officers participate, (ii) the payments made to David
         J. Lewis, James E. Lewis and George T. Lewis, Jr. 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 fiscal 1997, which
         amounts are included in column two, "Bonuses" and (iii) in the case of
         Frank J. Benner, compensation related to severance payments.





                                       73
<PAGE>   74

COMPENSATION PURSUANT TO INCENTIVE COMPENSATION PLANS

Profit-Sharing Plan

         The Company has a non-qualified incentive compensation plan for the
benefit of approximately 40 employees of the Company and its affiliates (the
"Profit-Sharing Plan"). Under the Profit-Sharing Plan, the Company has entered
into arrangements with each of its executive officers, which provide for annual
cash compensation distribution awards to each participant equal to a designated
percentage of the Company's adjusted net income before taxes each fiscal year
plus the amount of any accrual for payments to be made under the Profit-Sharing
Plan (the "Designated Percentage"), with the Designated Percentage determined
annually at the discretion of the Company's Chief Executive Officer or Chief
Operating Officer based on criteria they deem appropriate. No payments were made
under the Profit-Sharing Plan for the fiscal year ended June 30, 1997.

         In the event a participant in the Profit-Sharing Plan terminates his or
her employment with the Company (for a reason other than death, total
disability, retirement or termination by the Company 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 the Company.

         Under the Profit-Sharing Plan, Frank J. Benner (or his beneficiary) is
entitled, after age 60 or in the event of total disability or death, to begin
receiving annual distribution awards for each fiscal year through June 30, 2007,
the amount of which shall be calculated using Mr. Benner's Designated Percentage
in effect as of the date of his termination. In the event of death or total
disability occurring after June 30, 2002, Mr. Benner (or his beneficiary) shall
be entitled to receive benefits for five full years following the year in which
such death or total disability occurred.

Executive Incentive Bonus Plan

         In addition to the annual cash compensation distribution awards payable
under the Profit-Sharing Plan or the Facility Cash Flow Incentive Compensation
Agreement described below, certain executive officers, including David J. Lewis,
James E. Lewis, Mark F. Miller, Dennis W. Alexander and James R. Pagano may
receive additional incentive cash compensation awards, determined on a sliding
scale, if the Company achieves certain designated net income before income tax
targets for a given fiscal year. No such additional incentive cash compensation
awards were earned during the fiscal year ended June 30, 1997.

Facility Cash Flow Incentive Compensation Agreements

         The Company had entered into non-qualified incentive compensation
agreements with three of the Named Executive Officers, David J. Lewis, James E.
Lewis and George T. Lewis, Jr., each of whom is a director and a shareholder of
the Company. Such 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 one or both of two of the
Company's facilities. In fiscal 1997, the Company terminated the facility cash
flow incentive compensation agreements with these named executive officers. In
connection with the termination of these plans, David J. Lewis, James E. Lewis
and George T. Lewis, Jr. will be paid $1,157,996, $1,119,816 and $1,268,860,
respectively.

EXECUTIVE EMPLOYMENT AGREEMENT WITH VICE CHAIRMAN AND CHIEF EXECUTIVE OFFICER

         In August 1995, the board of directors elected David J. Lewis Vice
Chairman and Chief Executive Officer of the Company. George T. Lewis, Jr., the
former Chief Executive Officer, will continue to serve as Chairman of the Board.
The Company has an employment agreement with David J. Lewis through August 2000,
which provides for a base annual salary. 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.





                                       74
<PAGE>   75

         The employment agreement is terminable upon notice given by the Company
in the event a majority of the board of directors terminates Mr. Lewis's
employment for cause. In addition, the Company may terminate the agreement at
any time at its 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
the Company would not be in the best interest of the Company 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 (which shall have been a
reasonable time period) specified in such notice. Mr. Lewis may terminate his
employment agreement at any time at his option in the event of a Change of
Control (as defined) of the Company.

EXECUTIVE EMPLOYMENT AGREEMENT WITH CHAIRMAN OF THE BOARD

         In August 1995, the Company 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 the Company during customary business hours for
consultations, either in person or by telephone, with respect to such of the
Company's business and affairs as the Company 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, adjusted
annually based on an inflationary index, as well as performance bonuses, the
amount of which will be determined in accordance with Company policy by the
Chief Executive Officer in consultation with the Chief Operating Officer. Mr.
Lewis received base compensation of $638,000 for the year ended June 30, 1997.

         In the event of Mr. Lewis' death or inability to provide services due
to disability, the agreement shall terminate and the Company is obligated to
continue making payments to him or to his estate for a period of six months
after such termination. The Company 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 the Company terminates 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.

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 fiscal year ended
June 30, 1997, there were five meetings of the Company's board of directors.

         The Company has entered into a consulting agreement with Mr. Garrett 
that provides for payment to him of $15,000 annually for consulting services to
be rendered to the Company.

         In September 1991, the Company entered into a consulting agreement with
Robert W. Lewis, a shareholder, director and former executive officer of
Cogentrix. Under the terms of the consulting agreement, Mr. Lewis is required,
subject to certain limits, to be available on reasonable notice and at
reasonable times during customary business hours for consultations, either in
person or by telephone, with respect to such of the Company's business and
affairs as the Company may reasonably call on him to furnish. Under the
consulting agreement, Mr. Lewis was entitled to receive base compensation
payments through December 31, 1996. The Company paid Mr. Lewis $50,000 pursuant
to the consulting agreement in fiscal year 1997.

         While he was employed as an executive officer, Cogentrix entered into a
non-qualified incentive compensation agreement with Robert W. Lewis 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
the Company's facilities. The Company's obligation to make such annual payments
to him continues through the fiscal year ending June 30, 2007. The Company has
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 the Company, 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 annual


                                       75
<PAGE>   76

distribution Mr. Lewis received pursuant to his facility cash flow compensation
agreement for the fiscal year ended June 30, 1997 was $324,253.

         If at any time through June 1, 2007 Mr. Lewis sells or transfers any of
the shares of common stock of the Company held by him to anyone other than
certain other members of the Lewis family without granting the Company 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 the Company
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 the Company's
Senior Notes conducted in March 1994, the Company's 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 the Company's
disinterested directors. The Indenture under which the Senior Notes were issued
and the covenants of the Credit Facility place certain limitations on the
Company's ability to enter into material transactions with related parties as
well.

LEASES AND REAL PROPERTY TRANSACTIONS

         Equipment Leasing Partners ("ELP"), a North Carolina general
partnership consisting of four of the Company's shareholders, George T. Lewis,
Jr., David J. Lewis, James E. Lewis and Robert W. Lewis, owns and leases certain
equipment to the Company's project subsidiaries related to the operations of
the plants. Each of the partners in ELP is a member of the Company's board of
directors. David J. Lewis, James E. Lewis and George T. Lewis, Jr. are also
executive officers of the Company. Total rent paid by the Company to ELP under
such equipment leases was $1,021,400 in fiscal 1997, $1,112,000 in fiscal 1996
and $1,244,000 in fiscal 1995.

         ELP also owns and leases to the Company the Company's executive 
offices under a long term lease with an initial term expiring in 2004. Total
rent paid by the Company to ELP under such lease was $834,000 in fiscal 1997,
$817,000 in fiscal 1996 and $801,000 in fiscal 1995.





                                       76
<PAGE>   77


         ELP leases the land on which the Company's 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 in fiscal
1997, $112,000 in fiscal 1996 and $112,000 in fiscal 1995.

INDEBTEDNESS OF MANAGEMENT

         The Company has from time to time made loans and advances to certain
shareholders, each of whom is also a director of the Company. The largest
aggregate amount of indebtedness outstanding exceeding $60,000 at any time
during the last fiscal year for these shareholders and the outstanding balances
at June 30, 1997 were as follows:

<TABLE>
<CAPTION>
                                                   LARGEST BALANCE                   OUTSTANDING
                                                  OUTSTANDING DURING                BALANCE AS OF
          SHAREHOLDER/DIRECTOR                     FISCAL YEAR 1997                 JUNE 30, 1997
          --------------------                     ----------------                 -------------
<S>                                                    <C>                             <C>     
          George T. Lewis, Jr.                         $140,000                        $140,000
</TABLE>

         The loans to George T. Lewis, Jr. were made at interest rates equal in
each case to the prime rate of certain designated banks plus one percent.

         Cogentrix has also from time to time made loans to ELP for the purpose
of financing purchases of equipment. These loans were made at variable rates of
interest equal to the prime rate of designated banks plus approximately two
percentage points. The largest aggregate amount of indebtedness of ELP to
Cogentrix outstanding during the fiscal year ended June 30, 1997 was $284,000.
The outstanding amount of ELP's indebtedness to Cogentrix as of June 30, 1997
was $44,000.

FACILITY CASH FLOW INCENTIVE COMPENSATION AGREEMENTS

         The Company has entered into agreements with four of the beneficial
owners of the Company's outstanding shares of common stock, three of whom are
executive officers of the Company (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 the Company's facilities. During fiscal
1997, the Company terminated these agreements for the three executive officers.
See "Executive Compensation -- Compensation Pursuant to Incentive Compensation
Plans -- Facility Cash Flow Incentive Compensation Agreements -- 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 the Company's 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 the Company, she must
first offer to sell them to the Company 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 the Company 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 the Company 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.

CONSULTING AGREEMENTS WITH SHAREHOLDERS

         The Company has entered a consulting agreement with one of its
shareholders who is also a member of the board of directors. See "Executive
Compensation -- Directors' Compensation and Consulting Agreements" herein.




                                       77
<PAGE>   78


                                    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 45.

             (2) Financial Statement Schedules - See index on page 45.

             (3) Index to Exhibits.

    Designation Of
       Exhibit                   Description Of Exhibit
    --------------               ----------------------
         1.1      Form of Underwriting Agreement (1.1). (3)

         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). (13)

         4.1      Indenture, dated as of March 15, 1994, between Cogentrix
                  Energy, Inc. and First Union National Bank of North Carolina,
                  as Trustee (4.1). (5)

         10.1     Electric Power Purchase Agreement, dated as of June 13, 1984,
                  among Cogentrix of North Carolina, Inc. (then known as
                  Cogentrix Leasing Corporation), Cogentrix, Inc. (then known as
                  Cogentrix of North Carolina, Inc.) and Carolina Power & Light
                  Company, as amended (assigned to and assumed by Cogentrix
                  Eastern Carolina Corporation) (Elizabethtown Facility) (10.1).
                  (1)

         10.1(a)  Second Amendment to Electric Power Purchase Agreement, dated
                  as of August 5, 1996, between Cogentrix Eastern Carolina
                  Corporation and Carolina Power & Light Company (Elizabethtown
                  Facility) (10.1(a)). (*)(13)

         10.2     Electric Power Purchase Agreement, dated as of June 13, 1984,
                  among Cogentrix of North Carolina, Inc. (then known as
                  Cogentrix Leasing Corporation), Cogentrix, Inc. (then known as
                  Cogentrix of North Carolina, Inc.) and Carolina Power & Light
                  Company, as amended (assigned to and assumed by Cogentrix
                  Eastern Carolina Corporation) (Lumberton Facility) (10.2). (1)

         10.2(a)  Second Amendment to Electric Power Purchase Agreement, dated
                  as of August 5, 1996, between Cogentrix Eastern Carolina
                  Corporation and Carolina Power & Light Company (Lumberton
                  Facility) (10.2(a)). (*)(13)

         10.3     Electric Power Purchase Agreement, dated as of June 13, 1984,
                  among Cogentrix of North Carolina, Inc. (then known as
                  Cogentrix Leasing Corporation), Cogentrix, Inc. (then known as
                  Cogentrix of North Carolina, Inc.) and Carolina Power & Light
                  Company, as amended (assigned to and assumed by Cogentrix
                  Eastern Carolina Corporation) (Kenansville Facility) (10.3).
                  (1)

         10.3(a)  Second Amendment to Electric Power Purchase Agreement, dated
                  as of August 5, 1996, between Cogentrix Eastern Carolina
                  Corporation and Carolina Power & Light Company (Kenansville
                  Facility) (10.3(a)). (*)(13)

         10.4     Electric Power Purchase Agreement, dated as of December 17,
                  1985, among Cogentrix of North Carolina, Inc. (successor by
                  merger to Cogentrix Carolina Leasing Corporation), Cogentrix,
                  Inc. (then known as Cogentrix of North Carolina, Inc.) and
                  Carolina Power & Light Company, as amended (Roxboro Facility)
                  (10.4). (1)

         10.4(a)  Third Amendment to Electric Power Purchase Agreement, dated as
                  of August 5, 1996, between Cogentrix of North Carolina, Inc.
                  and Carolina Power & Light Company (Roxboro Facility)
                  (10.4(a)). (*)(13)

         10.5     Electric Power Purchase Agreement, dated as of December 17,
                  1985, among Cogentrix of North Carolina, Inc. (successor by
                  merger to Cogentrix Carolina Leasing Corporation), Cogentrix,
                  Inc. (then known as Cogentrix of North Carolina, Inc.) and
                  Carolina Power & Light Company, as amended (Southport
                  Facility) (10.5). (1)




                                       78
<PAGE>   79


    Designation Of
       Exhibit                   Description Of Exhibit
    --------------               ----------------------
         10.5(a)  Third Amendment to Electric Power Purchase Agreement, dated as
                  of August 5, 1996, between Cogentrix of North Carolina, Inc.
                  and Carolina Power & Light Company (Southport Facility)
                  (10.5(a)). (*)(13)

         10.6     Power Purchase and Operating Agreement, dated as of December
                  31, 1985, between Cogentrix of Virginia, Inc. and Virginia
                  Electric and Power Company, as amended (assigned to and
                  assumed by James River Cogeneration Company) (Hopewell
                  Facility) (10.6). (1)

         10.6(a)  Amendment No. 4 to Power Purchase and Operating Agreement,
                  dated as of January 1, 1996, by and between James River
                  Cogeneration Company and Virginia Electric and Power Company
                  (Hopewell Facility) (10.1). (12)

         10.7     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)

         10.8     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)

         10.9     Agreement, dated as of June 23, 1986, for the Sale of Energy
                  from the Ringgold Cogeneration/Greenhouse Plant, between Xiox
                  Corporation and Pennsylvania Electric Company, as amended
                  (assigned to and assumed by Cogentrix of Pennsylvania, Inc.)
                  (Ringgold Facility) (10.9). (1)

         10.10    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)

         10.11    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)

         10.12    Power Purchase Agreement, dated as of August 4, 1992, between
                  Consumers Power Company and Muskegon Generation, Inc., as
                  amended (assigned to and assumed by Michigan Cogeneration
                  Partners) (Michigan Facility) (10.12). (1)

         10.12(a) Memorandum of Agreement, dated as of July 18, 1994, among
                  Consumers Power Company and Michigan Cogeneration Partners
                  Limited Partnership (10.12(a)). (5)

         10.13    Power Purchase and Operating Agreement, dated as of July 13,
                  1990, between SEI Birchwood, Inc. (assigned to and assumed by
                  Birchwood Power Partners, L.P.) and Virginia Electric and
                  Power Company, as amended (Birchwood Facility) (10.6). (14)

         10.14    Steam Purchase Agreement, dated as of August 23, 1984, between
                  Cogentrix of North Carolina, Inc. (then known as Cogentrix
                  Leasing Corporation) and West Point Stevens Inc. (then known
                  as West-Point Pepperell, Inc.), as amended (assigned to and
                  assumed by Cogentrix Eastern Carolina Corporation
                  (Elizabethtown Facility) (10.13). (*)(3)

         10.15    Steam Purchase Agreement, dated as of August 23, 1984, between
                  Cogentrix of North Carolina, Inc. (then known as Cogentrix
                  Leasing Corporation) and West Point Stevens Inc. (then known
                  as West-Point Pepperell, Inc.), as amended (assigned to and
                  assumed by Cogentrix Eastern Carolina Corporation) (Lumberton
                  Facility) (10.14). (*)(3)

         10.16    Steam Purchase Agreement, dated as of November 30, 1984,
                  between Cogentrix of North Carolina, Inc. (then known as
                  Cogentrix Leasing Corporation) and Guilford Mills, Inc., as
                  amended (assigned to and assumed by Cogentrix Eastern Carolina
                  Corporation) (Kenansville Facility) (10.15). (*)(3)




                                       79
<PAGE>   80


    Designation Of
       Exhibit                   Description Of Exhibit
    --------------               ----------------------

         10.17    Steam Purchase Agreement, dated as of December 31, 1985, among
                  Cogentrix of North Carolina, Inc. (successor by merger to
                  Cogentrix Carolina Leasing Corporation) and Collins & Aikman
                  Corporation, as amended (Roxboro Facility) (10.16). (*)(3)

         10.18    Steam Purchase Agreement, dated as of December 31, 1985, among
                  Cogentrix of North Carolina, Inc. (successor by merger to
                  Cogentrix Carolina Leasing Corporation), Roxboro/Southport
                  General Partnership and Archer-Daniels-Midland Company (as
                  assignee of Pfizer Inc.), as amended (Southport Facility)
                  (10.17). (*)(3)

         10.19    Steam Purchase Agreement, dated as of January 31, 1986,
                  between Cogentrix of Virginia, Inc. and Allied-Signal Inc.
                  (then known as Allied Corporation), as amended (assigned to
                  and assumed by James River Cogeneration Company) (Hopewell
                  Facility) (10.18). (*)(3)

         10.20    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). (*)(3)

         10.21    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).
                  (*)(3)

         10.22    Lease Agreement dated as of September 21, 1993 between
                  Cogentrix of Pennsylvania, Inc. and Keystone Village Farms,
                  Inc., as amended (Ringgold Facility) (10.21). (*)(3)

         10.23    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). (*)(3)

         10.24    Coal Sales Agreement, dated as of November 15, 1991, among
                  Blue Crystal Sales Company, Bell County Coal Corporation and
                  Cogentrix Eastern Carolina Corporation (Elizabethtown,
                  Lumberton and Kenansville Facilities) (10.23). (*)(3)

         10.24(a) First Amendment to Coal Sales Agreement, dated as of April 17,
                  1995, between James River Coal Sales, Inc. (formerly named
                  Blue Crystal Coal Sales Company), Bell County Coal Corporation
                  and Cogentrix Eastern Carolina Corporation (Elizabethtown,
                  Lumberton and Kenansville Facilities) (10.1). (9)

         10.25    Coal Sales Agreement, dated as of March 11, 1986, between
                  Martiki Coal Corporation and Cogentrix of North Carolina, Inc.
                  (successor by merger to Cogentrix Carolina Leasing
                  Corporation) (Roxboro Facility) (10.24). (*)(3)

         10.26    Coal Sales Agreement, dated as of June 30, 1997, by and
                  between Pontiki Coal Corporation and Cogentrix of North
                  Carolina, Inc. (Roxboro Facility). (**)

         10.27    Coal Sales Agreement, dated as of May 19, 1986, among Coastal
                  Coal International Inc., Johnson Processing, Incorporated and
                  Cogentrix of North Carolina, Inc. (successor by merger to
                  Cogentrix Carolina Leasing Corporation) (Southport Facility)
                  (10.25). (*)(3)

         10.28    Coal Sales Agreement, dated as of June 30, 1997, by and
                  between MC Mining, Inc. and Cogentrix of North Carolina, Inc.
                  (Southport Facility). (**)

         10.29    Coal Sales Agreement, dated as of December 1, 1986, between
                  Pontiki Coal Corporation and Cogentrix of Virginia, Inc.
                  (assigned to and assumed by James River Cogeneration Company)
                  (Hopewell Facility) (10.26). (*)(3)

         10.30    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). (*)(3)

         10.30(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). (11)




                                       80
<PAGE>   81


    Designation Of
       Exhibit                   Description Of Exhibit
    --------------               ----------------------
         10.31    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). (*)(3)

         10.32    Gas Supply Contract, dated as of June 15, 1989, among
                  Cogentrix of Pennsylvania, Inc., Cogentrix, Inc. and J. C.
                  Enterprises, as amended (Ringgold Facility) (10.29). (1)

         10.33    Gas Sale and Purchase Agreement, dated as of September 8,
                  1989, between Eastern Marketing Corporation and Cogentrix of
                  Pennsylvania, Inc. (Ringgold Facility) (10.30). (1)

         10.34    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). (*)(3)

         10.35    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). (*)(3)

         10.36    Coal Supply Agreement, dated as of July 22, 1993, by and among
                  Birchwood Power Partners, L.P., AgipCoal Holding USA, Inc. and
                  AgipCoal Sales USA, Inc. (assigned to and assumed by Neweagle
                  Coal Sales Corp. and Neweagle Industries, Inc.), Laurel Creek
                  Co., Inc. and Rockspring Development, Inc. (Birchwood
                  Facility) (10.7). (*)(14)

         10.36(a) First Amendment to Coal Supply Agreement, dated as of May 18,
                  1994, by and among Birchwood Power Partners, L.P., Laurel
                  Creek Co., Inc., Rockspring Development, Inc., Neweagle Coal
                  Sales Corp. and Neweagle Industries, Inc. (Birchwood Facility)
                  (10.7(a)). (14)

         10.37    Railroad Transportation Contract, dated December 5, 1984,
                  between Cogentrix of North Carolina, Inc. (then known as
                  Cogentrix Leasing Corporation) and CSX Transportation, Inc.
                  (then known as The Chesapeake and Ohio Railway Company and
                  Seaboard System Railroad, Inc.), as amended (assigned to and
                  assumed by Cogentrix Carolina Leasing Corporation)
                  (Elizabethtown Facility) (10.33). (*)(3)

         10.37(a) Fifth Amendment to Railroad Transportation Contract, dated
                  January 21, 1994, between Cogentrix Eastern Carolina
                  Corporation and CSX Transportation, Inc. (Elizabethtown
                  Facility) (10.33(a)). (*)(3)

         10.37(b) Sixth Amendment to Railroad Transportation Contract, dated
                  August 23, 1995, between Cogentrix Eastern Carolina
                  Corporation and CSX Transportation, Inc. (Elizabethtown
                  Facility) (10.33(b)). (*)(10)

         10.38    Railroad Transportation Contract, dated December 5, 1984,
                  between Cogentrix of North Carolina, Inc. (then known as
                  Cogentrix Leasing Corporation) and CSX Transportation, Inc.
                  (then known as The Chesapeake and Ohio Railway Company and
                  Seaboard System Railway, Inc.), as amended (assigned to and
                  assumed by Cogentrix Eastern Carolina Corporation) (Lumberton
                  Facility) (10.34). (*)(3)

         10.38(a) Fifth Amendment to Railroad Transportation Contract, dated
                  January 21, 1994, between Cogentrix Eastern Carolina
                  Corporation and CSX Transportation, Inc. (Lumberton Facility)
                  (10.34(a)). (*)(3)

         10.38(b) Sixth Amendment to Railroad Transportation Contract, dated
                  August 23, 1995, between Cogentrix Eastern Carolina
                  Corporation and CSX Transportation, Inc. (Lumberton Facility)
                  (10.34(b)). (*)(10)

         10.39    Railroad Transportation Contract, dated December 5, 1984,
                  between Cogentrix of North Carolina, Inc. (then known as
                  Cogentrix Leasing Corporation) and CSX Transportation, Inc.
                  (then known as The Chesapeake and Ohio Railway Company and
                  Seaboard System Railway, Inc.), as amended (assigned to and
                  assumed by Cogentrix Eastern Carolina Corporation)
                  (Kenansville Facility) (10.35). (*)(3)

         10.39(a) Fifth Amendment to Railroad Transportation Contract, dated
                  January 21, 1994, between Cogentrix Eastern Carolina
                  Corporation and CSX Transportation, Inc. (Kenansville
                  Facility) (10.35(a)). (*)(3)




                                       81
<PAGE>   82


    Designation Of
       Exhibit                   Description Of Exhibit
    --------------               ----------------------
         10.39(b) Sixth Amendment to Railroad Transportation Contract, dated
                  August 23, 1995, between Cogentrix Eastern Carolina
                  Corporation and CSX Transportation, Inc. (Kenansville
                  Facility) (10.35(b)). (*)(10)

         10.40    Railroad Transportation Contract, dated as of July 15, 1986,
                  between Cogentrix of North Carolina, Inc. (successor by merger
                  to Cogentrix Carolina Leasing Corporation), and Norfolk
                  Southern Railway Company (Roxboro Facility) (10.36). (*)(3)

         10.41    Railroad Transportation Contract, dated as of June 23, 1997,
                  by and between Cogentrix of North Carolina, Inc. and Norfolk
                  Southern Railway Company (Roxboro Facility). (**)

         10.42    Railroad Transportation Contract, dated as of July 15, 1986,
                  between Cogentrix of North Carolina, Inc. (successor by merger
                  to Cogentrix Carolina Leasing Corporation) and CSX
                  Transportation, Inc. (then known as The Chesapeake and Ohio
                  Railway Company and Seaboard System Railroad, Inc.), as
                  amended (Southport Facility) (10.37). (*)(3)

         10.42(a) Sixth Amendment to Railroad Transportation Contract, effective
                  as of January 1, 1996, between Cogentrix of North Carolina,
                  Inc. and CSX Transportation, Inc. (Southport Facility)
                  (10.37(a)). (*)(13)

         10.43    Railroad Transportation Contract, dated as of June 30, 1997,
                  by and among Cogentrix of North Carolina, Inc. and CSX
                  Transportation, Inc. (Southport Facility). (**)

         10.44    Railroad Transportation Contract, dated as of December 15,
                  1986, between Cogentrix of Virginia, Inc., and Norfolk
                  Southern Railway Company, as amended (assigned to and assumed
                  by James River Cogeneration Company) (Hopewell Facility)
                  (10.38). (*)(3)

         10.45    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). (*)(3)

         10.46    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)

         10.47    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). (*)(3)

         10.47(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)). (10)

         10.47(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)). (13)

         10.47(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). (14)

         10.47(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).

         10.48    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). (*)(3)

         10.48(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). (8)

         10.49    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). (*)(3)




                                       82
<PAGE>   83


    Designation Of
       Exhibit                   Description Of Exhibit
    --------------               ----------------------
         10.49(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). (8)

         10.49(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)). (*)(13)

         10.50    Coal Transportation Agreement, dated as of July 22, 1993,
                  between Birchwood Power Partners, L.P. and ER&L-Birchwood,
                  Inc. (Birchwood Facility) (10.8). (*)(14)

         10.50(a) First Amendment to Coal Transportation Agreement, dated as of
                  April 28, 1994, between Birchwood Power Partners, L.P. and
                  ER&L Birchwood, Inc. (Birchwood Facility) (10.8(a)). (*)(14)

         10.51    Amended and Restated Senior Term Loan Agreement, dated as of
                  September 24, 1996, among Cogentrix Eastern Carolina
                  Corporation, the Lenders party thereto, Credit Lyonnais New
                  York Branch, as Issuing Bank and Agent (Elizabethtown,
                  Lumberton and Kenansville Facilities) (10.44). (13)

         10.52    Amended and Restated Senior Term Loan Agreement and Guarantee,
                  dated as of September 24, 1996, among United States Trust
                  Company of New York, as Roxboro Owner Trustee, United States
                  Trust Company of New York, as Southport Owner Trustee, United
                  States Trust Company of New York in its individual capacity
                  only to the extent expressly provided therein, Cogentrix of
                  North Carolina, Inc., Roxboro/Southport General Partnership,
                  Credit Lyonnais New York Branch, as Lender, Administrative
                  Agent and Issuing Bank, and the other lenders party thereto
                  (Roxboro and Southport Facilities) (10.45). (13)

         10.53    Second Amended and Restated Application for Letter of Credit
                  and Reimbursement Agreement, dated as of July 1, 1996, among
                  James River Cogeneration Company, the Banks named therein, and
                  Banque Paribas, New York Branch, as Agent (Hopewell Facility)
                  (10.46). (13)

         10.54    Second Amended and Restated Loan Agreement, dated as of May
                  15, 1992, among Cogentrix Virginia Leasing Corporation, the
                  lenders party thereto and The CIT Group/Equipment Financing,
                  Inc., as Agent, as amended (Portsmouth Facility) (10.51). (1)

         10.55    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)

         10.55(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). (12)

         10.55(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)). (13)

         10.56    Construction and Term Loan Agreement, dated as of June 15,
                  1989, among Cogentrix of Pennsylvania, Inc., the lenders party
                  thereto and Banque Paribas, New York Branch, as Agent, as
                  amended (Ringgold Facility) (10.53). (1)

         10.57    Convertible Subordinated Note dated April 1, 1991 of Cogentrix
                  of Pennsylvania, Inc. payable to Westinghouse Credit
                  Corporation (10.54). (1)




                                       83
<PAGE>   84


    Designation Of
       Exhibit                   Description Of Exhibit
    --------------               ----------------------
         10.58    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)

         10.58(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)). (10)

         10.58(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)). (10)

         10.58(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). (12)

         10.59    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)

         10.60    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)

         10.61    Loan and Reimbursement Agreement, dated as of May 18, 1994,
                  among Birchwood Power Partners, L.P., the Banks party thereto,
                  John Hancock Mutual Life Insurance Company, Allstate Insurance
                  Company, New York Life Insurance Company and the other
                  Institutions party thereto, Banque Paribas, New York Branch,
                  Barclays Bank PLC, Credit Suisse, Union Bank of California, as
                  Co-Agents for the Banks and Credit Suisse, as Issuing Bank and
                  as Administrative Agent for the Banks (Birchwood Facility)
                  (10.1). (14)

         10.62    Security Deposit and Intercreditor Agreement, dated as of May
                  18, 1994, among Birchwood Power Partners, L.P., the Secured
                  Parties named therein and Credit Suisse, as Security Agent
                  (Birchwood Facility) (10.2). (14)

         10.63    First Amendment to Composite Amendment and Consent to Project
                  Loan Agreement and Security Deposit Agreement, among Birchwood
                  Power Partners, L.P. and the persons party to the Loan and
                  Reimbursement Agreement, dated as of May 18, 1994, as amended,
                  and the Security Deposit and Intercreditor Agreement, dated as
                  of May 18, 1994, as amended (Birchwood Facility) (10.3). (14)

         10.64    Greenhouse Restructure Amendment, dated as of March 27, 1997,
                  to the Loan and Reimbursement Agreement, the Security Deposit
                  and Intercreditor Agreement, the Loan and Contribution
                  Agreement and the Steam Sales Agreement, among the parties
                  obligated under such agreements (Birchwood Facility).

         10.65    Amended and Restated Security Deposit Agreement, dated as of
                  September 24, 1996, among Cogentrix Eastern Carolina
                  Corporation, Credit Lyonnais New York Branch, as Senior Debt
                  Agent and Issuing Bank and The Chase Manhattan Bank, as
                  Security Agent (Elizabethtown, Lumberton and Kenansville
                  Facilities) (10.54). (13)




                                       84
<PAGE>   85


    Designation Of
       Exhibit                   Description Of Exhibit
    --------------               ----------------------
         10.66    Amended and Restated Security Deposit Agreement, dated as of
                  September 24, 1996, among United States Trust Company of New
                  York, as Roxboro Owner Trustee, United States Trust Company of
                  New York, as Southport Owner Trustee, Cogentrix of North
                  Carolina, Inc., Roxboro/Southport General Partnership, Credit
                  Lyonnais New York Branch, as Administrative Agent and Issuing
                  Bank, and The Chase Manhattan Bank, as Security Agent (Roxboro
                  and Southport Facilities) (10.55). (13)

         10.67    Second Amended and Restated Security Deposit Agreement, dated
                  as of July 1, 1996, among James River Cogeneration Company,
                  Cogentrix of Virginia, Inc., Banque Paribas, New York Branch,
                  as Grantee, and First Union National Bank of North Carolina,
                  as Security Agent (Hopewell Facility) (10.56). (13)

         10.68    Second Amended and Restated Security Deposit Agreement, dated
                  as of May 15, 1992, among Cogentrix Virginia Leasing
                  Corporation, Cogentrix, Inc., The CIT Group/Equipment
                  Financing, Inc., as Agent and First Union National Bank of
                  North Carolina, as Security Agent, as amended (Portsmouth
                  Facility) (10.64). (1)

         10.69    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)

         10.70    Security Deposit Agreement, dated as of June 15, 1989, among
                  Cogentrix of Pennsylvania, Inc., Banque Paribas, New York
                  Branch, as Bank Agent and First Union National Bank of North
                  Carolina, as Security Agent (Ringgold Facility) (10.66). (1)

         10.71    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)

         10.71(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)). (3)

         10.72    Stock Pledge and Security Agreement, dated as of September 24,
                  1996, made by Cogentrix, Inc. in favor of Credit Lyonnais New
                  York Branch, as Agent (Elizabethtown, Lumberton and
                  Kenansville Facilities) (10.61). (13)

         10.73    Stock Pledge and Security Agreement, dated as of September 24,
                  1996, made by Cogentrix of North Carolina Holdings, Inc. in
                  favor of Credit Lyonnais New York Branch, as Administrative
                  Agent (Roxboro and Southport Facilities) (10.62). (13)

         10.74    Stock Pledge and Security Agreement, dated as of September 24,
                  1996, made by Roxboro/Southport I, Inc. in favor of Credit
                  Lyonnais New York Branch, as Administrative Agent (Roxboro and
                  Southport Facilities) (10.63). (13)

         10.75    General Partner Assignment and Security Agreement, dated as of
                  September 24, 1996, made by Roxboro/Southport II, Inc. in
                  favor of Credit Lyonnais New York Branch, as Administrative
                  Agent (Roxboro and Southport Facilities) (10.64). (13)

         10.76    General Partner Assignment and Security Agreement, dated as of
                  September 24, 1996, made by Roxboro/Southport I, Inc. in favor
                  of Credit Lyonnais New York Branch, as Administrative Agent
                  (Roxboro and Southport Facilities) (10.65). (13)

         10.77    Stock Pledge Agreement, dated as of December 1, 1986, between
                  Cogentrix, Inc., as Pledgor and Banque Paribas, New York
                  Branch, as Agent, as amended (Hopewell Facility) (10.78). (1)

         10.77(a) Amendment No. 2 to Pledge and Security Agreement, dated as of
                  July 1, 1996, made by Cogentrix, Inc., as Pledgor to Banque
                  Paribas, New York Branch, as Grantee (Hopewell Facility)
                  (10.66(a)). (13)




                                       85
<PAGE>   86


    Designation Of
       Exhibit                   Description Of Exhibit
    --------------               ----------------------
         10.78    Assignment and Security Agreement dated as of October 1, 1987
                  between Cogentrix of Virginia, Inc. and Banque Paribas, New
                  York Branch, as Grantee, as amended (Hopewell Facility)
                  (10.79). (1)

         10.78(a) Amendment No. 2 to Assignment and Security Agreement dated as
                  of July 1, 1996, between Cogentrix of Virginia, Inc. and
                  Banque Paribas, New York Branch, as Grantee (Hopewell
                  Facility) (10.67(a)). (13)

         10.79    Second Amended and Restated Pledge Agreement, dated as of May
                  15, 1992, between Cogentrix, Inc., as Pledgor and The CIT
                  Group/Equipment Financing, Inc., as Agent (Portsmouth
                  Facility) (10.80). (1)

         10.80    Pledge Agreement, dated as of June 15, 1989, between
                  Cogentrix, Inc., as Pledgor and Banque Paribas, New York
                  Branch, as Agent (Ringgold Facility) (10.81). (1)

         10.81    Amended and Restated Stock Pledge Agreement, dated as of
                  November 19, 1996, by and between Cogentrix/Birchwood Two,
                  L.P., as Pledgor, and Birchwood Power Partners, L.P., as
                  Lender (Birchwood Facility) (10.4). (14)

         10.82    Ground Lease, dated as of August 23, 1984, between Cogentrix
                  of North Carolina, Inc. (then known as Cogentrix Leasing
                  Corporation) and West Point Stevens Inc. (then known as West
                  Point-Pepperell, Inc.), as amended (assigned to and assumed by
                  Cogentrix Eastern Carolina Corporation) (Elizabethtown
                  Facility) (10.82). (1)

         10.83    Ground Lease, dated as of August 23, 1984, between Cogentrix
                  of North Carolina, Inc. (then known as Cogentrix Leasing
                  Corporation) and West Point Stevens Inc. (then known as West
                  Point-Pepperell, Inc.), as amended (assigned to and assumed by
                  Cogentrix Eastern Carolina Corporation) (Lumberton Facility)
                  (10.83). (1)

         10.84    Ground Lease, dated as of November 30, 1984, between Cogentrix
                  of North Carolina, Inc. (then known as Cogentrix Leasing
                  Corporation) and Guilford Mills, Inc., as amended (assigned to
                  and assumed by Cogentrix Eastern Carolina Corporation)
                  (Kenansville Facility) (10.84). (1)

         10.85    Lease (SBD 9284; RE-81558) from Seaboard System Railroad, Inc.
                  to Cumberland Elkhorn Coal and Coke, Inc., dated December 17,
                  1985, assigned by Cumberland Elkhorn Coal & Coke, Inc. to
                  Oxbow Carbon and Minerals Inc. and further assigned by Oxbow
                  Carbon & Minerals, Inc. to Cogentrix Eastern Carolina
                  Corporation, as amended (Kenansville Facility) (10.85). (1)

         10.86    Lease (SBD 8074; RE-81558) from Seaboard System Railroad, Inc.
                  to Cumberland Elkhorn Coal & Coke, Inc., dated October 4,
                  1985, assigned by Cumberland Elkhorn Coal & Coke, Inc. to
                  Oxbow Carbon and Minerals Inc. and further assigned by Oxbow
                  Carbon & Minerals, Inc. to Cogentrix Eastern Carolina
                  Corporation, as amended (Kenansville Facility) (10.86). (1)

         10.87    Agreement (SBD 8801; RE-81558) dated October 2, 1985, as
                  amended, between CSX Transportation, Inc. (as successor to the
                  rights and obligations of Seaboard System Railroad, Inc.), and
                  Cogentrix Eastern Carolina Corporation (as successor to the
                  rights of Oxbow Carbon & Minerals, Inc., which succeeded to
                  the rights and obligations of Cumberland Elkhorn Coal & Coke,
                  Inc. by assignment), as amended (Kenansville Facility)
                  (10.87). (1)

         10.88    Agreement (SBD 10257; RE-83767) dated June 18, 1986, as
                  amended, between CSX Transportation, Inc. (as successor to the
                  rights and obligations of Seaboard System Railroad, Inc.), and
                  Cogentrix Eastern Carolina Corporation (as successor to the
                  rights of Oxbow Carbon & Minerals, Inc., which succeeded to
                  the rights and obligations of Cumberland Elkhorn Coal & Coke,
                  Inc. by assignment), as amended (Elizabethtown and Lumberton
                  Facilities) (10.88). (1)

         10.89    Lease Agreement, dated as of November 10, 1987, between United
                  States Trust Company of New York, as Roxboro Owner Trustee, as
                  Lessor, and Cogentrix of North Carolina, Inc. (successor by
                  merger to Cogentrix Carolina Leasing Corporation), as Lessee,
                  as amended (Roxboro Facility) (10.89). (1)




                                       86
<PAGE>   87


    Designation Of
       Exhibit                   Description Of Exhibit
    --------------               ----------------------
         10.89(a) Fourth Amendment to Lease Agreement, dated as of September 24,
                  1996, between United States Trust Company, as Roxboro Owner
                  Trustee and Cogentrix of North Carolina, Inc. (Roxboro
                  Facility) (10.77(a)). (13)

         10.90    Lease Agreement, dated as of November 10, 1987, between United
                  States Trust Company of New York, as Southport Owner Trustee,
                  as Lessor, and Cogentrix of North Carolina, Inc. (successor by
                  merger to Cogentrix Carolina Leasing Corporation), as Lessee,
                  as amended (Southport Facility) (10.90). (1)

         10.90(a) Fourth Amendment to Lease Agreement, dated as of September 24,
                  1996, between United States Trust Company, as Southport Owner
                  Trustee and Cogentrix of North Carolina, Inc. (Southport
                  Facility) (10.78(a)). (13)

         10.91    Ground Lease, dated as of December 31, 1985, between United
                  States Trust Company, as Roxboro Owner Trustee, as Lessee, and
                  Cogentrix of North Carolina, Inc. (successor by merger to
                  Cogentrix Carolina Leasing Corporation), as Lessor (Roxboro
                  Facility) (10.91). (1)

         10.92    Amended and Restated Ground Lease, dated as of December 31,
                  1985, between Carolina Power & Light Company, as Lessor, and
                  Cogentrix of North Carolina, Inc. (successor by merger to
                  Cogentrix Carolina Leasing Corporation), as Lessee, as amended
                  (Southport Facility) (10.92). (1)

         10.93    Ground Lease, dated January 31, 1986, between Allied-Signal,
                  Inc., as Lessor, and Cogentrix of Virginia, Inc., as Lessee,
                  as amended (assigned to and assumed by James River
                  Cogeneration Company) (Hopewell Facility) (10.93). (1)

         10.94    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)

         10.95    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)

         10.96    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)

         10.97    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)

         10.98    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)

         10.99    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)

         10.100   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)

         10.101   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)

         10.102   Form of Profit-Sharing Plan (I) (10.102). (1)

         10.103   Form of Profit-Sharing Plan (II) (10.103). (1)

         10.104   Executive Incentive Bonus Plan (10.104). (3)

         10.105   Facility Cash Flow Incentive Compensation Agreement with
                  Robert W. Lewis (10.105). (1)

         10.106   General Partnership Agreement dated as of September 30, 1987
                  between Cogentrix of Virginia, Inc. and Capistrano
                  Cogeneration Company (10.110). (1)


                                       87
<PAGE>   88


    Designation Of
       Exhibit                   Description Of Exhibit
    --------------               ----------------------
         10.107   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)

         10.108   Employment Agreement, dated as of June 24, 1994, between David
                  J. Lewis and Cogentrix Energy, Inc. (10.115). (5)

         10.109   Employment Agreement, dated as of May 1, 1997, between Mark F.
                  Miller and Cogentrix Energy, Inc.

         10.110   Power Purchase Agreement, dated as of September 30, 1994,
                  between Mangalore Power Company and Karnataka Electricity
                  Board (Phase One Facility) (10.1). (6)

         10.111   Power Purchase Agreement, dated as of September 30, 1994,
                  between Mangalore Power Company and Karnataka Electricity
                  Board (Phase Two Facility) (10.2). (6)

         10.112   Transaction Agreement by and among SEI Birchwood, Inc.,
                  Birchwood Development Corp., Birchwood Power Partners, L.P.,
                  Cogentrix/Birchwood Two, L.P. and Cogentrix Energy, Inc.,
                  dated as of November 23, 1994 (Birchwood Facility) (2.1). (7)

         10.113   Engineering, Procurement and Construction Agreement, dated as
                  of December 8, 1994, between Cogentrix Energy, Inc. and Public
                  Utility District No. 1 of Clark County, Washington, together
                  with Letter Agreement, dated January 18, 1995 (Clark Facility)
                  (10.1). (8)

         10.114   Development and Engineering Agreement, dated as of December 8,
                  1994, between Cogentrix of Vancouver, Inc. and Public Utility
                  District No. 1 of Clark County, Washington (Clark Facility)
                  (10.2). (8)

         10.115   Operation and Maintenance Agreement, dated as of December 8,
                  1994, between Cogentrix of Vancouver, Inc. and Public Utility
                  District No. 1 of Clark County, Washington (Clark Facility)
                  (10.3). (8)

         10.116   Amended and Restated Facility Operations and Maintenance
                  Agreement, dated as of May 18, 1994, between Southern Electric
                  International, Inc. and Birchwood Power Partners, L.P.
                  (Birchwood Facility) (10.5). (*)(14)

         10.117   Amended and Restated Limited Partnership Agreement of
                  Birchwood Power Partners, L.P., dated December 15, 1994
                  (10.6). (8)

         10.118   Equity Contribution Agreement, dated as of December 15, 1994,
                  among Cogentrix Energy, Inc., Cogentrix Delaware Holdings,
                  Inc., Birchwood Power Partners, L.P., and Credit Suisse
                  (Birchwood Facility) (10.9). (8)

         10.119   Limited Partner Pledge Agreement, dated as of December 15,
                  1994, made by Cogentrix/Birchwood Two, L.P. in favor of Credit
                  Suisse (Birchwood Facility) (10.10). (8)

         10.120   General Partner Pledge Agreement, dated as of December 15,
                  1994, made by Cogentrix/Birchwood Two, L.P. in favor of Credit
                  Suisse (Birchwood Facility) (10.11). (8)

         10.121   Agreement of Limited Partnership of Rathdrum Generation
                  Partners Limited Partnership, dated as of November 3, 1994, by
                  and among BTU Energy I, Inc. and Cogentrix of Rathdrum I,
                  Inc., as General Partners, and BTU Energy II, Inc. and
                  Cogentrix of Rathdrum II, Inc., as Limited Partners (10.131).
                  (10)

         10.122   Supplemental Retirement Savings Plan (10.132). (10)

         10.123   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). (10)

         10.124   Consulting and Noncompetition Employment Agreement, dated as
                  of August 11, 1995, between Cogentrix Energy, Inc. and George
                  T. Lewis, Jr. (10.135). (10)

         10.125   Joint Development Agreement, dated as of July 14, 1995,
                  between Cogentrix Mauritius Company and Malconna Company
                  Limited (10.136). (*)(10)

         10.126   Support Agreement, dated as of July 14, 1995, from Cogentrix
                  Energy, Inc. to Malconna Company Limited (10.137). (10)




                                       88
<PAGE>   89


    Designation Of
       Exhibit                   Description Of Exhibit
    --------------               ----------------------
         10.127   Working Capital Letter of Credit and Reimbursement Agreement,
                  dated as of October 30, 1995, by and between Cogentrix Energy,
                  Inc. and First Union National Bank of North Carolina (10.3).
                  (11)

         10.128   Pledge and Security Agreement, dated as of October 30, 1995,
                  by and between Cogentrix Energy, Inc. and First Union National
                  Bank of North Carolina (10.4). (11)

         10.129   Credit Agreement, dated as of May 22, 1997, among Cogentrix
                  Energy, Inc., the several Lenders from time to time parties
                  thereto and Australia and New Zealand Banking Group Limited,
                  as Agent and as the Issuing Bank.

         10.130   Guarantee, dated as of May 22, 1997, made by Cogentrix
                  Delaware Holdings, Inc., the Guarantor, in favor of the
                  Borrower Creditors.

         10.131   Agreement of Limited Partnership of Village Farms of Texas,
                  L.P., dated as of February 6, 1996, by and among Cogentrix of
                  Fort Davis I, Inc. and Village Farms of Delaware, L.L.C., as
                  General Partners, and Cogentrix of Fort Davis II, Inc. and
                  Village Farms, L.L.C., as Limited Partners (10.6). (*)(12)

         10.132   Guaranty, dated as of February 14, 1996, made by Cogentrix
                  Energy, Inc. in favor of Farm Credit Bank of Texas and Texas
                  Production Credit Association, as Lenders, and CoBank, ACB, as
                  Administrative Agent, to guarantee certain obligations of
                  Village Farms of Texas, L.P. (10.7). (12)

         10.133   Agreement of Limited Partnership, dated as of March 10, 1997,
                  of Pocono Village Farms, L.P. by and among Cogentrix of
                  Pocono, Inc., Cogentrix Greenhouse Investments, Inc., Village
                  Farms of Delaware, L.L.C. and Village Farms, L.L.C. (10.1).
                  (15)

         10.134   Agreement of Limited Partnership, dated as of June 4, 1997, of
                  Village Farms of Marfa, L.P. by and among Cogentrix of Marfa,
                  Inc., Cogentrix Greenhouse Investments, Inc., Village Farms of
                  Delaware, L.L.C. and Village Farms, L.L.C. (**)

         10.135   Agreement of Limited Partnership, dated as of September 4,
                  1997, of Village Farms of Buffalo, L.P. by and among Cogentrix
                  of Buffalo, Inc., Cogentrix Greenhouse Investments, Inc.,
                  Village Farms of Delaware, L.L.C. and Village Farms, L.L.C.
                  (**)

         21.1     Direct and Indirect Subsidiaries of Cogentrix Energy, Inc.

         27       Financial Data Schedule, which is submitted electronically to
                  the Securities and Exchange Commission for information only
                  and is not filed.

----------------------------
(*)      Portions of these agreements have been deleted pursuant to previously
         approved requests for confidential treatment.
(**)     Portions of these agreements have been deleted pursuant to a request
         for confidential treatment 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. 1 to Registration Statement
         on Form S-1 (File No. 33-74254) filed February 24, 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 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.
(4)      Incorporated by reference to the Form 10-Q (File No. 33-74254) filed
         May 16, 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.
(5)      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.




                                       89
<PAGE>   90


(6)      Incorporated by reference to the Form 10-Q (File No. 33-74254) filed
         November 14, 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.
(7)      Incorporated by reference to the Form 8-K (File No. 33-74254) filed
         December 29, 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.
(8)      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.
(9)      Incorporated by reference to the Form 10-Q (File No. 33-74254) filed
         May 16, 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.
(10)     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.
(11)     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.
(12)     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.
(13)     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.
(14)     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.
(15)     Incorporated by reference to the Form 10-Q (File No. 33-74254) filed
         May 15, 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.


         (b)      Reports on Form 8-K.

                  There were no reports on Form 8-K filed during the fourth
                  quarter ended June 30, 1997.





                                       90
<PAGE>   91


SIGNATURES.

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

                                        COGENTRIX ENERGY, INC.
                                             (Registrant)


Date:    September 29, 1997             By: /s/ David J. Lewis
                                            David J. Lewis
                                            Vice Chairman of the Board,
                                            Chief Executive Officer and Director
                                            (Principal Executive Officer)

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

<TABLE>
<CAPTION>
         Signature                                           Title                               Date
         ---------                                           -----                               ----
<S>                                         <C>                                           <C> 
        /s/ George T. Lewis, Jr.            Chairman of the Board and Director            September 29, 1997
        George T. Lewis, Jr.

        /s/ David J. Lewis                  Vice Chairman of the Board, Chief             September 29, 1997
        David J. Lewis                          Executive Officer and Director

        /s/ Mark F. Miller                  President, Chief Operating Officer            September 29, 1997
        Mark F. Miller                          and Director

        /s/ Betty G. Lewis                  Director                                      September 29, 1997
        Betty G. Lewis

        /s/ James E. Lewis                  Executive Vice President and Director         September 29, 1997
        James E. Lewis

        /s/ Robert W. Lewis                 Director                                      September 29, 1997
        Robert W. Lewis

        /s/ Dennis W. Alexander             Group Senior Vice President, General          September 29, 1997
        Dennis W. Alexander                     Counsel, Secretary and Director

        /s/ W. E. Garrett                   Director                                      September 29, 1997
        W. E. Garrett

        /s/ James R. Pagano                 Group Senior Vice President,                  September 29, 1997
        James R. Pagano                         Chief Financial Officer
                                                (Principal Financial Officer)

        /s/ Thomas F. Schwartz              Vice President - Finance and Treasurer        September 29, 1997
        Thomas F. Schwartz                      (Principal Accounting Officer)
</TABLE>



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