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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 DECEMBER 31, 1999
Commission File Number: 33-67171
COGENTRIX DELAWARE HOLDINGS, INC.
(Exact name of registrant as specified in its charter)
DELAWARE 51-0352024
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
1105 NORTH MARKET STREET, SUITE 1108
WILMINGTON, DELAWARE 19801
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (302) 427-9635
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.
Yes [X] No [ ]
Indicate by checkmark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
Number of shares of Common Stock, no par value, outstanding at March 30, 2000:
1,000
DOCUMENTS INCORPORATED BY REFERENCE: NONE
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COGENTRIX DELAWARE HOLDINGS, INC.
INDEX TO ANNUAL REPORT ON FORM 10-K
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PART I
ITEM 1. BUSINESS......................................................................................1
ITEM 2. PROPERTIES...................................................................................20
ITEM 3. LEGAL PROCEEDINGS............................................................................21
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS..........................................21
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED SHAREHOLDER MATTERS.....................21
ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA.........................................................21
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS........23
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA..................................................32
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.........58
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT..........................................58
ITEM 11. EXECUTIVE COMPENSATION......................................................................58
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT..............................58
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS..............................................58
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.............................59
SIGNATURES............................................................................................66
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PART I
ITEM 1. BUSINESS
INTRODUCTION
Cogentrix Delaware Holdings, Inc. is a holding company that through its
direct and indirect subsidiaries acquires, develops, owns and operates electric
generating plants, principally in the United States. We derive most of our
revenue from the sale of electricity, but we also produce and sell steam. We
sell the electricity we generate, primarily under long-term power purchase
agreements, to regulated electric utilities and power marketers. We sell the
steam we produce to industrial customers with manufacturing or other facilities
located near our electric generating plants. We were one of the early
participants in the market for electric power generated by independent power
producers that developed as a result of energy legislation the United States
Congress enacted in 1978. We believe we are one of the larger independent power
producers in the United States based on our total project megawatts in
operation.
We currently own -- entirely or in part -- a total of 25 electric
generating facilities in the United States. Our 25 plants are designed to
operate at a total production capability of approximately 4,000 megawatts. After
taking into account our part interests in the 16 plants that are not
wholly-owned by us, which range from 1.7% to approximately 74%, our net
ownership interests in the total production capability of our 25 electric
generating facilities is approximately 1,840 megawatts. We currently operate 12
of our facilities, 10 of which we developed and constructed.
We also have an ownership interest in and will operate three facilities
currently under construction in Mississippi, Oklahoma and Idaho. Once these
facilities begin operation, we will have ownership interests in a total of 28
domestic electric generating facilities that are designed with a total
production capability of approximately 5,870 megawatts. Our net equity interest
in the total production capability of those 28 facilities will be approximately
3,190 megawatts.
Unless the context requires otherwise, references in this report to "we,"
"us," "our," or "Holdings" refer to Cogentrix Delaware Holdings, Inc. and its
subsidiaries, including subsidiaries that hold investments in other corporations
or partnerships whose financial results are not consolidated with ours. The term
"Cogentrix" refers only to Cogentrix Energy, Inc., the parent of Holdings, which
is a development and management company that conducts its business primarily
through subsidiaries, most of which are subsidiaries of Holdings. Holdings'
subsidiaries that are engaged in the development, ownership or operation of
cogeneration facilities are sometimes referred to individually as a "project
subsidiary" and collectively as "project subsidiaries."
TRENDS AFFECTING THE DOMESTIC ELECTRIC GENERATING INDUSTRY AND OUR BUSINESS
Increasing Competition in the Domestic Electric Generating Industry
In response to increasing customer demand for access to low-cost electricity
and enhanced services, new regulatory initiatives are currently being adopted or
considered at both state and federal levels to increase competition in the
domestic electric generating industry. We believe that these regulatory
initiatives will lead to the transformation of the existing regulated market,
which sells to a captive customer base, to a more competitive market in which
end users may purchase electricity from a variety of suppliers, including
non-utility generators, power marketers, public utilities and others. Our
management believes that these market trends will create significant new
business opportunities for us because we have demonstrated our ability to
construct and operate efficient, low-cost electric generating facilities.
Growing Market for Sale of Electric Generating Assets
Regulatory initiatives to restructure the United States electric industry
have led to the development of a growing market for the sale of electric
generating assets principally by utilities, but also by independent power
producers and industrial companies. In addition to regulatory pressure, some
utilities' managements have decided for strategic reasons to sell some or all of
their generating assets and to concentrate on the transmission and distribution
segments of the power supply market. If this trend continues, it may create
additional investment opportunities for us. In connection with acquiring --
entirely or in part -- any additional electric generating assets, we expect to
reduce our exposure to electric market price risk by entering into contractual
arrangements with fuel suppliers, utilities and/or power marketers under which
they would assume some or all of the risks associated with fluctuations in
energy prices.
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Expansion of Our Options Resulting from Passage of the Energy Policy Act
The passage of the Energy Policy Act in 1992 significantly expanded the
options available to independent power producers, particularly with respect to
siting a generating facility. Among other things, The Energy Policy Act enables
independent power producers to obtain an order from the Federal Energy
Regulatory Commission requiring an intermediary utility to give access to its
transmission lines to transmit or "wheel" electric power from a generating
facility to its utility purchaser. The availability of wholesale transmission
"wheeling" could be an important aspect in the development of new projects. For
example, we may be able to develop a project in one utility's service territory
and "wheel" the electric power produced by the project through the transmission
lines of that utility to a second utility or another wholesale purchaser. The
Energy Policy Act also created a new class of generator -- exempt wholesale
generators -- that, unlike qualifying facilities, are not required to use
alternative or renewable fuels or to have useful thermal energy output.
See "Regulation -- Energy Regulations" herein.
OUR DEVELOPMENT AND ACQUISITION STRATEGY
We intend to remain among the leaders in the independent power industry by
developing and constructing or acquiring - entirely or in part - electric
generating facilities in the United States.
We have targeted three market segments for our future acquisition and
development activities. They are:
o Developing new, electric generating facilities using natural gas as fuel
o Acquiring interests in existing domestic electric generating plants
o Developing, owning, managing and operating on-site cogenerating
facilities for large industrial customers with significant energy needs
Developing New Electric Generating Plants. We intend to pursue domestic
development of new, highly-efficient, low-cost plants, concentrating on
mid-sized facilities that use natural gas as fuel. We expect these facilities to
enter into long-term contractual arrangements with fuel suppliers, electric
utilities or power marketers. These contractual arrangements will provide us a
scheduled and/or indexed payment for electricity and result in the fuel
supplier, electric utility or power marketer assuming the risks associated with
energy price fluctuations.
Acquiring Interests in Existing Domestic Electric Generating Plants. Our
candidates for future acquisitions will generally already have entered into
power sales contracts with electric utilities or other customers whose senior
unsecured debt carries investment-grade credit ratings. We may also seek to
acquire interests in electric generating facilities that do not have contracts
in place but are nonetheless highly efficient, low-cost providers that can take
advantage of opportunities in a rapidly deregulating energy market. If we do, we
intend to protect Holdings against the risk of changes in the market price for
electricity by entering into contracts at the time of acquisition with fuel
suppliers, utilities or power marketers which reduce or eliminate our exposure
to this risk by establishing future prices and quantities for the electricity
produced independent of the short-term market.
Developing New or Managing Existing Plants for Industrial Companies. Many
large, industrial companies with significant energy needs own on-site facilities
for generating the electricity and producing the steam they require for their
manufacturing, refining or other operations. We believe that cogenerating
facilities with state-of-the-art technology developed by us could replace or
upgrade existing facilities employing older technology that many of these
industrial companies currently operate themselves. We also expect that many
industrial companies choosing not to replace their existing facilities will seek
to contract with companies like Holdings to manage and operate their existing
facilities.
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We are concentrating on opportunities to develop or acquire interests in
mid-sized electric generating facilities which use low-cost, state-of-the-art
proven technology. We target projects that will allow us to capitalize on our
reputation as a low-cost, efficient and reliable provider. We seek to manage the
risks associated with owning and operating electric generating facilities by
emphasizing diversification and balance among our investments in terms of the
following criteria:
o the geographic location of the facilities in which we have an ownership
interest
o the electric utility or power marketing customers for the electricity we
generate and the industrial customers for the steam we produce
o the technology we employ to generate electricity and produce steam
o the coal, gas and other fuel suppliers to our plants
PROJECTS UNDER DEVELOPMENT
Rathdrum, Idaho Project. We are developing jointly with Avista Power, Inc.
a 270 megawatt electric generating facility to be located in Rathdrum, Idaho.
Avista Turbine Power, Inc. will deliver natural gas to the plant and purchase
the electrical output of the facility under a 25-year power purchase agreement.
Holdings will have a 51% ownership interest and Avista Power will have a 49%
ownership interest in the facility. We will have the lead role for the
development, construction and operation of the facility.
Subsequent to December 31, 1999, we closed the financing with a bank and
financial institution on a $126 million construction loan to fund the
construction of the facility in Rathdrum, Idaho. We have begun construction and
expect commercial operations to commence in the third quarter of 2001.
PROJECT AGREEMENTS, FINANCING AND OPERATING ARRANGEMENTS FOR OUR FACILITIES
Project Agreements
Our facilities have long-term power sales agreements to sell electricity to
electric utilities and power marketers. A facility's revenue from a power sales
agreement usually consists of two components: variable payments, which vary in
accordance with the amount of energy the facility produces, and fixed payments,
which are received in the same amounts whether or not the facility is producing
energy. Variable payments, which are generally intended to cover the costs of
actually generating electricity, such as fuel costs, if supplied by the
operating facility, and variable operation and maintenance expense, are based on
a facility's net electrical output measured in kilowatt hours. Variable payment
rates are either scheduled or indexed to the fuel costs of the electricity
purchaser and/or an inflationary index.
Fixed payments, which are intended to compensate us for the costs incurred
by the project subsidiary whether or not it is generating electricity, such as
debt service on the project financing, are more complex and are calculated based
on a declared production capability of a facility. Declared production
capability is the electric generating capability of a plant in megawatts that
the project subsidiary contractually agrees to make available to the electricity
purchaser. It is generally less than 100% of the facility's design production
capability dictated by its equipment and design specifications. Fixed payments
are based either on a facility's net electrical output and paid on a
kilowatt-hour basis or on the facility's declared production capability and can
be adjusted if actual production capability varies significantly from declared
production capability.
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Many power sales agreements permit the electricity purchaser to direct the
facility to deliver a variable amount of electrical output within limited
parameters. This means the purchaser may, within those parameters, direct the
facility to reduce or suspend the delivery of electricity. The power sales
agreements of substantially all our facilities provide the electricity purchaser
with the right to reduce or suspend their purchases of electricity whenever they
determine that they can obtain lower cost power either by generating power at
their own plants or by purchasing electricity in bulk from others. The power
sales agreements for these facilities are structured in a manner such that when
the amount of electrical output is reduced, the facility continues to receive
the fixed payments, which cover fixed operating costs and debt service
requirements and provide substantially all of the project subsidiary's profits.
The variable payments, which cover the operating, maintenance and fuel costs
incurred by the operating subsidiary to generate electricity, are received only
for each kilowatt hour delivered.
With some exceptions, our facilities produce process steam for use by an
industrial customer which has a manufacturing or other facility located nearby.
Our industrial customers, which include textile manufacturing companies,
pharmaceutical manufacturing companies, chemical producers and synthetic fiber
plants, use the process steam in their manufacturing processes. Our steam sales
contracts with these industrial customers generally are long-term contracts that
provide payment on a per thousand pound basis for steam delivered.
With the exception of facilities in which the electricity purchaser is
responsible for providing the fuel, each of our facilities purchases fuel under
long-term supply agreements. Substantially all fuel supply contracts are
structured so that the scheduled increases in the fuel cost are generally
matched by increases in the variable payments received by the project subsidiary
for electricity under its power sales agreement. This matching is typically
affected by having the fuel prices escalate as a function of the solid fuel
index of the purchasing utility. The matching is sometimes affected by
contracting for scheduled increases in the variable payments under our power
sales agreements designed to offset scheduled increases in fuel prices.
Project Financing
Each facility is financed primarily under financing arrangements at the
project subsidiary level which, except as noted below, require the loans to be
repaid solely from the project subsidiary's revenues. They also generally
provide that the repayment of the loans and payment of interest is secured
solely by the physical assets, agreements, cash flow and, in certain cases, the
capital stock of or partnership interests in that project subsidiary. This type
of financing is generally referred to as "project financing."
Project financing transactions are generally structured so that all
revenues of a project are deposited directly with a bank or other financial
institution acting as escrow or security deposit agent. These funds are then
payable in a specified order of priority to assure that, to the extent
available, they are used first to pay operating expenses, senior debt service
and taxes and to fund reserve accounts. Then, subject to satisfying debt service
coverage ratios and other conditions, any available funds may be disbursed to us
and our other partners, in the case of jointly-owned facilities, in the form of
management fees or dividends or for the payment of subordinated debt service,
where there are subordinated lenders.
These facilities are financed using a high proportion of debt to equity.
This leveraged financing permits us to develop projects with a limited equity
base but also increases the risk that a reduction in revenues could adversely
affect a particular project's ability to meet its debt or lease obligations. The
lenders to each project subsidiary have security interests covering some or all
of the aspects of the project, including the facility, related facility support
agreements, the stock or partnership interest of our project subsidiaries,
licenses and permits necessary to operate the facility and the cash flow derived
from the facility. In the event of a foreclosure after a default, the project
subsidiary would only retain an interest in the property remaining, if any,
after all debts and obligations were paid.
In addition, the debt of each operating project may reduce the liquidity of
our interest in such project since any sale or transfer of its interest would,
in most cases, be subject both to a lien securing such project debt and to
transfer restrictions in the relevant financing agreements. Also, our ability to
transfer or sell our interest in some of our projects is restricted by purchase
options we have granted to an industrial steam customer and to a utility and
certain rights of first refusal we have granted in favor of our power and steam
purchasers.
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Because the project debt is "non-recourse", the lenders under these project
financing structures cannot look to Cogentrix, Holdings or its other projects
for repayment unless Cogentrix Holdings or another project subsidiary expressly
agrees to undertake liability. Cogentrix has agreed to undertake limited
financial support for certain of Holdings project subsidiaries in the form of
limited obligations and contingent liabilities. These obligations and contingent
liabilities take the form of guarantees, indemnities, capital infusions and
agreements to pay debt service deficiencies. To the extent Cogentrix becomes
liable under such guarantees and other agreements with respect to a particular
project, distributions received by Cogentrix from other projects may be used by
Cogentrix to satisfy these obligations. To the extent of these obligations, the
lenders to a project may look to Cogentrix and the distributions to Cogentrix
from other projects for payment. The aggregate contractual liability of
Cogentrix to its project lenders is, in each case, a small portion of the
aggregate project debt. Thus the project financing structures are generally
described throughout this report as being "non-recourse" to Cogentrix, Holdings
and its other projects. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations."
Our facilities are insured in accordance with covenants in each project's
debt financing agreements. Coverages for each plant include workers'
compensation, commercial general liability, supplemented by primary and excess
umbrella liability, and a master property insurance program including property,
boiler and machinery and business interruption.
Operating Arrangements
Unlike many independent power producers who contract with third-party
operators, we operate many of our facilities. When we do operate a facility, our
project subsidiary employs directly the persons required to operate the
facility. We invest in training our operating personnel and structure our
facility bonus program to reward safe, efficient and cost-effective operation of
the facilities. Our management meets and conducts, several times a year, on-site
facility performance reviews with each facility manager.
We have established a strong record of safety, efficiency and reliability in
operating our electric generating plants, which reliability is measured in the
industry by a generating plant's "availability" to generate and sell
electricity. The table below shows the average "availability" of the plants we
currently operate for the periods indicated.
PERIOD AVERAGE AVAILABILITY
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Year ended December 31, 1999................ 95.6%
Year ended December 31, 1998................ 96.4%
Year ended December 31, 1997................ 97.2%
We provide to all but one of the facilities we operate administrative and
management services for a periodic fee, which in some cases is adjusted annually
by an inflation factor. The ability of a project subsidiary to pay these
management fees is contingent upon the continuing compliance by the project
subsidiary with covenants under its project financing agreements and may be
subordinated to the payment of obligations under those agreements. We have
earned and will continue to earn incentive compensation from our Hopewell
facility, in which Holdings indirectly holds a 50% general partnership interest
and is, through a subsidiary, the managing general partner, if the facility
achieves the contractually specified net income levels.
Ash Removal
Project subsidiaries owning nine of our coal-fired plants contract with our
subsidiary, ReUse Technology, to remove coal ash generated by such facilities.
As an alternative to disposing of coal ash in landfills, ReUse Technology uses
coal ash in the manufacturing and production of various ash derived products for
resale.
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FACILITIES UNDER CONSTRUCTION
In August 1998, we acquired an approximate 52% interest in an 800-megawatt,
combined-cycle, natural gas-fired electric generating facility under
construction in Batesville, Mississippi. We will operate this facility, which is
scheduled to begin operation in summer 2000. Electricity generated by the plant
will be sold under long-term power purchase agreements with two utilities. Both
of these utilities have senior, unsecured debt outstanding that
nationally-recognized credit rating agencies have rated investment grade.
In December 1999, we closed financing and commenced construction on an
800-megawatt, combined-cycle, natural gas-fired electric generating facility in
Jenks, Oklahoma. PECO Energy's Power Team will deliver natural gas to the plant
and purchase the electricity under a long term power purchase agreement. This
facility, which we will operate and manage, is scheduled to commence commercial
operations in early 2002.
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FACILITIES IN OPERATION
Our facilities described below rely on power sales agreements for the
majority of their revenues. During the fiscal year ended December 31, 1999, two
regulated utility customers accounted for approximately 64% of our consolidated
revenues. The failure of either of these utility customers to fulfill its
contractual obligations for a prolonged period of time would have a material
adverse effect on our primary source of revenues. Both of these utilities have
senior, unsecured debt outstanding that nationally-recognized credit rating
agencies have rated investment grade. As a result of recent growth, our future
operations will be more diverse with regard to both geography and fuel source
and less dependent on any single project or customer.
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OUR PERCENT OUR NET EQUITY
PLANT OWNERSHIP INTEREST IN POWER
FACILITY LOCATION FUEL MEGAWATTS INTEREST PLANT MEGAWATTS PURCHASING UTILITY
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Elizabethtown Elizabethtown, NC Coal 35 100% 35.0 CP&L*
Lumberton Lumberton, NC Coal 35 100 35.0 CP&L*
Kenansville Kenansville, NC Coal 35 100 35.0 CP&L*
Roxboro Roxboro, NC Coal 60 100 60.0 CP&L*
Southport Southport, NC Coal 120 100 120.0 CP&L*
Hopewell Hopewell, VA Coal 120 50.0 60.0 Virginia Power
Portsmouth Portsmouth, VA Coal 120 100 120.0 Virginia Power
Rocky Mount Rocky Mount, NC Coal 120 100 120.0 Virginia Power
Ringgold Ringgold, PA Gas 15.5 100 15.5 Pennsylvania
Electric Company
Richmond Richmond, VA Coal 240 100 240.0 Virginia Power
Birchwood King George, VA Coal 240 50.0 120.0 Virginia Power
Cottage Grove Cottage Grove, MN Gas 245 73.2 179.3 Northern States
Power Company
Whitewater Whitewater, WI Gas 245 74.2 181.8 Wisconsin Electric
Power Corporation
Logan Logan Township, NJ Coal 218 50.0 109.0 Atlantic City
Electric
Northampton Northampton County, PA Waste coal 110 50.0 55.0 Metropolitan Edison
Indiantown Martin County, FL Coal 380 50.0 190.0 Florida Power &
Light
Carneys Point Carneys Point, NJ Coal 262 10.0 26.2 Atlantic City
Electric
Panther Creek Carbon County, PA Waste coal 83 12.2 10.1 Metropolitan Edison
Scrubgrass Scrubgrass
Township, PA Waste coal 85 20.0 17.0 Pennsylvania Electric
Selkirk Albany, NY Gas 396 5.1 20.2 Con Edison &
Niagara Mohawk
Cedar Bay Jacksonville, FL Coal 260 16.0 41.6 Florida Power &
Light
Mass Power Springfield, MA Gas 258 1.7 4.4 Boston Edison
Gilberton Frackville, PA Waste coal 82 19.6 16.1 Pennsylvania Power
& Light
Pittsfield Pittsfield, MA Gas 173 10.9 18.9 New England Power
Morgantown Morgantown, WV Coal/Waste 62 15.0 9.3 Monongahela Power
Coal
Iroquois Gas Long Island, NY to - - 0.5 - -
Transmission Waddington, NY
System
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* Commonly-used acronym for Carolina Power & Light Company
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DESCRIPTION OF FACILITIES IN WHICH WE OWN A SIGNIFICANT ECONOMIC INTEREST
Elizabethtown, Lumberton and Kenansville, North Carolina Facilities
Our subsidiary, Cogentrix Eastern Carolina Corporation, owns and operates
three 35-megawatt stoker coal-fired cogeneration plants in Elizabethtown,
Lumberton and Kenansville, North Carolina.
The Elizabethtown, Lumberton and Kenansville facilities sell electricity to
CP&L under separate power sales agreements, which were amended effective in
September 1996. The power sales agreements for the Elizabethtown and Lumberton
facilities expire in November 2000, and the power sales agreement for the
Kenansville facility has an initial term expiring in September 2001. Each of the
facilities may operate at a declared production capability of up to
approximately 33 megawatts. Another subsidiary, Cogentrix, Inc., has guaranteed
the performance of CECC under the power sales agreements. Alamac Knit Fabrics,
Inc. purchases steam for its apparel fabrics division mills from the Lumberton
facility and the Elizabethtown facility under separate steam sales agreements.
Guilford Mills, Inc. purchases steam from the Kenansville facility for use in
its textile manufacturing plant.
Each of the power sales agreements provides that in the event of a
termination prior to the expiration of the initial term of the power sales
agreements, our project subsidiary must pay CP&L a termination charge. In the
event of a material breach by the utility, our project subsidiary may terminate
the power sales agreement prior to its expiration without incurring the
termination charge. The termination charge is an amount equal to the excess paid
for capacity and energy over what would have been paid to our project subsidiary
under the state utilities commission's published rates plus interest.
If the average production capability or electricity generated or made
available during any 12-month period falls below 80% of the established contract
level, a special charge will be imposed by CP&L equal to a percentage of the
termination charge described above. In addition, if our project subsidiary
desires to terminate the power sales agreement prior to its expiration and a
substitute operator satisfactory to the utility is not secured, our project
subsidiary must pay to the utility the termination charge described above plus
an amount equal to the depreciated installed cost of the interconnection
facilities relating to the plant.
Roxboro and Southport, North Carolina Facilities
Our subsidiary, Cogentrix of North Carolina, Inc., operates two stoker
coal-fired cogeneration plants in Roxboro and Southport, North Carolina, which
are owned by another wholly-owned project subsidiary of Cogentrix Energy.
The Roxboro and Southport facilities sell electricity under separate power
sales agreements, each having an initial term expiring in December 2002. The
60-megawatt Roxboro facility may operate at a declared production capability of
up to 56 megawatts and the 120-megawatt Southport facility may operate at a
declared production capability of up to 107 megawatts. Cogentrix, Inc., has
guaranteed the performance of our project subsidiary under the power sales
agreements. Collins & Aikman Corporation purchases process steam for its textile
manufacturing facility from the Roxboro facility and Archer-Daniels-Midland
Company purchases steam for its pharmaceutical and chemical manufacturing
company from the Southport facility.
Each of the power sales agreements provides that in the event our project
subsidiary desires to terminate the power sales agreement or abandons the
Roxboro or Southport facility, our project subsidiary must pay the utility a
termination charge. Such termination charge will be equal to the sum of the
following:
o the depreciated installed cost of the interconnection facilities
relating to the plant
o the cost incurred by the utility to replace the production capability
provided by the Roxboro or Southport facility in excess of the fixed
payments which would have been made to our project subsidiary for the
Roxboro or Southport facility
o a carrying charge equal to the overall pretax cost of capital allowed to
the utility by the retail rate order of the state utilities commission
in effect during the time the energy credits were received.
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Hopewell, Virginia Facility
Our facility, located in Hopewell, Virginia, is a 120-megawatt stoker
coal-fired cogeneration facility owned and operated by a general partnership, in
which a 50% general partnership interest is owned by one of our subsidiaries.
The remaining 50% partnership interest is owned by Capistrano Cogeneration
Company, a subsidiary of Edison Mission Energy.
The Hopewell facility provides declared production capability of up to 92.5
megawatts to Virginia Power under a power sales agreement which expires in
January 2008. If the power sales agreement is terminated prior to the end of its
initial or any subsequent term other than due to a default by Virginia Power,
the project partnership must pay a penalty to Virginia Power. The amount of the
penalty is the difference between payments for production capability already
made and those that would have been allowable under the applicable "avoided
cost" schedules of the utility plus interest. Allied-Signal Corporation
purchases steam from the Hopewell facility.
Portsmouth, Virginia Facility
Our facility located in Portsmouth, Virginia is a 120-megawatt stoker
coal-fired cogeneration facility. The Portsmouth facility provides Virginia
Power declared production capability of up to 115 megawatts under a power sales
agreement which expires in June 2008. The Portsmouth facility also sells process
steam to BASF Corporation and Celanese Chemical, Inc.
If the power sales agreement for this facility is terminated prior to the
end of its initial or any subsequent term other than due to a default by
Virginia Power, then our project subsidiary must pay a penalty to Virginia
Power. The amount of the penalty is the difference between payments for
production capability already made and those that would have been allowable
under the applicable "avoided cost" schedules of Virginia Power plus interest.
Rocky Mount, North Carolina Facility
Our facility located near Rocky Mount, North Carolina is a 120-megawatt
stoker coal-fired cogeneration plant. Under a power sales agreement with North
Carolina Power Company, a division of Virginia Power, the Rocky Mount facility
provides declared production capability of 115.5 megawatts of electricity for an
initial term expiring in October 2015. In addition, steam from the Rocky Mount
facility is sold to Abbott Laboratories.
The power sales agreement for this facility provides that in the event the
state utility commission prohibits North Carolina Power from recovering from its
customers payments made by North Carolina Power under the power sales agreement
to our project subsidiary, our project subsidiary would recognize a reduction in
payments received under the power sales agreement after the 18th anniversary of
commencement of commercial operations of the facility to the extent necessary to
repay North Carolina Power the amount disallowed by the utility commission with
interest. In light of this provision in the power sales agreement, the project
lender for the Rocky Mount facility has established a reserve account, which is
required to be funded at any time a disallowance of payments occurs or, from and
after January 1, 2004, any meritorious filing with the utility commission
challenging the pass-through of payments made by the utility under the power
sales agreement is made.
If a disallowance event occurs during the period from 1998 through 2002,
then 25% of cash flow from the facility must be deposited to the regulatory
disallowance reserve account until the balance of such account is equal to the
amount required to be funded. If a disallowance event occurs during the period
from 2003 through 2013, then 100% of the cash flow from the facility must be
deposited to the reserve account until the balance of the reserve account is
equal to the amount required to be funded. The amount required to be funded in
such account is an amount equal to the lesser of:
o Projected reduction in cash flows from 2009 through 2013 as a result of
the disallowance of payments made by the utility and,
o The amount of our project subsidiary's debt outstanding at September 30,
2008.
If the number of days in any year in which the Rocky Mount facility is
unable to generate electricity in an amount equal to its declared production
capability is more than the greater of 25 days or ten percent of the total
number of days the facility was required by North Carolina Power to operate,
then the fixed payments under the contract for that period will be reduced by
four percent for each excess day. In the event testing indicates that the Rocky
Mount facility's dependable production capability is less than 90% of the
declared production capability, our project subsidiary will be obligated to pay
annual
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liquidated damages to North Carolina Power. A letter of credit has been posted
by our project subsidiary in favor of North Carolina Power to secure its
obligations to perform under the power sales agreement.
Ringgold, Pennsylvania Facility
Our facility located in Ringgold, Pennsylvania, is a 15.5-megawatt gas-fired
cogeneration facility using an internal combustion engine fueled primarily by
natural gas. Pennsylvania Electric Company purchases energy from the facility.
Under the power sales agreement, the failure of our facility to generate and
sell electricity throughout the term of the agreement at an annual average level
which is at least equal to 85% of the average output achieved during a rolling
three-year period of operation would result in the payment of a penalty.
In January 1998, we signed an agreement with Pennsylvania Electric Company
to terminate this facility's power purchase agreement. This termination
agreement was the result of a request for proposals from the utility to buy-back
or restructure power sales agreements issued to all major operating independent
power projects in its territory in April 1997. The termination agreement
provides for a payment to our project subsidiary of approximately $20.4 million,
which will be sufficient to retire all of the project subsidiary's outstanding
debt. The buy-back of the power purchase agreement is subject to the issuance of
a satisfactory final order by the Pennsylvania Public Utility Commission
granting Pennsylvania Electric Company the authority to fully recover from its
customers the consideration paid under the buyout agreement. We do not expect
the termination of this facility's power purchase agreement, if it occurs, to
have an adverse impact on our consolidated results of operations or financial
position.
The Ringgold facility provides hot water to a 10-acre greenhouse owned by
our project subsidiary which is leased to and operated by Village Farms, L.P.
The lease has a ten-year term, which may be extended with our consent.
Richmond, Virginia Facility
Our 240-megawatt stoker coal-fired cogeneration plant in Richmond, Virginia
provides 209 megawatts of declared production capability to Virginia Power under
two 25-year power sales agreements expiring in 2017. Our Richmond facility also
provides steam to E. I. DuPont de Nemours & Company.
Each of the power sales agreement provides that in the event the state
utilities commission prohibits Virginia Power from recovering from its customers
payments made by Virginia Power to our project subsidiary, our subsidiary would
recognize a reduction in payments received under such power sales agreements
after the 18th anniversary of commencement of commercial operations of the
facility to the extent necessary to repay the amount of the disallowed payments
to Virginia Power with interest.
If the number of days in any year in which the Richmond facility is unable
to generate electricity in an amount equal to its declared production capability
is more than the greater of 25 days or ten percent of the total number of days
the facility was required by Virginia Power to operate, the fixed payments under
the contract for that period will be reduced by four percent for each excess
day. In the event testing indicates that the facility's dependable production
capability is less than 90% of the declared production capability, our
subsidiary will be obligated to pay annual liquidated damages to Virginia Power.
Our project subsidiary has letters of credit in favor of Virginia Power to
secure its obligations to perform under the power sales agreements.
Our project subsidiary purchased one of the power sales agreements from WV
Hydro, Inc. In connection with the purchase and in consideration of certain
consulting arrangements, our subsidiary has continuing obligations to make
payments to an affiliate of WV Hydro, in an aggregate amount ranging from
$250,000 to $750,000, each year through 2003, from excess facility cash flow. If
excess facility cash flow for any year is insufficient to pay the $250,000
minimum amount, the deficiency will be carried forward and is payable from
excess facility cash flow, if any, in future years. In addition, our subsidiary
is obligated to pay an amount ranging from 3 to 3.5 percent of the net proceeds
payable to our subsidiary upon any sale, disposition or refinancing of the
Richmond facility after payment of senior and subordinated project financing
debt and expenses.
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Birchwood, Virginia Facility
Through an indirect, wholly-owned subsidiary we have a 50% interest in a
partnership that owns a 240-megawatt stoker coal-fired cogeneration facility in
King George, Virginia. The Southern Company, a public utility holding company,
owns the remaining 50% of the facility. The 36-acre greenhouse located adjacent
to the facility, which is jointly owned by us and The Southern Company, uses
steam from the facility. An affiliate of The Southern Company manages and
operates and maintains the Birchwood facility.
The Birchwood facility provides up to 202 megawatts of declared production
capability to Virginia Power under a power sales agreement which expires in
2021. The power sales agreement provides that in the event the state utilities
commission prohibits Virginia Power from recovering from its customers payments
made by Virginia Power to our project subsidiary, the partnership that owns the
facility would recognize a reduction in payments received under the power sales
agreement after the 20th anniversary of commencement of commercial operations of
the facility to the extent necessary to repay the amount of the disallowed
payments to Virginia Power with interest.
If this facility is unable to operate within the parameters established by
Virginia Power under the power sales agreement, the fixed payments under the
agreement for the period the facility is not able to do so are subject to
reduction. In the event testing indicates that the facility's dependable
production capability is less than 90% of the declared production capability,
the partnership will be obligated to pay annual liquidated damages to Virginia
Power. The partnership has posted a letter of credit in favor of Virginia Power
to secure its obligations to perform under the power sales agreement.
Cottage Grove, Minnesota Facility
Our Cottage Grove facility is a 245-megawatt combined-cycle, natural
gas-fired cogeneration facility in Cottage Grove, Minnesota. One of our
wholly-owned indirect subsidiaries is the sole general partner of the
partnership that owns the facility with a 1% partnership interest. Another
wholly-owned indirect subsidiary of ours owns an approximate 72.2% limited
partnership interest in Cottage Grove. An affiliate of Tomen Power Corporation
owns the remaining approximate 26.8% limited partnership interest.
The Cottage Grove facility provides 245 megawatts of declared production
capability to Northern States Power Company measured at summer conditions and
262 megawatts of declared production capability measured at winter conditions
under a power sales agreement which expires in 2027. Fixed payments are subject
to adjustment on the basis of performance-based factors which reflect the
Cottage Grove facility's semiannually tested production capability and its
rolling 12-month average and on-peak availability. Fixed payments are also
adjusted for transmission losses or gains relative to a reference plant. The
Cottage Grove facility also sells steam to Minnesota Mining and Manufacturing
Company.
Currently, Northern States Power Company is permitted full recovery from its
customers of payments made under the power sales agreement. The power sales
agreement provides, however, that following the tenth anniversary of the
commercial operation date, if Northern States Power Company fails to obtain or
is denied authorization by any governmental authority having jurisdiction over
its retail rates and charges, granting it the right to recover from its
customers any payments made under the power sales agreement, the disallowed
amounts will be monitored in a tracking account and the unpaid balance in the
tracking account shall accrue interest. Within 30 days after the first mortgage
bonds issued to finance the construction of the facility have been fully
retired, Northern States Power Company may begin reducing payments to the
partnership that owns the facility to ensure the payments are in line with
Minnesota Public Utility Commission rates and begin amortizing the balance in
the tracking account. Should Northern States Power Company exercise its right to
reduce payments, the maximum reduction is 75% of the payment otherwise due for
the period.
We manage and administer the partnership's business with respect to the
Cottage Grove facility, and provide certain management and administrative
services to the general partner of the partnership. Also, one of our
wholly-owned subsidiaries operates the facility pursuant to an O&M Agreement
with the partnership.
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Whitewater, Wisconsin Facility
Our Whitewater facility is a 245-megawatt combined-cycle, natural gas-fired
cogeneration facility in Whitewater, Wisconsin. One of our wholly-owned indirect
subsidiaries is the sole general partner of the general partnership that owns
the facility with a 1% general partnership interest. Another wholly-owned
indirect subsidiary of ours owns an approximate 73.2% limited partnership
interest. An affiliate of Tomen Power Corporation owns the remaining approximate
25.8% limited partnership interest.
The Whitewater facility provides approximately 236.5 megawatts of declared
production capability to Wisconsin Electric Power Company under a power sales
agreement which expires in 2022. The Whitewater facility may also sell to third
parties up to 12 megawatts of electric production capability and any energy
which the utility does not dispatch. Fixed payments from the utility are subject
to adjustment on the basis of performance-based factors which reflect the
Whitewater facility's semiannually tested production capability and average and
on-peak availability for the preceding contract year.
The fixed payments from the utility may be reduced to the extent that the
utility's senior debt is downgraded by any two of Standard & Poor's Corporation,
Moody's Investors Services, Inc. and Duff & Phelps as a result of the utility's
long-term power purchase obligations under the power purchase agreement for the
Whitewater facility. So long as the partnership's first mortgage bonds issued to
finance construction of the facility are outstanding, the reduction may not
exceed the level necessary to cause the partnership's debt service coverage
ratio to be less than 1.4 in any one month, with such ratio calculated on a
rolling average of the four fiscal quarters immediately preceding the proposed
adjustment. After the partnership's first mortgage bonds have been repaid, the
reduction may not exceed 50% of the partnership's revenues minus expenses.
Reductions precluded by application of these limitations are accumulated in a
tracking account with interest accruing at a specified rate. Tracking account
balances are to be repaid when possible, subject to the limitations described
above, or may be applied to the price of the utility's option to purchase the
Whitewater facility at the expiration of the power sales agreement.
Currently, Wisconsin Electric Power Company is permitted full recovery from
its customers of payments made under the power sales agreement. The power sales
agreement provides, however, if at any time the utility is denied rate recovery
from its customers of any payment to be made under the power sales agreement by
an applicable regulatory authority, the utility's payments may be
correspondingly reduced, subject to contractually specified limitations. While
the partnership's first mortgage bonds are outstanding, the fixed payments may
be reduced by the annual regulatory disallowance provided that the reduction may
not cause the partnership's debt service coverage ratio to be less than 1.4 in
any month calculated on a rolling average of the four fiscal quarters preceding
the proposed adjustment. After the outstanding first mortgage bonds are repaid,
reductions may not exceed 50% of the Whitewater facility's revenues minus
expenses. Reductions precluded by these restrictions are accumulated in a
tracking account with repayment subject to the same provisions as for bond
downgrading adjustments discussed above.
The Whitewater facility sells steam to the University of Wisconsin --
Whitewater under a steam supply agreement expiring in 2005. The facility also
sells hot water to a greenhouse located adjacent to the facility. FloriCulture,
Inc., an affiliate of the partnership that owns the Whitewater facility, has
entered into an operational services agreement pursuant to which FloriCulture
provides all services necessary to produce, market and sell horticulture
products and to operate and maintain the greenhouse facility.
We manage and administer the partnership's business with respect to the
Whitewater facility, and provide management and administrative services to the
general partner of the partnership. Also, one of our wholly-owned subsidiaries
operates the facility pursuant to an O&M Agreement with the partnership.
Logan (New Jersey) Facility
A Delaware limited partnership owns the Logan facility, which is a
218-megawatt pulverized coal-fired cogeneration generating plant located on the
Delaware River in Logan Township, New Jersey. The partnership leases the Logan
facility to another Delaware limited partnership. An indirect, wholly-owned
subsidiary of Holdings, owns a 50% general partnership interest in each of the
first limited partnership and each of the partners of the second limited
partnership. An indirect, wholly-owned subsidiary of PG&E Generating Co.
("PG&E") is the sole limited partner in each of the first partnership and the
partners of the second limited partnership, owning a 1% limited partnership
interest. The PG&E subsidiary also owns a 49% general partnership interest in
each of the first partnership and each of the partners of the second limited
partnership.
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The Logan facility, which began operation in September 1994, provides up to
203 megawatts of declared production capability to Atlantic City Electric
Company under a power sales agreement which expires in 2024. The Logan facility
has the capability to provide up to approximately 15 megawatts of excess
production capability and energy to third parties. The Logan facility sells
steam to Solutia, Inc.
If the net deliverable production capability of the Logan facility falls
below 190,000 kilowatts, then the partnership that owns the facility must pay
liquidated damages to the utility in an amount calculated using a formula that
reflects both the amount of the deficiency and the rate those mid-Atlantic
electric utilities who are members of a mid-Atlantic regional power pool and
fail to satisfy their capacity obligations to the pool must pay to the other
members who make up the deficiency.
An affiliate of PG&E operates the Logan facility pursuant to an operation
and maintenance agreement with an initial term expiring in 2004. PG&E provides
management services pursuant to a management services agreement which expires in
2027.
Northampton (Pennsylvania) Facility
A Delaware limited partnership owns this 110-megawatt anthracite waste
coal-fired electric generating facility in Northampton County, Pennsylvania. An
indirect, wholly-owned subsidiary of Holdings owns a 50% general partnership
interest in this partnership. An indirect, wholly-owned subsidiary of PG&E owns
an aggregate 50% equity interest in the partnership that owns this project,
which consists of a 48% general partnership interest and 2% limited partnership
interest.
The Northampton facility, which began operation in September 1995, provides
electric energy to Metropolitan Edison Company pursuant to a power sales
agreement which expires in 2020. Capacity in excess of 89 megawatts may be sold
to third parties, but no energy from the Northampton facility may be sold to any
entity other than Metropolitan Edison.
The Northampton facility is not directly interconnected to Metropolitan
Edison's electric system and accordingly requires an electric utility that is
interconnected with Metropolitan Edison's electric system to transmit the
Northampton facility's output to Metropolitan Edison. Pursuant to a transmission
service agreement (which expires in 2020) with Pennsylvania Power & Light
Company, that utility transmits the Northampton Facility's net electric energy
to Metropolitan Edison's existing electric system.
In the event the Northampton facility's annual average delivery of
electricity for any year following the commercial operation date during on-peak
hours is less than 85% of the Northampton facility's annual average delivery of
electricity during the on-peak hours for the prior three years, the partnership
that owns the facility is obligated to make a penalty payment to Metropolitan
Edison. During the first 11 years of the power sales agreement commencing with
the commercial operation date, the penalty payment will equal the difference
between 85% of the annual average on-peak electricity delivered in the prior
three years and the actual on-peak electricity delivered in the year to which
the penalty relates times 3.4(cent) per kWh. After the eleventh year of the
power sales agreement, the penalty payment will be calculated as above, except
that the rate of 3.4(cent) per kWh shall be adjusted annually according to
changes in the Gross Domestic Product Implicit Price Deflator.
Based on its use of waste coal as its primary fuel source, the Federal
Energy Regulatory Commission has certified the Northampton facility as a
"qualifying small power production facility".
An affiliate of PG&E Generating Company operates and maintains the
Northampton facility pursuant to an operation and maintenance agreement with an
initial term expiring in 2020. PG&E Generating Company provides management and
administration services for the Northampton facility pursuant to a management
services agreement with an initial term expiring in 2020.
In addition to the partners' original equity contributions to the
partnership that owns the Northampton facility, the partners have posted letters
of credit or corporate guarantees in an aggregate amount of $9 million as a
standby equity commitment to be used for certain fuel-related costs. They have
also posted a letter of credit in the amount of $2.2 million as a standby equity
commitment to be used solely to establish the bank debt service reserve fund for
the exclusive benefit of the banks. Cogentrix provides letters of credit or
corporate guarantees for 50% of those standby equity commitments.
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Indiantown (Florida) Facility
A Delaware limited partnership owns this 380-megawatt pulverized coal-fired
cogeneration facility located in Martin County, Florida. An entity controlled by
PG&E owns a 50% general partnership interest in the partnership, and we own a
50% general partnership interest. The Indiantown facility began operation in
December 1995 and sells steam to Caulkins Indiantown Citrus Company.
The Indiantown facility provides 330 megawatts of declared production
capability to Florida Power & Light Company under a power sales agreement which
expires in 2025. Fixed payments by Florida Power & Light are subject to
adjustment on the basis of the Indiantown facility's actual production
capability.
Currently, Florida Power & Light is permitted full recovery from its
customers of payments made under the power sales agreement. The power sales
agreement contains a provision, which provides that if Florida Power & Light at
any time is denied authorization to recover from its customers any payments to
be made under the power sales agreement, Florida Power & Light may, in its sole
discretion, adjust payments under the power sales agreement to the amount it is
authorized to recover from its customers. The utility may also require the
partnership that owns the facility to return payments subsequently disallowed by
the regulatory agency. If the obligations of Florida Power & Light and the
partnership that owns the facility are materially altered due to the operation
of this provision in the agreement, the partnership may terminate the power
sales agreement upon 60 days' notice. The partnership and Florida Power & Light
must then in good faith attempt to negotiate a new power sales agreement or any
agreement for transmission of the Indiantown facility's capacity and energy to
another investor-owned, municipal, or cooperative electric utility
interconnected with Florida Power & Light in Florida.
An affiliate of PG&E Generating Company provides operation and maintenance
services for the Indiantown facility pursuant to an operating agreement which
expires in 2025. PG&E Generating Company manages and administers the business of
the partnership that owns the facility pursuant to a management service
agreement which expires in 2029.
Carneys Point (New Jersey) Facility
A Delaware limited partnership owns this 262-megawatt pulverized coal-fired
cogeneration facility located within the grounds of the DuPont Chamber Works, a
chemical complex in Carneys Point, New Jersey. The partnership leases the
Carneys Point facility to a partnership of wholly-owned subsidiaries of PG&E
Generating Company. Lease payments are structured to equal project cash flow,
and the lessee partnership derives no net cash flow or benefit from the lease.
We own a 10% general partnership interest in the limited partnership that owns
the facility. The other general partner is an indirect, wholly-owned subsidiary
of PG&E, which owns a 50% general partnership interest. The sole limited partner
is an indirect, wholly-owned subsidiary of General Electric Capital Corporation,
which owns a 40% limited partnership interest.
The Carneys Point facility began operation in March 1994. The facility
provides Atlantic City Electric Company with 187.6 megawatts in the summer
months and 173.2 megawatts in the winter months for an annual average of 180.4
megawatts. If the actual available production capability falls below 95% of the
respective production capability requirement for the winter or summer period,
the partnership that owns the facility must make a deficiency payment to the
utility until actual production capability for such period reaches 95% of the
production capability requirements for the period.
Under an energy services agreement, the Carneys Point facility sells steam
and up to 40 megawatts of electricity to DuPont. The Carneys Point facility has
the capability to sell an average of approximately 30 megawatts of excess
production capability and energy to third parties.
An affiliate of PG&E Generating Company operates the Carneys Point facility
under an operation and maintenance agreement with an initial term expiring in
2004. PG&E Generating Company provides management services for the facility
pursuant to a management services agreement with a term expiring in 2018.
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PRINCIPAL CUSTOMERS
Electric utility customers accounting for more than ten percent of our
consolidated revenue for the fiscal years ended December 31, 1999, 1998 and 1997
were as follows:
FISCAL YEAR ENDED
DECEMBER 31,
1999 1998 1997
---------- ---------- ----
CP&L................................. 17% 19% 22%
Virginia Power....................... 47% 50% 64%
As a result of our recent growth, our future operations will be more diverse
with regard to both geography and fuel source and less dependent on any single
project or customer.
REGULATION
Our plants are subject to federal, state and local energy and environmental
laws and regulations applicable to the development, ownership and operation of
electric generating facilities. Federal laws and regulations govern
transactions, types of fuel utilized, the type of energy produced and power
plant ownership. State regulatory commissions must approve the rates and, in
some instances, other terms under which utilities purchase electricity from
independent producers. These state commissions may have broad jurisdiction over
non-utility owned power plants. Power plants also are subject to laws and
regulations governing environmental emissions and other substances produced by a
plant, along with the geographical location, zoning, land use and operation of a
plant. Applicable federal environmental laws typically have state and local
enforcement and implementation provisions. These environmental laws and
regulations generally require that a wide variety of permits and other approvals
be obtained before construction or operation of a power plant commences and that
the power plant operates in compliance with them. We strive to comply with all
environmental laws, regulations, permits and licenses but, despite such efforts,
at times we have been in non-compliance.
Energy Regulations
QFS UNDER THE PUBLIC UTILITY REGULATORY POLICIES ACT OF 1978. All of our
current operating facilities are classified as a qualifying facility ("QF")
under the Public Utility Regulatory Policies Act of 1978 ("PURPA"). QFs are
relieved of compliance with extensive federal, state and local regulations that
control the development, financial structure and operation of power plants and
cost-of-service based ratemaking to determine the prices at which electric
generating facilities sell energy. In order to be a QF, a cogeneration facility
must sequentially produce both electricity and useful thermal energy for
non-mechanical or non-electrical uses in specified proportions to the facility's
total useful energy output. A QF utilizing oil or natural gas as fuel also must
meet energy efficiency standards. A small power production facility may be a QF
if it uses alternative fuels as its primary energy input, subject to limitations
on fossil fuel input and size for the facility. Finally, a QF must not be
controlled or more than 50% owned by an electric utility or by an electric
utility holding company, or a subsidiary of either or any combination thereof.
PURPA exempts QFs from the Public Utility Holding Company Act of 1935
("PUHCA"), most provisions of the Federal Power Act (the "FPA") and, except
under limited circumstances, state rate and financial regulations.
These exemptions are important to us and our competitors.
In the absence of a power sales agreement, regulations adopted by the
Federal Energy Regulatory Commission ("FERC") require utilities to purchase
electricity generated by QFs at a price based on the purchasing utility's full
"avoided cost," and that the utility sell back-up power to the QF on a
non-discriminatory basis. Avoided costs are the incremental costs to a utility
of electric energy or capacity, or both, which, but for the purchase from QFs,
the utility would generate for itself or purchase from another source. Due to
increasing competition for utility contracts, the current practice is for most
power sales agreements to be awarded below avoided cost.
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We endeavor to minimize the risk of our facilities losing their QF status.
The occurrence of events outside our control, such as loss of a steam customer,
could jeopardize QF status. While the facilities usually would be able to react
in a manner to avoid the loss of QF status by, for example, replacing the steam
customer or finding another use for the steam which meets PURPA's requirements,
there is no certainty that the alternative implemented would be practicable or
economic.
If one of our facilities were to lose its status as a QF, the subsidiary
could lose its exemptions from PUHCA and the FPA and from state laws and
regulations. This could subject the subsidiary to regulation under the FPA and,
in such event, would result in Holdings inadvertently becoming a public utility
holding company. Our other facilities could in turn lose their QF status.
Moreover, loss of QF status could result in utility customers terminating their
power sales agreement with the nonqualifying facility. If loss of QF status were
threatened for a facility, we could avoid holding company status and thereby
protect the QF status of our other facilities by applying to the FERC to obtain
exempt wholesale generator ("EWG") status for the owner of the nonqualifying
facility. See "-EWGs under the Energy Policy Act of 1992" herein. Alternatively,
the FERC may grant a limited waiver to the QF that would provide continued
exemption under PUHCA, provided the facility's rates were regulated under the
FPA.
EWGS UNDER THE ENERGY POLICY ACT OF 1992. The passage of the Energy Policy
Act has significantly expanded the options available to independent power
producers with respect to their regulatory status. In addition to or in lieu of
QF status, an independent power producer selling exclusively at wholesale now
can also apply to the FERC to be granted status as an EWG. Except for existing
cost-of-service based facilities for which state consents are required, any
owner of a facility may apply for status as an EWG. An EWG, like a QF, is exempt
from regulation under PUHCA. However, EWG status does not exempt a facility from
FERC and state public utility commission ("PUC") regulatory reviews, which may
be more expansive than those applicable to QFs. Several of Holdings' facilities,
which are QFs, have also been determined to be EWGs. In addition, several
project subsidiaries developing new generating facilities have also been
determined to be EWGs.
FOREIGN INVESTMENTS UNDER THE ENERGY POLICY ACT. The Energy Policy Act has
also expanded the options for companies that wish to invest in foreign
enterprises that own power production facilities outside the United States.
Amendments to PUHCA in the Energy Policy Act provide that a domestic company
making such an investment may avoid "holding company" status or other regulation
under PUHCA, if the foreign enterprise obtains EWG status or files a notice with
the Securities and Exchange Commission that it is a foreign utility company
("FUCO").
PUHCA. Under PUHCA, any entity owning or controlling ten percent or more of
the voting securities of a "public utility company" is a "holding company" and
is subject to registration with the Securities and Exchange Commission and
regulation under PUHCA, unless eligible for an exemption. Under the Energy
Policy Act and PURPA, EWGs, FUCOs, and owners and operators of QFs are deemed
not to be public utility companies under PUHCA. Momentum is growing in Congress
for the repeal of PUHCA, as more legislators adopt the view that this statute
has outlived its purpose. Elimination of PUHCA would enable more companies to
consider owning generating and transmission assets, would permit "single state"
utility systems to expand beyond their state borders, and would permit companies
that are currently in registered holding company systems to diversify their
investments to a greater extent than now permitted. This could attract more
competitors to the power development and power marketing business. We believe
that we are well positioned, however, to meet stronger competition and, indeed,
may be able to pursue more investment opportunities made available by the repeal
of PUHCA.
FPA. The FPA grants the FERC exclusive rate-making jurisdiction over
wholesale sales of electricity in interstate commerce, including ongoing as well
as initial rate jurisdiction, which enables the FERC to revoke or modify
previously approved rates. While QFs under PURPA typically are exempt from the
traditional rate-making and certain other provisions of the FPA, projects not
qualifying for QF status, for example, most EWGs, are subject to the FPA and to
FERC rate making jurisdiction. Power marketers are also subject to FERC review
of their wholesale rates, and to FERC oversight of various business dealings
such as corporate reorganizations. Pursuant to the FPA, our power marketing
subsidiary has filed its wholesale electric power rates with the FERC and
obtained authorization to sell electric power at rates set by supply and demand
in the marketplace. In addition, the Logan facility and certain other facilities
in which Holdings owns a small interest have filed their rates with the FERC and
obtained authorization to sell all of their power pursuant to those rates.
Several of our projects under development have also filed and obtained from FERC
market-based rates for sales of power from these facilities.
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STATE REGULATION. PUCs regulate retail rates of electric utilities and, in
many states, power sales agreements from independent power producers. In
addition, states have been delegated the authority to determine utilities'
avoided costs under PURPA. PUCs often will pre-approve agreements with prices
that do not exceed avoided costs, because such contracts often have been
acquired through a competitive or market-based process. Recognizing the
competitive nature of the acquisition process, many PUCs will permit utilities
to "pass through" expenses associated with a power sales agreement with an
independent power producer. In addition, retail sales of electricity or steam by
an independent power producer may be subject to PUC regulation, depending on
state law.
EWGs are subject to broad regulation by PUCs, ranging from the requirement
of certificates of public convenience and necessity to regulation of
organizational, accounting, financial and other corporate matters. In addition,
states may assert jurisdiction over the siting and construction of EWGs as well
as QFs and over the issuance of securities and the sale or other transfer of
assets by these facilities. Many state utility commissions and state
legislatures are actively seeking ways to lower electric power costs at the
retail level, including options that would permit or compel competition at the
retail level. Federal legislation that would require states to permit retail
competition is also being given serious consideration. An opening of the retail
market would create tremendous opportunities for companies that have until now
been limited to the wholesale market. At the same time, state commissions are
pressuring the utilities they regulate to cut purchased power costs through
strict enforcement of existing contracts with QFs and EWGs, many of which are
considered to be overpriced. State commissions are also encouraging efforts by
utilities to buy out or buy down such contracts.
PROPOSED LEGISLATION. In addition to federal legislative initiatives, the
state commissions or state legislatures of many states are considering, or have
considered, whether to open the retail electric power market to competition.
These initiatives are generally called "retail access" or "customer choice".
Such "customer choice" plans typically allow customers to choose their
electricity suppliers by a certain date. Retail competition is possible when a
customer's local utility agrees, or is required, to "unbundle" its distribution
service, that is, the delivery of electric power to retail customers through its
local distribution lines, from its transmission and generating service.
The competitive price environment that will result from retail competition
may cause utilities to experience revenue shortfalls and deteriorating
creditworthiness. However, most, if not all, state plans will insure that
utilities receive sufficient revenues, through a distribution surcharge if
necessary, to pay their obligations under existing long-term power purchase
contracts with QFs and EWGs, including the above-market rates, or "stranded
investment" costs, provided for in such contracts. Many states will also provide
that the stranded investment costs will be "securitized" through new financial
instruments. On the other hand, QFs and EWGs may be subject to pressure to lower
their contract prices or to renegotiate contracts in an effort to reduce the
"stranded investment" costs of their utility customers.
Retail access programs may provide Holdings with additional opportunities to
provide power from our projects to industrial users or power marketers.
TRANSMISSION AND WHEELING. Under the FPA, the FERC regulates the rates,
terms and conditions for electricity transmission in interstate commerce. The
FERC's authority under the FPA to require electric utilities to provide
transmission service to QFs and EWGs was significantly expanded by the Energy
Policy Act. Except when market factors such as an exceptional site or power
sales opportunity warrant it, we generally attempt to site our facilities within
the utility customer's service area, and thus avoid the need to utilize
wheeling. The new provisions of the Energy Policy Act, however, and actions
taken by the FERC under the FPA have improved transmission access and pricing
for independent power producers like us.
In April 1996, the FERC issued a rulemaking order under the FPA, Order 888,
requiring all jurisdictional public utilities to file "open access" transmission
tariffs. Compliance with Order 888 has been virtually universal. However, many
utilities are seeking permission from the FERC to recover for "stranded
investment" through add-ons to their transmission rates. To the extent that the
FERC permits such charges, the cost of transmission may be too high on some
systems to be of practical use to wholesale sellers like Cogentrix.
Therefore, the full value of Order 888 remains to be determined.
The FERC is also encouraging the voluntary restructuring of transmission
operations through the use of independent system operators and regional
transmission groups. Such entities may create efficiencies for traditional
utilities, but are not likely to have a substantial impact on power developers
and power marketers like Cogentrix.
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<PAGE> 20
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 Holdings primarily involve the discharge of emissions
into the water and air and the use of water, but can also include wetlands
preservation, endangered species, waste disposal and noise regulation. These
laws and regulations often require a lengthy and complex process of obtaining
and renewing licenses, permits and approvals from federal, state and local
agencies. If such laws and regulations are changed and our facilities are not
grandfathered, extensive modifications to power project technologies and
facilities could be required.
We expect that environmental regulations will continue to become more
stringent as environmental legislation previously passed becomes implemented and
new laws are enacted. Accordingly, we plan to continue a strong emphasis on
implementation of environmental standards and procedures at the facilities we
operate and at our other facilities to minimize the environmental impact of
energy generation at these facilities.
CLEAN AIR ACT. In late 1990, Congress passed the Clean Air Act Amendments of
1990 (the "1990 Amendments") which affect existing facilities as well as new
project development. The original Clean Air Act of 1970 set guidelines for
emissions standards for major pollutants from newly-built sources. All of the
facilities we operate are in compliance with federal performance standards
mandated for such facilities under the Clean Air Act and the 1990 Amendments.
The 1990 Amendments attempt to reduce emissions from existing sources --
particularly large older facilities that were exempted from certain regulations
under the original Clean Air Act.
The 1990 Amendments create a marketable commodity called a sulfur dioxide
("SO(2)") "allowance." All non-exempt facilities over 25 megawatts that emit
SO(2), including independent power plants, must obtain allowances in order to
operate after 1999. Each allowance gives the owner the right to emit one ton of
SO(2). The 1990 Amendments exempt from the SO(2) allowance provisions all
independent power projects which were operating, under construction or with
power sales agreements or letters of intent as of November 15, 1990, as well as
facilities outside the contiguous 48 states. As a result, most of the facilities
we operate are exempt. The non-exempt facilities we operate have determined
their need for allowances and have accounted for these requirements in their
operating budgets and financial forecasts. In the future, the facilities we
expect to develop will continue to rely on "clean low sulfur coal," with flue
gas desulfurization technology or natural gas technology. We believe that the
additional costs of obtaining the number of allowances needed for future
projects should not materially affect our ability to develop such projects.
The 1990 Amendments also contain other provisions that could affect our
projects. Provisions dealing with geographical areas the EPA has designated as
in "nonattainment" with national ambient air quality standards require that
existing sources of air pollutants in a nonattainment area be retrofit with
reasonably available control technology ("RACT") for all pollutants for which an
area is designated nonattainment. The technology currently installed at the
plants we operate should uniformly meet or exceed RACT for those pollutants. The
nonattainment provisions also require that each new or expanded source of air
pollutants in designated nonattainment areas must obtain emissions reductions
from existing sources that more than offset the emissions from the new or
expanded source. While the "offset" requirements may hamper new project
development in certain geographical areas, development of new projects has and
will likely continue, particularly as markets for "offsets" develop.
The 1990 Amendments also provide an extensive new operating permit program
for existing sources called the Title V permitting program. Because all of the
facilities we operate were permitted under the Prevention of Significant
Deterioration New Source Review Process, the permitting impact to Holdings under
the 1990 Amendments at those facilities is expected to be minimal. Continuous
emission monitoring systems may need to be upgraded at some facilities while the
permit fees will increase operating expenses. The costs of applying for and
obtaining operating air permits are not anticipated to be significant.
The hazardous air pollutant provisions of the 1990 Amendments presently
exclude electric steam generating facilities, such as our facilities. Studies of
the emissions from such facilities have been submitted to Congress. Until
Congress either amends the Clean Air Act further or the EPA promulgates
regulations, the federal hazardous air pollutants emissions restrictions, which
will be applied to our facilities and other electric steam generating
facilities, will remain uncertain.
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<PAGE> 21
In July 1997, the EPA promulgated more restrictive ambient air quality
standards for ozone and for particulate matter: less than 25 microns in diameter
- -- PM-2.5. These new standards will likely increase the number of nonattainment
areas for both ozone and PM-2.5. If our facilities are in these new
nonattainment areas, further emission reduction requirements could result in the
installation of additional control technology. In May 1999, the D.C. Circuit
Court of Appeals remanded these standards. However, we will continue to track
these standards and the potential impact on us.
In addition, the Ozone Transport Assessment Group ("OTAG"), composed of
state and local air regulatory officials from the 37 Eastern states, has
recommended additional NO(x) emission reductions that go beyond current federal
standards. These recommendations include reductions from utility and industrial
boilers. In the fall of 1998, the EPA adopted regulations requiring revisions to
state implementation plans ("SIPs"). These regulations implement some of the
OTAG's recommendations and go beyond some of the OTAG's recommendations for
reductions in NO(x) emissions. As a result of these more stringent NO(x)
emission standards, we may be required to install additional NO(x) emission
control technologies and/or obtain allowances from other emitters. We will
continue to monitor the potential effects this proposed legislation will have on
Holdings.
In December 1999, the EPA issued a final rule requiring reductions of NOx
emissions from 392 generating and other facilities in 12 Eastern and Midwestern
states, including North Carolina and Virginia, by May of 2003. This rule
responds to petitions by Northeastern States under CAA Section 126 for controls
on upwind NOx emission sources, which the states demonstrated prevents them from
attaining the ozone ambient standard. The Section 126 rule is an alternative to
the NOx SIP-Call rule and is very similar in structure. We are considering all
options in complying with this rule including installation of control equipment
and/or purchasing of NOx allowances.
The 1990 Amendments expand the enforcement authority of the federal
government by increasing the range of civil and criminal penalties for
violations of the Clean Air Act, enhancing administrative civil penalties, and
adding a citizen suit provision. These enforcement provisions also include
enhanced monitoring, recordkeeping and reporting requirements for existing and
new facilities. On February 13, 1997, the EPA issued a regulation providing for
the use of "any credible evidence or information" in lieu of, or in addition to,
the test methods prescribed by regulation to determine the compliance status of
permitted sources of air pollution. This rule may effectively make emission
limits previously established for many air pollution sources, including ours,
more stringent.
The Kyoto Protocol regarding greenhouse gas emissions and global warming was
signed by the U.S., committing to significant reductions in greenhouse gas
emissions. The U.S. Senate must ratify the agreement for the protocol to take
effect. The Clinton Administration has proposed a package of legislative and
administrative policies to curb greenhouse gases, none of which are affected by
the need for Senate ratification. Management believes that none of these
policies will have a material effect on the consolidated results of operations
or financial position of Holdings. Future initiatives on this issue and the
effects on Holdings are unknown at this time.
CLEAN WATER ACT. Our facilities are subject to a variety of state and
federal regulations governing existing and potential water/wastewater and
stormwater discharges from the facilities. Generally, federal regulations
promulgated through the Clean Water Act govern overall water/wastewater and
stormwater discharges through National Pollutant Discharge Elimination System
permits. Under current provisions of the Clean Water Act, existing permits must
be renewed every five years, at which time permit limits are under extensive
review and can be modified to account for more stringent regulations. In
addition, the permits have re-opener clauses which can be used to modify a
permit at anytime. Several of the facilities we operate have either recently
gone through permit renewal or will be renewed within the next few years. Based
upon recent renewals, we do not anticipate more stringent monitoring
requirements for any of the facilities we operate. We believe that we are in
material compliance with applicable discharge requirements under the Clean Water
Act.
EMERGENCY PLANNING AND COMMUNITY RIGHT-TO-KNOW ACT. In April of 1997, the
EPA expanded the list of industry groups required to report the Toxic Release
Inventory under Section 313 of the Emergency Planning and Community
Right-to-Know Act to include electric utilities. Our operating facilities are
required to complete a toxic chemical inventory release form for each listed
toxic chemical manufactured, processed or otherwise used in excess of threshold
levels. The purpose of this requirement is to inform the EPA, states, localities
and the public about releases of toxic chemicals to the air, water and land that
can pose a threat to the community.
19
<PAGE> 22
COMPREHENSIVE ENVIRONMENTAL RESPONSE, COMPENSATION, AND LIABILITY ACT. The
Comprehensive Environmental Response, Compensation, and Liability Act of 1980,
as amended ("CERCLA" or "Superfund"), requires cleanup of sites from which there
has been a release or threatened release of hazardous substances and authorized
the EPA to take any necessary response action at Superfund sites, including
ordering potentially responsible parties ("PRPs") liable for the release to take
or pay for such actions. PRPs are broadly defined under CERCLA to include past
and present owners and operators of, as well as generators of wastes sent to a
site. At present, we are not subject to liability for any Superfund matters and
take measures to assure that CERCLA will not apply to properties we own or
lease. However, we do generate certain wastes in the operation of our plants,
including small amounts of hazardous wastes, and send certain wastes to
third-party waste disposal sites. As a result, there can be no assurance that we
will not incur liability under CERCLA in the future.
RESOURCE CONSERVATION AND RECOVERY ACT ("RCRA"). RCRA regulates the
generation, treatment, storage, handling, transportation and disposal of
hazardous wastes. We are exempt from the solid waste requirements under RCRA
regarding coal combustion by-products. We are classified as a conditionally
exempt small quantity generator of hazardous wastes at all of our facilities. We
will continue to monitor regulations under this rule and will strive to maintain
the exempt status.
EMPLOYEES
At December 31, 1999, we employed 410 people, none of whom is covered by a
collective bargaining agreement.
ITEM 2. PROPERTIES
Our significant, operating properties are listed and described in the
section entitled "Business -- Facilities in Operation."
We believe that our facilities and properties have been satisfactorily
maintained, are in good condition, and are suitable for our operations.
20
<PAGE> 23
ITEM 3. LEGAL PROCEEDINGS
Claims and Litigation
One of our indirect, wholly-owned subsidiaries is party to certain product
liability claims related to the sale of coal combustion by-products for use in
various construction projects. Management cannot currently estimate the range of
possible loss, if any, we will ultimately bear as a result of these claims.
However, our management believes - based on its knowledge of the facts and legal
theories applicable to these claims and after consultations with various counsel
retained to represent the subsidiary in the defense of such claims - that the
ultimate resolution of these claims should not have a material adverse effect on
our consolidated financial position or results of operations or our ability to
generate sufficient cash flow to service our outstanding debt.
In addition to the litigation described above, we experience other routine
litigation in the normal course of business. Our management is of the opinion
that none of this routine litigation will have a material adverse impact on our
consolidated financial position or results of operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED SHAREHOLDER
MATTERS
(a) Market Information - There is no established market for our common
stock, which is closely held.
(b) Principal Shareholders - All of the issued and outstanding shares of
common stock of Cogentrix Delaware Holdings, Inc. are owned by our
Parent, Cogentrix Energy.
(c) Dividends - Our project subsidiaries and unconsolidated affiliates have
generated sufficient cash flow for the years ended December 31, 1999
and 1998, to service their debt and allow us to pay $141,873,000 and
$97,604,000 in dividends to our parent, Cogentrix Energy.
ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA
The following table sets forth certain selected consolidated financial
data as of and for the three fiscal years ended December 31, 1999, the six-month
periods ended December 31, 1997 and 1996 and the fiscal year ended June 30,
1997, and should be read in conjunction with our consolidated financial
statements and related notes thereto and with "Management's Discussion and
Analysis of Financial Condition and Results of Operations."
The selected consolidated financial information as of and for each of
the three fiscal years ended December 31, 1999, the six-month period ended
December 31, 1997 and 1996 and the fiscal year ended June 30, 1997 presented
below has been derived from our consolidated financial statements.
21
<PAGE> 24
Effective January 1, 1998, we changed our fiscal year to commence on
January 1 and conclude on December 31 of each year. Our fiscal year previously
commenced each July 1, concluding on June 30 of the following calendar year.
<TABLE>
<CAPTION>
SIX-MONTH PERIOD YEAR ENDED
YEARS ENDED DECEMBER 31, ENDED DECEMBER 31, JUNE 30,
--------------------------------------- ------------------------ ---------
1999 1998 1997 1997 1996 1997
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
Operating revenue:
Electric $ 294,185 $ 293,083 $ 307,104 $ 154,810 $ 162,909 $ 315,203
Steam 25,236 25,043 26,123 12,721 13,284 26,686
Lease 44,697 34,715 -- -- -- --
Service revenue under capital leases 43,888 34,470 -- -- -- --
Income from unconsolidated investments
in power projects 25,464 6,474 1,412 1,186 348 574
Other 18,964 15,908 13,264 7,370 4,556 10,450
--------- --------- --------- --------- --------- ---------
Total operating revenue 452,434 409,693 347,903 176,087 181,097 352,913
--------- --------- --------- --------- --------- ---------
Operating expenses:
Operating costs 222,730 210,590 210,580 93,689 108,348 204,446
General, administrative and development 1,502 515 2,005 10,988 8,056 19,568
Depreciation and amortization 41,583 40,988 40,429 19,741 18,179 38,775
Loss on impairment and cost of removal
of cogeneration facilities -- -- -- -- 65,628 65,628
--------- --------- --------- --------- --------- ---------
Total operating expenses 265,815 252,093 253,014 124,418 200,211 328,417
--------- --------- --------- --------- --------- ---------
Operating income 186,619 157,600 94,889 51,669 (19,114) 24,496
Other income (expense):
Interest expense (63,255) (61,802) (44,849) (21,828) (24,319) (47,340)
Investment and other income 12,523 9,687 9,240 4,424 4,821 9,739
Equity in net income (loss) of
affiliates, net -- (2,967) (1,190) (1,710) (1,242) (814)
Minority interest in income (14,752) (12,458) (4,672) (2,273) (1,614) (4,013)
--------- --------- --------- --------- --------- ---------
Income (loss) before income taxes and
extraordinary gain (loss) 121,135 90,060 53,418 30,282 (41,468) (17,932)
Benefit (provision) for income taxes (48,829) (35,844) (20,031) (11,992) 15,494 6,868
--------- --------- --------- --------- --------- ---------
Income (loss) before extraordinary loss 72,306 54,216 33,387 18,290 (25,974) (11,064)
Extraordinary loss on early
extinguishment of debt, net -- (743) (1,502) (1,502) (703) (703)
--------- --------- --------- --------- --------- ---------
Net income (loss) $ 72,306 $ 53,473 $ 31,885 $ 16,788 $ (26,677) $ (11,767)
========= ========= ========= ========= ========= =========
</TABLE>
22
<PAGE> 25
OTHER FINANCIAL RATIO DATA
Set forth below are other financial data and ratios for the periods
indicated (in thousands):
<TABLE>
<CAPTION>
AS OF DECEMBER 31, AS OF JUNE 30,
1999 1998 1997 1997 1996
---------- ---------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Total Assets ............. $1,990,819 $1,516,943 $846,963 $869,308 $922,263
========== ========== ======== ======== ========
Project financing debt (1) $1,204,983 $ 877,653 $567,705 $591,693 $616,588
========== ========== ======== ======== ========
Total shareholder's equity $ 390,415 $ 373,034 $118,894 $119,567 $140,003
========== ========== ======== ======== ========
</TABLE>
- --------------------
(1) Project financing debt with respect to each of our facilities is
"substantially non-recourse" to Holdings and its other project
subsidiaries. For a discussion of the term "substantially
non-recourse," see "Business - Project Agreements, Financing and
Operating Arrangements for Our Facilities -- Project Financing" herein.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
In addition to discussing and analyzing our recent historical financial
results and condition, the following "Management's Discussion and Analysis of
Financial Condition and Results of Operations" includes statements concerning
certain trends and other forward-looking information affecting or relating to
Cogentrix which are intended to qualify for the protections afforded
"Forward-Looking Statements" under the Private Securities Litigation Reform Act
of 1995, Public Law 104-67. The forward-looking statements made herein and
elsewhere in this Form 10-K are inherently subject to risks and uncertainties
which could cause the actual results to differ materially from the
forward-looking statements. See cautionary statements appearing under the
Business section above and elsewhere in this Form 10-K for a discussion of the
important factors affecting the realization of those results.
TRENDS AFFECTING OUR FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Effect of Recent Power Purchase Agreement Restructurings on our Revenues,
Expenses and Cash Flow
Each of our electric generating facilities in operation produces electricity
for sale to a utility and thermal energy for sale to an industrial user. The
electricity and thermal energy generated by these facilities are typically sold
under long-term power or steam sales agreements.
A number of the generating facilities we originally developed sold
electricity under long-term contracts that obligated the electric utility to
purchase all electricity generated by the facility. We subsequently negotiated
amendments to the majority of these contracts to provide the electric utility
the ability to suspend or reduce its purchases of electricity from each facility
if the electric utility determines the utility can operate its system for a
designated period of time more economically.
The amended power purchase agreements are structured so that we continue to
receive -- during any period the utility exercises its ability to suspend or
reduce purchases of electricity -- fixed payments that are designed in part to
cover the facility's debt service and its fixed operating costs. These fixed
payments also make up a substantial portion of the profit component of each
power purchase agreement.
When the electric utility exercises its right to suspend or reduce purchases
of electricity from us, we do not receive, or receive only in reduced amounts,
the variable payments for electricity produced that are intended primarily to
cover our variable operating and maintenance costs, as well as our coal and rail
transportation costs. Because we are not producing electricity, or are producing
electricity in reduced amounts, these variable costs are correspondingly
reduced.
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<PAGE> 26
Despite the reduced variable payments we receive when an electric utility
suspends or reduces its purchases of electricity from us, we generally recognize
an increase in cash flows. The increase in cash flows is a result of both the
lower operating and maintenance costs during the period of suspension or
reduction of the amount of the fixed payments the utility must continue to make
during the period.
The restructuring of these power purchase agreements represents a positive
development both for us and for the electric utilities. Even when the fixed
payments the utilities must make to us are combined with their cost of obtaining
electricity from alternative sources, those payments still represent a
significant reduction from the rates the electric utilities would have paid us
for electricity generated by our facilities had the power purchase agreements
not been restructured.
Termination Dates of Seven of our Power Sales Agreements
The power sales agreements at seven of our facilities either terminate in
years 2000 through 2002 or provide for a significant reduction in fixed payments
received under such agreements after 2002. Accordingly, revenues recognized by
us under these power sales agreements will, after 2002, be eliminated or
significantly reduced. Our management believes, however, that our project
subsidiaries and unconsolidated affiliates will generate sufficient cash flow to
service their debt, pay dividends to us and pay management fees to Cogentrix.
Legislative Proposals to Restructure the Electric Generating Industry
The domestic electric generating industry is currently going through a
period of significant change as many states are implementing or considering
regulatory initiatives designed to increase competition. In addition to
restructuring activities in various states, there have also been several
industry restructuring bills introduced in Congress. We cannot predict the final
form or timing of the proposed restructurings and the impact, if any, that such
restructurings would have on our existing business or consolidated results of
operations. Because these restructuring proposals have generally included a
grandfathering provision for contracts entered into prior to repeal of existing
legislation we believe that any such restructuring would not have a material
adverse effect on our power sales agreements. Accordingly, we believe that our
existing business and results of consolidated operations would not be materially
adversely affected, although there can be no assurance in this regard.
Recent Acquisitions, Development and Other Changes in our Portfolio of
Generating Plants
Our recent growth has substantially increased our electric production
capability. The acquisition of ownership interests in the Cottage Grove and
Whitewater facilities, whose power sales agreements are accounted for as
"sales-type" capital leases, has resulted in the recognition of lease and
service revenues, as well as cost of services under "sales-type" leases. The
acquisition of ownership interests in twelve electric generating facilities has
significantly impacted the amount of income recognized from unconsolidated power
projects. These acquisitions were financed with debt and as a result, have
impacted the interest expense reported in our results of operations. Our
facilities under construction will not have a significant impact on our results
of operations until they begin commercial operations, at which time, we will
experience an increase in operating revenues, operating expenses and interest
expense.
RESULTS OF OPERATIONS
The following table sets forth the results of operations and percentage
of total operating revenues represented by the components of operating revenues
and expenses for the years ended December 31, 1999, 1998 and 1997.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------------------------------------
1999 1998 1997
-------------------- ------------------- --------------------
<S> <C> <C> <C> <C> <C> <C>
Total operating revenues $452,434 100.0% $409,693 100.0% $347,903 100.0%
Operating costs 222,730 49.2% 210,590 51.4% 210,580 60.5%
General, administrative
and development 1,502 0.4% 515 0.1% 2,005 0.6%
Depreciation and amortization 41,583 9.2% 40,988 10.0% 40,429 11.6%
-------- ----- -------- ----- -------- -----
Operating income $186,619 41.2% $157,600 38.5% $ 94,889 27.3%
======== ===== ======== ===== ======== =====
</TABLE>
24
<PAGE> 27
Fiscal Year Ended December 31, 1999 as compared to Fiscal Year Ended December
31, 1998
Total operating revenues increased 10.4% to $452.4 million for the year
ended December 31, 1999, as compared to $409.7 million for the year ended
December 31, 1998. This increase was primarily attributable to the $19.4 million
increase in lease and service revenue earned under the power sales agreements
for the Cottage Grove and Whitewater facilities in which we acquired our
interests in March, 1998. The increase in operating revenues also relates to a
$19.0 million increase in income from unconsolidated investments in power
projects. This increase was primarily attributable to purchase of interests in
12 electric generating facilities in October 1998. The increase in income from
unconsolidated investments in power projects was also impacted by the purchase
of an additional 40% interest in the Indiantown facility during 1999.
Total operating expenses increased 5.7% to $222.7 million for the year
ended December 31, 1999 as compared to $210.6 million for the year ended
December 31, 1998. This increase was primarily attributable to the $10.2 million
increase in cost of services incurred by the Cottage Grove and Whitewater
facilities, interests in which we acquired in March 1998. Total operating
expenses also increased as a result of an increase in fuel expense of $3.4
million associated with an increase in overall megawatt hours sold to the
purchasing utilities at our plants, the amortization of our fuel litigation
settlement with a coal supplier and an increase in fuel sold to third parties at
the Cottage Grove and Whitewater facilities. The increase in total operating
expenses was partially offset by a $1.5 million decrease in operation and
maintenance expenses due to routine maintenance expenses incurred at several of
our facilities during the year ended December 31, 1998.
General, administrative, and development expenses were $1.5 million for
the year ended December 31, 1999 as compared to $.5 million for the year ended
December 31, 1998. The increase results primarily from the sale of a 49%
interest in a project subsidiary in the year ending December 31, 1998, resulting
in our new joint venture partner reimbursing us approximately $1.2 million of
project development expenses incurred during 1998.
Interest expense increased 2.4% to $63.3 million for the year ended
December 31, 1999 as compared to $61.8 million for the year ended December 31,
1998. Our average long-term debt increased to $908.9 million for the year ended
December 31, 1999 as compared to average long-term debt of $866.6 million for
the year ended December 31, 1998. The increases in interest expense and weighted
average debt outstanding were related to the inclusion of the project debt of
the Cottage Grove and Whitewater facilities acquired in March 1998, and
borrowings incurred during the year under revolving credit facilities at some
subsidiaries related to acquisitions made during the year. The increase in
average long-term debt outstanding was also impacted, to a lesser extent, by an
outstanding construction loan of approximately $70 million in December, 1999,
for the project under construction in Jenks, Oklahoma. The increase in interest
expense was partially offset by a decrease in interest expense at several of our
project subsidiaries resulting from the scheduled repayment of outstanding
project finance debt.
The increase in minority interest in income for the year ended December
31, 1999, as compared to the year ended December 31, 1998, related to the
inclusion of a full twelve months of results of operations for the Cottage Grove
and Whitewater facilities in the year ended December 31, 1999 as compared to
only nine months in the year ended December 31, 1998, and the settlement of the
construction contract on the Whitewater and Cottage Grove facilities.
25
<PAGE> 28
Fiscal Year Ended December 31, 1998 as compared to Fiscal Year Ended December
31, 1997
Total operating revenues increased 17.8% to $409.7 million for the year
ended December 31, 1998 as compared to $347.9 million for the year ended
December 31, 1997. This increase was primarily attributable to the $69.2 million
aggregate amount of lease revenue and service revenue earned under the power
sales agreements for the Cottage Grove and Whitewater facilities in which we
acquired our interests in March 1998. Operating revenues were also impacted by
an increase in income from unconsolidated investments in power projects. The
increase was primarily the result of the acquisition of ownership interest in 12
electric generating facilities in October 1998, in which we acquired ownership
interests in 12 electric generating plants. We recognized approximately $2.8
million of revenue, net of premium amortization, related to these ownership
interests. These increases in operating revenues were partially offset by a net
decrease in electric revenue for the year ended December 31, 1998 as compared to
the year ended December 31, 1997. This decrease is primarily the result of a
restructuring of power sales agreements at two of our facilities to give the
purchasing utility the right to suspend or reduce purchases of energy. The
decrease in electric revenues was partially offset by an increase in electric
revenue at three of our facilities due to an increase in megawatt hours sold to
the purchasing utilities.
Operating costs remained fairly consistent for the year ended December 31,
1998 as compared to the corresponding period of 1997. Operating costs decreased
as the result of a $40.3 million reduction in fuel expense, a component of
operating costs, at two of our facilities resulting from the restructuring of
their power sales agreements. Operating costs were also impacted as a result of
a decrease in operating costs incurred by ReUse related to third-party
agreements. These decreases were offset by the $37.0 million in cost of services
incurred by the Cottage Grove and Whitewater facilities, interests in which we
acquired in March 1998. Operating expenses were also impacted by the increases
in fuel expense at two of our facilities associated with an increase in megawatt
hours sold.
General, administrative and development expenses for the year ended
December 31, 1998 were $.5 million as compared to $2.0 million for the
corresponding period of 1997. The decrease is primarily the result of the sale
of a 49% interest in a project subsidiary. Under the sales agreement, the new
joint venture partner reimbursed Holdings for approximately $1.2 million of
development costs incurred during the year ended December 31, 1998.
Interest expense increased 37.9% to $61.8 million for the year ended
December 31, 1998 as compared to $44.8 million for the year ended December 31,
1997. Our average long-term debt increased to $866.7 million for the year ended
December 31, 1998 as compared to average long-term debt of $588.3 million for
the year ended December 31, 1997. The increases in interest expense and weighted
average debt outstanding are related to the inclusion of the project finance
debt of the Cottage Grove and Whitewater facilities acquired in March 1998, and
the increase in project finance debt outstanding at the Portsmouth facility,
which was refinanced in December 1997, and the Hopewell facility, which was
refinanced in February 1998. The increase in interest expense discussed above
was partially offset by a decrease in interest expense at several of our project
subsidiaries due to the scheduled repayment of outstanding project finance debt.
The increase in the equity in net loss of affiliates for the year ended
December 31, 1998 relates to an increase in losses recognized by the
partnerships operating tomato greenhouses in the states of New York and Texas.
In December 1998, we entered into an agreement to sell our interests in these
partnerships which resulted in the recognition of a $2.1 million gain included
in investment and other income in the accompanying consolidated statements of
operations.
The increase in minority interests in income for the year ended December
31, 1998 as compared to the prior year relates to the recognition of the
minority partner's share of earnings in the Cottage Grove and Whitewater
facilities, and an increase in earnings at the Hopewell facility as a result of
that facility's restructured power sales agreement.
The extraordinary loss on early extinguishment of debt for the year ended
December 31, 1998 relates to the refinancing of the Hopewell facility's project
debt in January 1998. The loss consisted of a write-off of the deferred
financing costs on the Hopewell facility's original project debt and a swap
termination fee on an interest rate swap agreement hedging the original project
debt.
26
<PAGE> 29
LIQUIDITY AND CAPITAL RESOURCES
The principal components of operating cash flow for the year ended December
31, 1999 were generated by net income of $72.3 million, increases due to
adjustments for depreciation and amortization of $41.6 million, deferred income
taxes of $41.0 million, minority interest in income of joint venture of $8.5
million and equity in net income of unconsolidated affiliates, net of dividends,
of $1.1 million, which were partially offset by amortization of unearned lease
income, net of minimum lease payments received of $1.6 million and a net $18.6
million use of cash reflecting changes in other working capital assets and
liabilities. Cash flow provided by operating activities of $144.3 million,
proceeds from project finance borrowings of $191.3 million, $12.4 million of
cash escrows released, and $88.1 million of contributions from our parent, were
primarily used to purchase property, plant and equipment additions of $3.7
million, to make investments in affiliates of $76.8 million, to pay deferred
financing costs of $8.2 million, to repay project finance borrowings of $122.2
million, to lend our Parent $19.1 million, to pay a dividend to our Parent of
$141.9 million and to fund payments on construction in progress and project
development costs of $52.3 million.
The principal components of operating cash flow for the year ended December
31, 1998 were net income of $53.5 million, increases due to adjustments for
depreciation and amortization of $41.0 million, deferred income taxes of 11.1
million, a write-off of deferred financing costs of $2.1 million and equity in
net income (loss) of unconsolidated affiliates, net of dividends of $10.2
million and a net $4.9 million of cash provided by operations reflecting changes
in other working capital assets and liabilities, which were partially offset by
amortization of unearned lease income, net of minimum lease payments received of
$2.0 million, and minority interests in income, net of dividends, of $14.5
million. Cash flow provided by operating activities of $106.3 million, proceeds
from borrowings of $100.4 million, proceeds from the sale of marketable
securities of $42.1 million, $27.8 million of cash escrows released, $298.3
million of contribution from our Parent and cash on hand at the beginning of the
year of $30.2 million were primarily used to acquire interests in facilities of
$155.3 million, purchase property plant and equipment of $5.2 million, make
investments in affiliates of $180.3 million, repay project finance borrowings of
$143.8 million, pay deferred financing costs of $1.7 million, lend $21.2 to our
Parent and pay a common stock dividend of $97.6 million to our Parent.
Historically, we have financed each facility primarily under financing
arrangements and related documents which generally require the extensions of
credit to be repaid solely from the project's revenues and provide that the
repayment of the extensions of credit (and interest thereon) is secured solely
by the physical assets, agreements, cash flow and, in certain cases, the capital
stock of or the partnership interest in that project subsidiary. This type of
financing is generally referred to as "project financing." The project financing
debt of our subsidiaries and joint ventures (aggregating $1.2 billion as of
December 31, 1999) is non-recourse to us and our other project subsidiaries,
except in connection with certain transactions where our Parent has agreed to
certain limited guarantees and other obligations with respect to such projects.
These limited guarantees and other obligations include agreements for the
benefit of the project lenders to two project subsidiaries to fund cash deficits
the projects may experience as a result of incurring certain costs, subject to
an aggregate cap of $40.6 million.
In addition, Cogentrix Inc., which is an indirect subsidiary of Holdings,
has guaranteed two project subsidiaries' obligations to the purchasing utility
under five power sales agreements. Three of these power sales agreements provide
that in the event of early termination that is not for cause, the project
subsidiary must pay the utility a termination charge equal to the excess paid
for capacity and energy over what would have been paid to the utility under the
utility's published five-year capacity credit and variable energy rates plus
interest. The remaining two power sales agreements provide that in the event of
early termination, the project subsidiary must pay the utility the cost of
replacing the electricity from a third party for the remainder of the
agreement's term. Because these project subsidiaries' obligations do not by
their terms stipulate a maximum dollar amount of liability, the aggregate amount
of potential exposure under these guarantees cannot be quantified. If we or our
subsidiary were required to satisfy all of these guarantees and other
obligations or even one or more of the significant ones, it could impair
Holdings' ability to pay dividends and management fees to the Parent.
Any project we develop in the future, and those electric generating
facilities we may seek to acquire, are likely to require substantial capital
investment. Our ability to arrange financing on a non-recourse basis and the
cost of such capital are dependent on numerous factors. In order to access
capital on a non-recourse basis in the future, we may have to make larger equity
investments in, or provide more financial support for, the project entity.
The ability of our subsidiaries and the project entities in which we have an
investment to pay dividends and management fees periodically to us and our
Parent is subject to limitations in their respective financing documents. These
limitations
27
<PAGE> 30
generally require that: (a) debt service payments be current, (b) debt service
coverage ratios be met, (c) all debt service and other reserve accounts be
funded at required levels and (d) there be no default or event of default under
the relevant financing documents. There are also additional limitations that are
adapted to the particular characteristics of each subsidiary and project
entities in which we have an investment. Management does not believe that such
restrictions or limitations will adversely affect our Parent's ability to meet
its debt obligations.
As of December 31, 1999, we had long-term debt (including the current
portion thereof) of approximately $1.3 billion. Substantially all of such
indebtedness is project financing debt. Future annual maturities of long-term
debt range from $34.8 million to $124.9 million in the five-year period ending
December 31, 2004. We believe that our project subsidiaries and the project
entities in which we have an investment will generate sufficient cash flow to
pay all required debt service on the project financing debt.
In December 1997, we renegotiated the project financing arrangements for our
Portsmouth facility. The amended agreements resulted in an extension of the
final maturity date of the loan by three months and an increase in the amount of
commitment provided by the project lenders in the form of a $40.5 million
revolving credit facility. The revolving credit facility is available to be
drawn by the project subsidiary owning the Portsmouth facility at any time for
general corporate purposes, including paying dividends to us. During
1999, the project subsidiary borrowed $20.4 million under the revolving credit
facility and distributed such amount to us for purposes of funding a
portion of the purchase price related to the acquisition of a 40% interest in
the Indiantown facility.
In February 1998, we renegotiated the project financing arrangements for the
Hopewell facility, in which we own a 50% interest. The amended agreements
resulted in a $34.6 million increase in outstanding indebtedness of the project
subsidiary owning and operating the facility, and extended the final maturity
date of the loan by six months. The project subsidiary transferred substantially
all of the additional funds borrowed (net of transaction costs) to its partners.
In March 1998, we acquired from LS Power Corporation an approximate 74%
ownership interest in the Whitewater facility and the Cottage Grove facility.
Each of the Cottage Grove and Whitewater facilities is a 245-megawatt gas-fired,
combined-cycle cogeneration facility. Commercial operations of the facilities
commenced in the last half of calendar 1997. The aggregate acquisition price for
our ownership interests in the Cottage Grove and Whitewater facilities was
$158.0 million. In addition, we pre-funded a $16.7 million distribution to the
previous owners. This distribution represented unused construction contingency
funds and cash flows that were accumulated by the Cottage Grove and Whitewater
facilities prior to January 1, 1998. We received a distribution of $15.7 million
in April 1998, and received a distribution of the remaining $1.0 million in
1999. The purchase price was funded with the proceeds of the corporate credit
facility and corporate cash balances.
In August 1998, we acquired an approximate 52% interest in the Batesville
facility. We have committed to provide an equity contribution to the project
subsidiary of approximately $54 million upon the earliest to occur of (a) the
incurrence of construction costs after all project financing has been expended,
(b) an event of default under the project subsidiary's financing arrangements or
(c) June 30, 2001. This equity commitment is supported by a $54 million letter
of credit, which is provided under the Cogentrix corporate credit facility. We
expect the Batesville facility, which we will operate, to begin operation in
summer 2000. Electricity generated by the Batesville facility will be sold
under long-term power purchase agreements with two investment-grade utilities.
In October 1998, we acquired Bechtel Generating Company, Inc.'s ownership
interests in 12 electric generating facilities, comprising a net equity interest
of approximately 365 megawatts, and one interstate natural gas pipeline. The
aggregate acquisition price for the Bechtel Acquisition including acquisition
costs was approximately $189.7 million. The purchase price was funded with
borrowings from some of our subsidiaries' revolving credit facilities, and a
portion of the proceeds from our Parent's sale of their 2008 notes.
As a result of a March 1999 arbitration award related to a contract dispute
with a coal supplier, we were obligated to pay the coal supplier approximately
$8 million in 1999. Approximately $3 million of this award relates to the
reduction in purchase quantities for prior periods and approximately $5 million
relates to the reduction in purchase quantities from the date of the award
through the balance of the term of the coal contract, which ends in September
2001. The future reduction in purchase quantities provides a future economic
benefit to our project subsidiary.
28
<PAGE> 31
In June 1999, we entered into an agreement to purchase an additional 40%
ownership interest in the Indiantown cogeneration facility in a three-phase
transaction. We paid $39.8 million to acquire a 19.9% interest in the facility
in June 1999, $36.6 million to acquire a 20% interest in the facility in
September 1999 and $0.2 million to acquire a 0.1% interest in the facility in
November 1999. We funded the purchase of these interests with proceeds from the
CEA credit facility and the Portsmouth credit facility.
In September 1999, one of our wholly-owned subsidiaries, Cogentrix Eastern
America, Inc. ("CEA"), formed to hold our twelve electric generating facilities
acquired in the Bechtel Acquisition, entered into a $75 million, three-year
revolving credit facility. The commitment under this facility reduces to $67.5
million after one-year and to $60 million after two years. Certain covenants and
financial conditions must be met under this credit facility prior to cash
distributions received by CEA being available for distribution to us and our
parent. With the closing of this credit facility, our subsidiaries now maintain
revolving credit facilities, which are non-recourse to us, with aggregate
commitments of $143.0 million. As of December 31, 1999, we had $42.6 million
available under these facilities.
In November 1999, Cottage Grove, Whitewater and the contractor, with the
concurrence of the independent engineer, reached a final agreement regarding the
settlement of all outstanding issues and obligations of Cottage Grove,
Whitewater and the contractor pursuant to the Cottage Grove and Whitewater
construction contracts. The final settlement of the construction contracts
provided for a payment to the contractor of approximately $4,030,000 from funds
available in Cottage Grove's and Whitewater's construction retainage accounts.
The contractor has also agreed to extend various warranty periods and perform
various repairs and inspection. Cottage Grove and Whitewater, in turn,
acknowledged that final acceptance shall have been deemed to have occurred. The
value of the existing letters of credit provided in lieu of cash retainage was
reduced from $11,030,000 to $5,000,000. The remaining value of these letters of
credit will be decreased in stages as the contractor successfully completes the
agreed upon inspections and additional work. The settlement provided for the
release of approximately $9,441,000 of remaining restricted cash from the
construction retainage accounts of Cottage Grove and Whitewater. These funds
were distributed to us in November 1999.
In December 1999, we closed a $350 million construction loan with several
banks and commenced construction on an approximate 800 megawatt, combined cycle,
natural gas-fired generating facility located in Jenks, Oklahoma. We have
committed to provide an equity contribution to the project subsidiary of
approximately $56.9 million upon the earliest to occur of (a) an event of
default under the project subsidiary's financing agreement or (b) the incurrence
of construction costs after all project financing has been expended or (c) June
24, 2002. The equity contribution is reduced by approximately $8.2 million upon
our receipt of a waste water discharge permit, and further reduced by
contributions made by us once the construction loan proceeds are exhausted. This
equity contribution is supported by a letter of credit, which is provided under
our Parent's corporate credit facility. We expect the Oklahoma facility, which
we will operate, to begin operation in June 2002. Electricity generated by the
Oklahoma facility will be sold under a long-term power purchase agreement to
PECO Energy's Power Team.
In March 2000, we closed a credit facility with a bank and a financial
institution which provides for a $126 million construction loan and a $5 million
debt service reserve letter of credit. Proceeds from the construction loan will
be used to construct an approximate 270 megawatt combined-cycle natural
gas-fired generating facility located in Rathdrum, Idaho. We own a 51% interest
in a partnership that will own this facility and have committed to provide an
equity contribution commitment to the project subsidiary of approximately $16.7
million upon the earliest to occur of (a) an event of default under the
project's subsidiary's financing agreement, (b) the incurrence of construction
costs after all project financing has been expended, or (c) October 1, 2002.
This equity contribution commitment is supported by a letter of credit, which is
provided under our Parent's corporate credit facility, in addition, our Parent
has agreed to make additional stand-by equity contributions to cover certain
contingent costs during the construction period capped at $3.6 million. An
indirect wholly owned subsidiary of Holdings has entered into an engineering,
procurement and construction (EPC) contract with the partnership to construct
the Rathdrum facility. Our Parent is providing a guarantee supporting the
subsidiary's obligations under the EPC contract. We expect the Rathdrum
facility, which we will operate, to begin operation in third quarter 2001.
Electricity generated by the Rathdrum facility will be sold under a long-term
power purchase agreement to Avista Turbine Power, Inc.
29
<PAGE> 32
IMPACT OF ENERGY PRICE CHANGES, INTEREST RATES AND INFLATION
Energy prices are influenced by changes in supply and demand, as well as
general economic conditions, and therefore tend to fluctuate significantly.
Through various hedging mechanisms, we have attempted to mitigate the impact of
changes on the results of operations of most of its projects. The basic hedging
mechanism against increased fuel and transportation costs is to provide
contractually for matching increases in the energy payments our project
subsidiaries receive from the utility purchasing the electricity generated by
the facility.
Under our power sales agreements, energy payments are indexed, subject to
certain caps, to reflect the purchasing utility's solid fuel cost of producing
electricity or provide periodic, scheduled increases in energy prices that are
designed to match periodic, scheduled increases in fuel and transportation costs
that are included in the fuel supply and transportation contracts for the
facilities.
Changes in interest rates could have a significant impact on us. Interest
rate changes affect the cost of capital needed to construct projects, as well as
interest expense of existing project financing debt. As with fuel price
escalation risk, we attempt to hedge against the risk of fluctuations in
interest rates by arranging either fixed-rate financing or variable-rate
financing with interest rate swaps, collars or caps on a portion of its
indebtedness.
Although hedged to a significant extent, our financial results will likely
be affected to some degree by fluctuations in energy prices, interest rates and
inflation. The effectiveness of the hedging techniques implemented by us is
dependent, in part, on each counterparty's ability to perform in accordance with
the provisions of the relevant contracts. We have sought to reduce this risk by
entering into contracts with creditworthy organizations.
Interest Rate Sensitivity
The following tables provide information about our derivative financial
instruments and other financial instruments that are sensitive to changes in
interest rates, including interest rate swaps, interest rate caps and debt
obligations.
The table below contains information on the interest rate sensitivity of our
debt portfolio. This table presents principal cash flows and related weighted
average interest rates by expected maturity dates for all of our debt
obligations as of December 31, 1999. This table does not reflect scheduled
future interest rate adjustments. The weighted average interest rates disclosed
in the table are calculated based on interest rates as of December 31, 1999.
Future interest rates are likely to vary from those disclosed in the table.
<TABLE>
<CAPTION>
EXPECTED MATURITY DATE
-------------------------------------------------------------------------
2000 2001 2002 2003 2004 THEREAFTER TOTAL
---- ---- ---- ---- ---- ----------- -----
(in thousands)
<S> <C> <C> <C> <C> <C> <C> <C>
Long-term Debt
Fixed Rate ........ $ 6,386 $ 8,662 $ 10,227 $ 12,471 $ 14,934 $726,462 $ 778,182
Weighted average
interest rate 7.50% 7.48% 7.52% 7.42% 7.40% 7.75%
Variable Rate ...... $ 83,728 $ 77,247 $ 48,321 $ 22,317 $ 23,272 $151,315 407,160
----------
Weighted average
interest rate 7.08% 7.07% 7.20% 7.63% 7.45% 7.48% $1,185,342
==========
</TABLE>
30
<PAGE> 33
The following tables contain information regarding interest rate swap and
interest rate cap agreements entered into by some of our project subsidiaries to
manage interest rate risk on their variable-rate project financing debt. The
notional amounts of debt covered by these agreements as of December 31, 1999 was
$263,279,000. These agreements effectively changed the interest rate, including
applicable margins, on the portion of debt covered by the notional amounts from
a weighted average variable rate of 7.22% to a weighted average effective rate
of 7.09% at December 31, 1999.
FIXED RATE PAY/VARIABLE RATE RECEIVE INTEREST RATE SWAPS
<TABLE>
<CAPTION>
HEDGED
NOTIONAL EFFECTIVE MATURITY FIXED RATE VARIABLE RATE FAIR MARKET
AMOUNT DATE DATE PAY RECEIVE (1) VALUE
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
$51,000,000 2/12/98 12/31/02 5.6875% 6.15% $ 711,875
4,500,000 8/30/90 8/30/00 9.503% 6.005% (151,731)
20,000,000 7/31/00 7/31/02 6.995% --- (31,272)
58,163,000 12/20/95 7/31/06 6.078% 6.022% 1,985,472
23,748,281 11/15/98 3/07/01 5.585% 6.15% 111,333
26,304,000 1/14/98 6/30/02 5.555% 6.21% 338,715
----------
$2,964,392
==========
</TABLE>
INTEREST RATE CAPS
<TABLE>
<CAPTION>
HEDGED ACTUAL
NOTIONAL EFFECTIVE MATURITY MAXIMUM INTEREST FAIR MARKET
AMOUNT DATE DATE INTEREST RATE RATE (1) VALUE
- ---------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
$ 6,824,000 12/31/96 3/31/01 7.50% 6.2113% $ 1,312
26,304,000 2/20/97 6/28/02 6.50% 6.2113% 119,137
80,000,000 9/18/99 7/31/02 9.00% 6.022% 41
31,000,000 7/31/00 7/31/02 9.00% ---- 50,773
---------
$ 171,263
=========
</TABLE>
- ---------------------------------------
(1) The "variable rate receive" and "actual interest rate" are based on the
interest rates in effect as of December 31, 1999. Interest rates in the
future are likely to vary from those disclosed in the tables above.
CHANGE OF CORPORATE FISCAL YEAR
Effective January 1, 1998, we changed our fiscal year to commence on January
1 and conclude on December 31 of each year. Our fiscal year previously commenced
each July 1, concluding on June 30 of the following calendar year. We have
restated our consolidated financial statements for the 1997 fiscal year to a
calendar basis.
YEAR 2000 COMPLIANCE
The Year 2000 issue existed because many computer systems and applications,
including those embedded in equipment and facilities, use two digit rather than
four digit fields to designate an applicable year. As a result, those systems
and applications may not have properly recognized the year 2000 or processed
data which included such date.
We performed extensive investigation, analysis contingency planning and
remediation to prepare our systems and applications for the Year 2000 issue. We
also communicated extensively with our critical suppliers, vendors, joint
venture partners, and major customers to assess their compliance, and our
exposure, with the Year 2000 issue.
Our systems were Year 2000 compliant before December 31, 1999, and there
have been no significant transition issues in our computers related to the Year
2000 issue at any of our plants or our corporate headquarters. We have not
encountered any Year 2000 issues with any of our business partners, critical
suppliers, vendors, joint venture partners or major customers.
31
<PAGE> 34
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX
<TABLE>
<CAPTION>
Page
----
<S> <C>
Report of Independent Public Accountants 33
Consolidated Financial Statements:
Consolidated Balance Sheets at December 31, 1999 and 1998 34
Consolidated Statements of Operations For the Years Ended
December 31, 1999, 1998 and 1997 35
Consolidated Statements of Changes in Shareholders' Equity For the Years Ended
December 31, 1999, 1998 and 1997 36
Consolidated Statements of Cash Flows For the Years Ended
December 31, 1999, 1998 and 1997 37
Notes to Consolidated Financial Statements 38
Financial Statement Schedules:
Schedule I - Condensed Financial Information of the Registrant 53
</TABLE>
Schedules other than those listed above have been omitted, since they are not
required, are not applicable or are unnecessary due to the presentation of the
required information in the financial statements or notes thereto.
32
<PAGE> 35
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
TO COGENTRIX DELAWARE HOLDINGS, INC.:
We have audited the accompanying consolidated balance sheets of
Cogentrix Delaware Holdings, Inc. (a Delaware corporation) and subsidiary
companies as of December 31, 1999 and 1998, and the related consolidated
statements of operations, changes in shareholders' equity and cash flows for
each of the three years in the period ended December 31, 1999. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of Cogentrix Delaware
Holdings, Inc. and subsidiary companies as of December 31, 1999 and 1998 and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 1999, in conformity with accounting principles
generally accepted in the United States.
Our audits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The schedule listed in the index of
financial statements is presented for purposes of complying with the Securities
and Exchange Commission's rules and is not part of the basic financial
statements. This schedule has been subjected to the auditing procedures applied
in the audit of the basic financial statements and, in our opinion, fairly
states in all material respects the financial data required to be set forth
therein in relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN LLP
Charlotte, North Carolina,
March 9, 2000.
33
<PAGE> 36
COGENTRIX DELAWARE HOLDINGS, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
December 31, 1999 and 1998
(dollars in thousands)
<TABLE>
<CAPTION>
ASSETS 1999 1998
----------- -----------
<S> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents $ 44,914 $ 33,027
Restricted cash 74,098 33,253
Accounts receivable 60,930 64,637
Inventories 20,137 18,697
Other current assets 1,972 5,018
----------- -----------
Total current assets 202,051 154,632
NET INVESTMENT IN LEASES 500,195 498,614
PROPERTY, PLANT AND EQUIPMENT
net of accumulated depreciation of $259,710 and $223,481, respectively 435,681 470,853
LAND AND IMPROVEMENTS 5,757 3,974
CONSTRUCTION IN PROGRESS 347,064 --
DEFERRED FINANCING COSTS
net of accumulated amortization: $20,950 and $12,371, respectively 43,324 28,419
NATURAL GAS RESERVES 744 1,557
INVESTMENTS IN AFFILIATES 325,504 251,312
PROJECT DEVELOPMENT COSTS 1,763 --
NOTE RECEIVABLE FROM PARENT 76,410 57,348
OTHER ASSETS 52,326 50,234
----------- -----------
$ 1,990,819 $ 1,516,943
=========== ===========
LIABILITIES AND SHAREHOLDER'S EQUITY
CURRENT LIABILITIES:
Current portion of long-term debt $ 90,114 $ 86,256
Accounts payable 55,973 27,766
Payable to Parent 10,365 15,537
Income taxes payable to Parent 16,745 38,511
Other accrued liabilities 31,837 15,936
----------- -----------
Total current liabilities 205,034 184,006
LONG-TERM DEBT 1,181,269 791,397
DEFERRED INCOME TAXES 129,193 91,460
MINORITY INTEREST 69,608 61,167
OTHER LONG-TERM LIABILITIES 15,300 15,879
----------- -----------
1,600,404 1,143,909
----------- -----------
COMMITMENTS AND CONTINGENCIES
SHAREHOLDERS' EQUITY:
Common stock, no par value, 1000 shares authorized; 1 1
Additional paid-in capital-from parent 610,458 522,381
Accumulated other comprehensive loss (1,144) (15)
Accumulated deficit (218,900) (149,333)
----------- -----------
390,415 373,034
----------- -----------
$ 1,990,819 $ 1,516,943
=========== ===========
</TABLE>
The accompanying notes to consolidated financial statements are an integral
part of these consolidated balance sheets.
34
<PAGE> 37
COGENTRIX DELAWARE HOLDINGS, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS
For the Years Ended December 31, 1999, 1998 and 1997
(dollars in thousands, except earnings per common share)
<TABLE>
<CAPTION>
1999 1998 1997
--------- --------- ---------
<S> <C> <C> <C>
OPERATING REVENUE:
Electric $ 294,185 $ 293,083 $ 307,104
Steam 25,236 25,043 26,123
Lease 44,697 34,715 --
Service 43,888 34,470 --
Income from unconsolidated investment in power projects,
net of premium amortization 25,464 6,474 1,412
Other 18,964 15,908 13,264
--------- --------- ---------
452,434 409,693 347,903
--------- --------- ---------
OPERATING EXPENSES:
Fuel expense 81,835 78,420 118,731
Cost of service 47,226 37,018 --
Operations and maintenance 93,669 95,152 91,849
General, administrative and development expenses 1,502 515 2,005
Depreciation and amortization 41,583 40,988 40,429
--------- --------- ---------
265,815 252,093 253,014
--------- --------- ---------
OPERATING INCOME 186,619 157,600 94,889
OTHER INCOME (EXPENSE):
Interest expense (63,255) (61,802) (44,849)
Investment and other income 12,523 9,687 9,240
Equity in net loss of affiliates, net -- (2,967) (1,190)
--------- --------- ---------
INCOME BEFORE MINORITY INTEREST IN INCOME,
INCOME TAXES AND EXTRAORDINARY LOSS 135,887 102,518 58,090
MINORITY INTEREST IN INCOME (14,752) (12,458) (4,672)
--------- --------- ---------
INCOME BEFORE INCOME TAXES AND EXTRAORDINARY LOSS 121,135 90,060 53,418
PROVISION FOR INCOME TAXES (48,829) (35,844) (20,031)
--------- --------- ---------
INCOME BEFORE EXTRAORDINARY LOSS 72,306 54,216 33,387
EXTRAORDINARY LOSS ON EARLY EXTINGUISHMENT OF DEBT,
NET OF INCOME TAX BENEFIT AND MINORITY INTEREST -- (743) (1,502)
--------- --------- ---------
NET INCOME $ 72,306 $ 53,473 $ 31,885
========= ========= =========
EARNINGS PER COMMON SHARE:
Income before extraordinary loss $ 72,306 $ 54,216 $ 33,387
Extraordinary loss -- (743) (1,502)
--------- --------- ---------
$ 72,306 $ 53,473 $ 31,885
========= ========= =========
WEIGHT AVERAGE COMMON SHARES OUTSTANDING 1,000 1,000 1,000
========= ========= =========
</TABLE>
The accompanying notes to consolidated financial statements are an integral
part of these consolidated statements.
35
<PAGE> 38
COGENTRIX DELAWARE HOLDINGS, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
For the Years Ended December 31, 1999, 1998 and 1997
(dollars in thousands)
<TABLE>
<CAPTION>
Accumulated
Additional Other
Common Paid-in Comprehensive Accumulated Comprehensive
Stock Capital Income Deficit Income (Loss) Total
-------- -------- -------- --------- ------------- --------
<S> <C> <C> <C> <C> <C> <C>
Balance, December 31, 1996 $ 1 $178,875 $ -- $ (83,399) $ -- $ 95,477
Comprehensive income
Net income -- 31,885 31,885 --
Other comprehensive income, net of tax:
Unrealized holding losses during year 26 -- 26
-------
Comprehensive income: $31,911 31,911
=======
Capital Contribution -- 45,194 -- -- 45,194
Common stock dividends -- -- (53,688) (53,688)
-------- -------- --------- ------- --------
Balance, December 31, 1997 1 224,069 (105,202) 26 118,894
Comprehensive income
Net income 53,473 53,473
Other comprehensive income, net of tax:
Realized gains included in net income (26) (26)
Unrealized holding losses during year (15) (15)
-------
Comprehensive income: $53,432 53,432
=======
Capital contributions -- 298,312 -- -- 298,312
Dividends paid to Cogentrix Energy, Inc. (97,604) (97,604)
-------- -------- --------- ------- --------
Balance, December 31, 1998 1 522,381 (149,333) (15) 373,034
Comprehensive income
Net income 72,306 72,306
Other comprehensive income, net of tax:
Unrealized holding losses during year (1,144) (1,144)
Realized gains included in net income 15 15
-------
Comprehensive income $71,177 71,177
=======
Capital contributions -- 88,077 -- -- 88,077
Dividends paid to Cogentrix Energy, Inc. -- -- (141,873) -- (141,873)
-------- -------- --------- ------- --------
Balance, December 31, 1999 $ 1 $610,458 $(218,900) $(1,144) $390,415
======== ======== ========= ======= ========
</TABLE>
The accompanying notes to consolidated financial statements are an integral
part of these consolidated statements.
36
<PAGE> 39
COGENTRIX DELAWARE HOLDINGS, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 1999, 1998 and 1997
(dollars in thousands)
<TABLE>
<CAPTION>
1999 1998 1997
--------- --------- ---------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 72,306 $ 53,473 $ 31,885
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization 41,583 40,988 40,429
Deferred income taxes 40,962 11,083 (7,290)
Extraordinary loss on early extinguishment of debt -- 2,145 2,458
Minority interest in income net of dividends 8,461 (14,494) 1,935
Equity in net (income) loss of unconsolidated affiliates (25,464) (3,507) 126
Dividends received from unconsolidated affiliates 26,647 13,669 15,354
Minimum lease payments received 43,116 31,500 --
Amortization of unearned lease income (44,697) (33,473) --
Decrease (increase) in accounts receivable 3,968 (6,805) (552)
Decrease (increase) in inventories (627) (1,029) 4,385
Increase (decrease) in accounts payable 6,339 209 (6,771)
Increase (decrease) in accrued liabilities (26,390) 4,294 5,537
Decrease (increase) in other, net (1,884) 8,260 18,622
--------- --------- ---------
Net cash flows provided by operating activities 144,320 106,313 106,118
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property, plant and equipment additions (3,754) (5,176) (2,142)
Decrease in marketable securities -- 42,118 1,603
Investments in unconsolidated affiliates (76,827) (180,292) (61,063)
Acquisition of facilities, net of cash acquired -- (155,324) --
Construction in progress and project development costs (52,318) -- --
Capital contribution from parent 88,077 298,312 45,194
Decrease in restricted cash 12,441 27,771 1,554
--------- --------- ---------
Net cash (used in) provided by investing activities (32,381) 27,409 (14,854)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds of notes payable and long-term debt 191,340 100,400 65,171
Repayments of notes payable and long-term debt (122,255) (143,812) (118,778)
Increase (decrease) in note receivable from parent, net (19,062) (21,239) 15,818
Increase in deferred financing costs (8,202) (1,645) (1,645)
Common stock dividends paid to parent (141,873) (97,604) (53,688)
--------- --------- ---------
Net cash flows used in financing activities (100,052) (163,900) (93,122)
--------- --------- ---------
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS 11,887 (30,178) (1,858)
CASH AND CASH EQUIVALENTS, beginning of year 33,027 63,205 65,063
--------- --------- ---------
CASH AND CASH EQUIVALENTS, end of year $ 44,914 $ 33,027 $ 63,205
========= ========= =========
</TABLE>
The accompanying notes to consolidated financial statements are an integral
part of these consolidated statements.
37
<PAGE> 40
COGENTRIX DELAWARE HOLDINGS, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. NATURE OF BUSINESS
Cogentrix Delaware Holdings, Inc. ("Holdings") is a Delaware holding
company whose subsidiary companies are principally engaged in the business of
acquiring, developing, owning and operating independent power generating
facilities (individually, a "Facility", or collectively, the "Facilities").
Cogentrix Delaware Holdings, Inc. and subsidiary companies are collectively
referred to as the "Company".
Holdings is a wholly-owned subsidiary of Cogentrix Energy, Inc. (the
"Parent") and has guaranteed all of the Parent's existing and future senior
unsecured debt for borrowed money (the "Guarantee"). This guarantee was given to
the lenders under the Parent's corporate credit facility and terminates, unless
the term of the credit agreement is extended, when the credit agreement for the
corporate credit facility terminates in 2002. As of December 31, 1999, the
Parent had $355 million of senior notes outstanding due 2004 and 2008 and had no
borrowings outstanding under the corporate credit facility. The Guarantee
provides that the terms of the Guarantee may be waived, amended, supplemented or
otherwise modified at any time and from time to time by Holdings and the agent
bank for the lenders under the credit agreement. The Guarantee is not
incorporated in the indenture under which the Parent issued its outstanding
senior notes due 2004 and 2008.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
In March 1998, Holdings filed a registration statement to register the
Guarantee under the Securities Act of 1933. As a result, Holdings is required by
Section 15(d) of the Securities Exchange Act of 1934 to file with the Commission
periodic reports required to be filed pursuant to Section 13 of the Exchange Act
in respect of a security registered pursuant to Section 12 of the Exchange Act.
The duty to file such reports shall be automatically suspended as to any fiscal
year, other than the current fiscal year, if, at the beginning of such fiscal
year, the securities of each class enjoying the benefit of the Guarantee are
held of record by less than three hundred persons. There are currently fewer
than three hundred holders of record of the outstanding 2004 and 2008 Notes, and
Holdings expects that its duty to file periodic reports under the Exchange Act
will be automatically suspended as of the beginning of the fiscal year ending
December 31, 2000.
Principles of Consolidation and Basis of Presentation -- The
accompanying consolidated financial statements include the accounts of Cogentrix
Delaware Holdings, Inc. and its subsidiary companies. Wholly-owned and majority
owned subsidiaries, including a 50% owned joint venture in which the Company has
effective control through majority representation on the board of directors of
the managing general partner, are consolidated. Less-than-majority-owned
subsidiaries, and subsidiaries for which control is deemed to be temporary, are
accounted for using the equity method. Investments in unconsolidated affiliates
in which the Company has less than a 20% interest and does not exercise
significant influence over operating and financial policies are accounted for
under the cost method. All material intercompany transactions and balances among
Cogentrix Delaware Holdings, Inc., its subsidiary companies and its consolidated
joint ventures have been eliminated in the accompanying consolidated financial
statements.
Cash and Cash Equivalents -- Cash and cash equivalents include bank
deposits, commercial paper, government securities and certificates of deposit
that mature within three months of their purchase. Amounts in debt service
accounts which might otherwise be considered cash equivalents are treated as
current restricted cash.
Inventories -- Coal inventories consist of the contract purchase price
of coal and all transportation costs incurred to deliver the coal to each
Facility. Gas inventories represent the cost of natural gas purchased as fuel
reserves for a Facility that are forecasted to be consumed during the next
fiscal year. Spare parts inventories consist of major equipment and recurring
maintenance supplies required to be maintained in order to facilitate routine
maintenance activities and minimize unscheduled maintenance outages. As of
December 31, 1999 and 1998, fuel and spare parts inventories are comprised of
the following (dollars in thousands):
DECEMBER 31,
-------------------
1999 1998
------- -------
Coal $ 8,469 $ 8,028
Natural gas 2,875 2,773
Spare parts 8,138 7,377
Fuel oil 655 519
------- -------
$20,137 $18,697
======= =======
38
<PAGE> 41
Coal inventories at certain Facilities are recorded at last-in, first-out
("LIFO") cost, with the remaining Facilities' coal inventories recorded at
first-in, first-out ("FIFO") cost. The cost of coal inventories recorded on a
LIFO basis was approximately $374,000 and $305,000 less than the cost of these
inventories on a FIFO basis as of December 31, 1999 and 1998, respectively.
Spare parts inventories are recorded at average cost.
Property, Plant and Equipment -- Property, plant and equipment is
recorded at actual cost. Substantially all property, plant and equipment
consists of cogeneration facilities which are depreciated on a straight-line
basis over their estimated useful lives (ranging from 9 to 30 years). Other
property and equipment is depreciated on a straight-line basis over the
estimated economic or service lives of the respective assets (ranging from 3 to
10 years). Maintenance and repairs are charged to expense as incurred. Emergency
and rotatable spare parts inventories are included in plant and are depreciated
over the useful life of the related components.
Construction in Progress - Construction progress payments, engineering
costs, insurance costs, wages, interest and other costs relating to construction
in progress are capitalized. Construction in progress balances are transferred
to property, plant and equipment when the assets are ready for their intended
use. Interest is capitalized on projects during the development and construction
period. For the year ended December 31, 1999, the Company capitalized $262,000
of interest in connection with the development and construction of power plants.
There was no interest capitalized in 1998 or 1997.
Deferred Financing Costs -- Financing costs, consisting primarily of
legal and other direct costs incurred to obtain financing, are deferred and
amortized over the financing term.
Natural Gas Reserves -- Natural gas reserves consist of the cost of
natural gas purchased as long-term fuel reserves for a Facility. These reserves
are recorded at cost.
Investments in Affiliates -- Investments in affiliates include
investments in unconsolidated entities which own or derive revenues from power
projects currently in operation and investments in unconsolidated development
joint venture entities. The Company's share of income or loss from investments
in operating power projects is included in operating revenues in the
accompanying consolidated statements of operations. The Company's share of
income or loss from investments in development joint venture entities and
investments previously held in entities which own and operate greenhouses, is
included in other income (expense) in the accompanying consolidated statements
of operations.
Project Development Costs - The Company capitalizes project development
costs once it is determined that it is probable that such costs will be realized
through the ultimate construction of a power plant. These costs include
professional services, salaries, permits and other costs directly related to the
development of a new project. These costs are generally transferred to
construction in progress when financing is obtained, or expensed when the
Company determines that a particular project will no longer be developed.
Capitalized costs are depreciated over the estimated useful life of the project.
Revenue Recognition -- Revenues from the sale of electricity and steam
are recorded based upon output delivered and capacity provided at rates
specified under contract terms. Significant portions of the Company's revenues
have been derived from certain electric utility customers. Two customers
accounted for 47% and 17% of revenues in the year ended December 31, 1999, 50%
and 19% of revenues in the year ended December 31, 1998 and 64% and 22% of
revenues in the year ended December 31, 1997.
Interest Rate Protection Agreements -- The Company enters into interest
rate protection agreements with major financial institutions to fix or limit the
volatility of interest rates on its long-term debt. The differential paid or
received is recognized as an adjustment to interest expense. Any premiums
associated with interest rate protection agreements are capitalized and
amortized to interest expense over the effective term of the agreement.
Unamortized premiums are included in other assets in the accompanying
consolidated balance sheets.
Income Taxes -- Deferred income tax assets and liabilities are
recognized for the estimated future income tax effects of temporary differences
between the tax bases of assets and liabilities and their reported amounts in
the financial statements. Deferred tax assets are also established for the
estimated future effect of net operating loss and tax credit carryforwards when
it is more likely than not that such assets will be realized. Deferred taxes are
calculated based on provisions of the enacted tax law.
39
<PAGE> 42
Use of Estimates -- The preparation of financial statements in
conformity with generally accepted accounting principles requires management to
make estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
Comprehensive Income -- The Company adopted Statement of Financial
Accounting Standards No. 130, "Reporting Comprehensive Income," ("SFAS No.
130"), which requires companies to report all changes in equity during a period,
except those resulting from investment by owners and distribution to owners, in
a financial statement for the period in which they are recognized. The Company
has chosen to disclose Comprehensive Income, which encompasses net income and
unrealized holding losses during the year in the Consolidated Statement of
Shareholders' Equity. Prior years have been restated to conform to the SFAS No.
130 requirements.
New Accounting Pronouncements -- In April 1998, the American Institute
of Certified Public Accounts ("AICPA") issued Statement of Position ("SOP") No.
98-5, "Reporting on the Costs of Start-Up Activities" which is effective for
financial statements for fiscal years beginning after December 15, 1998. SOP No.
98-5 requires costs incurred for start-up activities to be expensed as incurred.
For purposes of this SOP, start-up activities are defined broadly as those
one-time activities related to opening a new facility, conducting business in a
new territory, conducting business with a new class of customer or beneficiary,
initiating a new process in an existing facility, or commencing a new operation.
Start-up activities include activities related to organizing a new entity
(commonly referred to as organization costs). The Company adopted SOP No. 98-5
as of January 1, 1999. The adoption of SOP No. 98-5 did not have a material
impact on the consolidated financial statements.
In June 1998, the Financial Accounting Standards Board (FASB) issued SFAS
No. 133, "Accounting for Derivative Instruments and Hedging Activities." SFAS
No. 133 establishes accounting and reporting standards requiring that every
derivative instrument (including certain derivative instruments embedded in
other contracts) be recorded in the balance sheets as either an asset or
liability measured at its fair value. SFAS No. 133 requires that changes in the
derivative's fair value be recognized in current earnings unless specified hedge
accounting criteria are met. Special accounting for qualifying hedges allows a
derivative's gains and losses to offset related results on the hedged item in
the income statement, and requires that a company formally document, designate,
and assess the effectiveness of transactions that receive hedge accounting.
In June 1999, the FASB issued SFAS No. 137, "Accounting for Derivative
Investments and Hedging Activities - Deferral of the Effective Date of FASB
Statement No. 133." SFAS No. 137 requires the adoption of SFAS No. 133 to be
effective for fiscal years beginning after June 15, 2000. Early adoption is
allowed.
The Company has not yet quantified the impacts of adopting SFAS No. 133 on
the consolidated financial statements and has not determined the timing or
method of adoption of SFAS No. 133. However, SFAS No. 133 could increase
volatility in earnings.
Change of Fiscal Year -- Effective January 1, 1998, the Company changed
its fiscal year to commence on January 1 and conclude on December 31 of each
year. The Company's fiscal year previously commenced each July 1, concluding on
June 30 of the following calendar year. The Company has restated its
consolidated financial statements for the 1997 fiscal year to a calendar year
basis.
Reclassifications - Certain amounts included in the accompanying
consolidated financial statements for the fiscal years ended December 31, 1998
and 1997 have been reclassified from their original presentation to conform with
the presentation for the year ended December 31, 1999.
3. Acquisitions
LS Power Acquisition -- In March 1998, the Company acquired from LS
Power Corporation (the "LS Power Acquisition") an approximate 74% ownership
interest in two partnerships which own and operate electric generating
facilities located in Whitewater, Wisconsin (the "Whitewater Facility") and
Cottage Grove, Minnesota (the "Cottage Grove Facility"). Each of the Cottage
Grove and Whitewater Facilities is a 245-megawatt gas-fired, combined-cycle
cogeneration facility. Commercial operations of both of these facilities
commenced in the last half of calendar 1997. The Cottage Grove Facility sells
capacity and energy to Northern States Power Company under a 30-year power sales
contract terminating in 2027. The Whitewater Facility sells capacity and energy
to Wisconsin Electric Power Company under a 25-year power sales contract
terminating in 2022. Each of the power sales contracts has characteristics
similar to a lease in that the agreement gives the purchasing utility the right
to use specific property, plant and equipment. As such, each of the power sales
contracts is accounted for as a "sales-type" capital lease in accordance with
Statement of Financial Accounting Standards ("SFAS") No. 13, "Accounting for
Leases." (see Note 7).
40
<PAGE> 43
The aggregate acquisition price for the equity interests in the Cottage
Grove and Whitewater Facilities acquired by the Company was approximately $158.0
million. In addition, the Company pre-funded a $16.7 million distribution to the
previous owners, which represented unused construction contingency funds and
cash flows that were accumulated by the Cottage Grove and Whitewater Facilities
prior to January 1, 1998. Cogentrix Energy, Inc. received $15.7 million of this
distribution in April 1998 and received the remaining $1 million in 1999. The
purchase price was ultimately funded with a portion of the net proceeds of the
Parent's 2008 senior notes and corporate cash balances.
The Company accounted for the LS Power Acquisition using the purchase
method of accounting. The purchase price has been allocated to the assets and
liabilities acquired based on their fair market values at the date of
consummation. An adjustment in the amount of $22.2 million was recorded to
reflect the Company's portion of the excess of the fair value of the
Partnerships' fixed rate debt over its historical carrying value. This fair
value adjustment, or debt premium, will be amortized to income over the life of
the debt acquired using the effective interest method. The historical book
values of the remaining assets and liabilities approximated their fair values at
the date of consummation. The excess of the purchase price over the fair value
of the net assets acquired was approximately $27.7 million. This excess is
included in other assets on the accompanying balance sheets as of December 31,
1999 and 1998, and is being amortized on a straight line basis over the lives of
the power purchase agreements for the two facilities. The minority owner's share
of each partnership's net assets is included in minority interests on the
accompanying consolidated balance sheets as of December 31, 1999 and 1998. The
accompanying consolidated statement of operations for the year ended December
31, 1998 includes the results of operations of the acquired facilities for the
period beginning March 20, 1998 (closing date of the LS Power Acquisition) to
December 31, 1999.
During 1999, the Company and the contractor, with the concurrence of the
independent engineer, reached a final agreement regarding the settlement of all
outstanding issues and obligations of the Cottage Grove and Whitewater
facilities and the contractor pursuant to the construction contracts. The final
settlement of the construction contract provided for a payment to the contractor
of approximately $4,030,000 from funds available in Cottage Grove's and
Whitewater's construction retainage accounts. The contractor has also agreed to
extend various warranty periods and perform various repairs and inspections.
Cottage Grove and Whitewater, in turn, acknowledged that final acceptance shall
have been deemed to have occurred. Upon the release of the remaining
construction retainage accounts and settlement of outstanding warranty claims,
the Company recorded a gain of approximately $6,257,000 before minority
interests in income. The gain is included in Other income in the accompanying
consolidated statements of operations for the year ended December 31, 1999.
Batesville Acquisition -- In August 1998, the Company acquired an
approximate 52% interest in an 800-megawatt, gas-fired electric generating
facility (the "Batesville Facility") under construction in Batesville,
Mississippi (the "Batesville Acquisition"). The Company has committed to provide
an equity contribution to the project subsidiary of approximately $54 million
upon the earliest to occur of (i) the incurrence of construction costs after all
project financing has been expended, (ii) an event of default under the project
subsidiary's financing arrangements or (iii) June 30, 2001. This equity
commitment is supported by a $54 million letter of credit provided under the
Company's corporate credit facility. The Company expects the Batesville
Facility, which will be operated by the Company, to commence commercial
operation in summer 2000. Electricity generated by the Batesville Facility will
be sold under long-term power purchase agreements with two investment-grade
utilities.
The Batesville acquisition was originally accounted for under the equity
method of accounting, as the Company originally deemed its approximate 52%
interest to be temporary. As of December 31, 1999, the Company has reassessed
its ownership, and has determined that it will maintain an approximate 51%
interest in the project. As such, the Company has consolidated the net assets of
the Batesville Facility in the accompanying consolidated balance sheet at
December 31, 1999. The accompanying consolidated statements of operations at
December 31, 1999 and 1998 recognized earnings from the Batesville facility
under the equity method of accounting.
Bechtel Asset Acquisition -- In October 1998, the Company acquired from
Bechtel Generating Company, Inc. ("BGCI") ownership interests in 12 electric
generating facilities, comprising a net equity interest of approximately 365
megawatts, and one interstate natural gas pipeline in the United States (the
"BGCI Acquisition"). The aggregate acquisition price, including acquisition
costs, for the interests in the BGCI assets was approximately $189.7 million.
The Company utilized a portion of the net proceeds from the issuance of $255
million of senior notes due 2008 to fund the BGCI Acquisition.
41
<PAGE> 44
The BGCI Acquisition has been accounted for using the purchase method of
accounting, which resulted in the recognition of a net purchase premium of
approximately $66.5 million. The purchase premiums or discounts related to the
BGCI Acquisition are being amortized over the remaining lives of the facilities
or over the remaining terms of the power purchase agreements. The Company uses
the equity method of accounting to account for its ownership interests in eight
of these facilities and uses the cost method of accounting for its ownership
interests in the other four facilities (see Note 4).
Subsequent to December 31, 1999, the Company purchased an additional 1%
interest in the Logan and Northampton facilities, two of the twelve electric
generating facilities included in the BGCI Acquisition. The Company paid
approximately $1,650,000 for these additional interests. The Company will
continue to account for its 50% interest in the Logan and Northampton facilities
using the equity method.
Indiantown Acquisition - In June 1999, the Company entered into an
agreement to purchase an additional 40% ownership interest in the Indiantown
cogeneration facility (the "Indiantown Acquisition"), one of the twelve electric
generating facilities included in the BGCI Acquisition, in a three-phase
transaction. The Company paid $39.8 million to acquire a 19.9% interest in the
facility in June, 1999, $36.6 million to acquire a 20% interest in the facility
in September, 1999 and $0.2 million to acquire a 0.1% interest in the facility
in November, 1999. The Company funded the purchase of these interests with
proceeds from credit facilities. These purchases resulted in a premium of
approximately $38,000,000. This premium will be amortized over the remaining
term of the power purchase agreement. The Company currently has a 50% interest
in the Indiantown facility. This investment is accounted for using the equity
method of accounting.
The following unaudited pro forma consolidated results for the Company for
the year ended December 31, 1999 and 1998 give effect to the LS Power
Acquisition, the BGCI Acquisition and the Indiantown Acquisition as if these
transactions had occurred on January 1, 1999 and January 1, 1998, respectively
(dollars in thousands, except per share amount).
PRO FORMA
YEAR ENDED DECEMBER 31,
---------------------------
1999 1998
---- ----
Revenues $457,762 $454,566
Net Income $ 73,130 $ 54,222
Earnings per Share $ 73,130 $ 54,222
4. INVESTMENTS IN UNCONSOLIDATED POWER PROJECTS
Birchwood Power Partners, L.P.
The Company owns a 50% interest in Birchwood Power Partners, L.P.
("Birchwood Power"), a partnership which owns a 200-megawatt, coal-fired
cogeneration facility (the "Birchwood Facility") which sells electricity to a
utility and provides thermal energy to a 36-acre greenhouse under long-term
contracts. The Birchwood Facility is operated by an affiliate of The Southern
Company under a long-term operations and maintenance agreement. The Company has
50% representation on Birchwood Power's management committee, which must approve
all material transactions of Birchwood Power. The Company is accounting for its
investment in Birchwood Power under the equity method. The Company's share of
net income of Birchwood Power is recorded net of the amortization of the $36.4
million premium paid to purchase the Company's 50% share interest in Birchwood
Power. This premium is being amortized on a straight-line basis over the
estimated useful life of the Birchwood Facility. The Company recognized
approximately $3,508,000, $3,714,000 and $1,412,000 in income from
unconsolidated investments in power projects, net of premium amortization, in
the accompanying consolidated statements of operations for the years ended
December 31, 1999, 1998 and 1997, respectively, related to its investment in
Birchwood Power. The following table presents summarized financial information
for Birchwood Power as of December 31, 1999 and 1998 and for the years ended
December 31, 1999, 1998 and 1997 (dollars in thousands):
42
<PAGE> 45
1999 1998
-------- --------
BALANCE SHEET DATA:
Current assets $ 48,805 $ 48,416
Noncurrent assets 333,318 344,374
-------- --------
Total assets $382,123 $392,790
======== ========
Current liabilities $ 9,882 $ 7,952
Noncurrent liabilities 323,598 329,428
Partners' capital 48,643 55,410
-------- --------
$382,123 $392,790
======== ========
1999 1998 1997
------- ------- -------
INCOME STATEMENT DATA:
Operating revenues $75,582 $71,908 $69,275
Operating income 36,399 36,863 35,087
Net income 9,740 9,747 6,451
BGCI Assets
The Company acquired interests in 12 electric generating facilities
from BGCI on October 20, 1998 (the "BGCI assets") (see Note 3). The following
table presents the Company's ownership interests at December 31, 1999, in the
BGCI assets that are accounted for under the equity method:
Percent Net
Ownership Equity Interest
Plant Interest In Plant
Project Megawatts Acquired Megawatts
------- --------- --------- ---------------
Logan 218 49.0% 106.8
Northampton 110 49.0 53.9
Indiantown 380 50.0 190.0
Carney's Point 262 10.0 26.2
Panther Creek 83 12.2 10.1
Scrubgrass 85 20.0 17.0
Gilberton 82 19.6 16.1
Morgantown 62 15.0 9.3
The Company recognized approximately $21,954,000 and $2,760,000 in income
from unconsolidated investments in power projects in the accompanying
consolidated statement of operations for the year ended December 31, 1999 and
for the period from October 20, 1998 to December 31, 1998 related to its
investment in the projects acquired from BGCI. The following table presents
summarized combined financial data for the unconsolidated power projects
acquired from BGCI being accounted for under the equity method as of December
31, 1999 and 1998 and for the year ended December 31, 1999 and for the period
from October 20, 1998 to December 31, 1998 (dollars in thousands):
43
<PAGE> 46
DECEMBER 31,
-------------------------
1999 1998
---------- ----------
BALANCE SHEET DATA:
Current assets $ 157,396 $ 131,178
Noncurrent assets 2,988,277 2,827,875
---------- ----------
Total assets $3,145,673 $2,959,053
========== ==========
Current liabilities $ 205,667 $ 137,205
Noncurrent liabilities 2,523,826 2,398,944
Equity 416,180 422,904
---------- ----------
$3,145,673 $2,959,053
========== ==========
FOR THE PERIOD
FOR THE YEAR ENDED OCTOBER 20,1998 TO
INCOME STATEMENT DATA: DECEMBER 31, 1999 DECEMBER 31, 1998
------------------ ------------------
Operating revenues $624,010 $96,622
Operating income 365,429 51,948
Net income 56,818 15,071
5. INVESTMENT IN OTHER UNCONSOLIDATED AFFILIATES
The Company makes investments in other joint venture partnerships whose
purpose is to develop power projects. The Company utilizes the equity method of
accounting for those partnerships in which it holds an ownership interest
between 20% and 50%. The Company recognized approximately $208,000, $307,000,
and $471,000 in equity losses for the years ended December 31, 1999, 1998 and
1997, respectively, related to its investments in these partnerships. These
losses are reflected in equity in loss of affiliates in the accompanying
consolidated statements of operations.
The Company entered into an agreement with Agro Power Development, Inc. a
developer and operator of greenhouse facilities, ("Agro") to make investments in
partnerships which develop, construct and operate greenhouses which produce
tomatoes. The Company obtained a 50% interest in four limited partnerships which
had a combined 107 acres of production capacity in operation. In December 1998,
the Company entered into an agreement to sell its 50% interest in the
partnerships to EcoScience Corporation ("EcoScience"), the parent of Agro. In
return for its 50% interest, the Company received 1,000,000 shares of common
stock of EcoScience and a note receivable from EcoScience (the "EcoScience
Note") in the amount of approximately $20.6 million. The original note
receivable from EcoScience accrued interest at 11.25% per annum with principal
and interest due on March 15, 1999, (see below), and was secured by a pledge of
all the outstanding stock of Agro. The Company recognized a gain of $2.1 million
related to the fair market value of common stock received. This gain is included
in investment and other income in the accompanying consolidated statements of
operations for the year ended December 31, 1998. As of December 31, 1999, the
Company has recorded an unrealized holding loss on the EcoScience common stock
which has been included in the accompanying consolidated financial statements.
On March 15, 1999, the Company agreed to extend the due date for principal
and interest on the EcoScience Note to June 30, 1999. In exchange for this
extension, the Company received an extension fee of $1 million in the form of a
promissory note from EcoScience, which bears the same terms as the original
note. As of December 31, 1999 and 1998, the Company had a recorded investment in
the EcoScience Note of $21,600,000 and $20,600,000, respectively. The Company
has an allowance for credit losses related to the entire balance of its recorded
investment in the EcoScience Note of approximately $14,400,000 and $11,800,000
at December 31, 1999 and 1998, respectively. Currently, the Company is recording
interest income only as cash is received. The Company recognized and received no
interest on this note for the year ended December 31, 1999. The Company would
have recognized gross interest income of approximately $2,400,000 for the year
ended December 31, 1999 if EcoScience would have been current in their interest
payments.
Subsequent to December 31, 1999, the Company entered into an agreement to
exchange the EcoScience Note and all outstanding interest due for a promissory
note in the amount of $15,900,000. The promissory note bears interest at 5% per
year, and is due in five annual installments of $3,180,000, beginning on
December 1, 2003 until December 1, 2007. In consideration for this exchange,
EcoScience authorized and issued 333,333 shares of Series A Preferred Stock of
EcoScience to the Company.
44
<PAGE> 47
Prior to the sale of the greenhouse partnerships, the Company accounted for
its investment in these partnerships under the equity method, an recognized
approximately $2,967,000, and $1,066,000 in equity losses in the accompanying
consolidated statements of operations for the years ended December 31, 1998 and
1997, respectively.
6. LONG-TERM DEBT
The following long-term debt was outstanding as of December 31, 1999 and
1998, respectively (dollars in thousands):
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------------
1999 1998
----------------- -------------
<S> <C> <C>
LONG-TERM DEBT:
HOPEWELL FACILITY:
Note payable to banks $51,000 $ 67,000
PORTSMOUTH FACILITY:
Note payable to banks 41,649 43,129
ROCKY MOUNT FACILITY:
Note payable to financial institution 120,182 123,422
RINGGOLD FACILITY:
Note payable to banks 10,995 13,440
RICHMOND FACILITY:
Commercial paper notes payable, net of unamortized issue
discount of $745 and $350, respectively, and tax-exempt bonds 171,848 185,814
ELIZABETHTOWN, LUMBERTON AND KENANSVILLE FACILITIES:
Notes payable to banks 6,824 16,964
ROXBORO AND SOUTHPORT FACILITIES:
Note payable to banks 52,608 73,400
COTTAGE GROVE AND WHITEWATER FACILITIES:
Bonds payable, due 2010 and 2016, including unamortized fair market
value adjustment related to purchase of facilities of
$20,386 and $21,345 352,386 353,345
BATESVILLE FACILITY:
Bonds payable, due 2014 and 2025 326,000 -
OKLAHOMA FACILITY:
Construction note payable to banks 70,531 -
CEA CREDIT FACILITY 66,400 -
OTHER 960 1,139
Total Long-Term Debt 1,271,383 877,653
Less: Current portion (90,114) (86,256)
---------- --------
Long-term portion $1,181,269 $791,397
========== ========
</TABLE>
Information related to each of these borrowings is as follows:
HOPEWELL FACILITY:
The Hopewell Facility's project debt agreement was amended in February 1998
resulting in an extension of the final maturity of the note payable by six
months to December 31, 2002. The amended terms of the loan agreement increased
outstanding borrowings by $34.6 million, the proceeds of which (net of
transaction costs) were paid as a distribution to the partners in that project.
The amended note payable accrues interest at an annual rate equal to the
applicable LIBOR rate, as chosen by the Company, plus an additional margin of
1.00% (7.15% at December 31, 1999). The amended note payable also provides for a
$5 million letter of credit to secure the project's obligation to pay debt
service. Cogentrix Energy, Inc. has indemnified the lenders of the note payable
for any cash deficits the Hopewell Facility could experience as a result of
incurring certain costs, subject to a cap of $10.6 million.
45
<PAGE> 48
An extraordinary loss of $2.4 million was recorded in the first quarter of
1998 related to the write-off of unamortized deferred financing costs from the
original project debt and a swap termination fee on an interest rate swap
agreement hedging the original project debt. The Company's share of this
extraordinary loss of approximately $700,000, net of a tax benefit of
approximately $500,000 and minority interest of $1.2 million, is shown in the
accompanying consolidated statements of operations.
PORTSMOUTH FACILITY:
The Portsmouth Facility's project debt agreement was amended in December
1997, resulting in the extension of the final maturity of the loan by three
months to December 31, 2002. The amended terms of the loan agreement also
increased the outstanding credit commitment from the project lenders to $43.5
million in the form of a revolving credit facility. As of December 31, 1999, the
balance outstanding under the credit facility is approximately $41,600,000, of
which $20,400,000 was outstanding under the revolving credit facility. The
amended terms of the loan agreement provide for interest to accrue at an annual
rate equal to the applicable LIBOR rate, as chosen by the Company, plus an
additional margin of 1.0% (7.15% at December 31, 1999). The banks' outstanding
credit commitment under the loan agreement is reduced quarterly, with interest
payable the earlier of the maturity of the applicable LIBOR term or quarterly
through December 2002. The loan agreement also provides for a $6 million letter
of credit to secure the project's obligations to pay debt service. Cogentrix
Energy, Inc. has indemnified the lenders of the senior credit facility for any
cash deficits the Portsmouth Facility could experience as a result of incurring
certain costs, subject to a cap of $30 million.
An extraordinary loss of $2,458,000 was recorded in the year ended December
31, 1997 related to the write-off of unamortized deferred financing costs from
the original senior loan of $1,395,000 and net swap termination fees of
$1,063,000 related to interest rate swap agreements hedging the original project
debt. This extraordinary loss is shown net of a tax benefit of $956,000 in the
accompanying consolidated statement of operations.
ROCKY MOUNT FACILITY:
The note payable to financial institution consists of a $120,182,000 senior
loan which accrues interest at a fixed annual rate of 7.58%. Payment of
principal and interest is due quarterly through December 2013.
RINGGOLD FACILITY:
The note payable to banks consists of a senior loan which accrues interest
at an annual rate equal to the applicable LIBOR rate, as chosen by the Company,
plus 1.35% per annum (7.36% at December 31, 1999). Interest is payable at the
earlier of the maturity of the applicable LIBOR term or quarterly in arrears.
Payments of principal under the senior loan are due semiannually through April
2004.
In January 1998, the Company signed an agreement with Pennsylvania Electric
Company ("Penelec") to terminate its power purchase agreement. This termination
agreement was the result of a request for proposals from the utility to buy-back
or restructure power sales agreements issued to all major operating independent
power producers in Penelec's territory in April 1997. The termination agreement
with Penelec provides for a payment to the project subsidiary of approximately
$20.4 million, which will be sufficient to retire all of the project
subsidiary's outstanding debt. The buy-back of the power purchase agreement is
subject to the issuance of a satisfactory final order by the Pennsylvania Public
Utility Commission, which is not subject to appeal, granting Penelec the
authority to fully recover from its customers the consideration paid under the
buyout agreement. Management does not expect the termination of this project
subsidiary's power purchase agreement, if it occurs, this event to have an
adverse impact on the Company's consolidated results of operations or financial
position.
RICHMOND FACILITY:
Commercial paper notes outstanding are supported by an irrevocable,
direct-pay letter of credit provided by a syndicate of banks (the "Banks"). The
maximum amount of commercial paper notes supported by the letter of credit is
$124,600,000 as of December 31, 1999. The annual interest rate incurred is the
yield on the commercial paper notes plus a 1.25% to 1.50% per annum fee
(weighted average rate of 7.27% at December 31, 1999) paid to the Banks for
providing the letter of credit.
Tax-exempt industrial development bonds (the "Bonds") have been issued
to support the purchase of certain pollution control and solid waste disposal
equipment for the Facility ($48 million outstanding at December 31, 1999 and
1998). Principal and interest payments on the Bonds are supported by an
irrevocable, direct-pay letter of credit provided by the Banks. The annual
interest rate is the yield on the Bonds plus a 1.25% to 1.50% per annum fee
(5.6% at December 31, 1999). The letters of credit described above are part of
one credit facility (the "Credit Facility"). The Credit Facility provides for
commitment reductions through September 2007.
46
<PAGE> 49
ELIZABETHTOWN, LUMBERTON AND KENANSVILLE FACILITIES:
The project debt on the Elizabethtown, Lumberton and Kenansville Facilities
consists of a senior note payable that accrues interest at an annual rate equal
to the applicable LIBOR rate, as chosen by the Company, plus 1% (7.21% at
December 31, 1999). Principal is payable quarterly with interest payable at the
earlier of the maturity of the applicable LIBOR term or quarterly through
September 2000. The senior credit facility also provides for a $3.3 million
letter of credit to secure the project's obligations to pay debt service.
ROXBORO AND SOUTHPORT FACILITIES:
The project debt agreement for the Roxboro and Southport Facilities
consists of a senior note payable that accrues interest at an annual rate equal
to the applicable LIBOR rate, as chosen by the Company, plus 1% through
September 2001 and 1.125% thereafter (7.21% at December 31, 1999). Principal is
payable quarterly with interest payable at the earlier of the maturity of the
applicable LIBOR term or quarterly through June 2002. The senior credit facility
also provides for a $6.5 million letter of credit to secure the project's
obligations to pay debt service.
COTTAGE GROVE AND WHITEWATER FACILITIES:
The project debt of the Cottage Grove and Whitewater Facilities consist of
the following senior secured bonds (dollars in thousands):
7.19% Senior Secured Bonds due June 30, 2010 $105,551
8.08% Senior Secured Bonds due December 30, 2016 226,449
--------
$332,000
========
Interest and principal is payable on these bonds semi-annually on June 30
and December 30 of each year. Principal payments commence on June 30, 2000 for
the 2010 Bonds and December 30, 2010 for the 2016 Bonds.
In December 1998, Cogentrix Mid-America, Inc., a wholly-owned subsidiary,
which holds the Company's interest in the Cottage Grove and Whitewater
Facilities entered into a credit agreement with a bank to provide for a $25
million revolving credit facility available in a form of the issuance of letters
of credit to support the debt reserve requirements for the 2010 and 2016 Bonds
which vary from $12.9 million to $28.1 million over the term of the Bonds. The
credit agreement also provides for direct advances up to the amount of any
excess of the $25 million commitment over the then debt service reserve
requirement. As of December 31, 1999, letters of credit totalling $14.1 million
were issued and outstanding under the credit agreement.
JENKS FACILITY:
The construction loan agreement for the Jenks facility consists of a
construction note payable up to $350 million to construct an 800-megawatt,
combined cycle, natural gas-fired generating facility. The construction loan
will convert to a term loan, due December 2006, upon commencement of commercial
operations. The loan agreement provides for interest to accrue at an annual rate
equal to the applicable LIBOR rate, as chosen by the Company, plus 1.25% to
2.25% per annum. The loan facility also provides for an $8 million letter of
credit to secure the project's obligation to pay debt service.
In accordance with the terms of the project financing agreements, the
Company is committed to provide an equity contribution to the project subsidiary
of approximately $56.9 million upon the earliest to occur of (a) an event of
default under the project subsidiary's financing agreement, (b) the incurrence
of construction costs after all project financing has been expended or (c) June
24, 2002. The equity contribution commitment will be reduced by approximately
$8.2 million upon the project subsidiary's receipt of a waste water discharge
permit. This equity contribution commitment is supported by a letter of credit,
which is provided under the corporate credit facility.
BATESVILLE FACILITY:
The project debt of the Batesville Facility consists of the following
senior secured bonds (dollars in thousands):
7.16% Senior Secured Bonds due January 15, 2014 $150,000
8.16% Senior Secured Bonds due June 15, 2025 176,000
--------
$326,000
========
Interest and principal is due on these bonds semi-annually on January 15
and July 15 each year. Principal payments commence on July 15, 2001 for the 2014
Bonds, and July 15, 2014 for the 2025 Bonds.
INTEREST RATE PROTECTION AGREEMENTS:
The Company has entered into interest rate cap and interest rate swap
agreements (Note 12) to manage its interest rate risk on its variable-rate
project financing debt. The notional amounts of debt covered by these agreements
as of December 31, 1999 and 1998 were approximately $263,279,000 and
$343,112,000, respectively. The agreements effectively change the interest rate
on the portion of debt covered by the notional amounts from a weighted average
variable rate of 7.2% at December 31, 1999 to a weighted average effective rate
of 7.1% at December 31, 1999. These agreements expire at various dates through
July 2006.
47
<PAGE> 50
CEA Credit Facility
In September 1999, one of the Company's wholly-owned subsidiaries,
Cogentrix Eastern America, Inc., formed to hold the Company's ownership
interest in twelve electric generating facilities acquired in the BGCI
Acquisition, entered into a $75 million, three-year credit facility. The
commitment under this facility reduces to $67.5 million after one year and to
$60 million after two years. As of December 31, 1999, advances totaling $66.4
million were outstanding under this facility.
The project financing debt is substantially non-recourse to Holdings. The
project financing agreements of the subsidiaries 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 subsidiaries to pay dividends and management fees
periodically to Holdings is subject to certain limitations in their respective
financing documents. Such limitations generally require that: (i) debt service
payments be current, (ii) debt service coverage ratios be met, (iii) all debt
service and other reserve accounts be funded at required levels, and (iv) there
be no default or event of default under the relevant credit documents.
Dividends, when permitted, are declared and paid immediately to Holdings at the
end of such period.
Future maturities of long-term debt at December 31, 1999, net of
unamortized issue discounts on commercial paper notes, are as follows (dollars
in thousands):
YEAR ENDED
DECEMBER 31,
------------
2000 $ 90,114
2001 85,911
2002 124,949
2003 34,789
2004 38,206
Thereafter 877,773
----------
$1,251,742
==========
Cash paid for interest on the Company's long-term debt amounted to
$61,032,000, $66,899,000, and $44,708,000 for the years ended December 31, 1999,
1998 and 1997, respectively.
7. SALES TYPE CAPITAL LEASE
The power purchase agreements acquired by the Company as a result of the LS
Power Acquisition have characteristics similar to leases in that the agreements
confer to the purchasing utility the right to use specific property, plant and
equipment. At the commercial operations date, the partnerships accounted for the
power purchase agreements as "sales-type" capital leases in accordance with
Statement of Financial Accounting Standards (SFAS) No. 13, "Accounting for
Leases".
The components of the net investment in the leases at December 31, 1999 and
1998 are as follows (dollars in thousands):
1999 1998
----------- -----------
Gross Investment in Leases $ 1,097,787 $ 1,140,909
Unearned Income on Leases (597,592) (642,295)
----------- -----------
Net Investment in Leases $ 500,195 $ 498,614
=========== ===========
Gross investment in leases represents total capacity payments receivable
over the terms of the power purchase agreements, net of executory costs, which
are considered minimum lease payments in accordance with SFAS No. 13.
Estimated minimum lease payments over the remaining term of the power
purchase agreements as of December 31, 1999 are as follows (dollars in
thousands):
2000 $ 45,180
2001 45,187
2002 47,253
2003 49,052
2004 50,957
Thereafter 860,158
----------
Total $1,097,787
==========
48
<PAGE> 51
8. INCOME TAXES
The Company files a consolidated federal tax return with the Parent, but
records its income tax provisions on a separate-entity basis for financial
reporting purposes. Deferred income tax assets and liabilities are recognized
for the estimated future income tax effect 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.
Reconciliations between the federal statutory income tax rate and the
Company's effective income tax rate are as follows:
YEARS ENDED DECEMBER 31,
--------------------------
1999 1998 1997
---- ---- ----
Federal statutory tax rate 35% 35% 35%
State income taxes, net of loss
carryforwards and federal tax impact 4.7 3.4 3.4
Other (0.9) (2.5) (0.0)
---- ---- ----
Effective tax rate 38.8% 40.9% 37.5%
==== ==== ====
The net current and noncurrent components of deferred income taxes
reflected in the accompanying consolidated balance sheets as of December 31,
1999 and 1998 are as follows (dollars in thousands):
<TABLE>
<CAPTION>
DECEMBER 31,
------------------------
1999 1998
--------- ---------
<S> <C> <C>
Net current deferred tax liability (asset) $ 788 $ (1,757)
Net noncurrent deferred tax liability 129,693 91,460
--------- ---------
Net deferred tax liability $ 130,481 $ 89,703
========= =========
</TABLE>
9. COMMITMENTS AND CONTINGENCIES
Parent Debt Guaranteed by the Cogentrix Delaware Holdings, Inc. - Cogentrix
Delaware Holdings, Inc. has guaranteed all of the Parent's existing and future
senior unsecured debt for borrowed money. This guarantee was given to the
lenders under the Parent's corporate credit facility and terminates, unless the
term of the credit agreement is extended, when the credit agreement for the
corporate credit facility terminates in 2002 (Note 1). The agreement under which
the guarantee was given provides that the terms or provisions of the guarantee
may be waived, amended, supplemented or otherwise modified at any time and from
time to time by Cogentrix Delaware Holdings, Inc. and the agent bank for the
lenders under the credit agreement.
SENIOR NOTES
On March 15, 1994, the Parent 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%. The Senior Notes require annual sinking
fund payments beginning in March 2001.
On October 20, 1998, the Parent issues $220 million of registered,
unsecured 8.75% senior notes due 2008 (the "2008 Notes"). These notes were
issued at a discount resulting in an effective rate of approximately 8.824%. On
November 25, 1998, the Company issued an additional $35 million of the 2008
Notes at a premium resulting in an effective rate of approximately 7.95%.
49
<PAGE> 52
CORPORATE CREDIT FACILITY
In May 1997, the Parent entered into a credit agreement with Australia and New
Zealand Banking Group Limited, as agent for a group of lending banks. In October
1998, the Parent amended and restated the corporate credit facility to provide
for $125 million of revolving credit available through October 2002 in the form
of direct advances or the issuance of letters of credit (the "Corporate Credit
Facility"). As of December 31, 1999, the Parent has used this credit facility to
issue approximately $117 million of letters of credit in connection with
investments made in electric-generating plants, and two plants under
construction. Subsequent to December 31, 1999, the Corporate Credit Facility was
amended to provide for $175 million of revolving credit and to modify the
covenants. The revolving credit facility has been extended through October 2002.
Long-Term Contracts -- The Company has several long-term contractual
commitments that comprise a significant portion of its financial obligations.
These contractual commitments with original terms varying in length from 10 to
30 years are the basis for a major portion of the revenue and operating expenses
recognized by the Company and provide for specific services to be provided at
fixed or indexed prices. The major long-term contractual commitments are as
follows:
(i) The Company is required to sell electricity generated by each
Facility to a Utility and the Utility is required to purchase this
electricity or make capacity payments at pre-established or annually
escalating prices.
(ii) The Company is required to sell and the Steam Purchaser is
required to purchase a minimum amount of process steam from each
Facility for each contract year. The Steam Purchaser is generally
required to purchase its entire steam requirements from the Company.
The purchase price of steam under these contracts escalates annually or
is fixed and determinable during the term of the contracts.
(iii) The Company is obligated to purchase and fuel suppliers are
required to supply all of the fuel requirements of each Facility. Fuel
requirements include the quality and estimated quantity of fuel
required to operate each Facility. The price of fuel escalates annually
for the term of each contract. In addition, the Company has
transportation contracts with various entities to deliver the fuel to
each Facility. These contracts also provide for annual escalations
throughout the term of the contracts.
Effective September 1996, the Company amended the power sales agreements on
its Lumberton, Elizabethtown, Kenansville, Roxboro and Southport Facilities.
These amendments provide the purchasing utility additional rights related to the
dispatch of the Facilities and eliminated the purchase options which the utility
held related to the Roxboro and Southport Facilities.
The Company has also amended the power sales agreement on its Portsmouth
Facility and Hopewell Facility, effective December 1997 and February 1998,
respectively. These amendments provide the purchasing utility additional rights
related to the dispatch of these Facilities. The terms of Portsmouth's amended
power sales agreement also eliminated Portsmouth's accrued obligation to return
previously disallowed capacity payments to the purchasing utility.
Under the terms of certain contracts with electricity purchasers, the
Company is obligated to pay up to $37,350,000 in aggregate liquidated damages to
the respective electricity purchasers if the respective facility does not
demonstrate certain operating and reliability standards. Banks have issued
letters of credit, non-recourse to us and our Parent, in favor of electricity
purchasers which secure the Company's obligations to the electricity purchasers
under this provision of the contracts.
Under certain power sales agreements, the Utility is permitted to reduce
future payments or recover certain payments previously made upon the occurrence
of certain events, which include a state utility commission prohibiting the
Utility from recovering such payments made under such power sales agreement.
However, in most cases, the Utility is prohibited from reducing or recovering
such payments prior to the maturity date of the original project financing debt.
50
<PAGE> 53
Guarantees -- In connection with its substantially non-recourse project
financings and certain other subsidiary contracts, the Parent and its
subsidiary, Cogentrix, Inc. have expressly undertaken certain limited
obligations and commitments, most of which will only be effective or will be
terminated upon the occurrence of future events. These obligations and
commitments include guarantees by Cogentrix, Inc. of a certain subsidiary's
obligation capped at $1.5 million and certain subsidiaries' performance under
their contracts with one Utility.
Claims and Litigation - One of the Company's indirect, wholly-owned
subsidiaries is party to certain product liability claims related to the sale of
coal combustion by-products for use in various construction projects. Management
cannot currently estimate the range of possible loss, if any, the Company will
ultimately bear as a result of these claims. However, the Company's management
believes - based on its knowledge of the facts and legal theories applicable to
these claims and after consultations with various counsel retained to represent
the subsidiary in the defense of such claims - that the ultimate resolution of
these claims should not have a material adverse effect on the Company's
consolidated financial position or results of operations.
In addition to the litigation described above, the Company experiences other
routine litigation in the normal course of business. The Company's management is
of the opinion that none of this routine litigation will have a material adverse
impact on its consolidated financial position or results of operations.
10. FUNDS HELD BY TRUSTEES
The majority of revenue received by the Company is required by the terms of
various credit agreements to be deposited in accounts administered by certain
banks (the "Trustees"). The Trustees invest funds held in these accounts at the
direction of the Company. These accounts are established for the purpose of
depositing all receipts and monitoring all disbursements of each Facility. In
addition, special accounts are established to provide debt service payments and
income taxes. The funds in these accounts are pledged as security under the
project financing agreements of each subsidiary.
Funds held by the Trustees were approximately $110,945,000 and $47,188,000
at December 31, 1999 and 1998, respectively. Debt service account balances are
reflected as restricted cash, whereas all other accounts are classified as cash
and cash equivalents in the accompanying consolidated balance sheets.
11. FAIR VALUE OF FINANCIAL INSTRUMENTS AND CONCENTRATION OF CREDIT RISKS
The Company invests its temporary cash balances in U.S. government
obligations, corporate obligations and financial instruments of highly-rated
financial institutions. A substantial portion of the Company's accounts
receivable are from two major regulated electric utilities and the associated
credit risks are limited.
The carrying values reflected in the accompanying consolidated balance
sheets at December 31, 1999 and 1998, approximate the fair values for cash and
cash equivalents and variable-rate long-term debt. Investments in certificates
of deposit and restricted investments are included in restricted cash and are
reported at fair market value, which approximates cost, at December 31, 1999,
and 1998. The fair value of the Company's fixed-rate borrowings at December 31,
1999 and 1998 is $17,989,000 and $62,613,000 greater than the historical
carrying value of $778,181,000 and $518,035,000, respectively. In making such
calculations, the Company utilized credit reviews, quoted market prices and
discounted cash flow analyses, as appropriate.
The Company is exposed to credit-related losses in the event of
non-performance by counterparties to the Company's interest rate protection
agreements (Note 6). The Company does not obtain collateral or other security to
support such agreements but continually monitors its positions with, and the
credit quality of, the counterparties to such agreements. As of December 31,
1999 and 1998, the net unrealized gain (loss) on the interest rate protection
agreements was $2,325,000 and $(6,086,000), respectively.
51
<PAGE> 54
12. RELATED PARTY TRANSACTIONS
The Company has had transactions in the normal course of business with
various affiliate corporations including the Parent. The Company had notes
receivable due from affiliates of $76,410,000 and $57,348,000 as of December 31,
1999 and 1998, respectively. These notes accrue interest at the prime rate and
principal and interest are due upon demand. The Company also had note payables
due to the Parent of $4,815,000 and $6,010,000 as of December 31, 1999 and 1998,
respectively. These notes consist primarily of working capital loans which
accrue interest at the prime rate. Principal and interest of these notes are due
upon demand.
13. SUBSEQUENT EVENT
The Company has been developing jointly with Avista Power, Inc. a 270
megawatt, combined cycle, natural gas-fired electric generating facility to be
located in Rathdrum, Idaho. The Company and Avista Power own a 51% and 49%
interest, respectively, in a partnership that will own the Rathdrum facility. On
March 9, 2000, the partnership closed a credit facility with a bank and a
financial institution which provides for a $126 million construction loan and a
$5 million debt service reserve letter of credit. In accordance with the terms
of the financing agreements, the Company has committed to provide an equity
contribution to the partnership of approximately $16.7 million upon the earliest
to occur of (a) an event of default under the project's financing agreement, (b)
the incurrence of construction costs after all project financing has been
expended or (c) October 1, 2002. The equity contribution agreement is supported
by a letter of credit, which is provided under the Parent's corporate credit
facility. In addition, the Parent has agreed to make additional stand-by equity
contributions to cover certain contingent costs during the construction period,
subject to a cap of $3.6 million.
An indirect, wholly-owned subsidiary of the Company has entered into an
engineering, procurement, and construction (EPC) contract with the partnership
to construct the Rathdrum facility. The Parent is providing a guarantee
supporting the subsidiary's obligations under the EPC contract. The Rathdrum
facility, which the Company will operate, is anticipated to begin operation in
the third quarter of 2001. Avista Turbine Power, Inc. will deliver natural gas
to the plant and purchase the electrical output of the facility under a 25 year
power purchase agreement.
52
<PAGE> 55
SCHEDULE I
COGENTRIX DELAWARE HOLDINGS, INC.
CONDENSED BALANCE SHEETS OF REGISTRANT
December 31, 1999 and 1998
(dollars in thousands)
<TABLE>
<CAPTION>
ASSETS 1999 1998
--------- ---------
<S> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents $ 580 $ 12,535
Accounts receivable 8,473 16,216
--------- ---------
Total current assets 9,053 28,751
--------- ---------
INVESTMENT IN SUBSIDIARIES (ON THE EQUITY METHOD) 151,303 (63,664)
--------- ---------
OTHER ASSETS:
Notes receivable from affiliates 229,789 412,760
Other 23,842 12,638
--------- ---------
Total other assets 253,631 425,398
--------- ---------
Total Assets $ 413,987 $ 390,485
========= =========
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable -- 79
--------- ---------
Total current liabilities -- 79
--------- ---------
LONG-TERM DEBT
Deferred income taxes 23,570 17,372
--------- ---------
Total liabilities 23,570 17,451
--------- ---------
SHAREHOLDERS' EQUITY:
Common stock 1 1
Additional paid-in capital 610,458 522,381
Accumulated comprehensive income (1,144) (15)
Accumulated deficit (218,898) (149,333)
--------- ---------
Total shareholders' equity 390,417 373,034
--------- ---------
Total liabilities and shareholders' equity $ 413,987 $ 390,485
========= =========
</TABLE>
The accompanying condensed notes to condensed financial statements
are an integral part of this schedule.
53
<PAGE> 56
SCHEDULE I
COGENTRIX OF DELAWARE HOLDINGS, INC.
CONDENSED STATEMENTS OF INCOME OF REGISTRANT
For the Years Ended December 31, 1999, 1998 and 1997
(dollars in thousands)
<TABLE>
<CAPTION>
1999 1998 1997
-------- -------- --------
<S> <C> <C> <C>
OPERATING REVENUE $ -- $ -- $ --
OPERATING EXPENSES:
General, administrative and development expenses (21) (69) (126)
-------- -------- --------
OPERATING LOSS (21) (69) (126)
-------- -------- --------
OTHER INCOME (EXPENSE):
Investment and other income 15,998 22,234 10,472
-------- -------- --------
Total other income 15,998 22,234 10,472
-------- -------- --------
INCOME BEFORE INCOME TAXES 15,977 22,165 10,346
INCOME TAX PROVISION (6,199) (9,056) (4,138)
EQUITY IN EARNINGS (LOSS) OF SUBSIDIARIES 62,528 40,364 25,677
-------- -------- --------
NET INCOME (LOSS) $ 72,306 $ 53,473 $ 31,885
======== ======== ========
</TABLE>
The accompanying condensed notes to condensed financial statements
are an integral part of this schedule.
54
<PAGE> 57
SCHEDULE I
COGENTRIX DELAWARE HOLDINGS, INC.
CONDENSED STATEMENTS OF CASH FLOWS OF REGISTRANT
For the Years Ended December 31, 1999, 1998 and 1997
(dollars in thousands)
<TABLE>
<CAPTION>
1999 1998 1997
--------- --------- ---------
<S> <C> <C> <C>
NET CASH FLOW PROVIDED BY OPERATING ACTIVITIES $ 81,198 $ 53,632 $ 43,380
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Investments in subsidiaries (222,330) (526) (10,204)
--------- --------- ---------
Net cash (used in) provided by investing activities (222,330) (526) (10,204)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Decrease (increase) in notes receivable from affiliates 182,971 (291,492) (20,800)
Contributed capital from Parent 88,077 298,312 45,194
Dividends paid to Parent (141,871) (97,604) (53,689)
--------- --------- ---------
Net cash flows provided by (used in) financing activities 129,177 (90,784) (29,295)
--------- --------- ---------
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS (11,955) (37,678) 3,881
CASH AND CASH EQUIVALENTS, beginning of period 12,535 50,213 46,332
--------- --------- ---------
CASH AND CASH EQUIVALENTS, end of period $ 580 $ 12,535 $ 50,213
========= ========= =========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW
INFORMATION - CASH DIVIDENDS RECEIVED $ 69,890 $ 58,780 $ 30,648
========= ========= =========
</TABLE>
The accompanying condensed notes to condensed financial statements
are an integral part of this schedule.
55
<PAGE> 58
SCHEDULE I
COGENTRIX DELAWARE HOLDINGS, INC.
NOTES TO CONDENSED FINANCIAL STATEMENTS OF REGISTRANT
1. SIGNIFICANT ACCOUNTING POLICIES
These condensed notes should be read in conjunction with the
consolidated financial statements, and accompanying notes.
Accounting for Subsidiaries -- Cogentrix Delaware Holdings, Inc. has
accounted for its investment in and earnings of its subsidiaries on the equity
method in the condensed financial information.
Income Taxes -- The benefit for income taxes has been computed based on
the Company's consolidated effective income tax rate.
Change of Fiscal Year -- Effective January 1, 1998, Cogentrix Energy,
Inc. changed its fiscal year to commence on January 1 and conclude on December
31 of each year. Cogentrix Energy, Inc.'s fiscal year previously commenced each
July 1, concluding on June 30 of the following calendar year. Cogentrix Energy
has restated its financial statements for the years ending December 31, 1997
fiscal year to a calendar year basis.
2. GUARANTEE OF PARENT DEBT
Cogentrix Delaware Holdings, Inc., a wholly-owned subsidiary of
Cogentrix Energy, has guaranteed all of the existing and future senior,
unsecured outstanding indebtedness for borrowed money of Cogentrix Energy. This
guarantee, provided for in the credit agreement for the Corporate Credit
Facility, expires by its terms in 2002, unless the term of the credit agreement
is extended. The agreement under which the guarantee was given provides that the
terms or provisions of the guarantee may be waived, amended, supplemented or
otherwise modified at any time and from time to time by Cogentrix Delaware
Holdings, Inc. and the agent bank for the lenders under the credit agreement.
Senior Notes
On March 15, 1994, Cogentrix Energy, Inc. issued $100 million of
registered, unsecured senior notes due 2004 (the "2004 Notes") in a public debt
offering. The 2004 Notes were priced at par to yield 8.10%. In February 1994,
Cogentrix Energy, Inc. entered into a forward sale of ten-year U.S. Treasury
Notes in order to protect against a possible increase in the general level of
interest rates prior to the completion of the 2004 Notes offering. This hedge
transaction resulted in the recognition of a gain which has been deferred and
included as part of the 2004 Notes on the accompanying consolidated balance
sheets. This deferred gain will be recognized over the term of the 2004 Notes,
reducing the effective rate of interest on the 2004 Notes to 7.5%. The 2004
Notes require annual sinking fund payments beginning in March 2001. The impact
of the sinking fund requirements has been reflected in the schedule of future
maturities of long-term debt contained herein.
On October 20, 1998, Cogentrix Energy, Inc. issued $220 million of
registered, unsecured 8.75% senior notes due 2008 (the "2008 Notes"). These
notes were issued at a discount resulting in an effective rate of approximately
8.824%. On November 25, 1998, the Company issued an additional $35 million of
the 2008 Notes at a premium resulting in an effective rate of approximately
7.95%.
In March 1998, in anticipation of the offering of the 2008 Notes, the
Company entered into an interest rate hedge agreement to protect against a
possible increase in the general level of interest rates. The settlement costs
of approximately $22.1 million related to this hedge agreement were deferred and
will be recognized over the term of the 2008 Notes resulting in an overall
effective rate of approximately 9.59%.
56
<PAGE> 59
Future maturities of long-term debt at December 31, 1999, excluding the
unamortized balance of the net deferred hedge loss and excluding the net
unamortized premium, are as follows (dollars in thousands):
YEAR ENDED
DECEMBER 31,
------------
2000 $ 0
2001 20,000
2002 20,000
2003 20,000
2004 20,000
Thereafter 275,000
--------
$355,000
========
Corporate Credit Facility
In May 1997, the Company entered into a credit agreement with Australia and
New Zealand Banking Group Limited, as agent for a group of lending banks. In
October 1998, the Company amended and restated the corporate credit facility to
provide for $125 million of revolving credit available through October 2002 in
the form of direct advances or the issuance of letters of credit (the "Corporate
Credit Facility"). Borrowings bear interest at LIBOR plus an applicable margin
based on the credit rating on Cogentrix Energy's 2004 and 2008 Notes. Commitment
fees related to the Corporate Credit Facility are currently 50 basis points per
annum, payable each quarter on the outstanding unused portion of the Corporate
Credit Facility. As of December 31, 1999, the Company has used this credit
facility to issue approximately $117 million of letters of credit in connection
with investments made in electric-generating plants, and two plants under
construction. Subsequent to December 31, 1999, the Corporate Credit Facility was
amended to provide for $175 million of revolving credit and to modify the
covenants. The revolving credit facility has been extended through October,
2002.
Cogentrix Delaware Holdings, Inc., a wholly-owned subsidiary of Cogentrix
Energy, has guaranteed all of the existing and future senior, unsecured
outstanding indebtedness for borrowed money of Cogentrix Energy. This guarantee,
provided for in the credit agreement for the Corporate Credit Facility, expires
by its terms in 2002, unless the term of the credit agreement is extended. The
agreement under which the guarantee was given provides that the terms or
provisions of the guarantee may be waived, amended, supplemented or otherwise
modified at any time and from time to time by Cogentrix Delaware Holdings, Inc.
and the agent bank for the lenders under the credit agreement.
57
<PAGE> 60
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The directors and executive officers of Cogentrix Holdings are as set
forth below.
NAME AGE POSITION
- ---- --- --------
Thomas F. Schwartz........ 38 President and Director
John W. O'Connor.......... 31 Vice-President - Finance, and Director
David P. Fontello......... 50 Director
THOMAS F. SCHWARTZ has been President and Director since December 1993.
Mr. Schwartz has been Group Senior Vice President-Finance and Chief Financial
Officer of Cogentrix Energy, the parent of Holdings since December 1999. From
March 1997 until then he was Senior Vice President--Finance and Treasurer of
Cogentrix Energy, prior to which he was Vice President--Finance and Treasurer
since Cogentrix Energy's formation in 1993. From April 1991 to 1993, Mr.
Schwartz was Controller of Cogentrix, Inc. Prior to joining Cogentrix, Inc., he
was an audit manager with Arthur Andersen, LLP's Small Business Advisory
Division.
JOHN W. O'CONNOR John W. O'Connor has been Vice President-Finance and a
Director since October 1999. He has been Vice President-Controller of Cogentrix
Energy, the parent of Holdings, since September 1997. Previously, Mr. O'Connor
was Assistant Controller of Cogentrix Energy since January 1996.
DAVID P. FONTELLO David Fontello has been a Director since October
1996. He is employed by Wilmington Trust Company as a Vice President since 1989.
He was appointed Section Manager of the Corporate Custody/Corporate Trust
Section in 1995. Mr. Fontello currently serves as a Director of over 50 Delaware
holding companies.
ITEM 11. EXECUTIVE COMPENSATION
None of the officers or directors of Cogentrix Delaware Holdings, Inc.
have received, or, it is anticipated, will receive, compensation for their
services with Holdings.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
All of the issued and outstanding shares of common stock of Holdings
are owned by its parent, Cogentrix Energy, Inc.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None
58
<PAGE> 61
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 32.
(2) Financial Statement Schedules - See index on page 32.
(3) Index to Exhibits.
Designation Of
Exhibit Description Of Exhibit
-------------- ----------------------
3.1 Certificate of Incorporation of Cogentrix Delaware
Holdings, Inc. (3.3) (16)
3.2 Bylaws of Cogentrix Delaware Holdings, Inc. (3.4)
(16)
4.1 Indenture, dated as of March 15, 1994 between
Cogentrix Energy, Inc. and First Union National Bank
of North Carolina, as Trustee, including form of
8.10% 2004 Senior Note (4.1) (3)
4.2 Indenture, dated as of October 20, 1998, between
Cogentrix Energy, Inc. and First Union National Bank,
as Trustee, including form of 8.75% Senior Note (4.2)
(14)
4.3 First Supplemental Indenture, dated as of October 20,
1998 between Cogentrix Energy, Inc. and First Union
National Bank, as Trustee (4.3) (14)
4.4 Registration Agreement, dated as of October 20, 1998,
by and among Cogentrix Energy, Inc., Salomon Smith
Barney Inc., Goldman, Sachs & Co. and CIBC
Oppenheimer Corp. (4.4) (14)
4.5 Registration Agreement, dated as of November 25,
1998, between Cogentrix Energy, Inc. and Salomon
Smith Barney, Inc. (4.5) (15)
4.6 Amendment No. 1 to the First Supplemental Indenture,
dated as of November 25, 1998 between Cogentrix
Energy, Inc. and First Union National Bank, as
Trustee (4.6) (15)
4.7 Amended and Restated Guarantee, dated as of October
29, 1998, made by Cogentrix Delaware Holdings, Inc.
the Guarantor in favor of the Borrower Creditors of
Cogentrix Energy, Inc. (10.130) (14)
4.7(a) Second Amended and Restated Guarantee, dated as of
March 3, 2000, made by Cogentrix Delaware Holdings,
Inc., the Guarantor, in favor of the Borrower
Creditors of Cogentrix Energy, Inc. (10.49a) (27)
4.8 Pledge Agreement, dated as of September 8, 1999,
between Cogentrix Delaware Holdings, Inc. and
Dresdner Bank, AG, as administrative agent.
(10.2)(26)
10.1 Power Purchase and Operating Agreement, dated as of
July 21, 1986, between Cogentrix of Virginia, Inc.
and Virginia Electric and Power Company, as amended
(assigned to and assumed by Cogentrix Virginia
Leasing Corporation) (Portsmouth Facility) (10.7).
(1)
10.1(a) Third Amendment and Restatement of the Power Purchase
and Operating Agreement, dated December 5, 1997,
between Cogentrix Virginia Leasing Corporation and
Virginia Electric and Power Company (Portsmouth
Facility) (10.7(a)). (11)
10.2 Power Purchase and Operating Agreement, dated as of
January 24, 1989, between Cogentrix of Rocky Mount,
Inc. and Virginia Electric and Power Company, doing
business in North Carolina as North Carolina Power,
as amended (Rocky Mount Facility) (10.8). (1)
10.3 Power Purchase and Operating Agreement, dated as of
January 24, 1989, between Cogentrix of Richmond, Inc.
(formerly named Cogentrix of Petersburg, Inc.) and
Virginia Electric and Power Company, as amended.
(Richmond Facility, Unit I) (10.10). (1)
10.4 Power Purchase and Operating Agreement, dated as of
January 24, 1989, between WV Hydro, Inc. and Virginia
Electric and Power Company, as amended
59
<PAGE> 62
(assigned to and assumed by Cogentrix of Richmond,
Inc.) (Richmond Facility, Unit II) (10.11). (1)
10.5 Steam Purchase Agreement, dated as of December 31,
1985, between Cogentrix Virginia Leasing Corporation
and Hoechst-Celanese Corporation (successor to
Virginia Chemicals Inc.) (Portsmouth Facility)
(10.19). (*)(2)
10.6 Steam Purchase Agreement, dated as of November 15,
1988, between Cogentrix of Rocky Mount, Inc. and
Abbott Laboratories, as amended (Rocky Mount
Facility) (10.20). (*)(2)
10.7 Steam Purchase Agreement, dated as of May 18, 1990,
between Cogentrix of Richmond, Inc. and E.I. du Pont
de Nemours and Company, as amended (Richmond
Facility) (10.22). (*)(2)
10.8 Coal Sales Agreement, dated as of December 15, 1986,
among AgipCoal Sales USA, Inc. (formerly named Enoxy
Coal Sales, Inc.), AgipCoal USA, Inc. (formerly named
Enoxy Coal, Inc.) and Cogentrix Virginia Leasing
Corporation (Portsmouth Facility) (10.27). (*)(2)
10.8(a) First Amendment to Coal Sales Agreement, dated
September 29, 1995, by and between Arch Coal Sales
Company, Inc., and Cogentrix Virginia Leasing
Corporation (Portsmouth Facility) (10.1). (6)
10.8(b) Second Amendment, dated as of April 20, 1999, to Coal
Sales Agreement, dated as of December 15, 1986, by
and between Cogentrix Virginia Leasing Corporation
and Arch Coal Sales Company. (10.1) (*) (25)
10.9 Coal Sales Agreement, dated as of October 1, 1989,
among Agip Coal Sales USA, Inc., Laurel Creek Co.,
Inc. and Cogentrix of Rocky Mount, Inc., as amended
(Rocky Mount Facility) (10.28). (*)(2)
10.10 Coal Sales Agreement, dated as of February 15, 1990,
among Electric Fuels Corporation, Kentucky May Coal
Company, Inc. and Cogentrix of Richmond, Inc., as
amended (Richmond Facility, Unit I) (10.31). (*)(2)
10.10(a) Fourth Amendment to Coal Sales Agreement, dated as of
July 1, 1998, among Electric Fuels Corporation,
Kentucky May Coal Company, Inc. and Cogentrix of
Richmond, Inc. (10.10(a)) (*) (22)
10.11 Coal Sales Agreement, dated as of January 1, 1990,
between Coastal Coal Sales, Inc., and Cogentrix of
Richmond, Inc., as amended (Richmond Facility, Unit
II) (10.32). (*)(2)
10.12 Railroad Transportation Contract, dated as of
December 22, 1986, between Cogentrix Virginia Leasing
Corporation, and Norfolk Southern Railway Company, as
amended (Portsmouth Facility) (10.39). (*)(2)
10.13 Barge Transportation Contract, dated as of December
23, 1986, between Cogentrix Virginia Leasing
Corporation and McAllister Brothers, Inc., as amended
(Portsmouth Facility) (10.40). (1)
10.14 Railroad Transportation Contract, dated as of
September 26, 1989, between Cogentrix of Rocky Mount,
Inc. and CSX Transportation, Inc., as amended (Rocky
Mount Facility) (10.41). (*)(2)
10.14(a) Fourth Amendment, dated as of August 23, 1995, to the
Railroad Transportation Contract, dated as of
September 26, 1989, between Cogentrix of Rocky Mount,
Inc. and CSX Transportation, Inc. (Rocky Mount
Facility) (10.41(a)). (5)
10.14(b) Fifth Amendment, dated as of January 1, 1996, to the
Railroad Transportation Contract, dated as of
September 26, 1989, between Cogentrix of Rocky Mount,
Inc. and CSX Transportation, Inc. (Rocky Mount
Facility) (10.41(b)). (8)
10.14(c) Amendment No. 6 to Contract CSXT-C-03951, dated as of
January 1, 1997, between Cogentrix of Rocky Mount,
Inc. and CSX Transportation, Inc. (Rocky Mount
Facility) (10.9). (9)
10.14(d) Amendment No. 7 to Contract CSXT-C-03951, dated as of
July 1, 1997, between Cogentrix of Rocky Mount, Inc.
and CSX Transportation, Inc. (Rocky Mount Facility)
(10.47(d)). (10)
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10.14(e) Amendment No. 8 to Contract CSXT-C-03951, dated as of
January 1, 1999, between Cogentrix of Rocky Mount,
Inc. and CSX Transportation, Inc. (Rocky Mount
Facility). (10.14(e)) (22)
10.15 Railroad Transportation Contract, dated as of March
1, 1990, between Cogentrix of Richmond, Inc. and CSX
Transportation, Inc., as amended (Richmond Facility,
Unit I) (10.42). (*)(2)
10.15(a) Third Amendment to Railroad Transportation Contract,
filed with the ICC on December 13, 1994, between
Cogentrix of Richmond, Inc. and CSX Transportation,
Inc. (Richmond Facility, Unit I) (10.4). (4)
10.16 Railroad Transportation Contract, dated as of March
1, 1990, between Cogentrix of Richmond, Inc. and CSX
Transportation, Inc., as amended (Richmond Facility,
Unit II) (10.43). (*)(2)
10.16(a) Fourth Amendment to Railroad Transportation Contract,
filed with the ICC on December 13, 1994, between
Cogentrix of Richmond, Inc. and CSX Transportation,
Inc. (Richmond Facility, Unit II) (10.5). (4)
10.16(b) Fifth Amendment to Railroad Transportation Contract,
effective as of November 16, 1995, between Cogentrix
of Richmond, Inc. and CSX Transportation, Inc.
(Richmond Facility, Unit II) (10.43(b)). (*)(8)
10.16(c) Amendment No. 6 to Railroad Transportation Contract,
effective on June 9, 1998, between Cogentrix of
Richmond, Inc. and CSX Transportation, Inc. (Richmond
Facility). (*)(14)
10.17 Third Amended and Restated Loan Agreement, dated as
of December 22, 1997, among Cogentrix Virginia
Leasing Corporation, the lenders party thereto and
Credit Lyonnais, as the Agent, Issuing Bank and a
Lender (Portsmouth Facility) (10.54). (11)
10.17(a) Amendment No 1 to the Third Amended and Restated Loan
Agreement dated December 22, 1997 between Cogentrix
Virginia Leasing Company and several banks and other
financial institutions. (10.2) (25)
10.18 Amended and Restated Construction and Term Loan
Agreement, dated as of December 1, 1993, among
Cogentrix of Rocky Mount, Inc., the Tranche B Lenders
party thereto, and The Prudential Insurance Company
of America, as Credit Facility Agent (Rocky Mount
Facility) (10.52). (1)
10.18(a) First Amendment, dated as of March 31, 1996, to the
Amended and Restated Construction and Term Loan
Agreement, dated as of December 1, 1993, among
Cogentrix of Rocky Mount, Inc., the Tranche B Lenders
party thereto, and The Prudential Insurance Company
of America, as Credit Facility Agent (Rocky Mount
Facility) (10.4). (7)
10.18(b) Second Amendment, dated as of May 31, 1996, to the
Amended and Restated Construction and Term Loan
Agreement, dated as of December 1, 1993, among
Cogentrix of Rocky Mount, Inc., the Tranche B Lenders
party thereto, and The Prudential Insurance Company
of America, as Credit Facility Agent (Rocky Mount
Facility) (10.48(b)). (8)
10.18(c) Third Amendment, dated as of December 1, 1997, to the
Amended and Restated Construction and Term Loan
Agreement, dated as of December 1, 1993, among
Cogentrix of Rocky Mount, Inc, the Tranche B Lenders
party thereto, and The Prudential Insurance Company
of America, as Credit Facility Agent (Rocky Mount
Facility) (10.55(c)). (11)
10.19 Amended and Restated Subordinated Note dated April
22, 1994 of Cogentrix of Pennsylvania, Inc. payable
to Cogentrix Delaware Holdings, Inc. (10.57). (11)
10.20 Reimbursement and Loan Agreement, dated as of
December 1, 1990, among Cogentrix of Richmond, Inc.,
Banque Paribas, New York Branch as Issuing Bank, the
lenders party thereto and Banque Paribas, New York
Branch, as Agent, as amended (Richmond Facility)
(10.55). (1)
10.20(a) Fourth Amendment, dated as of February 15, 1995, to
the Reimbursement and Loan Agreement, dated as of
December 1, 1990, among Cogentrix of Richmond, Inc.,
Banque Paribas, New York Branch, as Issuing Bank, the
lenders party thereto
61
<PAGE> 64
and Banque Paribas, New York Branch, as Agent
(Richmond Facility) (10.55(a)). (5)
10.20(b) Fifth Amendment, dated as of June 1, 1995, to the
Reimbursement and Loan Agreement, dated as of
December 1, 1990, among Cogentrix of Richmond, Inc.,
Banque Paribas, New York Branch, as Issuing Bank, the
lenders party thereto and Banque Paribas, New York
Branch, as Agent (Richmond Facility) (10.55(b)). (5)
10.20(c) Sixth Amendment, dated as of March 31, 1996, to the
Reimbursement and Loan Agreement, dated as of
December 1, 1990, among Cogentrix of Richmond, Inc.,
Banque Paribas, New York Branch, as Issuing Bank, the
lenders party thereto and Banque Paribas, New York
Branch, as Agent (Richmond Facility) (10.5). (7)
10.20(d) Seventh Amendment, dated as of December 1, 1997, to
the Reimbursement and Loan Agreement, dated as of
December 1, 1990, among Cogentrix of Richmond, Inc.,
Banque Paribas, New York Branch, as Issuing Bank, the
lenders party thereto and Banque Paribas, New York
Branch, as Agent (Richmond Facility) (10.58(d)). (11)
10.21 Indenture of Trust, dated as of December 1, 1990,
between the Industrial Development Authority of the
City of Richmond, Virginia and Sovran Bank, N.A., as
Trustee, including First and Second Supplemental
Indentures of Trust (Richmond Facility) (10.56). (1)
10.22 Sale Agreement, dated as of December 1, 1990, between
the Industrial Development Authority of the City of
Richmond, Virginia and Cogentrix of Richmond, Inc.,
including First and Second Supplemental Sale
Agreements (Richmond Facility) (10.57). (1)
10.23 Third Amended and Restated Security Deposit
Agreement, dated as of December 22, 1997, among
Cogentrix Virginia Leasing Corporation, Credit
Lyonnais, as Agent and Issuing Bank, and First Union
National Bank, as Security Agent (Portsmouth
Facility) (10.68). (11)
10.24 Amended and Restated Security Deposit Agreement,
dated as of December 1, 1993, among Cogentrix of
Rocky Mount, Inc., The Prudential Insurance Company
of America, as Credit Facility Agent and First Union
National Bank of North Carolina, as Security Agent
(Rocky Mount Facility) (10.65). (1)
10.25 Security Deposit Agreement, dated as of December 1,
1990, among Cogentrix of Richmond, Inc., Banque
Paribas, New York Branch, as Agent and First Union
National Bank of North Carolina, as Security Agent
(Richmond Facility) (10.67). (1)
10.25(a) First Amendment to Security Deposit Agreement, dated
December 15, 1993, among Cogentrix of Richmond, Inc.,
Banque Paribas, New York Branch, as Agent and First
Union National Bank of North Carolina, as Security
Agent (Richmond Facility) (10.67(a)). (2)
10.26 Third Amended and Restated Pledge Agreement, dated as
of December 22, 1997, made by Cogentrix, Inc., as
Pledgor, and Credit Lyonnais, as Agent (Portsmouth
Facility) (10.79). (11)
10.27 Ground Lease and Easement, dated as of December 15,
1986, between Virginia Chemicals, Inc., as Lessor and
Cogentrix Virginia Leasing Corporation, as Lessee
(Portsmouth Facility) (10.94). (1)
10.28 Ground Lease, dated as of December 13, 1990, between
Cogentrix of Richmond, Inc., as Lessee, and E.I. du
Pont de Nemours and Company, as Lessor (Richmond
Facility) (10.95). (1)
10.29 Amended and Restated Land Lease Agreement, dated as
of February 18, 1988, among Arrowpoint Associates
Limited Partnership, as Landlord, and Cogentrix,
Inc., CI Properties, Inc. and Equipment Leasing
Partners, as Tenant, as amended (assigned to and
assumed by Equipment Leasing Partners, with
Cogentrix, Inc., as guarantor) (Corporate
Headquarters) (10.96). (1)
10.30 Amended and Restated Lease Agreement, dated as of
April 30, 1993, among Equipment Leasing Partners, as
Landlord, Cogentrix, Inc., as Tenant, and CI
Properties, Inc., as amended (Corporate Headquarters)
(10.97). (1)
62
<PAGE> 65
10.31 Letter Agreement, dated May 25, 1989, among
Cogentrix, Inc., Cogentrix of Richmond, Inc.
(formerly named Cogentrix of Petersburg, Inc.), and
WV Hydro, Inc., as amended (Richmond Facility)
(10.98). (1)
10.32 Amended and Restated Limited Partnership Agreement,
dated as of June 30, 1995, among LSP-Cottage Grove,
Inc., Granite Power Partners, L.P., and TPC Cottage
Grove, Inc. (17)
10.32(a) Amendment #1 to the Cottage Grove Partnership
Agreement. (18)
10.32(b) Consent, Waiver and Amendment No. 2, dated March 20,
1998, to the Amended and Restated Limited Partnership
Agreement of LSP-Cottage Grove, L.P. (20)
10.32(c) Third Amendment, dated December 11, 1998, to the
Amended and Restated Limited Partnership Agreement of
LSP-Cottage Grove, L.P. (23)
10.33 Amended and Restated Partnership Agreement, dated as
of June 30, 1995, among LSP-Whitewater I, Inc.,
Granite Power Partners, L.P. and TPC Whitewater, Inc.
(17)
10.33(a) Consent, Waiver and Amendment No. 1, dated March 20,
1998, to the Amended and Restated Limited Partnership
Agreement of LSP-Whitewater Limited Partnership. (20)
10.33(b) Second Amendment, dated December 11, 1998, to the
Amended and Restated Limited Partnership Agreement of
LSP-Whitewater Limited Partnership. (23)
10.34 Power Purchase Agreement, dated as of May 9, 1994,
between Northern States Power Company and LSP-Cottage
Grove, L.P. (17)
10.35 Power Purchase Agreement, dated as of December 21,
1993, between Wisconsin Electric Power Company and
LSP-Whitewater Limited Partnership. (17)
10.35(a) Amendment to Power Purchase Agreement, dated as of
February 10, 1994, between Wisconsin Electric Power
Company and LSP-Whitewater Limited Partnership. (17)
10.35(b) Second Amendment to Power Purchase Agreement, dated
as of October 5, 1994, between Wisconsin Electric
Power Company and LSP-Whitewater Limited Partnership.
(17)
10.35(c) Third Amendment to Power Purchase Agreement, dated as
of May 5, 1995, between Wisconsin Electric Power
Company and LSP-Whitewater Limited Partnership. (17)
10.35(d) Fourth Amendment to Power Purchase Agreement, dated
March 18, 1997, between Wisconsin Electric Power
Company and LSP-Whitewater Limited Partnership. (19)
10.35(e) Fifth Amendment to Power Purchase Agreement, dated
February 26, 1998, between Wisconsin Electric Power
Company and LSP-Whitewater Limited Partnership. (20)
10.36 Operations and Maintenance Agreement by and between
LSP-Whitewater Limited Partnership as Owner and
LSP-Whitewater I, Inc. as Operator dated as of April
15, 1999. (10.1) (*) (24)
10.37 Operations and Maintenance Agreement by and between
LSP-Cottage Grove, L.P. as Owner and LSP-Cottage
Grove, Inc. as Operator dated as of April 15, 1999.
(10.2) (*) (24)
10.38 Steam Purchase Contract, effective as of January 1,
1999, by and between Celanese Chemical, Inc. and
Cogentrix Virginia Leasing Corporation. (10.3) (*)
(25)
10.39 Steam Purchase Contract, effective as of January 1,
1999, by and between BASF Corporation and Cogentrix
Virginia Leasing Corporation. (10.4) (*) (25)
10.40 Credit Agreement, dated as of September 8, 1999,
between Cogentrix Eastern America, Inc. and Dresdner
Bank, AG, as administrative agent. (10.1) (26)
10.40(a) First Amendment, dated as of December 17, 1999, to
the Credit Agreement, dated as of September 8, 1999,
between Cogentrix Eastern America, Inc. and Dresdner
Bank, AG, as administrative agent. (27)
63
<PAGE> 66
21 Direct and Indirect Subsidiaries of Cogentrix
Delaware Holdings, Inc.
27 Financial Data Schedule, which is submitted
electronically to the U.S. Securities and Exchange
Commission for information only and is not filed.
(b) Reports on Form 8-K
No reports on Form 8-K were filed during the quarter covered
by this report.
(*) Certain portions of this exhibit have been omitted pursuant to
previously approved requests for confidential treatment.
(1) Incorporated by reference to Registration Statement on Form
S-1 (File No. 33-74254) filed January 19, 1994 by Cogentrix
Energy, Inc. The number designating the exhibit on the exhibit
index to such previously-filed report is enclosed in
parentheses at the end of the description of the exhibit
above.
(2) Incorporated by reference to Amendment No. 2 to Registration
Statement on Form S-1 (File No. 33-74254) filed March 7, 1994
by Cogentrix Energy, Inc. The number designating the exhibit
on the exhibit index to such previously-filed report is
enclosed in parentheses at the end of the description of the
exhibit above.
(3) Incorporated by reference to the Form 10-K (File No. 33-74254)
filed September 28, 1994 by Cogentrix Energy, Inc. The number
designating the exhibit on the exhibit index to such
previously-filed report is enclosed in parentheses at the end
of the description of the exhibit above.
(4) Incorporated by reference to the Form 10-Q (File No. 33-74254)
filed February 14, 1995 by Cogentrix Energy, Inc. The number
designating the exhibit on the exhibit index to such
previously-filed report is enclosed in parentheses at the end
of the description of the exhibit above.
(5) Incorporated by reference to the Form 10-K (File No. 33-74254)
filed September 28, 1995 by Cogentrix Energy, Inc. The number
designating the exhibit on the exhibit index to such
previously-filed report is enclosed in parentheses at the end
of the description of the exhibit above.
(6) Incorporated by reference to the Form 10-Q (File No. 33-74254)
filed November 14, 1995 by Cogentrix Energy, Inc. The number
designating the exhibit on the exhibit index to such
previously-filed report is enclosed in parentheses at the end
of the description of the exhibit above.
(7) Incorporated by reference to the Form 10-Q (File No. 33-74254)
filed May 3, 1996 by Cogentrix Energy, Inc. The number
designating the exhibit on the exhibit index to such
previously-filed report is enclosed in parentheses at the end
of the description of the exhibit above.
(8) Incorporated by reference to the Form 10-K (File No. 33-74254)
filed October 10, 1996 by Cogentrix Energy, Inc. 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.
64
<PAGE> 67
(9) Incorporated by reference to the Form 10-Q (File No. 33-74254)
filed February 14, 1997 by Cogentrix Energy, Inc. The number
designating the exhibit on the exhibit index to such
previously-filed report is enclosed in parentheses at the end
of the description of the exhibit above.
(10) Incorporated by reference to the Form 10-K (File No. 33-74254)
filed September 29, 1997 by Cogentrix Energy, Inc. The number
designating the exhibit on the exhibit index to such
previously-filed report is enclosed in parentheses at the end
of the description of the exhibit above.
(11) Incorporated by reference to the Form 10-K (File No. 33-74254)
filed March 30, 1998 by Cogentrix Energy, Inc. The number
designating the exhibit on the exhibit index to such
previously-filed report is enclosed in parentheses at the end
of the description of the exhibit above.
(12) Incorporated by reference to the Form 8-K (File No. 33-74254)
filed April 6, 1998 by Cogentrix Energy, Inc. The number
designating the exhibit on the exhibit index to such
previously-filed report is enclosed in parentheses at the end
of the description of the exhibit above.
(13) Incorporated by reference to the Form 10-Q (File No. 33-74254)
filed May 15, 1998 by Cogentrix Energy, Inc. The number
designating the exhibit on the exhibit index to such
previously-filed report is enclosed in parentheses at the end
of the description of the exhibit above.
(14) Incorporated by reference to the Registration Statement on
Form S-4 (File No. 33-67171) filed November 12, 1998 by
Cogentrix Energy, Inc. The number designating the exhibit on
the exhibit index to such previously file report is enclosed
in parentheses at the end of the description of the exhibit
above.
(15) Incorporated by reference to Amendment No. 1 to the
Registration Statement on Form S-4 (File No. 33-67171) filed
January 27, 1999 by Cogentrix Energy, Inc. The number
designating the exhibit on the exhibit index to such
previously file report is enclosed in parentheses at the end
of the description of the exhibit above.
(16) Incorporated by reference to Amendment No. 3 to the
Registration Statement on Form S-4 (File No. 33-67171) filed
March 15, 1999 by Cogentrix Energy, Inc. and Cogentrix
Delaware Holdings, Inc. The number designating the exhibit on
the exhibit index to such previously file report is enclosed
in parentheses at the end of the description of the exhibit
above.
(17) Incorporated by reference to the Registration Statement on
Form S-4 (File No. 33-95928) filed on August 16, 1995, as
amended, or to the Form 10-K filed for the fiscal year ended
December 31, 1995 by LS Power Funding Corporation, LSP-Cottage
Grove, L.P. and LSP-Whitewater Limited Partnership.
(18) Incorporated by reference to the Form 10-Q (File No. 33-95928)
filed August 12, 1996 by LS Power Funding Corporation,
LSP-Cottage Grove, L.P. and LSP-Whitewater Limited
Partnership.
(19) Incorporated by reference to the Form 10-Q (File No. 33-95928)
filed May 14, 1997 by LS Power Funding Corporation,
LSP-Cottage Grove, L.P. and LSP-Whitewater Limited
Partnership.
(20) Incorporated by reference to the Form 10-K (File No. 33-95928)
filed April 15, 1998 by LS Power Funding Corporation,
LSP-Cottage Grove, L.P. and LSP-Whitewater Limited
Partnership.
(21) Incorporated by reference to the Form 8-K (File No. 33-74254)
filed November 4, 1998 by Cogentrix Energy, Inc. The number
designating the exhibit on the exhibit index to such
previously-filed report is enclosed in parentheses at the end
of the description of the exhibit above.
(22) Incorporated by reference to the Form 10-K (File No. 33-74254)
filed March 31, 1999 by Cogentrix Energy, Inc. The number
designating the exhibit on the exhibit index to such
previously-filed report is enclosed in parentheses at the end
of the description of the exhibit above.
(23) Incorporated by reference to the Form 10-K (File No. 33-95928)
filed March 31, 1999 by LS Power Funding Corporation,
LSP-Cottage Grove, L.P. and LSP-Whitewater Limited
Partnership.
(24) Incorporated by reference to the Form 10-Q (File No.
33-95928) filed May 17, 1999 by LS Power Funding Corporation,
LSP-Cottage Grove, L.P. and LSP-Whitewater Limited
Partnership. The number designating the exhibit on the exhibit
index to such previously filed report is enclosed in
parentheses at the end of the description of the exhibit
above.
(25) Incorporated by reference to the Form 10-Q (File No. 33-74254)
filed August 16, 1999 by Cogentrix Energy, Inc. 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.
(26) Incorporated by reference to the Form 10-Q (File No. 33-74254)
filed November 15, 1999 by Cogentrix Energy, Inc. 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.
(27) Incorporated by reference to the Form 10-K (File No. 33-74254)
filed by Cogentrix Energy, Inc. on March 30, 2000. The number
designating the exhibit index to such previously filed report
is enclosed in parentheses at the end of the description of
the exhibit above.
65
<PAGE> 68
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 DELAWARE HOLDINGS, INC.
(Registrant)
Date: March 30, 2000 By: /s/ Thomas F. Schwartz
----------------------------
Thomas F. Schwartz
President and Director
(Principal Executive Financial
and Accounting 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.
Signature Title Date
- --------- ----- ----
/s/ John W. O'Connor Vice President and Director March 30, 2000
- -----------------------
John W. O'Connor
/s/ David P. Fontello Director March 30, 2000
- -----------------------
David P. Fontello
66
<PAGE> 1
Exhibit 21
COGENTRIX DELAWARE HOLDINGS, INC.
SUBSIDIARIES
Cogentrix Delaware Holdings, Inc. (DE)
Cogentrix Holdings Corporation (NC)
Cogentrix of Richmond, Inc. (NC)
Cogentrix of Rocky Mount, Inc. (NC)
Cogentrix, Inc. (NC)
Cogentrix Eastern Carolina Corporation (NC)
Cogentrix of North Carolina Holdings, Inc. (NC)
Cogentrix of North Carolina, Inc. (NC)
Roxboro/Southport I, Inc. (NC)
Roxboro/Southport II, Inc. (NC)
Roxboro/Southport General Partnership (NC)*
Cogentrix of Virginia, Inc. (VA)
Cogentrix Virginia Leasing Corporation (NC)
Cogentrix of Pennsylvania, Inc. (DE)
ReUse Technology, Inc. (NC) (doing business as RT Soil Sciences)
Cogentrix - Mexico, Inc. (NC)
Cogeneracion Mexicana, S.A. de C.V. (Mexico)
CI Properties, Inc. (NC)
Moapa Valley Holdings, Inc. (NV)
Cogentrix of Asia Pte Ltd. (Singapore)
Cogentrix of Lawrence County, Inc. (DE)
Cogentrix Lawrence County, LLC (DE)
Cogentrix of Oklahoma, Inc. (DE)
Green Country Energy, LLC (DE)
Green Country Operating Services, LLC (DE)
Cogentrix Southaven Holdings, Inc. (DE)
Southaven Power LLC, (DE)
Cogentrix/Batesville Holdings, Inc. (DE)
Cogentrix/Batesville, Inc. (DE)
Cogentrix Batesville Operations, LLC (DE)*
Cogentrix/Batesville, LLC (DE)*
LSP-Batesville Holdings, LLC (DE)*
LSP Batesville Funding Corporation (DE)
LSP Energy, Inc. (DE)
LSP Energy Limited Partnership (DE)*
Cogentrix Eastern America, Inc. (DE)
Cogentrix/Logan, Inc. (DE)
Cogentrix/Northampton, Inc. (DE)
Cogentrix/Carney's Point, Inc. (DE)
Cogentrix/Scrubgrass, Inc. (DE)
Palm Power Corporation (DE)
Thaleia, LLC (DE)
Cedar Power Corporation (DE)
Cedar I Power Corporation (DE)
Cedar II Power Corporation (DE)
Hickory Power Corporation (DE)
Birch Power Corporation (PA)
Panther Creek Leasing, Inc. (DE)
<PAGE> 2
Arcanum, Inc. (DE)
Cogentrix Energy Power Marketing, Inc. (NC)
Cogentrix of Latin America, Inc. (NC)
Cogentrix of Vancouver, Inc. (NC)
Cogentrix Mid-America, Inc. (DE)
Floriculture, Inc. (DE)
Cogentrix Cottage Grove, LLC (DE)
LSP-Cottage Grove, Inc. (DE)
LSP-Cottage Grove, LP (DE)*
LS Power Funding Corporation (DE)
Cogentrix Whitewater, LLC (DE)
LSP-Whitewater I, Inc. (DE)
LSP-Whitewater Limited Partnership (DE)*
LS Power Funding Corporation (DE)
Cogentrix of Rathdrum, Inc. (NC)
Rathdrum Construction Company, Inc. (DE)
Rathdrum Operating Services Company, Inc. (DE)
Rathdrum Power, LLC (DE)
Cogentrix of Birchwood I, Inc. (DE)
Cogentrix of Birchwood II, Inc. (DE)
Cogentrix/Birchwood One Partners (DE)*
Cogentrix/Birchwood Two, L.P. (DE)*
(PARTNERSHIPS DENOTED BY ASTERISK)
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED FINANCIAL STATEMENTS OF COGENTRIX DELAWARE HOLDINGS, INC AS OF AND
FOR THE YEAR ENDED DECEMBER 31, 1999 AND IS QUALIFIED IN ITS ENTIRETY BY
REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<CURRENCY> U.S. DOLLARS
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> DEC-31-1999
<EXCHANGE-RATE> 1
<CASH> 119,012
<SECURITIES> 0
<RECEIVABLES> 60,930
<ALLOWANCES> 0
<INVENTORY> 20,137
<CURRENT-ASSETS> 202,051
<PP&E> 695,391
<DEPRECIATION> 259,710
<TOTAL-ASSETS> 1,990,819
<CURRENT-LIABILITIES> 205,034
<BONDS> 1,181,270
0
0
<COMMON> 1
<OTHER-SE> 390,414
<TOTAL-LIABILITY-AND-EQUITY> 1,990,819
<SALES> 319,421
<TOTAL-REVENUES> 464,957
<CGS> 222,730
<TOTAL-COSTS> 265,815
<OTHER-EXPENSES> 14,752
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 63,255
<INCOME-PRETAX> 121,135
<INCOME-TAX> 48,829
<INCOME-CONTINUING> 72,306
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 72,306
<EPS-BASIC> 72.31
<EPS-DILUTED> 72.31
</TABLE>
