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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, 2000
Commission File Number: 33-67171
COGENTRIX DELAWARE HOLDINGS, INC.
(Exact name of registrant as specified in its charter)
NORTH CAROLINA 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.
[X] Yes [ ] No
Indicate by checkmark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
Number of shares of Common Stock, no par value, outstanding at March 30, 2001:
1,000
DOCUMENTS INCORPORATED BY REFERENCE: NONE
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COGENTRIX DELAWARE HOLDINGS, INC.
INDEX TO ANNUAL REPORT ON FORM 10-K
PAGE
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PART I
Item 1: Business................................................................... 3
Item 2: Properties................................................................. 23
Item 3: Legal Proceedings.......................................................... 23
Item 4: Submission of Matters to a Vote of Security Holders........................ 23
PART II
Item 5: Market for the Registrant's Common Stock and Related Shareholder Matters... 23
Item 6: Selected Consolidated Financial Data....................................... 24
Item 7: Management's Discussion and Analysis of Financial Condition and
Results of Operations...................................................... 25
Item 8: Financial Statements and Supplementary Data................................ 32
Item 9: Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure....................................................... 57
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. and its Parent, Cogentrix Energy, Inc.,
are holding companies that through their direct and indirect subsidiaries
acquire, develop, own and operate 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 to regulated
electric utilities and power marketers, primarily under long-term power purchase
agreements. We sell the steam we produce to industrial customers with
manufacturing or other facilities located near our electric generating plants.
We were one of the early participants in the market for electric power generated
by independent power producers that developed as a result of energy legislation
the United States Congress enacted in 1978. We believe we are one of the larger
independent power producers in the United States based on our total project
megawatts in operation.
We currently own - entirely or in part - a total of 22 electric generating
facilities in the United States. Our 22 plants are designed to operate at a
total production capability of approximately 3,914 megawatts. After taking into
account our part interests in the 16 plants that are not wholly-owned by us,
that range from 1.6% to 74.2%, our net ownership interests in the total
production capability of our 22 electric generating facilities is approximately
1,754 megawatts. We currently operate nine of our facilities, seven of which we
developed and constructed.
We also have ownership interests in and will operate three facilities
currently under construction in Louisiana, Oklahoma and Idaho. Once these
facilities begin operation, we will have ownership interests in a total of 25
domestic electric generating facilities that are designed with a total
production capability of approximately 5,810 megawatts. Our net equity interest
in the total production capability of those 26 facilities will be approximately
3,110 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 Energy" 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 Holdings' "project subsidiaries."
The unconsolidated affiliates of Holdings that are engaged in the ownership and
operation of electric generating facilities and in which we have less than a
majority interest are sometimes referred to individually as a "project
affiliate" or collectively as "project affiliates."
OUR STRATEGY
We intend to remain among the leaders in the independent power industry by
developing and constructing or acquiring - entirely or in part - electric
generating facilities in the United States.
We have targeted three market segments for our future development and
acquisition activities:
o Developing New Electric Generating Plants. We intend to pursue domestic
development of new, highly-efficient, low-cost plants, concentrating on
facilities that use natural gas as fuel. We expect these facilities to
enter into long-term contractual arrangements with fuel suppliers,
electric utilities or power marketers. These contractual arrangements
will provide us a scheduled and/or indexed payment for electricity and
result in the fuel supplier, electric utility or power marketer assuming
the risks associated with fuel and energy price fluctuations.
o Acquiring Interests in Existing Domestic Electric Generating Plants. We
intend to generally focus our future acquisition opportunities on
projects that 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
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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 that reduce or eliminate our exposure to
this risk by establishing future prices and quantities for the
electricity produced independent of the short-term market.
o 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.
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 geographic location of the facilities in which we have an ownership
interest;
o electric utility or power marketing customers for the electricity we
generate and the industrial customers for the steam we produce;
o technology we employ to generate electricity and produce steam; and
o coal, gas and other fuel suppliers to our plants.
INDUSTRY TRENDS CREATING MARKET OPPORTUNITIES
Increasing Competition in the Domestic Electric Generating Industry
In response to increasing customer demand for access to low-cost
electricity and enhanced services, new regulatory initiatives are currently
being adopted or considered at both state and federal levels to increase
competition in the domestic electric generating industry. We believe that these
regulatory initiatives may lead to the transformation of the existing regulated,
utility dominated market, that sells to a captive customer base and is based
upon cost-of-service pricing, to a more competitive market in which end users
may purchase electricity from a variety of suppliers, including non-utility
generators, power marketers, public utilities and others at competitive prices.
Our management believes that these market trends will create significant new
business opportunities for us because we have demonstrated our ability to
construct and operate efficient, low-cost electric generating facilities.
Growing Market for Sale of Electric Generating Assets
Regulatory initiatives to restructure the United States electric industry
have led to the development of a growing market for the sale of electric
generating assets principally by utilities, but also by independent power
producers and industrial companies. In addition to regulatory pressure, the
management of some utilities 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 fuel and energy prices.
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Expanded Options Resulting from Passage of the Energy Policy Act
The passage of the Energy Policy Act in 1992 significantly expanded the options
available to independent power producers, particularly with respect to siting a
generating facility. Among other things, the Energy Policy Act enables
independent power producers to obtain an order from the Federal Energy
Regulatory Commission requiring an intermediary utility to give access to its
transmission lines to transmit or "wheel" electric power from a generating
facility to its utility purchaser. The availability of wholesale transmission
"wheeling" could be an important aspect in the development of new projects. For
example, we may be able to develop a project in one utility's service territory
and "wheel" the electric power produced by the project through the transmission
lines of that utility to a second utility or another wholesale purchaser. The
Energy Policy Act also created a new class of generator - exempt wholesale
generators - that, unlike qualifying facilities, are not required to use
alternative or renewable fuels or to have useful thermal energy output. Finally,
the Energy Policy Act created another new class of utility-foreign utility
companies-which may own and operate foreign utility assets without U.S.
regulation consequences. See "Regulation - Energy Regulations" herein.
PROJECT AGREEMENTS, FINANCING AND OPERATING ARRANGEMENTS FOR OUR OPERATING
FACILITIES
Project Agreements
Our facilities have long-term power sales agreements to sell electricity to
electric utilities and power marketers. A facility's revenue from a power sales
agreement usually consists of two components: variable payments, which vary in
accordance with the amount of energy the facility produces, and fixed payments
that are received in the same amounts whether or not the facility is producing
energy. Variable payments, which are generally intended to cover the costs of
actually generating electricity, such as fuel costs, if supplied by the
operating facility, and variable operation and maintenance expense, are based on
a facility's net electrical output measured in kilowatt hours. Variable payment
rates are either scheduled or indexed to the fuel costs of the electricity
purchaser and/or an inflationary index.
Fixed payments, that 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.
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 of our facilities provide the electricity
purchaser with the right to reduce or suspend their purchases of electricity
whenever they determine that they can obtain lower cost power either by
generating power at their own plants or by purchasing electricity in bulk from
others. The power sales agreements for these facilities are structured in a
manner such that when the amount of electrical output is reduced, the facility
continues to receive the fixed payments, that cover fixed operating costs and
debt service requirements and provide substantially all of the project
subsidiary's profits. The variable payments, that cover the operating,
maintenance and fuel costs incurred by the project subsidiary to generate
electricity, are received only for each kilowatt hour delivered.
Many of our facilities produce process steam for use by an industrial
customer that has a manufacturing or other facility located nearby. Our
industrial customers, that 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.
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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 or project affiliate level that, except as noted below,
require the loans to be repaid solely from the project subsidiary's or project
affiliate's revenues. They also generally provide that the repayment of the
loans and payment of interest is secured solely by the physical assets,
agreements, cash flow and, in certain cases, the capital stock of or partnership
interests in that project subsidiary or project affiliate. This type of
financing is generally referred to as "project financing."
Project financing transactions are generally structured so that all
revenues of a project are deposited directly with a bank or other financial
institution acting as escrow or security deposit agent. These funds are then
payable in a specified order of priority to assure that, to the extent
available, they are used first to pay operating expenses, senior debt service
and taxes and to fund reserve accounts. Then, subject to satisfying debt service
coverage ratios and other conditions, any available funds may be disbursed to us
and our other partners in the case of jointly-owned facilities in the form of
management fees, dividends, or distributions.
Our facilities are financed using a high proportion of debt to equity. This
leveraged financing permits our project subsidiaries and project affiliates to
develop projects with a limited equity base but also increases the risk that a
reduction in revenues could adversely affect a particular project's ability to
meet its debt or lease obligations. The lenders to each project subsidiary or
project affiliate have security interests covering some or all of the aspects of
the project, including the facility, related facility support agreements, the
stock or partnership interest of our project subsidiaries or project affiliates,
licenses and permits necessary to operate the facility and the cash flow derived
from the facility. In the event of a foreclosure after a default, the project
subsidiary or project affiliate would only retain an interest in the property
remaining, if any, after all debts and obligations were paid.
In addition, the debt of each operating project may reduce the liquidity of
our interest in such project since any sale or transfer of its interest would,
in most cases, be subject both to a lien securing such project debt and to
transfer restrictions in the relevant financing agreements. Also, our ability to
transfer or sell our interest in some of our projects is restricted by purchase
options or rights of first refusal we have granted in favor of our power and
steam purchasers.
Because the project debt is "non-recourse", the lenders under these project
financing structures cannot look to Cogentrix Energy, Holdings or its other
projects for repayment unless Cogentrix Energy, Holdings or another project
subsidiary expressly agrees to undertake liability. Cogentrix Energy has agreed
to undertake limited financial support for certain of its project subsidiaries
in the form of limited obligations and contingent liabilities. These obligations
and contingent liabilities take the form of guarantees, indemnities, capital
infusions, support agreements and agreements to pay debt service deficiencies.
To the extent Cogentrix Energy becomes liable under such guarantees and other
agreements with respect to a particular project, distributions received by
Cogentrix Energy from other projects may be used to satisfy these obligations.
To the extent of these obligations, the lenders to a project may look to
Cogentrix Energy and the distributions it receives from other projects for
repayment. The aggregate contractual liability of Cogentrix Energy to its
project lenders is, in each case, a small portion of the aggregate project debt.
Thus, the project financing structures are generally described throughout this
report as being "non-recourse" to Cogentrix Energy, Holdings and its other
projects.
In addition, Cogentrix, Inc., an indirect subsidiary of Holdings, has
guaranteed two project subsidiaries' obligations to the purchasing utility under
three power sales agreements. Because these project subsidiaries' obligations do
not by their terms stipulate a maximum dollar amount of liability, the aggregate
amount of potential exposure under these guarantees cannot be quantified.
Although we believe it is unlikely that Cogentrix, Inc. will
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have to honor either of these guarantees, if we or our subsidiary were required
to satisfy all of these guarantees and other obligations at the same time, it
could have a material adverse effect on our financial condition and results of
operations.
Two of our wholly-owned subsidiaries, which were formed to hold our
interests in the electric generating facilities we acquired in 1999 and 1998,
maintain their own credit agreements with banks that provide in the aggregate
$92.5 million of revolving credit availability. Distributions received by these
subsidiaries from the project subsidiaries or project affiliates they own or
hold an interest in may be used by these subsidiaries to satisfy any outstanding
obligations under these revolving credit facilities.
Our facilities are insured in accordance with covenants in each project's
debt financing agreements. Coverages for each plant include workers'
compensation, commercial general liability, supplemented by primary and excess
umbrella liability, and a master property insurance program including property,
boiler and machinery and business interruption.
Operating Arrangements
We operate nine of our facilities. When we 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
operated during the periods indicated.
PERIOD AVERAGE AVAILABILITY
Year ended December 31, 2000 ........................94.9%
Year ended December 31, 1999 ........................95.6
Year ended December 31, 1998 ........................96.4
We provide, to the facilities we operate, administrative and management
services for a periodic fee, that in some cases is adjusted annually by an
inflation factor. The ability of a project subsidiary to pay these management
fees is contingent upon the continuing compliance by the project subsidiary with
covenants under its project financing agreements and may be subordinated to the
payment of obligations under those agreements. We have earned and will continue
to earn incentive compensation from our Hopewell facility, in which Holdings
holds a 50% general partnership interest and is, through a subsidiary, the
managing general partner, if the facility achieves the contractually specified
net income levels.
Ash Removal
Project subsidiaries owning seven of our coal-fired plants contract with
our subsidiary, ReUse Technology, Inc., to remove coal combustion by-products
generated by such facilities. ReUse constructs structural fills with these coal
combustion by-products on property owned by itself and others and provides coal
combustion by-products to others for use in manufacturing and producing various
products for resale.
FACILITIES UNDER CONSTRUCTION
We currently have three new "greenfield" electric generating facilities
under construction. A brief description of each of these facilities follows with
an estimate of the dates we expect them to commence commercial operations.
o Ouachita Parish, Louisiana Facility. In August 2000, we closed financing
and commenced construction on an 816-megawatt combined-cycle, natural
gas-fired electric generating facility near Sterlington, Louisiana.
Dynegy Power Marketing, Inc. will deliver natural gas to and purchase
electricity produced by this facility
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under a 15-year power purchase agreement. Subsequent to December 31,
2000, we sold a 50% interest in the facility to an indirect subsidiary
of General Electric Capital Corporation. We continue to own a 50%
interest in the facility and will operate and manage it when it
commences commercial operations in mid-2002.
o Rathdrum, Idaho Facility. In March 2000, a partnership, in which we own
a 51% interest, closed financing and commenced construction on a
270-megawatt combined-cycle, natural gas-fired electric generating
facility in Rathdrum, Idaho. Avista Turbine Power, Inc. will deliver
natural gas to and purchase electricity produced by this facility under
a 25-year power purchase agreement. This facility, which we will operate
and manage, is scheduled to commence commercial operations in late 2001.
o Jenks, Oklahoma Facility. In December 1999, we closed financing and
commenced construction on a wholly-owned 810-megawatt combined-cycle,
natural gas-fired electric generating facility in Jenks, Oklahoma. PECO
Energy's Power Team will deliver natural gas to and purchase electricity
produced by this facility under a 20-year 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, 2000, two
regulated utility customers accounted for approximately 60% 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.
OUR
OUR NET EQUITY
PERCENT INTEREST IN
PLANT OWNERSHIP PLANT POWER
FACILITY LOCATION FUEL MEGAWATTS INTEREST MEGAWATTS PURCHASING UTILITY
- -------- -------- ---- --------- --------- ----------- ------------------
Richmond Richmond, VA Coal 240 100.0 240.0 Virginia Power
Indiantown Martin County, FL Coal 380 50.0 190.0 Florida Power &
Light
Whitewater Whitewater, WI Natural Gas 245 74.2 181.8 Wisconsin Electric
Power Corporation
Cottage Grove Cottage Grove, MN Natural Gas 245 73.2 179.3 Northern States
Power Company
Birchwood King George, VA Coal 240 50.0 120.0 Virginia Power
Portsmouth Portsmouth, VA Coal 120 100.0 120.0 Virginia Power
Rocky Mount Rocky Mount, NC Coal 120 100.0 120.0 Virginia Power
Southport Southport, NC Coal 120 100.0 120.0 CP&L*
Logan Logan Township, NJ Coal 218 50.0 109.0 Atlantic City
Electric
Hopewell Hopewell, VA Coal 120 50.0 60.0 Virginia Power
Roxboro Roxboro, NC Coal 60 100.0 60.0 CP&L*
Northampton Northampton County, Waste coal 110 50.0 55.0 Metropolitan Edison
PA
Cedar Bay Jacksonville, FL Coal 260 16.0 41.6 Florida Power &
Light
Kenansville Kenansville, NC Coal 35 100.0 35.0 CP&L*
Carneys Point Carneys Point, NJ Coal 262 10.0 26.2 Atlantic City
Electric
Selkirk Albany, NY Natural Gas 396 5.1 20.2 Consolidated Edison
& Niagara Mohawk
Pittsfield Pittsfield, MA Natural Gas 173 10.9 18.9 New England Power
Scrubgrass Scrubgrass Township, PA Waste coal 85 20.0 17.0 Pennsylvania
Electric
Gilberton Frackville, PA Waste coal 82 19.6 16.1 Pennsylvania Power
& Light
Panther Creek Carbon County, PA Waste coal 83 12.2 10.1 Metropolitan Edison
Morgantown Morgantown, WV Coal/Waste 62 15.0 9.3 Monongahela Power
coal
Mass Power Springfield, MA Natural Gas 258 1.6 4.1 Boston Edison
----- -------
Totals 3,914 1,753.6
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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
Richmond, Virginia Facility
Our 240-megawatt stoker coal-fired cogeneration plant in Richmond, Virginia
provides 209 megawatts of declared production capability to Virginia Power under
two 25-year power sales agreements expiring in 2017. Our Richmond facility also
provides steam to E. I. DuPont de Nemours & Company.
Each of the power sales agreements provides that in the event the state
utilities commission prohibits Virginia Power from recovering from its customers
payments made by Virginia Power to our project subsidiary, our subsidiary would
recognize a reduction in payments received under such power sales agreements
after the 18th anniversary of commencement of commercial operations of the
facility to the extent necessary to repay the amount of the disallowed payments
to Virginia Power with interest.
If the number of days in any year in which the Richmond facility is unable
to generate electricity in an amount equal to its declared production capability
is more than the greater of 25 days or ten percent of the total number of days
the facility was required by Virginia Power to operate, the fixed payments under
the contract for that period will be reduced by four percent for each excess
day. In the event testing indicates that the facility's dependable production
capability is less than 90% of the declared production capability, our
subsidiary will be obligated to pay annual liquidated damages to Virginia Power.
Our project subsidiary has posted letters of credit in favor of Virginia Power
to secure its obligations to perform under the power sales agreements.
Indiantown, Florida Facility
A Delaware limited partnership owns this 380-megawatt pulverized coal-fired
cogeneration facility located in Martin County, Florida. An indirect,
wholly-owned subsidiary of PG&E National Energy Group, Inc. ("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 that
expires in 2025. Fixed payments by Florida Power & Light are subject to
adjustment on the basis of the Indiantown facility's actual production
capability.
Currently, Florida Power & Light is permitted full recovery from its
customers of payments made under the power sales agreement. The power sales
agreement contains a provision that provides if Florida Power & Light at any
time is denied authorization to recover from its customers any payments to be
made under the power sales agreement, Florida Power & Light may, in its sole
discretion, adjust payments under the power sales agreement to the amount it is
authorized to recover from its customers. The utility may also require the
partnership that owns the facility to return payments subsequently disallowed by
the regulatory agency. If the obligations of Florida Power & Light and the
partnership that owns the facility are materially altered due to the operation
of this provision in the agreement, the partnership may terminate the power
sales agreement upon 60 days' notice. The partnership and Florida Power & Light
must then, in good faith, attempt to negotiate a new power sales agreement or
any agreement for transmission of the Indiantown facility's capacity and energy
to another investor-owned, municipal, or cooperative electric utility
interconnected with Florida Power & Light in Florida.
An affiliate of PG&E provides operation and maintenance services for the
Indiantown facility pursuant to an operating agreement that expires in 2025.
PG&E manages and administers the business of the partnership that owns the
facility pursuant to a management service agreement that expires in 2029.
Whitewater, Wisconsin Facility
Our Whitewater facility is a 245-megawatt combined-cycle, natural gas-fired
cogeneration facility in Whitewater, Wisconsin. One of our wholly-owned indirect
subsidiaries is the sole general partner of the general partnership that owns
the facility with a 1% general partnership interest. Another wholly-owned
indirect subsidiary
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of ours owns an approximate 73.2% limited partnership interest. An affiliate of
Tomen Power Corporation owns the remaining approximate 25.8% limited partnership
interest.
The Whitewater facility provides approximately 236.5 megawatts of declared
production capability to Wisconsin Electric Power Corporation under a power
sales agreement that expires in 2022. The Whitewater facility may also sell to
third parties up to 12 megawatts of electric production capability and any
energy that the utility does not dispatch. Fixed payments from the utility are
subject to adjustment on the basis of performance-based factors that reflect the
Whitewater facility's semiannually tested production capability and average and
on-peak availability for the preceding contract year.
The fixed payments from the utility may be reduced to the extent that the
utility's senior debt is downgraded by any two of Standard & Poor's Corporation,
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.
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 that expires in 2027. Fixed payments are subject
to adjustment on the basis
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of performance-based factors that reflect the Cottage Grove facility's
semiannually tested production capability and its rolling 12-month average and
on-peak availability. Fixed payments are also adjusted for transmission losses
or gains relative to a reference plant. The Cottage Grove facility, also sells
steam to Minnesota Mining and Manufacturing Company.
Currently, Northern States Power 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.
Birchwood, Virginia Facility
Through an indirect, wholly-owned subsidiary we have a 50% interest in a
partnership that owns a 240-megawatt pulverized coal-fired cogeneration facility
in King George, Virginia. A subsidiary of 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 a subsidiary
of The Southern Company, uses steam from the facility. An affiliate of The
Southern Company manages and operates the Birchwood facility.
The Birchwood facility provides 218 megawatts of declared production
capability to Virginia Power measured at summer conditions and 222 megawatts of
declared production capability measured at winter conditions under a power sales
agreement that expires in 2021. The power sales agreement provides that in the
event the state utilities commission prohibits Virginia Power from recovering
from its customers payments made by Virginia Power to our project affiliate, the
partnership that owns the facility would recognize a reduction in payments
received under the power sales agreement after the 20th anniversary of
commencement of commercial operations of the facility to the extent necessary to
repay the amount of the disallowed payments to Virginia Power with interest.
During June 2000, the Birchwood facility signed a separate agreement with
Virginia Power to sell up to 20 megawatts of supplemental capacity and energy,
with an initial term expiring in 2003.
If this facility is unable to operate within the parameters established by
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.
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 that expires in June 2008. The Portsmouth facility also sells process
steam to BASF Corporation and Celanese Chemical, Inc.
If the power sales agreement for this facility is terminated prior to the
end of its initial or any subsequent term, other than due to a default by
Virginia Power, then our project subsidiary must pay a penalty to Virginia
Power. The
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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 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 the projected reduction in cash flows from 2009 through 2013 as a result
of the disallowance of payments made by the utility, or
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 liquidated damages to North Carolina Power. A letter of credit has been
posted by our project subsidiary in favor of North Carolina Power to secure its
obligations to perform under the power sales agreement.
Roxboro and Southport, North Carolina Facilities
Our subsidiary, Cogentrix of North Carolina, Inc., operates two stoker
coal-fired cogeneration plants in Roxboro and Southport, North Carolina, that
are owned by another wholly-owned project subsidiary of Holdings.
The Roxboro and Southport facilities sell electricity under separate power
sales agreements with CP&L, 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
ArcherDaniels-Midland Company purchases steam for its pharmaceutical and
chemical manufacturing company from the Southport facility.
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Each of the power sales agreements provide that in the event our project
subsidiary desires to terminate the power sales agreement or abandons the
Roxboro or Southport facility, our project subsidiary must pay the utility a
termination charge. Such termination charge will be equal to the sum of the
following:
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 that would have been made to our project subsidiary for the
Roxboro or Southport facility, and
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.
Logan, New Jersey Facility
A Delaware limited partnership owns the Logan facility, a 218-megawatt
pulverized coal-fired cogeneration plant located on the Delaware River in Logan
Township, New Jersey. The partnership leases the Logan facility to another
Delaware limited partnership. Our indirect, wholly-owned subsidiary, owns a 50%
general partnership interest in each of the first limited partnership and each
of the partners of the second limited partnership. PG&E is the sole limited
partner in each of the first partnership and the partners of the second limited
partnership, owning a 1% limited partnership interest. The PG&E subsidiary also
owns a 49% general partnership interest in each of the first partnership and
each of the partners of the second limited partnership.
The Logan facility, which began operation in September 1994, provides up to
203 megawatts of declared production capability to Atlantic City Electric
Company under a power sales agreement that expires in 2024. The Logan facility
has the capability to provide up to approximately 15 megawatts of excess
production capability and energy to third parties. The Logan facility sells
steam to Solutia, Inc.
If the net deliverable production capability of the Logan facility falls
below 190,000 kilowatts, then the partnership that owns the facility must pay
liquidated damages to the utility in an amount calculated using a formula that
reflects both the amount of the deficiency and the rate those mid-Atlantic
electric utilities who are members of a mid-Atlantic regional power pool and
fail to satisfy their capacity obligations to the pool must pay to the other
members to make up the deficiency.
An affiliate of PG&E provides operation and maintenance services for the
Logan facility pursuant to an operation and maintenance agreement with an
initial term expiring in 2004. PG&E provides management services pursuant to a
management services agreement that expires in 2027.
Hopewell, Virginia Facility
Our facility, located in Hopewell, Virginia, is a 120-megawatt stoker
coal-fired cogeneration facility owned and operated by a general partnership, in
which a 50% general partnership interest is owned by one of our subsidiaries.
The remaining 50% partnership interest is owned by Capistrano Cogeneration
Company, a subsidiary of Edison Mission Energy.
The Hopewell facility provides declared production capability of up to 92.5
megawatts to Virginia Power under a power sales agreement that expires in
January 2008. If the power sales agreement is terminated prior to the end of its
initial or any subsequent term other than due to a default by 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. Honeywell International, formerly
known as Allied-Signal Corporation, purchases steam from the Hopewell facility.
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Northampton, Pennsylvania Facility
A Delaware limited partnership owns this 110-megawatt anthracite waste
coal-fired electric generating facility in Northampton County, Pennsylvania. Our
indirect, wholly-owned subsidiary 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 owning this project, that 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 that 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 (that 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 3.40 cents per kWh. After the eleventh year of the
power sales agreement, the penalty payment will be calculated as above, except
that the rate of 3.40 cents per kWh shall be adjusted annually according to
changes in the Gross Domestic Product Implicit Price Deflator.
An affiliate of PG&E provides operation and maintenance services for the
Northampton facility pursuant to an operation and maintenance agreement with an
initial term expiring in 2020. PG&E provides management and administration
services for the Northampton facility pursuant to a management services
agreement with an initial term expiring in 2020.
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 Energy provides letters of credit
for 50% of those standby equity commitments.
Cedar Bay, Florida Facility
A Delaware limited partnership owns this 260-megawatt coal-fired
cogeneration facility located in Jacksonville, Florida. An indirect subsidiary
of PG&E owns an approximate 62% general partnership interest and an approximate
2% limited interest in the partnership, and we own an approximate 16% general
partnership interest. The remaining approximate 20% general partnership interest
is owned by a group of equity companies consisting mainly of bank and financial
institutions. The Cedar Bay facility began operation in January 1994, and sells
steam to Stone Container Corporation.
The Cedar Bay facility provides an annual average of 250 megawatts of
production capability to Florida Power & Light under a power sales agreement
that expires in 2024. Fixed payments by Florida Power & Light are subject to
adjustment on the basis of the Cedar Bay facility's actual production
capability.
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Currently, Florida Power & Light is permitted full recovery from its
customers of payments made under the power sales agreement. The power sales
agreement contains a provision that provides if Florida Power & Light at any
time is denied authorization to recover from its customers any payments to be
made under the power sales agreement, Florida Power & Light may, in its sole
discretion, adjust payments under the power sales agreement to the amount it is
authorized to recover from its customers. The utility may also require the
partnership that owns the facility to return payments subsequently disallowed by
the regulatory agency. If the obligations of Florida Power & Light and the
partnership that owns the facility are materially altered due to the operation
of this provision in the agreement, the partnership may terminate the power
sales agreement upon 60 days' notice. The partnership and Florida Power & Light
must then, in good faith, attempt to negotiate a new power sales agreement or
any agreement for transmission of the Cedar Bay facility's capacity and energy
to another investor-owned, municipal, or cooperative electric utility
interconnected with Florida Power & Light in Florida.
An affiliate of PG&E provides operation and maintenance services for the
Cedar Bay facility pursuant to an operating agreement that expires in 2024. PG&E
manages and administers the business of the partnership that owns the facility
pursuant to a management service agreement that also expires in 2024.
Kenansville, North Carolina Facility
Our subsidiary, Cogentrix Eastern Carolina, LLC, owns and operates a 35-megawatt
stoker coal-fired cogeneration plant in Kenansville, North Carolina. The
Kenansville facility provides declared production capability of up to
approximately 33 megawatts to CP&L under a power sales agreement with an initial
term expiring in September 2001. Another subsidiary, Cogentrix, Inc., has
guaranteed the performance of the Kenansville facility under the power sales
agreement. Guilford Mills, Inc. purchases steam from the Kenansville facility
for use in its textile manufacturing plant.
The power sales agreement provides that in the event of a termination prior
to the expiration of the initial term of the power sales agreement, 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.
Carneys Point, New Jersey Facility
A Delaware limited partnership owns this 262-megawatt pulverized coal-fired
cogeneration facility located within the grounds of the DuPont Chamber Works, a
chemical complex in Carneys Point, New Jersey. The partnership leases the
Carneys Point facility to a partnership of wholly-owned subsidiaries of PG&E.
Lease payments are structured to equal project cash flow, and the lessee
partnership derives no net cash flow or benefit from the lease. We own a 10%
general partnership interest in the limited partnership that owns the facility.
The other general partner is an indirect, wholly-owned subsidiary of PG&E, that
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
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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 provides operation and maintenance services for the
Carneys Point facility under an operation and maintenance agreement with an
initial term expiring in 2004. PG&E provides management services for the
facility pursuant to a management services agreement with a term expiring in
2018.
PRINCIPAL CUSTOMERS
Electric utility customers accounting for more than ten percent of our
consolidated revenue for the fiscal years ended December 31, 2000, 1999 and 1998
were as follows:
YEAR ENDED DECEMBER 31,
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2000 1999 1998
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CP&L 16% 17% 19%
Virginia Power 44 46 50
As a result of our acquisitions and our projects currently under
construction, our operations are now and will be even more diverse in the future
with regard to both geography and fuel source and less dependent on any single
project or customer.
REGULATION
Our facilities are subject to federal, state and local energy and
environmental laws and regulations applicable to the development, ownership and
operation of electric generating facilities. Federal laws and regulations govern
transactions, as well as types of fuel utilized, the type of energy produced and
power plant ownership for some plants. State regulatory commissions may approve
the rates and, in some instances, other terms under which utilities purchase
electricity from independent producers. These state commissions may have broad
jurisdiction over non-utility owned power plants. Power plants also are subject
to laws and regulations governing environmental emissions and other substances
produced by a plant, along with the geographical location, zoning, land use and
operation of a plant. Applicable federal environmental laws typically have state
and local enforcement and implementation provisions. These environmental laws
and regulations generally require that a wide variety of permits and other
approvals be obtained before construction or operation of a power plant
commences and that the power plant operates in compliance with them. We strive
to comply with all environmental laws, regulations, permits and licenses but,
despite such efforts, at times we have been in non-compliance.
Energy Regulations
QFs under the Public Utility Regulatory Policies Act of 1978. Most 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.
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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
nondiscriminatory basis. Avoided costs are the incremental costs to a utility of
electric energy or capacity, or both, that, but for the purchase from QFs, the
utility would generate for itself or purchase from another source. Due to
increasing competition for utility contracts, the current practice is for most
power sales agreements to be awarded below avoided cost.
We endeavor to minimize the risk of our facilities losing their QF status.
The occurrence of events outside our control, such as loss of a steam customer,
could jeopardize QF status. While the facilities usually would be able to react
in a manner to avoid the loss of QF status by, for example, replacing the steam
customer or finding another use for the steam that meets PURPA's requirements,
there is no certainty that the alternative implemented would be practicable or
economic.
If one of our facilities were to lose its status as a QF, the subsidiary
may lose its exemptions from PUHCA and the FPA and from state laws and
regulations. This could subject the subsidiary to regulation under the FPA and
may result in 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 non-qualifying 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 non-qualifying 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 without prior condition. 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 that 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, transmission and distribution assets, would permit
"single state" utility systems to expand beyond their state borders, and would
permit companies that are currently in registered holding company systems to
diversify their investments to a greater extent than now permitted. This could
attract more competitors to the power development and power marketing business.
We believe that we are well positioned, however, to meet stronger competition
and, indeed, may be able to pursue more investment opportunities made available
by the repeal of PUHCA.
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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, that 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 or in construction have also filed and
obtained from FERC market-based rates for sales of power from these facilities.
State Regulation. PUCs regulate retail rates of electric utilities. 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 may be subject to broad regulation by PUCs, ranging from the
requirement of certificates of public convenience and necessity to regulation of
organizational, accounting, financial and other corporate matters. In addition,
states may assert jurisdiction over the siting and construction of EWGs (as well
as QFs) and over the issuance of securities and the sale or other transfer of
assets by these facilities. 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. An opening of the retail market would create tremendous
opportunities for companies that have until now been limited to the wholesale
market. At the same time, state commissions are pressuring the utilities they
regulate to cut purchased power costs through strict enforcement of existing
contracts with QFs, many of which are considered to be overpriced. State
commissions are also encouraging efforts by utilities to buy out or buy down
such contracts.
Proposed Legislation - 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 generally 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 OFs and EWGs was significantly expanded by the Energy
Policy Act. The new provisions of the Energy Policy Act and actions taken by the
FERC under the FPA have improved transmission access and pricing for independent
power producers like us.
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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. FERC has also
mandated that utilities with open access transmission tariffs provide
interconnection service to generators as a separate component of transmission
service.
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 and may eliminate the assessment of multiple rates (i.e., parcel
rates) to wheel power through a region.
Environmental Regulations - United States
The following discussion includes forward-looking statements relating to
environmental protection compliance measures and the possible future impact on
us of increasingly stringent environmental regulations. This information
reflects current estimates that we periodically evaluate and revise. Our
estimates are subject to a number of assumptions and uncertainties, including
future Federal and state energy and environmental policy, other changing laws
and regulations, the ultimate outcome of complex factual investigations, changes
in emission control technology, and selection of compliance alternatives.
The construction and operation of power projects are subject to extensive
environmental protection and land use regulation in the United States. Those
regulations applicable to 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 is implemented, new
laws are enacted and existing regulations are re-evaluated. Accordingly, we plan
to continue a strong emphasis on implementation of environmental controls and
procedures to minimize the environmental impact of energy generation at our
facilities.
Clean Air Act and the 1990 Amendments. In late 1990, Congress passed the
Clean Air Act Amendments of 1990 (the "1990 Amendments") that affect existing
facilities - including facilities exempt from regulation under the Clean Air Act
of 1970 - as well as new project development. All of the facilities we operate
are currently in compliance with federal performance standards mandated for such
facilities under the Clean Air Act and the 1990 Amendments.
The 1990 Amendments create a marketable commodity called a sulfur dioxide
("SO2") "allowance." All non-exempt facilities over 25 megawatts that emit SO2
including independent power plants, must obtain allowances in order to operate
after 2000. Each allowance gives the owner the right to emit one ton of SO2. The
1990 Amendments exempt from the SO2 allowance provisions all independent power
projects that were operating, under construction or with power sales agreements
or letters of intent as of November 15, 1990, as well as facilities outside the
contiguous 48 states. As a result, most of the facilities we operate are exempt.
The non-exempt facilities we operate have determined their need for allowances
and have accounted for these requirements in their operating budgets and
financial forecasts. Most of the facilities we have developed in recent years
and expect to develop in the future rely on natural gas technology. The
additional costs of obtaining the number of allowances needed for our future
projects should not materially affect our ability to develop new projects.
The 1990 Amendments also contain other provisions that could affect our
projects. Provisions dealing with geographical areas the EPA has designated as
being in "nonattainment" with national ambient air quality standards require
that each new or expanded source of air pollutants in nonattainment areas must
obtain emissions reductions from existing sources that more than offset the
emissions from the new or expanded source. While the "offset" requirements may
hamper new project development in certain geographical areas, development of new
projects has continued, and management expects will likely continue,
particularly as markets for "offsets" develop.
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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. The costs of
applying for and maintaining operating air permits are not anticipated to be
significant.
The 1990 Amendments also regulate certain hazardous air pollutant ("HAP")
emissions. Although the HAP provisions of the 1990 Amendments exclude electric
steam generating facilities, they direct the EPA to prepare a study on HAP
emissions from power plants. The EPA has conducted agreed studies and is
expected to regulate mercury emissions from power plants on or before December
15, 2004. If it is determined that mercury emissions from power plants should be
regulated, the use of "maximum achievable control technology" could be required,
which could require additional control equipment on some or all of our
facilities.
The EPA continues to conduct an industry-wide investigation of coal-fired
electric power generators to determine compliance with environmental
requirements under the Clean Air Act associated with repairs, maintenance,
modifications and operational changes made to the facilities over the years. The
EPA's focus is on whether any of the changes made were subject to new source
review or new performance standards, and whether best available control
technology was or should have been used. Holdings has not received any notices
of violation from the EPA relating to any of its facilities as a result of this
industry-wide investigation. The Portsmouth Plant has received and responded to
a Section 114 Request from EPA Region III to "provide information reasonably
required for the purpose of determining whether that person is in violation of,
among other things, any requirements of the State Implementation Plan (SIP), New
Source Performance Standards (NSPS) and Review of New Sources and modifications
(NSR)." The EPA conducted its site visit to the Portsmouth Plant on March 7,
2001. Management believes that Holdings would have a meritorious defense to any
action brought by the EPA relating to any of its facilities.
EPA Initiatives. In July 1997, the EPA promulgated more restrictive ambient
air quality standards for ozone and for particulate matter. These new standards
were affirmed by the Supreme Court in February 2001 and when finally promulgated
by the EPA will likely increase the number of nonattainment areas for both ozone
and particulate matter. If our facilities are in these new nonattainment areas,
further emission reduction requirements, which states will be required to adopt,
could require us to install additional control technology for oxides of nitrogen
("NOx") emissions and other ozone precursors.
In October 1998, the EPA issued a final rule addressing the regional
transport of ground-level ozone across state boundaries to the eastern United
States through NOx emissions reduction. The rule focuses on such reductions in
the eastern United States, requiring 22 states and the District of Columbia to
submit revised "state implementation plans" (SIPs) by September 1999 and have
NOx emission controls in place by May 2003 (the " NOx SIP call"). In March 2000,
a federal appeals court upheld the NOx SIP call rule. In March 2001, the
Supreme Court declined to hear an appeal of this ruling.
In a related action, the EPA in December 1999 granted petitions of four
northeastern states seeking to reduce transport of ozone across state boundaries
by requiring reductions in NOx emissions from sources in 30 states and the
District of Columbia. As a result, 392 facilities, including those operated by
our project subsidiaries in North Carolina and Virginia, will have to reduce NOx
emissions or take other steps to meet these NOx emission reduction requirements.
These facilities must implement controls or use emission allowances to achieve
required NOx emission reductions by May 2003.
We are evaluating the NOx emission reductions that these EPA initiatives
and state regulations will require us to meet. We expect we will need to install
additional or new control equipment and continuous emissions monitoring
equipment at several of the facilities operated by our project subsidiaries in
North Carolina and Virginia. The costs of the additional equipment should not be
material to the operations of these facilities. In addition to installing new
control equipment, we may need, or decide to purchase NOx "allowances".
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The 1990 Amendments expand the enforcement authority of the federal
government by increasing the range of civil and criminal penalties for
violations of the Clean Air Act, enhancing administrative civil penalties, and
adding a citizen suit provision. These enforcement provisions also include
enhanced monitoring, recordkeeping and reporting requirements for existing and
new facilities. On February 13, 1997, the EPA issued a regulation providing for
the use of "any credible evidence or information" in lieu of, or in addition to,
the test methods prescribed by regulation to determine the compliance status of
permitted sources of air pollution. This rule may effectively make emission
limits previously established for many air pollution sources, including the
Facilities, more stringent.
The Kyoto Protocol. In 1998, the Kyoto Protocol regarding greenhouse gas
emissions and global warming was signed by the U.S., committing to reductions in
greenhouse gas emissions of at least 7% below 1990 levels to be achieved by 2008
- - 2012. The U.S. Senate must ratify the agreement for the protocol to take
effect. In March 2001, the EPA announced that the United States would not be
implementing the Kyoto Protocol in its present form. 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 that can be used to modify a permit
at anytime, and the states are required to establish total maximum daily load
limits for water bodies that are impaired. Several of the facilities we operate
have either recently gone through permit renewal or will be renewed within the
next few years. Based upon recent renewals, we do not anticipate significantly
more stringent monitoring or treatment requirements for any of the facilities we
operate. We believe that the plants we operate are in material compliance with
applicable discharge requirements under the Clean Water Act.
Emergency Planning and Community Right-to-Know Act. In April of 1997, the
EPA expanded the list of industry groups required to report the Toxic Release
Inventory under Section 313 of the Emergency Planning and Community
Right-to-Know Act to include electric utilities. Our operating facilities are
required to complete a toxic chemical inventory release form for each listed
toxic chemical manufactured, processed or otherwise used in excess of threshold
levels. The purpose of this requirement is to inform the EPA, states, localities
and the public about releases of toxic chemicals to the air, water and land that
can pose a threat to the community.
Comprehensive Environmental Response, Compensation, and Liability Act. The
Comprehensive Environmental Response, Compensation, and Liability Act of 1980,
as amended ("CERCLA" or "Superfund"), requires cleanup of sites from which there
has been a release or threatened release of hazardous substances and authorized
the EPA to take any necessary response action at Superfund sites, including
ordering potentially responsible parties ("PRPs") liable for the release to take
action or pay for such actions by others. PRPs are broadly defined under CERCLA
to include past and present owners and operators of sites, as well as generators
of wastes sent to a site. At present, we are not subject to liability for any
Superfund matters and take measures to assure that CERCLA will not apply to
properties we own or lease. However, we do generate certain wastes in the
operation of our plants, including small amounts of hazardous wastes, and send
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, 2000, we employed 422 people, none of whom is covered
by a collective bargaining agreement.
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ITEM 2. PROPERTIES
In addition to our properties listed and described in the section
entitled "Business--Facilities in Operation," we lease office space in
Wilmington, Delaware. The lease has an initial term expiring in September 2001
with automatic one-year renewals thereafter.
We also lease office space in Prince George, Virginia.
We believe that our facilities and properties have been satisfactorily
maintained, are in good condition, and are suitable for our operations.
ITEM 3. LEGAL PROCEEDINGS
Claims and Litigation
One of our indirect, wholly-owned subsidiaries is party to certain
product liability claims related to the sale of coal combustion by-products for
use in various construction projects. Management cannot currently estimate the
range of possible loss, if any, we will ultimately bear as a result of these
claims. However, our management believes - based on its knowledge of the facts
and legal theories applicable to these claims, after consultations with various
counsel retained to represent the subsidiary in the defense of such claims, and
considering all claims resolved to date - that the ultimate resolution of these
claims should not have a material adverse effect on our consolidated financial
position or results of operations.
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 Holdings are beneficially owned by Cogentrix
Energy.
(c) Dividends--Our project subsidiaries and project affiliates have
generated sufficient cash flow for the years ended December 31,
2000, 1999 and 1998 to service their debt and allow us to pay
$153,071,000, $141,873,000 and $97,604,000, respectively, in
dividends to Cogentrix Energy.
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ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA
The following table sets forth certain selected consolidated financial
data as of and for the five years ended December 31, 2000, which should be read
in conjunction with our consolidated financial statements and related notes
thereto and with "Management's Discussion and Analysis of Financial Condition
and Results of Operations." The selected consolidated financial data as of and
for each of the four years in the period ended December 31, 2000 set forth below
has been derived from our audited consolidated financial statements. The
information for the year ended December 31, 1996 has been derived from our
unaudited consolidated financial statements. In the opinion of management, the
unaudited consolidated financial statements have been prepared on the same basis
as the audited consolidated financial statements and include all adjustments,
consisting of normal recurring adjustments, necessary for a fair presentation of
the consolidated financial position and consolidated results of operations for
these periods. The unaudited consolidated results of operations are not
necessarily indicative of the consolidated results of operations for any other
period or for any year as a whole.
YEARS ENDED DECEMBER 31,
-------------------------------------------------------------------------
2000 1999 1998 1997 1996
--------- --------- --------- --------- ---------
(UNAUDITED)
(DOLLARS IN THOUSANDS)
STATEMENT OF OPERATIONS DATA:
Total operating revenues $ 535,122 $ 452,434 $ 409,693 $ 347,903 $ 388,364
Operating expenses:
Operating costs 283,461 222,730 210,590 210,580 239,572
General and administrative 786 1,502 515 2,005 4,667
Depreciation and amortization 48,238 41,583 40,988 40,429 36,801
Loss on impairment and cost
of removal of cogeneration
facilities -- -- -- -- 65,628
--------- --------- --------- --------- ---------
Total operating expenses 332,485 265,815 252,093 253,014 346,668
--------- --------- --------- --------- ---------
Operating income 202,637 186,619 157,600 94,889 41,696
Other income (expense):
Interest expense (72,846) (63,255) (61,802) (44,849) (49,340)
Other, net (10,837) (2,229) (5,738) 3,378 (2,984)
--------- --------- --------- --------- ---------
Income (loss) before income taxes
and extraordinary loss 118,954 121,135 90,060 53,418 (10,628)
Benefit (provision) for income
taxes (45,581) (48,829) (35,844) (20,031) 3,804
--------- --------- --------- --------- ---------
Income (loss) before
extraordinary loss 73,373 72,306 54,216 33,387 (6,824)
Extraordinary loss on early
extinguishment of debt, net -- -- (743) (1,502) (703)
--------- --------- --------- --------- ---------
Net income (loss) $ 73,373 $ 72,306 $ 53,473 $ 31,885 $ (7,527)
========= ========= ========= ========= =========
AS OF DECEMBER 31,
--------------------------------------------------------------------------
2000 1999 1998 1997 1996
---------- ---------- ---------- ---------- ----------
BALANCE SHEET DATA:
Total assets $2,129,912 $1,629,566 $1,516,943 $ 846,963 $ 853,926
Project financing debt (1) 1,241,188 945,383 877,653 567,705 620,886
Total shareholders' equity 452,368 390,415 373,034 118,894 152,270
(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 "non-recourse," see
"Business--Project Agreements, Financing and Operating Arrangements for
Our Operating Facilities--Project Financing" herein.
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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
Holdings 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
Termination of Five of our Power Sales Agreements
The power sales agreements at two of our project subsidiaries
terminated in the year ended December 31, 2000. The power sales agreements at
three of our other project subsidiaries will terminate in years 2001 through
2002 and the power sales agreements at two of our other project subsidiaries
provide for a significant reduction in fixed payments received under such
agreements after 2002. Accordingly, revenues recognized by us under these power
sales agreements have and will be eliminated or significantly reduced. Our
management believes, however, that our remaining project subsidiaries and
project affiliates will generate sufficient cash flow to allow them to pay
management fees and dividends to Holdings periodically in sufficient amounts to
allow Holdings to pay dividends to Cogentrix Energy and to meet its other
obligations.
Legislative Proposals to Restructure the Electric Generating Industry
The domestic electric generating industry is currently going through a
period of significant change as many states are implementing or considering
regulatory initiatives designed to increase competition. 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.
Acquisitions, Development and Other Changes in our Portfolio of Generating
Plants
Our growth has substantially increased our electric production
capability. The acquisition of ownership interests in the Cottage Grove and
Whitewater facilities in March 1998, 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.
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RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31,
-------------------------------------------------------------------------------------------
2000 1999 1998
------------------------- ------------------------- -------------------------
Total operating revenues $535,122 100% $452,434 100% $409,693 100%
Operating expenses 283,461 53 222,730 49 210,590 51
General and administrative
786 -- 1,502 -- 515 --
Depreciation and amortization 48,238 9 41,583 9 40,988 10
-------- -------- --------
Operating income $202,637 38% $186,619 41% $157,600 38%
======== ======== ========
YEAR ENDED DECEMBER 31, 2000 AS COMPARED TO YEAR ENDED DECEMBER 31, 1999
Operating Revenues
Total operating revenues increased 18.3% to $535.1 million for the year
ended December 31, 2000 as compared to $452.4 million for the year ended
December 31, 1999 as a result of the following:
(0) Electric revenue increased approximately $38.6 million as a result of
the initial recognition of electric revenue generated from the
Batesville facility, which commenced commercial operation in August
2000 (see Significant Events below), and an increase in megawatt hours
sold to the purchasing utilities at most of our electric generating
facilities. The increase in electric revenue was partially offset by a
decrease in electric revenue at three of our facilities as the result
of the termination or sale of their power purchase agreements during
2000.
(0) Service revenue increased approximately $19.4 million as a result of an
increase in the variable energy rate charged to the purchasing
utilities at our Cottage Grove and Whitewater facilities. The increase
in the variable energy rate was a direct result of an overall increase
in natural gas prices during the year. The increase in service revenue
was partially offset by a decrease in megawatt hours sold to the
purchasing utility at these facilities.
(0) Income from unconsolidated investments in power projects increased
approximately $18.5 million primarily as a result of increased megawatt
hours sold to the purchasing utility at the Logan and Northampton
facilities. The increase was also a result of recognizing a full year's
income in 2000 on our 50% interest in the Indiantown facility. To a
lesser extent, the increase was a result of a reduction of major
overhaul expenses at four project affiliates.
Operating Expenses
Total operating expenses increased 27.3% to $283.5 million for the year
ended December 31, 2000 as compared to $222.7 million for the year ended
December 31, 1999 as a result of the following:
(0) Fuel expense increased approximately $32.7 million as a result of an
increase in megawatt hours sold to the purchasing utilities at most of
our project subsidiaries. The increase was partially offset by a
decrease in fuel expense at our Ringgold facility as a result of the
sale of the power purchase agreement.
(0) Operations and maintenance costs increased $10.8 million primarily as a
result of the commencement of commercial operations at the Batesville
facility in August 2000. To a lesser extent, the increase was also a
result of planned maintenance costs incurred at several of our electric
generating facilities during 2000.
(0) Cost of services increased $17.2 million as a result of an increase in
fuel costs at our Cottage Grove and Whitewater facilities. The increase
in fuel costs resulted from an overall increase in natural gas prices
during the year.
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(0) Depreciation and amortization increased approximately $6.7 million
primarily from the commencement of commercial operations of the
Batesville facility.
Interest Expense
Interest expense increased 15.0% to $72.8 million for the year ended
December 31, 2000 as compared to $63.3 million for the year ended December 31,
1999. The increase in interest expense is primarily related to incremental
interest expense from the inclusion of long-term debt from the Batesville
facility which began commercial operations in August 2000 and additional
borrowings of approximately $25.2 million at our Richmond facility in June 2000.
The increase in interest expense was offset by a reduction in interest expense
at several of our project subsidiaries due to scheduled repayments and
retirements of outstanding project financing debt.
Other Expense, Net
Other expense, net, increased primarily as a result of a charge to
reduce the carrying value of a note receivable to its estimated net realizable
value, as a result of uncertainties with respect to collectibility.
YEAR ENDED DECEMBER 31, 1999 AS COMPARED TO YEAR ENDED DECEMBER 31, 1998
Operating Revenues
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 as a result of the following:
(0) Lease and service revenue increased $19.4 million as a result of
recognizing a full year's income from the power sales agreements for
the Cottage Grove and Whitewater facilities, interests we acquired in
March 1998.
(0) Income from unconsolidated investments in power projects increased
$19.0 million as a result of recognizing a full year's income from
interests in 12 electric generating facilities we acquired in October
1998. The increase was also impacted by the purchase of an additional
40% interest in the Indiantown facility during 1999.
Operating Expenses
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 as a result of the following:
(0) Cost of services increased $10.2 million as a result of
recognizing a full year's expenses from the power sales agreements for
the Cottage Grove and Whitewater facilities, interests we acquired in
March 1998.
(0) Fuel expense increased $3.4 million as a result of an overall
increase in megawatt hours sold to the purchasing utilities at our
project subsidiaries, 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.
(0) The increase in total operating expenses was partially offset by a
$4.6 million decrease in operation and maintenance expenses due to
routine maintenance expenses incurred at several of our facilities
during the year ended December 31, 1998.
Interest Expense
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
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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 project 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.
Minority Interest
The increase in minority interest in income for the year ended December
31, 1999, as compared to the year ended December 31, 1998, related to the
inclusion of a full twelve months of operations for the Cottage Grove and
Whitewater facilities in the year ended December 31, 1999, as compared to only
nine months in the year ended December 31, 1998, and the settlement of the
construction contract on the Whitewater and Cottage Grove facilities.
LIQUIDITY AND CAPITAL RESOURCES
Consolidated Information
The primary components of cash flows from operations for the year ended
December 31, 2000, were as follows (dollars in millions):
(0) Net income $73.4
(0) Depreciation and amortization 48.2
(0) Deferred income taxes 34.9
(0) Equity in net income of unconsolidated affiliates,
net of dividends (9.0)
Total cash flows from operations of $189.0, proceeds from borrowings of $436.5,
capital contributions from Parent of $141.7 and funds released from escrow of
$16.3 were used primarily to (dollars in millions):
(0) Purchase property, plant and equipment and
construction in progress $361.3
(0) Invest in unconsolidated subsidiaries 1.7
(0) Repay project financing borrowings 140.6
(0) Pay deferred financing costs 11.6
(0) Pay dividends to Parent 153.1
Holdings has guaranteed all of Cogentrix Energy's existing and future
senior unsecured debt for borrowed money. This guarantee was given to the
lenders under Cogentrix Energy's corporate credit facility and terminates,
unless extended, in October 2003. At December 31, 2000, Cogentrix Energy had
$455.0 million of senior notes due 2004 and 2008 and had no borrowings
outstanding under the corporate credit facility
As of December 31, 2000, we had long-term debt (including the current
portion thereof) of approximately $1.2 billion. All such indebtedness is project
financing debt, the majority of which is non-recourse to Holdings. The project
financing debt generally requires 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. Future annual maturities of
long-term debt range from $30.0 million to $124.7 million in the five-year
period ending December 31, 2005. We believe that our project subsidiaries and
project affiliates will generate sufficient cash flow to pay all required debt
service on their project financing debt and to allow them to pay management
fees, dividends or distributions to Holdings periodically in sufficient amounts
to allow Holdings to meet its other obligations including paying dividends to
Cogentrix Energy.
The ability of our project subsidiaries and project affiliates to pay
dividends, distributions and management fees periodically to Holdings or
Cogentrix Energy is subject to certain limitations in our respective financing
documents. Such limitations generally require that: (1) debt service payments be
current, (2) debt service coverage ratios be met, (3) all debt service and other
reserve accounts be funded at required levels and (4) there be no default
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or event of default under the relevant financing documents. There are also
additional limitations that are adapted to the particular characteristics of
each project subsidiary and project affiliate.
Credit Facilities
Two of our wholly-owned subsidiaries, Cogentrix Eastern America, Inc.
and Cogentrix Mid-America, Inc. ("Mid-America"), formed to hold interests in
electric generating facilities acquired in 1999 and 1998, maintain credit
agreements with banks to provide for $67.5 million and $25.0 million of
revolving credit, respectively. Both credit facilities provide for credit in the
form of direct advances, and the Mid-America facility provides for issuances of
letters of credit. Including the credit facilities described above, and the
revolving credit facility at one of our project subsidiaries, we maintain
revolving credit that is non-recourse to Holdings, with aggregate commitments of
$135.3 million. As of December 31, 2000, we had approximately $33.5 million
available under these facilities. The aggregate commitments on these facilities
will decrease to $105.4 million by December 31, 2001.
Facilities Under Construction
We currently have three "greenfield" electric generating facilities
under construction. The construction of each facility is being funded under each
project subsidiary's separate financing agreements and equity contribution
commitments by Cogentrix Energy and/or our partners. The equity contribution
commitments for the Rathdrum and Jenks facilities are supported by letters of
credit provided under Cogentrix Energy's corporate credit facility. The equity
commitments will be contributed upon the earliest to occur of (1) an event of
default under the project subsidiary's financing agreements, (2) the incurrence
of construction costs after all project financing has been expended, or (3) the
mandatory equity contribution date. Summarized information regarding each of the
facilities under construction follows (dollars in millions):
OUACHITA, RATHDRUM, JENKS,
LOUISIANA(A) IDAHO OKLAHOMA
------------ ---------- -------------
OWNERSHIP PERCENTAGE 50% 51% 100%
FINANCIAL CLOSE DATE August 2000 March 2000 December 1999
PROJECT FUNDING:
Total Project Financing Commitment $460.0 $126.0 $350.0
Total Project Equity Commitment 61.6 32.7 48.7
------ ------ ------
$521.6 $158.7 $398.7
====== ====== ======
HOLDINGS EQUITY COMMITMENT:
Total Commitment $ 5.3 $ 16.7 $ 48.7
Contributions through December 31, 2000 - - -
------ ------ ------
Remaining Commitment $ 5.3 $ 16.7 $ 48.7
====== ====== ======
Mandatory Equity Contribution Date June 2002 December 2002 June 2002
(a) See additional discussion under Other Significant Events
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.
Other Significant Events
On September 1, 2000, we received approximately $18.0 million related
to the utility customer's buy back of our Ringgold, Pennsylvania facility's
power purchase agreement. A portion of the proceeds was used to retire the
entire amount of the Ringgold facility's outstanding debt. In conjunction with
this buyback, we discontinued operation of the facility.
29
30
During January 2001, our wholly-owned subsidiary sold a 50% membership
interest in our Ouachita Parish, Louisiana facility currently under
construction. In exchange, we received $48.3 million in cash and were relieved
of our original equity commitment up to approximately $56.3 million that was
previously supported by a letter of credit under Cogentrix Energy's corporate
credit facility. We will continue to own 50% of this facility and we will
operate the facility upon commercial operations.
During March 2001, we sold our 51.37% interest in the Batesville
facility to NRG Energy, Inc. for $64.0 million in cash. In connection with the
sale, we also assigned our responsibility for the operation and maintenance of
the Batesville facility from us to NRG Energy, Inc.
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.
We protect against the risk of changes in the market price for electricity by
entering into contracts with fuel suppliers, utilities or power marketers that
reduce or eliminate our exposure to this risk by establishing future prices and
quantities for the electricity produced independent of the short-term market.
Through various hedging mechanisms, we have attempted to mitigate the impact of
changes on the results of operations of most of our projects. The hedging
mechanism against increased fuel and transportation costs for most of our
currently operating facilities 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 the power sales agreements for certain of our facilities, 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.
Most of our facilities currently under construction have tolling
arrangements in place to minimize the impact of fluctuating fuel prices. Under
these tolling arrangements, each customer is typically obligated to supply and
pay for fuel necessary to generate the electrical output expected to be
dispatched by the customer.
Changes in interest rates could have a significant impact on our
results of operations because they 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 or caps on a portion of our
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.
30
31
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, 2000. 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, 2000.
Future interest rates are likely to vary from those disclosed in the table.
EXPECTED MATURITY DATE
----------------------------------------------------------------------------------------
2001 2002 2003 2004 2005 THEREAFTER TOTAL
------- ------- ------- ------- ------- ---------- ----------
(DOLLARS IN THOUSANDS)
LONG-TERM DEBT
Fixed Rate $15,064 $70,229 $12,472 $14,934 $19,724 $380,734 $ 513,157
Weighted average
interest rate 7.59% 7.72% 7.42% 7.40% 7.40% 7.80%
Variable Rate $34,419 $54,480 $17,503 $20,776 $22,626 $558,869 708,673
----------
Weighted average
interest rate 7.68% 7.68% 7.68% 7.68% 7.68% 7.92%
$1,221,830
==========
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, 2000, was $125,967,981. 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 7.88% to a
weighted average effective rate of 7.28% at December 31, 2000.
FIXED RATE PAY/VARIABLE RATE RECEIVE INTEREST RATE SWAPS
HEDGED
NOTIONAL EFFECTIVE MATURITY FIXED RATE VARIABLE RATE FAIR MARKET
AMOUNT DATE DATE PAY RECEIVE (1) VALUE
-------- ----- ----- ------ ------------ ----------
$34,000,000 2/12/98 12/31/02 5.688% 6.680% $ 75,265
58,639,000 4/28/00 1/31/06 6.078 6.885 (395,637)
2,328,981 1/15/98 3/07/01 5.585 6.680 6,355
----------
$(314,017)
==========
INTEREST RATE CAPS
HEDGED
NOTIONAL EFFECTIVE MATURITY MAXIMUM ACTUAL FAIR MARKET
AMOUNT DATE DATE INTEREST RATE INTEREST RATE(1) VALUE
-------- --------- -------- ------------- ---------------- -----------
$31,000,000 7/31/00 7/31/02 9.00% 6.88% $478
====
(1) The "variable rate receive" and "actual interest rate" are based on
the interest rates in effect as of December 31, 2000. Interest rates
in the future are likely to vary from those disclosed in the tables
above.
31
32
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX
PAGE
----
Report of Independent Public Accountants....................................... 33
Consolidated Financial Statements:
Consolidated Balance Sheets at December 31, 2000 and 1999................... 34
Consolidated Statements of Income For the Years Ended December 31, 2000,
1999 and 1998............................................................ 35
Consolidated Statements of Changes in Shareholders' Equity For the Years
Ended December 31, 2000, 1999 and 1998................................... 36
Consolidated Statements of Cash Flows For the Years Ended
December 31, 2000, 1999 and 1998......................................... 37
Notes to Consolidated Financial Statements..................................... 38
Financial Statement Schedules:
Schedule I - Condensed Financial Information of the Registrant................. 54
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
33
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, 2000 and 1999, and the related consolidated
statements of income, changes in shareholders' equity and cash flows for each of
the three years in the period ended December 31, 2000. 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, 2000 and 1999 and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2000, 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, 2001 (except
with respect to the matter discussed in the
second paragraph of Note 14 as to which the date
is March 30, 2001).
33
34
COGENTRIX DELAWARE HOLDINGS, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2000 AND 1999
(dollars in thousands)
ASSETS 2000 1999
----------- -----------
CURRENT ASSETS:
Cash and cash equivalents $ 100,506 $ 44,709
Restricted cash 4,469 20,812
Accounts receivable 66,399 60,669
Inventories 15,050 20,137
Net assets held for sale 52,258 --
Other current assets 2,289 1,079
----------- -----------
Total current assets 240,971 147,406
NET INVESTMENT IN LEASES 499,774 500,195
PROPERTY, PLANT AND EQUIPMENT, net of
accumulated depreciation of $297,789 and $259,710, respectively 398,144 435,681
LAND AND IMPROVEMENTS 7,053 5,757
CONSTRUCTION IN PROGRESS 483,927 50,555
DEFERRED FINANCING COSTS, net of
accumulated amortization of $18,687 and $16,904, respectively 34,483 33,225
INVESTMENTS IN UNCONSOLIDATED AFFILIATES 346,794 325,504
PROJECT DEVELOPMENT COSTS 2,326 1,763
NOTE RECEIVABLE FROM PARENT 82,822 76,410
OTHER ASSETS 33,618 53,070
----------- -----------
$ 2,129,912 $ 1,629,566
=========== ===========
LIABILITIES AND SHAREHOLDER'S EQUITY
CURRENT LIABILITIES:
Current portion of long-term debt $ 49,483 $ 90,114
Accounts payable 45,996 34,105
Payable to Parent 63,466 10,365
Other accrued liabilities 83,806 34,242
----------- -----------
Total current liabilities 242,751 168,826
LONG-TERM DEBT 1,191,705 855,269
DEFERRED INCOME TAXES 164,128 129,193
MINORITY INTEREST 74,365 70,563
OTHER LONG-TERM LIABILITIES 4,595 15,300
----------- -----------
1,677,544 1,239,151
----------- -----------
COMMITMENTS AND CONTINGENCIES
SHAREHOLDER'S EQUITY:
Common stock, no par value, 1000 shares authorized,
issued and outstanding; 1 1
Additional paid-in capital from Parent 752,117 610,458
Accumulated other comprehensive loss (1,152) (1,144)
Accumulated deficit (298,598) (218,900)
----------- -----------
452,368 390,415
----------- -----------
$ 2,129,912 $ 1,629,566
=========== ===========
The accompanying notes to consolidated financial statements are an integral part
of these consolidated balance sheets.
34
35
COGENTRIX OF DELAWARE HOLDINGS, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
(dollars in thousands, except share and earnings per common share amounts)
2000 1999 1998
--------- --------- ---------
OPERATING REVENUES:
Electric $ 332,751 $ 294,185 $ 293,083
Steam 28,671 25,236 25,043
Lease 44,759 44,697 34,715
Service 63,238 43,888 34,470
Income from unconsolidated investment in power projects,
net of premium amortization 43,987 25,464 6,474
Other 21,716 18,964 15,908
--------- --------- ---------
535,122 452,434 409,693
--------- --------- ---------
OPERATING EXPENSES:
Fuel expense 114,540 81,835 78,420
Cost of service 64,462 47,226 37,018
Operations and maintenance 104,459 93,669 95,152
General and administrative 786 1,502 515
Depreciation and amortization 48,238 41,583 40,988
--------- --------- ---------
332,485 265,815 252,093
--------- --------- ---------
OPERATING INCOME 202,637 186,619 157,600
OTHER INCOME (EXPENSE):
Interest expense (72,846) (63,255) (61,802)
Investment and other income 1,741 12,523 9,687
Equity in net loss of affiliates, net -- -- (2,967)
--------- --------- ---------
INCOME BEFORE MINORITY INTEREST IN INCOME,
INCOME TAXES AND EXTRAORDINARY LOSS 131,532 135,887 102,518
MINORITY INTEREST IN INCOME (12,578) (14,752) (12,458)
--------- --------- ---------
INCOME BEFORE INCOME TAXES
AND EXTRAORDINARY LOSS 118,954 121,135 90,060
PROVISION FOR INCOME TAXES (45,581) (48,829) (35,844)
--------- --------- ---------
INCOME BEFORE EXTRAORDINARY LOSS 73,373 72,306 54,216
EXTRAORDINARY LOSS ON EARLY EXTINGUISHMENT
OF DEBT, NET OF INCOME TAX BENEFIT
AND MINORITY INTEREST -- -- (743)
--------- --------- ---------
NET INCOME $ 73,373 $ 72,306 $ 53,473
========= ========= =========
EARNINGS PER COMMON SHARE:
Income before extraordinary loss $ 73,373 $ 72,306 $ 54,216
Extraordinary loss -- -- (743)
--------- --------- ---------
$ 73,373 $ 72,306 $ 53,473
========= ========= =========
WEIGHT AVERAGE COMMON SHARES OUTSTANDING 1,000 1,000 1,000
========= ========= =========
The accompanying notes to consolidated financial statements are an integral part
of these consolidated statements.
35
36
COGENTRIX DELAWARE HOLDINGS, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
(dollars in thousands)
ADDITIONAL ACCUMULATED
PAID-IN OTHER
COMMON CAPITAL COMPREHENSIVE ACCUMULATED COMPREHENSIVE
STOCK FROM PARENT INCOME DEFICIT INCOME (LOSS) TOTAL
---------- ----------- ------------- ----------- ------------- -----------
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
Comprehensive income
Net income 73,373 73,373
Other comprehensive income,
net of tax:
Unrealized holding losses
during year (8) (8)
---------
Comprehensive income $ 73,365 73,365
=========
Capital contributions - 141,659 - - 141,659
Dividends paid to
Cogentrix Energy, Inc. - - (153,071) - (153,071)
------- ------- --------- ------- --------
BALANCE, December 31, 2000 $ 1 $752,117 $(298,598) $ (1,152) $452,368
======= ======== ========== ========= ========
The accompanying notes to consolidated financial statements are an integral part
of these consolidated statements.
36
37
COGENTRIX DELAWARE HOLDINGS, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
(dollars in thousands)
2000 1999 1998
--------- --------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 73,373 $ 72,306 $ 53,473
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization 42,450 41,583 40,988
Deferred income taxes 34,943 38,496 11,083
Extraordinary loss on early extinguishment of debt -- -- 2,145
Minority interest in income of joint venture, net of dividends 3,781 8,461 (14,494)
Equity in net income of unconsolidated affiliates (40,001) (22,998) (3,738)
Dividends received from unconsolidated affiliates 31,037 26,647 13,669
Minimum lease payments received 45,180 43,116 31,500
Amortization of unearned lease income (44,759) (44,697) (33,473)
Decrease (increase) in accounts receivable (5,730) 3,968 (6,805)
Decrease (increase) in inventories 5,087 117 (1,029)
Increase in accounts payable 11,891 6,339 209
Increase (decrease) in accrued liabilities 41,699 (25,377) 4,294
Decrease (increase) in other, net (9,915) (4,627) 8,260
--------- --------- ---------
Net cash flows provided by operating activities 189,036 143,334 106,082
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property, plant and equipment additions (3,117) (3,754) (5,176)
Construction in progress and project development costs (358,148) (59,321) --
Investments in unconsolidated affiliates (1,675) (76,827) (180,292)
Net additional investment in net assets held for sale (53,271) 782 231
Acquisition of facilities, net of cash acquired -- -- (155,324)
Decrease in marketable securities -- -- 42,118
Decrease in restricted cash 16,343 12,441 27,771
--------- --------- ---------
Net cash used in investing activities (399,868) (126,679) (270,672)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds of notes payable and long-term debt 436,542 191,339 100,400
Repayments of notes payable and long-term debt (140,455) (122,255) (143,812)
Increase in note receivable from Parent, net (6,412) (19,062) (21,239)
Capital contribution from Parent 141,659 88,077 298,312
Increase in deferred financing costs (11,634) (1,199) (1,645)
Common stock dividends paid to Parent (153,071) (141,873) (97,604)
--------- --------- ---------
Net cash flows provided by (used in)
financing activities 266,629 (4,973) 134,412
--------- --------- ---------
NET INCREASE (DECREASE) IN CASH
AND CASH EQUIVALENTS 55,797 11,682 (30,178)
CASH AND CASH EQUIVALENTS, beginning of year 44,709 33,027 63,205
--------- --------- ---------
CASH AND CASH EQUIVALENTS, end of year $ 100,506 $ 44,709 $ 33,027
========= ========= =========
The accompanying notes to consolidated financial statements are an integral part
of these consolidated statements.
37
38
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 2003. As of December 31, 2000, the
Parent had $455 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, 2001.
Principles of Consolidation and Basis of Presentation - The
accompanying consolidated financial statements include the accounts of Holdings
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 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
Holdings, its subsidiary companies and its consolidated joint ventures have been
eliminated in the accompanying consolidated financial statements.
Cash and Cash Equivalents - Cash and cash equivalents include bank
deposits, commercial paper, government securities and certificates of deposit
that mature within three months of their purchase. Amounts in debt service
accounts which might otherwise be considered cash equivalents are treated as
current restricted cash.
Inventories - Coal inventories consist of the contract purchase price
of coal and all transportation costs incurred to deliver the coal to each
Facility. Gas inventories represent the cost of natural gas purchased as fuel
reserves that are forecasted to be consumed during the next fiscal year. Spare
parts inventories consist of major equipment and recurring maintenance supplies
required to be maintained in order to facilitate routine maintenance activities
and minimize unscheduled maintenance outages. As of December 31, 2000 and 1999,
fuel and spare parts inventories are comprised of the following (dollars in
thousands):
38
39
DECEMBER 31,
-----------------------
2000 1999
------- -------
Coal $ 5,152 $ 8,469
Natural gas 1,687 2,875
Fuel oil 917 655
Spare parts 7,294 8,138
------- -------
$15,050 $20,137
======= =======
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 $181,000 and $374,000 less than the
cost of these inventories on a FIFO basis as of December 31, 2000 and 1999,
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 15 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 years ended December 31, 2000 and 1999, the Company capitalized
$18,321,000 and $262,000, respectively, of interest in connection with the
development and construction of power plants. There was no interest capitalized
in 1998.
Deferred Financing Costs - Financing costs, consisting primarily of
commitment fees, legal and other direct costs incurred to obtain financing, are
deferred and amortized over the expected financing term.
Investments in Unconsolidated 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 revenue in the
accompanying consolidated statements of income. The Company's share of income or
loss from investments previously held in entities which own and operate
greenhouses, is included in other income (expense) in the accompanying
consolidated statements of income.
Project Development Costs - The Company capitalizes project development
costs once it is determined that it is probable that such costs will be realized
through the ultimate construction of a power plant. These costs include
professional services, salaries, permits and other costs directly related to the
development of a new project. These costs are generally transferred to
construction in progress when financing is obtained, or expensed when the
Company determines that a particular project will no longer be developed.
Capitalized costs are amortized over the estimated useful life of the project.
Revenue Recognition - Revenues from the sale of electricity and steam
are recorded based upon output delivered and capacity provided at rates
specified under contract terms. Significant portions of the Company's revenues
have been derived from certain electric utility customers. Two customers
accounted for 46% and 16% of revenues in the year ended December 31, 2000, 47%
and 17% of revenues in the year ended December 31, 1999 and 50% and 19% of
revenues in the year ended December 31, 1998.
39
40
Interest Rate Protection Agreements - The Company enters into interest
rate protection agreements with major financial institutions to fix or limit the
volatility of interest rates on its long-term debt. The differential paid or
received is recognized as an adjustment to interest expense. Any premiums
associated with interest rate protection agreements are capitalized and
amortized to interest expense over the effective term of the agreement.
Unamortized premiums are included in other assets in the accompanying
consolidated balance sheets.
Income Taxes - Deferred income tax assets and liabilities are
recognized for the estimated future income tax effects of temporary differences
between the tax bases of assets and liabilities and their reported amounts in
the financial statements. Deferred tax assets are also established for the
estimated future effect of net operating loss and tax credit carryforwards when
it is more likely than not that such assets will be realized. Deferred taxes are
calculated based on provisions of the enacted tax law.
Use of Estimates - The preparation of financial statements in
conformity with generally accepted accounting principles requires management to
make estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
Start-Up Activities - Start-up activities, including initial activities
related to opening a new facility, initiating a new process in an existing
facility and activities related to organizing a new entity (commonly referred to
as organization costs), are expensed as incurred.
New Accounting Pronouncements - In June 1998, the Financial Accounting
Standards Board ("FASB") issued Statement of Financial Accounting Standards
("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging
Activities." In June 2000, the FASB issued SFAS No. 138, "Accounting for Certain
Derivative Instruments and Certain Hedging Activities, an amendment of SFAS No.
133." SFAS No. 133, as amended, established accounting and reporting standards
requiring that every derivative instrument (including certain derivative
instruments embedded in other contracts) be recorded in the balance sheet as
either an asset or liability measured at its fair value. SFAS No. 133 requires
that changes in the derivative instrument's fair value be recognized currently
in earnings unless specific hedge accounting criteria are met. Special
accounting for qualifying hedges allows a derivative instrument's gains and
losses to offset related results on the hedged item in the income statement, to
the extent effective, and requires that a company must formally document,
designate, and assess the effectiveness of transactions that receive hedge
accounting.
In June 1999, the FASB issued Statement No. 137, "Accounting for
Derivative Instruments and Hedging Activities - Deferral of the Effective Date
of FASB Statement No. 133." SFAS No. 137 requires the adoption of SFAS No. 133,
as amended, to be effective for fiscal years beginning after June 15, 2000. The
Company will adopt SFAS No. 133 on January 1, 2001.
The Company has identified all financial instruments that meet the
definition of a derivative under SFAS No. 133, as amended. The Company has
determined that certain interest rate protection agreements qualify for cash
flow hedge treatment under SFAS No. 133. The Company identified various other
financial instruments and contracts that did not meet the definition of a
derivative under SFAS No. 133 or were excluded from the accounting treatment of
SFAS No. 133 as a result of qualifying for the normal purchases and sales
exception. The Company has determined that the adoption of SFAS No. 133 will not
have a material impact on the consolidated financial statements.
Reclassifications - Certain amounts included in the accompanying
consolidated financial statements for the fiscal year ended December 31, 1999
and 1998 have been reclassified from their original presentation to conform with
the presentation for the year ended December 31, 2000.
3. ACQUISITIONS
LS Power Acquisition - In March 1998, the Company acquired from LS
Power Corporation an approximate 74% ownership interest in two partnerships (the
"LS Power Acquisition") 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 that sells capacity and energy under power sales contracts that expire
in 2027 and 2022,
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respectively. 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
SFAS No. 13, "Accounting for Leases" (see Note 8).
The aggregate purchase price, including acquisition costs, for the LS
Power Acquisition was approximately $158.0 million and was funded with a portion
of the net proceeds of the Parent's 2008 senior notes issued in 1998 (see Note
10) and corporate cash balances. The LS Power Acquisition has been accounted for
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,
2000 and 1999, and is being amortized on a straight line basis over the lives of
the power purchase agreements for the two facilities. The accompanying
consolidated statement of income for the year ended December 31, 1998 includes
the results of operations of the acquired facilities since the acquisition date.
Batesville Acquisition - In August 1998, the Company acquired an
approximate 52% interest in an 837-megawatt, gas-fired electric generating
facility (the "Batesville Facility") that was under construction in Batesville,
Mississippi (the "Batesville Acquisition"). During 2000, the Company made an
equity contribution to the project subsidiary of $54.0 million, which
represented the original consideration for the Batesville Acquisition. The
Batesville Facility commenced commercial operation in August 2000 and sells
electricity under two separate power purchase agreements with an
investment-grade utility and a power marketer that have initial terms of 13 and
16 years, respectively.
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 reassessed
its ownership, and determined that it would maintain an approximate 51% interest
in the project. As such, the Company consolidated the Batesville Facility in the
accompanying consolidated financial statements beginning on December 31, 1999.
The accompanying consolidated statements of income for the years ended December
31, 1999 and 1998 recognized earnings from the Batesville facility under the
equity method of accounting. Subsequent to December 31, 2000, the Company sold
its entire interest in the Batesville facility (see Notes 6 and 14).
Bechtel Asset Acquisitions - 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, was approximately $189.7 million. The Company utilized a portion of the
net proceeds from the 1998 issuance of the Parent's 2008 senior notes to fund
the BGCI Acquisition (see Note 10).
The BGCI Acquisition resulted in the recognition of a net purchase
premium of approximately $66.5 million. The purchase premiums and 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 nine of these facilities and uses the cost method of accounting for
its ownership interests in the other three facilities (see Note 4).
During 1999, the Company purchased an additional 40% ownership interest
in the Indiantown facility, one of the twelve electric generating facilities
included in the BGCI Acquisition. The aggregate purchase price was approximately
$76.6 million and was acquired in a three-phase transaction. The purchase
resulted in a premium of approximately $38.0 million and is being amortized over
the remaining term of the power purchase agreement. The Company currently has a
50% interest in the Indiantown facility and the investment is accounted for
using the equity method of accounting.
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During 2000, the Company purchased additional 1% interests in the Logan
and Northampton facilities, two of the twelve electric generating facilities
included in the BGCI Acquisition. The Company paid approximately $1.7 million
for these additional interests. The Company will continue to account for its 50%
interest in the Logan and Northampton facilities using the equity method.
The following unaudited pro forma consolidated results for the Company
for the years ended December 31, 1999 and 1998 give effect to the LS Power
Acquisition and the BGCI Acquisitions as if these transactions had occurred on
January 1, 1999 and January 1, 1998, respectively (dollars in thousands, except
per share amount).
PRO FORMA FOR THE
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 220-megawatt, coal-fired
cogeneration facility (the "Birchwood Facility") which sells electricity to a
utility and provides thermal energy to a 36-acre greenhouse under long-term
contracts. The Birchwood Facility is operated by a subsidiary 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 $5,297,000, $3,509,000 and $3,714,000 in income from
unconsolidated investments in power projects, net of premium amortization, in
the accompanying consolidated statements of income for the years ended December
31, 2000, 1999 and 1998, respectively, related to its investment in Birchwood
Power. The following table presents summarized financial information for
Birchwood Power for the dates indicated (dollars in thousands):
DECEMBER 31,
------------------------
2000 1999
-------- --------
BALANCE SHEET DATA:
Current assets $ 50,793 $ 48,805
Noncurrent assets 324,201 333,318
-------- --------
Total assets $374,994 $382,123
======== ========
Current liabilities $ 11,823 $ 9,882
Noncurrent liabilities 316,543 323,598
Partners' capital 46,628 48,643
-------- --------
$374,994 $382,123
======== ========
FOR THE YEAR ENDED DECEMBER 31,
--------------------------------------------------------
2000 1999 1998
--------------- ---------------- ----------------
INCOME STATEMENT DATA:
Operating revenues $83,472 $75,582 $71,908
Operating income 40,864 36,399 36,863
Net income 13,873 9,740 9,747
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BGCI Assets
The Company recognized approximately $38,690,000, $21,954,000 and
$2,760,000 in income from unconsolidated investments in power projects in the
accompanying consolidated statements of income for the years ended December 31,
2000 and 1999 and for the period from October 20, 1998 to December 31, 1998,
respectively, related to its investment in the BGCI assets. Approximately
$34,704,000, $19,488,000 and $2,760,000 of these respective amounts relates to
the nine power projects accounted for under the equity method. The following
table presents the Company's ownership interests at December 31, 2000 in the
BGCI assets that are accounted for under the equity method:
NET EQUITY
PERCENT INTEREST
PLANT OWNERSHIP IN PLANT
PROJECT MEGAWATTS INTEREST MEGAWATTS
- ------- --------- --------- ----------
Indiantown 380 50.0% 190.0
Logan 218 50.0 109.0
Northampton 110 50.0 55.0
Cedar Bay 260 16.0 41.6
Carneys Point 262 10.0 26.2
Scrubgrass 85 20.0 17.0
Gilberton 82 19.6 16.1
Panther Creek 83 12.2 10.1
Morgantown 62 15.0 9.3
The following table presents summarized combined financial data of the
above BGCI projects accounted for under the equity method for the dates
indicated (dollars in thousands):
DECEMBER 31,
----------------------------
2000 1999
---------- ----------
BALANCE SHEET DATA:
Current assets $ 167,679 $ 157,396
Noncurrent assets 2,909,379 2,988,277
---------- ----------
Total assets $3,077,058 $3,145,673
========== ==========
Current liabilities $ 242,770 $ 205,667
Noncurrent liabilities 2,394,207 2,523,826
Partners' capital 440,081 416,180
---------- ----------
$3,077,058 $3,145,673
========== ==========
FOR THE YEAR ENDED DECEMBER 31, FOR THE PERIOD
-------------------------------------- OCTOBER 20, 1998 TO
2000 1999 DECEMBER 31, 1998
----------------- ----------------- -----------------------
INCOME STATEMENT DATA:
Operating revenues $706,002 $624,010 $96,622
Operating income 325,303 258,581 51,948
Net income 95,568 56,818 15,071
5. INVESTMENTS IN OTHER UNCONSOLIDATED AFFILIATES
The Company entered into an agreement to make investments in
partnerships which develop, construct and operate greenhouses which produce
tomatoes. Through December 1998, the Company owned a 50% interest in four
43
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limited partnerships which had a combined 107 acres of production capacity in
operation. While the Company owned this interest in the greenhouse partnerships,
the Company accounted for its investment in these partnerships under the equity
method, and recognized approximately $2,967,000 in equity in net loss of
affiliates in the accompanying consolidated statements of income for the year
ended December 31, 1998. In December 1998, the Company sold its 50% interest in
the partnerships to EcoScience Corporation ("EcoScience"). In return for its 50%
interest, the Company received 1,000,000 shares of common stock of EcoScience
and a note receivable. As of December 31, 2000, the Company's note receivable
from EcoScience totaled approximately $15,487,000. The Company has established
an allowance for credit losses related to the entire balance of the EcoScience
note receivable.
6. NET ASSETS HELD FOR SALE
During 2000, management formalized plans to dispose of its interest in the
Batesville facility. The assets and liabilities of this facility are included in
net assets held for sale and are summarized as follows:
December 31,
---------------------------
2000 1999
--------- ---------
Cash and cash equivalents $ 7,083 $ 205
Restricted cash 28,578 53,286
Other current assets 8,627 1,154
Property and equipment, net 333,567 296,509
Deferred financing charges, net 9,849 10,099
Other long-term assets 8,483 --
Current liabilities (17,929) (36,266)
Long-term debt (326,000) (326,000)
--------- ---------
Total net assets (liabilities) held for sale $ 52,258 $ (1,013)
========= =========
Subsequent to December 31, 2000, the Company sold the Batesville facility
(see Note 14) and the net assets held for sale are recorded in current assets in
the accompanying consolidated balance sheet at December 31, 2000. These net
liabilities held for sale at December 31, 1999 are included in other accrued
liabilities in the accompanying consolidated balance sheet.
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7. LONG-TERM DEBT
The following long-term debt was outstanding as of December 31, 2000
and 1999, respectively (dollars in thousands):
DECEMBER 31,
-------------------------------
2000 1999
----------- -----------
HOPEWELL FACILITY:
Note payable to banks $ 34,000 $ 51,000
PORTSMOUTH FACILITY:
Revolving credit facility with banks 20,889 41,649
ROCKY MOUNT FACILITY:
Note payable to financial institution 116,291 120,182
RICHMOND FACILITY:
Notes payable and tax-exempt bonds 181,193 171,848
COTTAGE GROVE AND WHITEWATER FACILITIES:
Bonds payable, due 2010 and 2016, including unamortized fair
market value adjustment related to purchase of facilities of
$19,359 and $20,386 349,037 352,386
JENKS FACILITY:
Note payable to banks 226,389 70,531
RATHDRUM FACILITY:
Notes payable to banks and financial institutions 91,585 --
OUACHITA FACILITY:
Notes payable to banks 154,618 --
RINGGOLD FACILITY:
Note payable to banks -- 10,995
ELIZABETHTOWN, LUMBERTON AND KENANSVILLE FACILITIES:
Notes payable to banks -- 6,824
ROXBORO AND SOUTHPORT FACILITIES:
Note payable to banks -- 52,608
CEA CREDIT FACILITY 66,400 66,400
OTHER 786 960
----------- -----------
Total long-term debt 1,241,188 945,383
Less: Current portion (49,483) (90,114)
----------- -----------
Long-term portion $ 1,191,705 $ 855,269
=========== ===========
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% (7.68% at December 31, 2000). The amended note
payable also provides for a $5.0 million letter of credit to secure the
project's obligation to pay debt service. The Parent has indemnified the
lenders of the note payable for any cash deficits the Hopewell Facility
could experience as a result of incurring certain costs, subject to a cap
of $10.6 million.
An extraordinary loss of $2,432,000 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 $743,000, net of a tax benefit
of approximately $473,000 and minority interest of $1,216,000, is shown in
the accompanying consolidated statements of income.
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PORTSMOUTH FACILITY:
The Portsmouth Facility's project debt consists of a credit facility
with a bank with available borrowings up to $42,840,000. As of December 31,
2000, the balance outstanding under the credit facility was approximately
$20,889,000. The banks' outstanding credit commitment under the loan
agreement is reduced quarterly through December 2002. Interest on the
revolving credit facility accrues at an annual rate equal to the applicable
LIBOR rate, as chosen by the Company, plus an additional margin of 1.0%
(7.68% at December 31, 2000) and is payable the earlier of the applicable
LIBOR term or quarterly. The loan agreement also provides for a $6.0
million letter of credit to secure the project's obligations to pay debt
service. Cogentrix Energy 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 $30.0 million. As
of December 31, 1999, the credit facility also included a term loan. The
entire balance of the term loan was repaid during 2000.
ROCKY MOUNT FACILITY:
The note payable to financial institution consists of a $116,291,000
senior loan which accrues interest at a fixed annual rate of 7.58%. Payment
of principal and interest is due quarterly through December 2013.
RICHMOND FACILITY:
The Richmond Facility's project debt includes $133,193,000 of notes
payable and $48,000,000 tax-exempt industrial development bonds (the
"Bonds"). The notes payable and Bonds are part of a credit facility with a
syndicate of banks that was amended during June 2000. The amended terms of
the credit facility increased outstanding borrowings by $25,181,000 and
extended the final maturity of the notes payable by five months to December
31, 2007. Interest on the notes payable accrues at an annual rate equal to
the applicable LIBOR rate, as chosen by the Company, plus 1.13% through
June 2003, 1.25% through June 2007, and 1.38% thereafter. Principal
payments on the notes payable are due quarterly with interest payable the
earlier of maturity of the applicable LIBOR term or quarterly through
December 2007.
The Bonds have been issued to support the purchase of certain pollution
control and solid waste disposal equipment for the Facility. Principal and
interest payments on the Bonds are supported by an irrevocable, direct-pay
letter of credit provided under the Loan Agreement. The amended credit
facility extended the irrevocable, direct-pay letter of credit of the Bonds
through March 2010. The annual interest rate is the yield on the Bonds plus
a 1.25% to 1.50% per annum fee (7.76% at December 31, 2000).
COTTAGE GROVE AND WHITEWATER FACILITIES:
The project debt, excluding the fair market value adjustment, of the
Cottage Grove and Whitewater Facilities consist of the following senior
secured bonds as of December 31, 2000 (dollars in thousands):
7.19% Senior Secured Bonds due June 30, 2010 $103,229
8.08% Senior Secured Bonds due December 30, 2016 226,449
--------
$329,678
========
Interest and principal is payable on these bonds semi-annually on June
30 and December 30 of each year. Principal payments commenced on June 30,
2000 for the 2010 Bonds and will commence on 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 $25.0 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 $25.0
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million commitment over the then debt service reserve requirement. As
of December 31, 2000, letters of credit totaling $14.5 million were
issued and outstanding under the credit agreement.
JENKS FACILITY:
The loan agreement for the Jenks facility consists of a note payable
with available borrowings up to $350.0 million. Proceeds of the borrowings
($226,389,000 as of December 31, 2000) are being used to construct an
800-megawatt, combined cycle, natural gas-fired generating facility.
Construction on the facility began in December 1999. The loan will convert
to a term loan, due December 2006, upon commencement of commercial
operations. The loan agreement provides for interest to accrue at an annual
rate equal to the applicable LIBOR rate, as chosen by the Company plus
1.25% to 1.50% per annum (7.90% at December 31, 2000). The loan facility
also provides for an $8.0 million letter of credit to secure the project's
obligation to pay debt service and a $28.5 million letter of credit to
secure the facility's obligations under its conversion services agreement.
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 $48.7 million upon the earliest to occur of (a)
an event of default under the project subsidiary's loan agreement, (b) the
incurrence of construction costs after the loan has been expended or (c)
June 24, 2002. This equity contribution commitment is supported by a letter
of credit, which is provided under the Parent's corporate credit facility.
RATHDRUM FACILITY:
The loan agreement for the Rathdrum facility consists of a credit
agreement with a bank, as agent for a group of lending banks, and a
financial institution, which provides up to $126.0 million in borrowings
and a $5.0 million debt service reserve letter of credit. Proceeds from the
borrowings ($91,585,000 as of December 31, 2000) are being used to
construct an approximate 270-megawatt, combined-cycle, natural gas-fired
generating facility located in Rathdrum, Idaho (the "Rathdrum Facility").
Construction on the facility began in March 2000. The credit agreement
provides borrowings up to $49.0 million from the financial institution and
$77.0 million from the banks. The financial institution loans accrue
interest at 8.56% per annum and have a term equal to the construction
period plus 25 years and the bank loans accrue interest at the applicable
LIBOR rate plus an applicable margin ranging from 1.25% to 2.25% (7.89% at
December 31, 2000) and will have a term equal to the construction period
plus periods up to 18 years.
In accordance with the terms of the project financing agreements, the
Company has committed to provide an equity contribution to the project
subsidiary of approximately $16.7 million upon the earliest to occur of (a)
an event of default under the project subsidiary's loan agreement, (b) the
incurrence of construction costs after the loans have been expended, or (c)
October 1, 2002. This equity contribution commitment is supported by a
letter of credit, which is provided under the Parent's corporate credit
facility.
OUACHITA FACILITY
The construction loan agreement for the Ouachita facility consists of a
credit agreement with a bank, as agent for several banks and other
financial institutions, which provides up to $460.0 million in borrowings,
a credit support letter of credit in the maximum amount of $30.0 million,
and a $10.0 million debt service reserve letter of credit. The proceeds of
the borrowing ($154,618,000 as of December 31, 2000) are being used to
construct an approximate 816-megawatt, combined-cycle, natural gas-fired
electric generating facility located near the city of Sterlington,
Louisiana (the "Ouachita Facility"). Construction on the facility began in
August 2000. The borrowings under the credit agreement accrue interest per
annum at an annual rate equal to the applicable LIBOR rate plus 1.25%
during the construction period. The construction loans convert to term
loans on the earliest to occur of (a) the commencement of commercial
operations, or (b) June 1, 2002. The term loans accrue interest per annum
at an annual rate equal to the applicable LIBOR rate plus 1.30% to 1.63%.
The term loans mature 5 years after the commencement of commercial
operations.
The Company had committed to provide an equity contribution to the
project subsidiary of approximately $61.6 million which was supported by a
letter of credit provided under the Parent's corporate credit facility.
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Subsequent to December 31, 2000, the Company sold a 50% interest in the
Ouachita Facility for approximately $48.3 million and was relieved of its
commitment to provide all but $5.3 million of the original equity
commitment (see Note 15).
RINGGOLD FACILITY:
The Company retired the entire amount of the Ringgold facility's
outstanding debt with a portion of the proceeds received from the sale of
the Ringgold facility's power purchase agreement during September 2000. The
sale 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 Pennsylvania Electric Company's territory in
April 1997. The Ringgold facility received approximately $18.0 million as
consideration for this sale and recorded other operating income of
approximately $1.3 million, net of transaction costs, related to this
termination.
ROXBORO AND SOUTHPORT FACILITIES:
The project debt agreement for the Roxboro and Southport facilities was
repaid in full with a portion of the proceeds from the Parent's issuance of
2008 Senior Notes during September 2000(see Note 10).
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 for the BGCI Acquisitions, entered into a $75.0 million,
three-year credit facility. The commitment under this facility was reduced
to $67.5 million in September 2000 and will reduce to $60.0 million in
September 2001. As of December 31, 2000, advances totaling $66.4 million
were outstanding under this facility. The credit facility accrues interest
at an annual rate equal to the applicable LIBOR plus 1.50%.
INTEREST RATE PROTECTION AGREEMENTS:
The Company has entered into interest rate cap and interest rate swap
agreements (see Note 13) 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, 2000 and 1999 were approximately
$125,968,000 and $263,279,000, 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 7.88% at December 31, 2000
to a weighted average effective rate of 7.28%. These agreements expire at
various dates through July 2006.
The project financing debt is substantially non-recourse to the Company
(as parent). The project financing agreements of the Company's subsidiaries
contain certain covenants which, among other things, place limitations on the
payment of dividends, limit additional indebtedness, and restrict the sale of
assets. The project financing agreements also require certain cash to be held
with a trustee as security for future debt service payments. In addition, the
Facilities, as well as the long-term contracts which support them, are pledged
as collateral for the Company's obligations under the project financing
agreements.
The ability of the 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.
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Future maturities of long-term debt at December 31, 2000, excluding the
unamortized fair market value adjustments are as follows (dollars in thousands):
YEAR ENDED
DECEMBER 31,
------------
2001.................................... $ 49,483
2002.................................... 124,709
2003.................................... 29,975
2004.................................... 35,710
2005.................................... 42,350
Thereafter.............................. 939,603
-----------
$1,221,830
===========
Cash paid for interest on the Company's long-term debt amounted to
$63,353,000, $61,032,000 and $66,899,000 for the years ended December 31, 2000,
1999 and 1998, respectively.
8. SALES TYPE CAPITAL LEASE
The power purchase agreements acquired by the Company as a result of
the LS Power Acquisition have characteristics similar to leases in that the
agreements confer to the purchasing utility the right to use specific property,
plant and equipment. At the commercial operations date, the partnerships
accounted for the power purchase agreements as "sales-type" capital leases in
accordance with SFAS No. 13, "Accounting for Leases".
The components of the net investment in the leases are as follows
(dollars in thousands):
DECEMBER 31,
-------------------------------
2000 1999
----------- -----------
Gross Investment in Leases $ 1,052,607 $ 1,097,787
Unearned Income on Leases (552,833) (597,592)
----------- -----------
Net Investment in Leases $ 499,774 $ 500,195
=========== ===========
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, 2000 are as follows (dollars in
thousands):
2001 $ 45,187
2002 47,253
2003 49,052
2004 50,957
2005 51,326
Thereafter 808,832
----------
$1,052,607
==========
9. 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.
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50
Reconciliations between the federal statutory income tax rate and the
Company's effective income tax rate are as follows:
FOR THE YEARS ENDED DECEMBER 31,
----------------------------------
2000 1999 1998
------ ------ ------
Federal statutory tax rate 35.0% 35.0% 35.0%
State income taxes, net of loss
carryforwards and federal tax impact 4.4 4.7 3.4
Other (1.1) 0.6 1.4
------ ------ ------
Effective tax rate 38.3% 40.3% 39.8%
====== ====== ======
The net current and noncurrent components of deferred income taxes
reflected in the accompanying consolidated balance sheets as of December 31,
2000 and 1999 are as follows (dollars in thousands):
DECEMBER 31,
---------------------------
2000 1999
--------- ---------
Net current deferred tax liability (asset) $ (649) $ 788
Net noncurrent deferred tax liability 164,128 129,193
--------- ---------
Net deferred tax liability $ 163,479 $ 129,981
========= =========
10. COMMITMENTS AND CONTINGENCIES
Parent Debt Guaranteed by the Holdings -The Guarantee covers the following
Parent's senior unsecured debt:
SENIOR NOTES
On March 15, 1994, the Parent issued $100 million of registered,
unsecured 8.10% senior notes due 2004 (the "Senior Notes") in a public debt
offering. 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"). On November 25,
1998, the Parent issued an additional $35 million of the 2008 Notes and in
September 2000, the Parent issued an additional $100.0 million of its 2008
Notes.
CORPORATE CREDIT FACILITY (SEE NOTE 14)
The Parent's corporate credit facility provides up to $250.0 million of
revolving credit through October 2003 in the form of direct advances or the
issuance of letters of credit. As of December 31, 2000, the Parent has used
this credit facility to issue approximately $183.8 million of letters of
credit in connection with investments made in electric-generating plants,
and four plants under construction.
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
35 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:
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(i) The Company is required to sell electricity generated by
each Facility to the Electric Customers and the Electric Customers are
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,
except for those facilities where the Electric Customer is responsible
for providing fuel. Fuel requirements include the quality and
estimated quantity of fuel required to operate the applicable
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 the applicable 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 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 certain Electric Customers,
the Company is obligated to pay up to $37,350,000 in aggregate liquidated
damages to the respective electricity purchasers if the respective facility does
not demonstrate certain operating and reliability standards. Banks have issued
letters of credit, non-recourse to Cogentrix Energy, in favor of the Electric
Customer which secure the Company's obligations to the Electric Customer under
this provision of the contracts.
Under certain power sales agreements, the Electric Customer 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 Electric Customer from recovering such payments made under such
power sales agreement. However, in most cases, the Electric Customer is
prohibited from reducing or recovering such payments prior to the maturity date
of the original project financing debt.
Guarantees - In connection with its substantially non-recourse project
financings and certain other subsidiary contracts, the Company and its
subsidiary, Cogentrix, Inc. have expressly undertaken certain limited
obligations and commitments, most of which will only be effective or will be
terminated upon the occurrence of future events. These obligations and
commitments include guarantees by Cogentrix, Inc. of a certain subsidiary's
obligation capped at $1.5 million and certain subsidiaries' performance under
their contracts with one Electric Customer.
Claims and Litigation - One of the Company's indirect, wholly-owned
subsidiaries is party to certain product liability claims related to the sale of
coal combustion by-products for use in various construction projects. Management
cannot currently estimate the range of possible loss, if any, the Company will
ultimately bear as a result of these claims. However, management believes--based
on its knowledge of the facts and legal theories applicable to these claims,
after consultations with various counsel retained to represent the subsidiary in
the defense of such claims, and considering all claims resolved to date--that
the ultimate resolution of these claims should not have a material adverse
effect on its consolidated financial position or results of operations or on the
Company's ability to generate sufficient cash flow to pay dividends and meet its
other obligations.
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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.
11. FUNDS HELD BY TRUSTEES
The majority of revenue received by the Company is required by the
terms of various credit agreements to be deposited in accounts administered by
certain banks (the "Trustees"). The Trustees invest funds held in these accounts
at the direction of the Company. These accounts are established for the purpose
of depositing all receipts and monitoring all disbursements of each Facility. In
addition, special accounts are established to provide debt service payments and
income taxes. The funds in these accounts are pledged as security under the
project financing agreements of each subsidiary.
Funds held by the Trustees were approximately $58,278,000 and
$118,494,000 at December 31, 2000 and 1999, respectively. Debt service account
balances are reflected as restricted cash, whereas all other accounts are
classified as cash and cash equivalents in the accompanying consolidated balance
sheets.
12. FAIR VALUE OF FINANCIAL INSTRUMENTS AND CONCENTRATION OF CREDIT RISKS
The Company invests its temporary cash balances in U.S. government
obligations, corporate obligations and financial instruments of highly-rated
financial institutions. A substantial portion of the Company's accounts
receivable is 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, 2000 and 1999, 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, 2000 and
1999. The fair value of the Company's fixed-rate borrowings at December 31, 2000
and 1999 is $20,685,000 higher and $17,989,000 higher than the historical
carrying value of $513,160,000 and $778,181,000, 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 (see Note 7). The Company does not obtain collateral or other
security to support such agreements but continually monitors its positions with,
and the credit quality of, the counterparties to such agreements. As of December
31, 2000 and 1999, the net unrealized gain (loss) on the interest rate
protection agreements was approximately $(551,000) and $2,325,000, respectively.
13. 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 the Parent of $82,822,000 and $76,410,000 as of December 31,
2000 and 1999, respectively. These notes accrue interest at the prime rate, and
principal and interest are due upon demand. The Company also had notes payable
due to the Parent of $728,000 and $4,815,000 as of December 31, 2000 and 1999,
respectively. These notes consist primarily of working capital loans which
accrue interest at the prime rate. Principal and interest on these notes are due
upon demand.
14. SUBSEQUENT EVENTS
On January 17, 2001, Ouachita Holdings, Inc. ("Ouachita Holdings"), a
wholly-owned subsidiary of the Company and sole member of Ouachita Power, LLC
("Ouachita Power", the owner of the Ouachita Facility), sold a 50% membership
interest in Ouachita Power to an indirect subsidiary of General Electric Capital
Corporation. In exchange for the membership interest, Ouachita Holdings received
$48.3 million in cash and was relieved of $56.3 million of its original equity
contribution commitment to Ouachita Power. This equity commitment was previously
supported by a letter of credit by the Parent under the Corporate Credit
Facility. The Company will retain a 50%
52
53
membership interest in Ouachita Power and will continue to manage and operate
the facility. The Company expects to record a gain of approximately $21.0
million, net of transaction costs related to this sale.
On March 30, 2001, the Company sold its interest in the Batesville
facility to NRG Energy, Inc. In exchange, the Company received $64.0 million and
assigned the operation and maintenance agreement to NRG Energy, Inc. The Company
expects to record a gain of approximately $10.0 million, net of transaction
costs related to this sale.
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SCHEDULE I
COGENTRIX DELAWARE HOLDINGS, INC.
CONDENSED BALANCE SHEETS OF REGISTRANT
DECEMBER 31, 2000 AND 1999
(dollars in thousands)
ASSETS 2000 1999
--------- ---------
CURRENT ASSETS:
Cash and cash equivalents $ 51,313 $ 580
Accounts receivable 899 8,473
--------- ---------
Total current assets 52,212 9,053
--------- ---------
INVESTMENT IN SUBSIDIARIES (ON THE EQUITY METHOD) 154,206 151,303
--------- ---------
OTHER ASSETS:
Notes receivable from affiliates 303,018 229,789
Other 21,913 23,842
--------- ---------
Total other assets 324,931 253,631
--------- ---------
Total Assets $ 531,349 $ 413,987
========= =========
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable 49,594 --
--------- ---------
Total current liabilities 49,594 --
--------- ---------
DEFERRED INCOME TAXES 29,387 23,572
--------- ---------
Total long-term liabilities 29,387 23,572
--------- ---------
Total liabilities 78,981 23,572
--------- ---------
SHAREHOLDERS' EQUITY:
Common stock 1 1
Additional paid-in capital 752,117 610,458
Accumulated comprehensive loss (1,152) (1,144)
Accumulated deficit (298,598) (218,900)
--------- ---------
Total shareholders' equity 452,368 390,415
--------- ---------
Total liabilities and shareholders' equity $ 531,349 $ 413,987
========= =========
The accompanying notes to condensed financial statements are an integral part
of this schedule.
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SCHEDULE I
COGENTRIX OF DELAWARE HOLDINGS, INC.
CONDENSED STATEMENTS OF INCOME OF REGISTRANT
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
(dollars in thousands)
2000 1999 1998
-------- -------- --------
INCOME $ -- $ -- $ --
OPERATING EXPENSES:
General and administrative 31 21 69
-------- -------- --------
OPERATING LOSS (31) (21) (69)
-------- -------- --------
OTHER INCOME:
Investment and other income 15,199 15,998 22,234
-------- -------- --------
Total other income 15,199 15,998 22,234
-------- -------- --------
INCOME BEFORE INCOME TAXES 15,168 15,977 22,165
INCOME TAX PROVISION (5,814) (6,199) (9,056)
EQUITY IN EARNINGS OF SUBSIDIARIES 64,019 62,528 40,364
-------- -------- --------
NET INCOME $ 73,373 $ 72,306 $ 53,473
======== ======== ========
The accompanying notes to condensed financial statements are an integral part
of this schedule.
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SCHEDULE I
COGENTRIX DELAWARE HOLDINGS, INC.
CONDENSED STATEMENTS OF CASH FLOWS OF REGISTRANT
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
(dollars in thousands)
2000 1999 1998
--------- --------- ---------
NET CASH FLOW PROVIDED BY
OPERATING ACTIVITIES $ 199,394 $ 81,198 $ 53,632
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Investments in subsidiaries (64,021) (222,330) (526)
--------- --------- ---------
Net cash used in investing activities (64,021) (222,330) (526)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds (repayment) from notes payable to affiliate, net -- 182,971 (291,492)
Contributed capital from Parent 141,659 88,077 298,312
Decrease in notes receivable from affiliates (73,229) -- --
Dividends paid to Parent (153,070) (141,871) (97,604)
--------- --------- ---------
Net cash flows provided by (used in) financing activities (84,640) 129,177 (90,784)
--------- --------- ---------
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS 50,733 (11,955) (37,678)
CASH AND CASH EQUIVALENTS, beginning of year 580 12,535 50,213
--------- --------- ---------
CASH AND CASH EQUIVALENTS, end of year $ 51,313 $ 580 $ 12,535
========= ========= =========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW
INFORMATION - CASH DIVIDENDS RECEIVED $ 125,137 $ 69,891 $ 58,798
========= ========= =========
The accompanying notes to condensed financial statements are an integral part
of this schedule.
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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.
("Holdings") 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.
2. GUARANTEE OF PARENT DEBT
Holdings has guaranteed all of the existing and future senior,
unsecured outstanding indebtedness for borrowed money of Cogentrix Energy, Inc.,
the parent of Holdings. This guarantee, provided for in the credit agreement for
the Parent's corporate credit facility, expires by its terms in 2003, 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 Holdings and the agent bank for the lenders under the credit
agreement. The Parent's senior, unsecured outstanding indebtedness is as
follows:
Senior Notes
On March 15, 1994, Cogentrix Energy, Inc. issued $100 million of
registered, unsecured 8.10% senior notes due 2004 (the "2004 Notes") in a
public debt offering. The 2004 Notes require annual sinking fund payments
beginning in March 2001.
On October 20, 1998, Cogentrix Energy, Inc. issued $220 million of
registered, unsecured 8.75% senior notes due 2008 (the "2008 Notes"). On
November 25, 1998, the Company issued an additional $35 million of the 2008
Notes and in September 2000, Cogentrix Energy issued an additional $100.0
million of its 2008 Notes.
Corporate Credit Facility
The Parent's corporate credit facility provides up to $250.0 million of
revolving credit through October 2003 in the form of direct advances or the
issuance of letters of credit. As of December 31, 2000, the Parent has used
this credit facility to issue approximately $183.8 million of letters of
credit in connection with investments made in electric-generating plants,
and four plants under construction.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None
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PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The directors and executive officers of Holdings are as set forth
below.
NAME AGE POSITION
- ---- --- --------
Thomas F. Schwartz......... 39 President and Director
John W. O'Connor........... 32 Vice-President - Finance, and Director
David P. Fontello.......... 51 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 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 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.
has received or, it is anticipated, will receive compensation for his 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
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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) (1)
3.2 Bylaws of Cogentrix Delaware Holdings, Inc. (3.4) (1)
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) (2)
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) (3)
4.3 First Supplemental Indenture, dated as of October 20,
1998 between Cogentrix Energy, Inc. and First Union
National Bank, as Trustee (4.3) (3)
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) (3)
4.5 Registration Agreement, dated as of November 25, 1998,
between Cogentrix Energy, Inc. and Salomon Smith Barney,
Inc. (4.5) (4)
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) (4)
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 (10.130)
(3)
10.1 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 (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)
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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
AgipCoal Sales USA, Inc., Laurel Creek Co., Inc. and
Cogentrix of Rocky Mount, Inc., as amended (Rocky Mount
Facility) (10.28). (*)(2)
10.10 Coal Sales Agreement, dated as of February 15, 1990,
among Electric Fuels Corporation, Kentucky May Coal
Company, Inc. and Cogentrix of Richmond, Inc., as
amended (Richmond Facility, Unit I) (10.31). (*)(2)
10.10(a) Fourth Amendment to Coal Sales Agreement, dated as of
July 1, 1998, among Electric Fuels Corporation, Kentucky
May Coal Company, Inc. and Cogentrix of Richmond, Inc.
(10.10(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)
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)
10.14(f) Amendment No. 9 to Contract CSXT-C-03951, dated as of
January 1, 2001, between Cogentrix of Rocky Mount, Inc.
and CSX Transportation, Inc. (Rocky Mount Facility)
(10.14(f)). (31)
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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)
10.20 Amended and Restated Reimbursement and Loan Agreement,
dated as of June 28, 2000, by and among Cogentrix of
Richmond, Inc. and BNP Paribas (Richmond Facility)
(10.1). (29)
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)
61
62
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 Amended and Restated Security Deposit Agreement, dated
as of June 28, 2000, among Cogentrix of Richmond, Inc.,
BNP Paribas, as Agent, and First Union National Bank, as
Security Agent and Securities Intermediary (Richmond
Facility) (10.2). (29)
10.26 Third Amended and Restated Pledge Agreement, dated as of
December 22, 1997, made by Cogentrix, Inc., as Pledgor,
and Credit Lyonnais, as Agent (Portsmouth Facility)
(10.79). (11)
10.27 Ground Lease and Easement, dated as of December 15,
1986, between Virginia Chemicals, Inc., as Lessor and
Cogentrix Virginia Leasing Corporation, as Lessee
(Portsmouth Facility) (10.94). (1)
10.28 Ground Lease, dated as of December 13, 1990, between
Cogentrix of Richmond, Inc., as Lessee, and E.I. du Pont
de Nemours and Company, as Lessor (Richmond Facility)
(10.95). (1)
10.29 Amended and Restated Land Lease Agreement, dated as of
February 18, 1988, among Arrowpoint Associates Limited
Partnership, as Landlord, and Cogentrix, Inc., CI
Properties, Inc. and Equipment Leasing Partners, as
Tenant, as amended (assigned to and assumed by Equipment
Leasing Partners, with Cogentrix, Inc., as guarantor)
(Corporate Headquarters) (10.96). (1)
10.30 Amended and Restated Lease Agreement, dated as of April
30, 1993, among Equipment Leasing Partners, as Landlord,
Cogentrix, Inc., as Tenant, and CI Properties, Inc., as
amended (Corporate Headquarters) (10.97). (1)
10.31 Letter Agreement, dated May 25, 1989, among Cogentrix,
Inc., Cogentrix of Richmond, Inc. (formerly named
Cogentrix of Petersburg, Inc.), and WV Hydro, Inc., as
amended (Richmond Facility) (10.98). (1)
10.32 Amended and Restated Guarantee, dated as of October 29,
1998, made by Cogentrix Delaware Holdings, Inc., the
Guarantor, in favor of the Borrower Creditors. (10.130)
(14)
10.32(a) Third Amended and Restated Guarantee, dated as of
September 14, 2000, made by Cogentrix Delaware Holdings,
Inc., the Guarantor, in favor of the Borrower Creditors
(10.47). (30)
10.33 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)
10.33(a) Amendment #1 to the Cottage Grove Partnership Agreement.
(18)
10.33(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)
10.33(c) Third Amendment, dated December 11, 1998, to the Amended
and Restated Limited Partnership Agreement of
LSP-Cottage Grove, L.P. (23)
10.34 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)
10.34(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)
10.34(b) Second Amendment, dated December 11, 1998, to the
Amended and Restated Limited Partnership Agreement of
LSP-Whitewater Limited Partnership. (23)
10.35 Power Purchase Agreement, dated as of May 9, 1994,
between Northern States Power Company and LSP-Cottage
Grove, L.P. (17)
62
63
10.36 Power Purchase Agreement, dated as of December 21, 1993,
between Wisconsin Electric Power Company and
LSP-Whitewater Limited Partnership. (17)
10.36(a) Amendment to Power Purchase Agreement, dated as of
February 10, 1994, between Wisconsin Electric Power
Company and LSP-Whitewater Limited Partnership. (17)
10.36(b) Second Amendment to Power Purchase Agreement, dated as
of October 5, 1994, between Wisconsin Electric Power
Company and LSP-Whitewater Limited Partnership. (17)
10.36(c) Third Amendment to Power Purchase Agreement, dated as of
May 5, 1995, between Wisconsin Electric Power Company
and LSP-Whitewater Limited Partnership. (17)
10.36(d) Fourth Amendment to Power Purchase Agreement, dated
March 18, 1997, between Wisconsin Electric Power Company
and LSP-Whitewater Limited Partnership. (19)
10.36(e) Fifth Amendment to Power Purchase Agreement, dated
February 26, 1998, between Wisconsin Electric Power
Company and LSP-Whitewater Limited Partnership. (20)
10.37 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)
10.38 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)
10.39 Steam Purchase Contract, effective as of January 1,
1999, by and between Celanese Chemical, Inc. and
Cogentrix Virginia Leasing Corporation. (10.3) (*) (25)
10.40 Steam Purchase Contract, effective as of January 1,
1999, by and between BASF Corporation and Cogentrix
Virginia Leasing Corporation. (10.4) (*) (25)
10.41 Credit Agreement, dated as of September 8, 1999, between
Cogentrix Eastern America, Inc. and Dresdner Bank, AG,
as administrative agent. (10.1) (26)
10.41(a) First Amendment, dated as of December 17, 1999, to the
Credit Agreement, dated as of September 8, 1999, between
Cogentrix Eastern America, Inc. and Dresdner Bank, AG,
as administrative agent (10.58(a)). (27)
10.42 Pledge Agreement, dated as of September 8, 1999, between
Cogentrix Delaware Holdings, Inc. and Dresdner Bank, AG,
as administrative agent. (10.2) (26)
10.43 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)
10.44 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)
10.45 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)
10.46 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)
10.47 Steam Purchase Contract, effective as of January 1,
1999, by and between Celanese Chemical Inc. and
Cogentrix Virginia Leasing Corporation (10.3). (*) (25)
10.48 Steam Purchase Contract, effective as of January 1,
1999, by and between BASF Corporation and Cogentrix
Virginia Leasing Corporation. (10.4) (*) (25)
10.49 Pledge Agreement, dated as of September 8, 1999 between
Cogentrix Delaware Holdings, Inc. and Dresdner Bank, AG
as administrative agent. (10.2) (26)
10.50 Pledge Agreement, dated as of September 8, 1999 between
Cogentrix Delaware Holdings, Inc. and Dresdner Bank, AG
as administrative agent. (10.8) (26)
10.51 Second Amended and Restated Guarantee, dated as of March
3, 2000, made by Cogentrix Delaware Holdings, Inc., the
Guarantor, in favor of the Borrower Creditor. (10.49a)
(27)
63
64
(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. The number
designating the exhibit on the exhibit index to such
previously-filed report is enclosed in parentheses at the end
of the description of the exhibit above.
(2) Incorporated by reference to Amendment No. 2 to Registration
Statement on Form S-1 (File No. 33-74254) filed March 7, 1994.
The number designating the exhibit on the exhibit index to
such previously-filed report is enclosed in parentheses at the
end of the description of the exhibit above.
(3) Incorporated by reference to the Form 10-K (File No. 33-74254)
filed September 28, 1994. The number designating the exhibit
on the exhibit index to such previously-filed report is
enclosed in parentheses at the end of the description of the
exhibit above.
(4) Incorporated by reference to the Form 10-Q (File No. 33-74254)
filed February 14, 1995. The number designating the exhibit on
the exhibit index to such previously-filed report is enclosed
in parentheses at the end of the description of the exhibit
above.
(5) Incorporated by reference to the Form 10-K (File No. 33-74254)
filed September 28, 1995. The number designating the exhibit
on the exhibit index to such previously-filed report is
enclosed in parentheses at the end of the description of the
exhibit above.
(6) Incorporated by reference to the Form 10-Q (File No. 33-74254)
filed November 14, 1995. The number designating the exhibit on
the exhibit index to such previously-filed report is enclosed
in parentheses at the end of the description of the exhibit
above.
(7) Incorporated by reference to the Form 10-Q (File No. 33-74254)
filed May 3, 1996. The number designating the exhibit on the
exhibit index to such previously-filed report is enclosed in
parentheses at the end of the description of the exhibit
above.
(8) Incorporated by reference to the Form 10-K (File No. 33-74254)
filed October 10, 1996. The number designating the exhibit on
the exhibit index to such previously-filed report is enclosed
in parentheses at the end of the description of the exhibit
above.
(9) Incorporated by reference to the Form 10-Q (File No. 33-74254)
filed February 14, 1997. The number designating the exhibit on
the exhibit index to such previously-filed report is enclosed
in parentheses at the end of the description of the exhibit
above.
(10) Incorporated by reference to the Form 10-K (File No. 33-74254)
filed September 29, 1997. The number designating the exhibit
on the exhibit index to such previously-filed report is
enclosed in parentheses at the end of the description of the
exhibit above.
(11) Incorporated by reference to the Form 10-K (File No. 33-74254)
filed March 30, 1998. The number designating the exhibit on
the exhibit index to such previously-filed report is enclosed
in parentheses at the end of the description of the exhibit
above.
(12) Incorporated by reference to the Form 8-K (File No. 33-74254)
filed April 6, 1998. The number designating the exhibit on the
exhibit index to such previously-filed report is enclosed in
parentheses at the end of the description of the exhibit
above.
(13) Incorporated by reference to the Form 10-Q (File No. 33-74254)
filed May 15, 1998. The number designating the exhibit on the
exhibit index to such previously-filed report is enclosed in
parentheses at the end of the description of the exhibit
above.
(14) Incorporated by reference to the Registration Statement on
Form S-4 (File No. 33-67171) filed November 12, 1998. The
number designating the exhibit on the exhibit index to such
previously file report is enclosed in parentheses at the end
of the description of the exhibit above.
(15) Incorporated by reference to Amendment No. 1 to the
Registration Statement on Form S-4 (File No. 33-67171) filed
January 27, 1999. The number designating the exhibit on the
exhibit index to such previously file report is enclosed in
parentheses at the end of the description of the exhibit
above.
64
65
(16) Incorporated by reference to Amendment No. 3 to the
Registration Statement on Form S-4 (File No. 33-67171) filed
March 15, 1999. The number designating the exhibit on the
exhibit index to such previously file report is enclosed in
parentheses at the end of the description of the exhibit
above.
(17) Incorporated by reference to the Registration Statement on
Form S-4 (File No. 33-95928) filed on August 16, 1995, as
amended, or to the Form 10-K filed for the fiscal year ended
December 31, 1995 by LS Power Funding Corporation, LSP-Cottage
Grove, L.P. and LSP-Whitewater Limited Partnership.
(18) Incorporated by reference to the Form 10-Q (File No. 33-95928)
filed August 12, 1996 by LS Power Funding Corporation,
LSP-Cottage Grove, L.P. and LSP-Whitewater Limited
Partnership.
(19) Incorporated by reference to the Form 10-Q (File No. 33-95928)
filed May 14, 1997 by LS Power Funding Corporation,
LSP-Cottage Grove, L.P. and LSP-Whitewater Limited
Partnership.
(20) Incorporated by reference to the Form 10-K (File No. 33-95928)
filed April 15, 1998 by LS Power Funding Corporation,
LSP-Cottage Grove, L.P. and LSP-Whitewater Limited
Partnership.
(21) Incorporated by reference to the Form 8-K (File No. 33-74254)
filed November 4, 1998. The number designating the exhibit on
the exhibit index to such previously-filed report is enclosed
in parentheses at the end of the description of the exhibit
above.
(22) Incorporated by reference to the Form 10-K (File No. 33-74254)
filed March 31, 1999. The number designating the exhibit on
the exhibit index to such previously-filed report is enclosed
in parentheses at the end of the description of the exhibit
above.
(23) Incorporated by reference to the Form 10-K (File No. 33-95928)
filed March 31, 1999 by LS Power Funding Corporation,
LSP-Cottage Grove, L.P. and LSP-Whitewater Limited
Partnership.
(24) Incorporated by reference to the Form 10-Q (File No. 33-45928)
filed May 17, 1999 by LS Power Funding Corporation,
LSP-Cottage Grove, L.P. and LSP-Whitewater Limited
Partnership. The number designating the exhibit on the exhibit
index to such previously filed report is enclosed in
parentheses at the end of the description of the exhibit
above.
(25) Incorporated by reference to the Form 10-Q (File No. 33-74254)
filed August 16, 1999. The number designating the exhibit on
the exhibit index to such previously filed report is enclosed
in parentheses at the end of the description of the exhibit
above.
(26) Incorporated by reference to the Form 10-Q (File No. 33-74254)
filed November 15, 1999. The number designating the exhibit on
the exhibit index to such previously filed report is enclosed
in parentheses at the end of the description of the exhibit
above.
(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.
(28) Incorporated by reference to the Form 10-Q (File No. 33-74254)
filed May 15, 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.
(29) Incorporated by reference to the Form 10-Q (File No. 33-74254)
filed August 14, 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.
(30) Incorporated by reference to the Registration Statement on
Form S-4 (File No. 333-48448) filed by Cogentrix Energy, Inc.,
on October 23, 2000. 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.
(31) Incorporated by reference to the Form 10-K (File No. 33-74254)
filed by Cogentrix Energy, Inc. on April 2, 2001. 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
66
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, 2001 By: /s/ THOMAS F. SCHWARTZ
-----------------------
Thomas F. Schwartz
President and Director
(Principal Executive 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/ THOMAS F. SCHWARTZ President and Director March 30, 2001
- -------------------------
Thomas F. Schwartz
/s/ JOHN W. O'CONNOR Vice President and Director March 30, 2001
- -------------------------
John W. O'Connor
/s/ DAVID P. FONTELLO Director March 30, 2001
- -------------------------
David P. Fontello
66