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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
------------------------
FORM 10-K
(MARK ONE)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT
OF 1934 [NO FEE REQUIRED]
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1997
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE
ACT OF 1934 [NO FEE REQUIRED]
COMMISSION FILE NUMBER 033-73160
CALPINE CORPORATION
(A DELAWARE CORPORATION)
I.R.S. EMPLOYER IDENTIFICATION NO. 77-0212977
50 WEST SAN FERNANDO STREET
SAN JOSE, CALIFORNIA 95113
TELEPHONE: (408) 995-5115
Securities registered pursuant to Section 12(b) of the Act: Calpine Corporation
Common Stock, $0.001 par value Registered on the New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None.
Indicate by check mark whether the Registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes [X] No [ ]
Indicate by check mark 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 Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of the Form 10-K or any amendment to this
Form 10-K. [ ]
Aggregate market value of the voting stock held by non-affiliates of the
Registrant as of March 4, 1998: $334.2 million
Common stock outstanding as of March 4, 1998: 20,104,890
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the documents listed below have been incorporated by reference
into the indicated parts of this report, as specified in the responses to the
item numbers involved.
(1) Designated portions of the Proxy Statement relating to
the 1998 Annual Meeting of Shareholders:... Part III (Items 10, 11 and 12)
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CALPINE CORPORATION
FORM 10-K
ANNUAL REPORT
FOR THE YEAR ENDED DECEMBER 31, 1997
TABLE OF CONTENTS
PART 1
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PAGE
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<S> <C> <C>
ITEM 1. Business.................................................... 1
ITEM 2. Properties.................................................. 41
ITEM 3. Legal Proceedings........................................... 42
ITEM 4. Submission of Matters To A Vote of Security Holders......... 43
PART II
ITEM 5. Market for Registrant's Common Equity and Related 43
Stockholder Matters.......................................
ITEM 6. Selected Financial Data..................................... 43
ITEM 7. Management's Discussion and Analysis of Financial Condition 43
and Results of Operations.................................
ITEM 8. Financial Statements and Supplementary Data................. 43
ITEM 9. Changes In and Disagreements with Accountants and Financial 43
Disclosure................................................
PART III
ITEM 10. Executive Officers, Directors and Key Employees............. 43
ITEM 11. Executive Compensation...................................... 43
ITEM 12. Security Ownership of Certain Beneficial Owners and 43
Management................................................
ITEM 13. Certain Relationships and Related Transactions.............. 43
PART IV
ITEM 14. Exhibits, Financial Statement Schedules and Reports on Form 44
8-K.......................................................
Signatures ............................................................ 51
Index to Consolidated Financial Statements and Schedules................ F-1
Schedule 11 Calculation of Earnings per Share
Exhibit Index
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ITEM 1. BUSINESS
Except for historical financial information contained herein, the matters
discussed in this annual report may be considered forward-looking statements
within the meaning of Section 27A of the Securities Act of 1933, as amended, and
Section 21E of the Securities Exchange Act of 1934, as amended and subject to
the safe harbor created by the Securities Litigation Reform Act of 1995. Such
statements include declarations regarding the intent, belief or current
expectations of the Company and its management. Prospective investors are
cautioned that any such forward-looking statements are not guarantees of future
performance and involve a number of risks and uncertainties; actual results
could differ materially from those indicated by such forward-looking statements.
Among the important factors that could cause actual results to differ materially
from those indicated by such forward-looking statements are: (i) that the
information is of a preliminary nature and may be subject to further adjustment,
(ii) those risks and uncertainties identified under "Risk Factors" included in
Item 1. Business in this Annual Report on Form 10-K, (iii) the possible
unavailability of financing, (iv) risks related to the development, acquisition
and operation of power plants, (v) the impact of avoided cost pricing, energy
price fluctuations and gas price increases, (vi) the impact of curtailment,
(vii) the seasonal nature of the Company's business, (viii) start-up risks, (ix)
general operating risks, (x) the dependence on third parties, (xi) risks
associated with international investments, (xii) risks associated with the power
marketing business, (xiii) changes in government regulation, (xiv) the
availability of natural gas, (xv) the effects of competition, (xvi) the
dependence on senior management, (xvii) volatility in the Company's stock price,
(xviii) fluctuations in quarterly results and seasonality, and (xix) other risks
identified from time to time in the Company's reports and registration
statements filed with the Securities and Exchange Commission.
OVERVIEW
Calpine Corporation ("Calpine"), a Delaware corporation, and subsidiaries
(collectively, the "Company") is engaged in the acquisition, development,
ownership and operation of power generation facilities and the sale of
electricity and steam, principally in the United States. The Company currently
has interests in 23 power plants and steam fields having an aggregate capacity
of 2,613 megawatts. The Company currently sells electricity and steam to 16
utility and other customers, principally under long-term power and steam sales
agreements, generated by power generation facilities located in six states and
Mexico. In addition, the Company has a 240 megawatt gas-fired power plant
currently under construction in Pasadena, Texas and an investment in a 169
megawatt gas-fired power plant currently under construction in Dighton,
Massachusetts. Since its inception in 1984, the Company has developed
substantial expertise in all aspects of electric power generation. The Company's
vertical integration has resulted in significant growth in recent years as the
Company has applied its extensive engineering, construction management,
operations, fuel management and financing capabilities to successfully implement
its acquisition and development program. The Company's strategy is to capitalize
on opportunities in the power market through an ongoing program to acquire,
develop, own and operate electric power generation facilities, as well as
marketing power and energy services to utilities and other end users.
The Company's net interest in power generation facilities has increased
from 297 megawatts in 1992 to 1,981 megawatts in 1997, including the facilities
currently under construction. Total assets have increased from $55.4 million as
of December 31, 1992 to $1.4 billion as of December 31, 1997. The Company's
revenue has increased to $276.3 million for 1997, representing a five-year
compound annual growth rate of 48% since 1992. The Company's EBITDA (as defined
herein) for 1997 increased to $172.6 million from $9.9 million in 1992,
representing a five-year compound annual growth rate of 77%.
THE MARKET
The power generation industry represents the third largest industry in the
United States, with an estimated end user market of over $200 billion of
electricity sales and 3,300 gigawatt hours of production in 1997. 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 power
generation industry. To date, such initiatives are under consideration at the
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federal level and in approximately 45 states. In April 1996, the Federal Energy
Regulatory Commission ("FERC") adopted Order No. 888, opening wholesale power
sales to competition and providing for open and fair electric transmission
services by public utilities. In addition, the California Public Utilities
Commission ("CPUC") has issued an electric industry restructuring decision,
which originally provided for commencement of deregulation and implementation of
customer choice of electricity supplier by January 1, 1998, and is currently
scheduled to commence on April 1, 1998. The Company believes that industry
trends and such regulatory initiatives will lead to the transformation of the
existing market, which is largely characterized by electric utility monopolies
having old, inefficient high-cost generating facilities, selling to a captive
customer base, to a more competitive market where end users may purchase
electricity from a variety of suppliers, including non-utility generators, power
marketers, public utilities and others. The Company believes that these market
trends will create substantial opportunities for companies such as themselves
that are low cost power producers and have an integrated power services
capability which enables them to produce and sell energy to customers at
competitive rates.
The Company also believes that these market trends will result in the
disposition of power generation facilities by utilities, independent power
producers and industrial companies. Numerous utilities have announced their
intentions to sell their power generation facilities. Many independent producers
operating a limited number of power plants are seeking to dispose of such plants
in response to competitive pressures, and industrial companies are selling their
power plants to redeploy capital in their core businesses. The Company believes
that this consolidation will continue in the highly fragmented independent power
industry.
STRATEGY
The Company's objective is to become a leading power company by
capitalizing on emerging market opportunities in the domestic power markets. The
key elements of the Company's strategy are as follows:
Expand and diversify its domestic portfolio of power projects. In pursuing
its growth strategy, the Company intends to focus on opportunities where it is
able to capitalize on its extensive management and technical expertise to
implement a fully integrated approach to the acquisition, development and
operation of power generation facilities. This approach includes design,
engineering, procurement, finance, construction, management, fuel and resource
acquisition, operations and power marketing, which the Company believes provides
it with a competitive advantage.
Acquisition of power plants. The Company has significantly expanded and
diversified its project portfolio through the acquisition of power generation
facilities. Since 1993, the Company has completed transactions involving
thirteen gas-fired cogeneration facilities and two steam fields. As a result of
these transactions, the Company has more than quadrupled its aggregate power
generation capacity and substantially diversified its fuel mix during this
period. The Company intends to continue to pursue an active acquisition program.
Development of merchant power plants. The Company is also pursuing the
development of highly efficient, low-cost power plants that seek to take
advantage of inefficiencies in the electricity market. The Company intends to
sell all or a portion of the power generated by such merchant plants into the
competitive market through a portfolio of short, medium and long-term power
sales agreements. As part of Calpine's initial effort to develop merchant
plants, the Company has a 240 megawatt gas-fired power generation facility
currently under construction in Pasadena, Texas and a 169 megawatt gas-fired
power generation facility currently under construction in Dighton,
Massachusetts. The Company currently plans to develop additional low-cost,
gas-fired facilities in California, Texas, New England and other high-priced
power markets.
Enhance the performance and efficiency of existing power projects. The
Company continually seeks to maximize the power generation potential of its
operating assets and minimize its operating and maintenance expenses and fuel
costs. To date, the Company's power generation facilities have operated at an
average availability of approximately 97%. The Company believes that achieving
and maintaining a low-cost of production will be increasingly important to
compete effectively in the power generation market.
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DESCRIPTION OF FACILITIES
The Company currently has interests in 23 power generation facilities and
steam fields with a current aggregate capacity of approximately 2,613 megawatts,
consisting of fifteen gas-fired power plants with a total capacity of 2,127
megawatts, three geothermal power generation facilities (which include a steam
field and a power plant) with a total capacity of 67 megawatts and five
geothermal steam fields that supply utility power plants with a total current
capacity of approximately 419 megawatts. In addition, the Company has a 240
megawatt gas-fired power generation facility under construction in Pasadena,
Texas, and an investment in a 169 megawatt gas-fired power generation facility
currently under construction in Dighton, Massachusetts. Each of the power
generation facilities currently in operation produces electricity for sale to a
utility or other thirdparty end user. Thermal energy produced by the gas-fired
cogeneration facilities is sold to governmental and industrial users, and steam
produced by the geothermal steam fields is sold to utility-owned-power plants.
The gas-fired and geothermal power generation projects in which the Company
has an interest produce electricity, thermal energy and steam that are typically
sold pursuant to long-term, take and pay power or steam sales agreements
generally having original terms of 20 or 30 years. Revenue from a power sales
agreement usually consists of two components: energy payments and capacity
payments. Energy payments are based on a power plant's net electrical output
where payment rates may be determined by a schedule of prices covering a fixed
number of years under the power sales agreement, after which payment rates are
usually indexed to the fuel costs of the contracting utility or to general
inflation indices. Capacity payments are based on a power plant's net electrical
output and/or its available capacity. Energy payments are made for each
kilowatt-hour of energy delivered, while capacity payments, under certain
circumstances, are made whether or not any electricity is delivered. The Company
is paid for steam supplied by its steam fields on the basis of the amount of
electrical energy produced by, or steam delivered to, the contracting utility's
power plants.
The Company currently provides operating and maintenance services for 16 of
the 23 power plants and steam fields in which the Company has an interest. Such
services include the operation of power plants, geothermal steam fields, wells
and well pumps, gathering systems and gas pipelines. The Company also supervises
maintenance, materials, purchasing and inventory control, manages cash flow,
trains staff and prepares operating and maintenance manuals for each power
generation facility. As a facility develops an operating history, the Company
analyzes its operation and may modify or upgrade equipment or adjust operating
procedures or maintenance measures to enhance the facility's reliability or
profitability. These services are performed under the terms of an operating and
maintenance agreement pursuant to which the Company is generally reimbursed for
certain costs, is paid an annual operating fee and may also be paid an incentive
fee based on the performance of the facility. The fees payable to the Company
are generally subordinated to any lease payments or debt service obligations of
non-recourse financing for the project.
In order to provide fuel for the gas-fired power generation facilities in
which the Company has an interest, natural gas reserves are acquired or natural
gas is purchased from third parties under supply agreements. The Company
attempts to structure a gas-fired power facility's fuel supply agreement so that
gas costs have a direct relationship to the fuel component of revenue energy
payments.
Certain power generation facilities in which the Company has an interest
have been financed primarily with non-recourse project financing that is
structured to be serviced out of the cash flows derived from the sale of
electricity, thermal energy and/or steam produced by such facilities and
provides that the obligations to pay interest and principal on the loans are
secured almost solely by the capital stock or partnership interests, physical
assets, contracts and/or cash flow attributable to the entities that own the
facilities. The lenders under non-recourse project financing generally have no
recourse for repayment against the Company or any assets of the Company or any
other entity other than foreclosure on pledges of stock or partnership interests
and the assets attributable to the entities that own the facilities.
Substantially all of the power generation facilities in which the Company
has an interest are located on sites which are leased on a long-term basis. The
Company currently holds interests in geothermal leaseholds in The Geysers that
produce steam for sale under steam sales agreements and for use in producing
electricity from its wholly-owned geothermal power generation facilities.
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The continued operation of power generation facilities and steam fields
involves many risks, including the breakdown or failure of power generation
equipment, transmission lines, pipelines or other equipment or processes and
performance below expected levels of output or efficiency. To date, the
Company's power plants have operated at an average availability of 97%. Although
from time to time the Company's power generation facilities have experienced
certain equipment breakdowns or failures, such breakdowns or failures have not
had a material adverse effect on the operation of such facilities or on the
Company's results of operations. Although the Company's facilities contain
certain redundancies and back-up mechanisms, there can be no assurance that any
such breakdown or failure would not prevent the affected facility or steam field
from performing under applicable power and/or steam sales agreements. In
addition, although insurance is maintained to protect against certain of these
operating risks, the proceeds of such insurance may not be adequate to cover
lost revenue or increased expenses, and, as a result, the entity owning such
power generation facility or steam field may be unable to service principal and
interest payments under its financing obligations and may operate at a loss. A
default under such a financing obligation could result in the Company losing its
interest in such power generation facility or steam field.
Insurance coverage for each power generation facility includes commercial
general liability, workers' compensation, employer's liability and property
damage coverage, which generally contains business interruption insurance
covering debt service and continuing expenses for a period ranging from 12 to 18
months.
The Company believes that each of the currently operating power generation
facilities in which the Company has an interest is exempt from financial and
rate regulation as a public utility under federal and state laws.
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Set forth below is certain information regarding the Company's operating
power plants, pending power plant acquisitions, development projects and
operating steam fields as of March 4, 1998.
POWER PLANTS
<TABLE>
<CAPTION>
TERM OF
POWER NAMEPLATE CALPINE CALPINE NET COMMENCEMENT POWER
GENERATION CAPACITY INTEREST INTEREST OF COMMERCIAL POWER SALES
POWER PLANT TECHNOLOGY (MEGAWATTS)(1) PERCENTAGE (MEGAWATTS) OPERATION PURCHASER AGREEMENT
----------- ---------- -------------- ---------- ----------- ------------- ----------------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
OPERATING POWER PLANTS
Texas City........... Gas-Fired 450 50% 225 1987 TUEC 2002
UCC(2) 2003
Clear Lake........... Gas-Fired 377 50% 188.5 1984 TNP 2004
HL&P 2005
HCCG(3) 2004
Gordonsville......... Gas-Fired 240 50% 120 1994 VEPCO(4) 2024
Lockport............. Gas-Fired 184 11.36% 20.9 1992 GM 2007
NYSEG(5)
Auburndale........... Gas-Fired 150 50% 75 1994 FPC(16) 2013
Sumas(6)............. Gas-Fired 125 70% 87.5 1993 Puget Sound and 2013
Electric Company
King City............ Gas-Fired 120 100% 120 1989 PG&E(17) 2019
Gilroy............... Gas-Fired 120 100% 120 1988 PG&E 2018
Kennedy International
Airport............ Gas-Fired 107 50% 53.5 1995 Port Authority(7) 2015
Bethpage............. Gas-Fired 57 100% 57 1989 NG Corp. 2004
LILCO(8)
Greenleaf 1.......... Gas-Fired 49.5 100% 49.5 1989 PG&E 2019
Greenleaf 2.......... Gas-Fired 49.5 100% 49.5 1989 PG&E 2019
Stony Brook.......... Gas-Fired 40 50% 20 1995 SUNY 2015
LILCO(9)
Agnews............... Gas-Fired 29 20% 5.8 1990 PG&E 2021
Watsonville.......... Gas-Fired 28.5 100% 28.5 1990 PG&E 2009
West Ford Flat....... Geothermal 27 100% 27 1988 PG&E 2008
Bear Canyon.......... Geothermal 20 100% 20 1988 PG&E 2008
Aidlin............... Geothermal 20 5% 1 1989 PG&E 2009
PENDING ACQUISITIONS
Pittsburgh........... Gas-Fired 70 100% 70 1966 Dow Chemical n/a
Corporation
PROJECTS UNDER CONSTRUCTION
Pasadena(10)......... Gas-Fired 240 100% 240 1998 Phillips 2018
Dighton(11).......... Gas-Fired 169 50% 84.5 1999 Merchant n/a
</TABLE>
STEAM FIELDS
<TABLE>
<CAPTION>
APPROXIMATE CALPINE CALPINE NET COMMENCEMENT
CAPACITY INTEREST INTEREST OF COMMERCIAL UTILITY ESTIMATED
STEAM FIELD (MEGAWATTS)(12) PERCENTAGE (MEGAWATTS) OPERATION PURCHASER LIFE(13)
----------- --------------- ---------- ----------- ------------- ------------- ---------
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Thermal Power Company 140 100% 140 1960 PG&E 2018
PG&E Unit 13 75 100% 75 1980 PG&E 2018
PG&E Unit 16 74 100% 74 1985 PG&E 2018
SMUDGEO #1 50 100% 50 1983 SMUD 2018
Cerro Prieto 80 100%(14) 80 1973 Comision 2000(15)
Federal de
Electricidad
Electric
</TABLE>
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(1) Nameplate capacity may not represent the actual output for a facility at
any particular time.
(2) The power purchasers for the Texas City Power Plant are the Texas Utilities
Electric Company ("TUEC") and the Union Carbide Corporation ("UCC").
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(3) The power purchasers for the Clear Lake Power Plant are the Texas-New
Mexico Power Company ("TNP"), the Houston Lighting and Power Company
("HL&P") and the Hoechst Celanese Chemical Group, Inc. ("HCCG").
(4) The power purchaser for the Gordonsville Power Plant is Virginia Electric
and Power Company ("VEPCO").
(5) The power purchasers for the Lockport Power Plant are General Motors
("GM"), and New York State Electric and Gas ("NYSEG").
(6) See Power Plants-Sumas Power Plants for a description of the Company's
interest in the Sumas partnership and current sales of power by the Sumas
Power Plant.
(7) Electricity generated by the Kennedy International Airport Power Plant is
sold to the Port Authority of New York and New Jersey ("Port Authority")
and excess energy is sold to other utility customers.
(8) Electricity generated by the Bethpage Power Plant is sold to the Northrup
Grumman Corporation ("NG Corp"), and excess energy is sold to Long Island
Lighting Corporation ("LILCo").
(9) Electricity generated by the Stony Brook Power Plant is sold to the State
University of New York at Stony Brook ("SUNY"), and excess energy is sold
to LILCo.
(10) The Pasadena Power Plant is currently under construction and is expected to
commence commercial operation in July 1998. Approximately 90 megawatts will
be sold to Phillips Petroleum Company ("Phillips"), with the remaining
available electricity generated to be sold into the open market.
(11) The Dighton Power Plant is currently under construction and is expected to
commence commercial operation in early 1999. The Company invested $16.0
million in the facility, which entitles the Company to receive a preferred
payment stream at a rate of 12.07% per annum on its investment. Based on
the Company's current estimates, this preferred payment stream will
represent approximately 50% of project cash flow beginning at the
commencement of commercial operation. A merchant plant is a power
generation facility that sells all or a portion of its electricity into the
competitive market rather than pursuant to long-term power sales
agreements.
(12) Capacity is expected to gradually diminish as the production of the related
steam fields declines.
(13) Other than the Cerro Prieto Steam Field, the steam sales agreements remain
in effect so long as steam is produced in commercial quantities. There can
be no assurance that the estimated life shown accurately predicts actual
productive capacity of the steam fields.
(14) See Steam Fields-Cerro Prieto Steam Fields for a description of the
Company's interest in and current sales of steam by the Cerro Prieto Steam
Field.
(15) Represents the actual termination of the steam sales agreement.
(16) Florida Power Company ("FPC").
(17) Pacific Gas & Electric Company ("PG&E").
POWER PLANTS
Texas City and Clear Lake Power Plants
On June 23, 1997, the Company completed the acquisition of a 50% equity
interest in the Texas City and the Clear Lake Cogeneration facilities for a
total purchase price of $35.4 million. The Company acquired its 50% interest in
these plants through the acquisition of 50% of the capital stock of Enron
Dominion Cogen Corp., subsequently renamed Texas Cogeneration Company ("TCC")
from Enron Power Corp., which is a wholly-owned subsidiary of Enron Corp.
("Enron"). The other 50% shareholder in TCC is Dominion Cogen, Inc., a
wholly-owned subsidiary of Dominion Energy, Inc. which in turn is a wholly-owned
subsidiary of Dominion Resources, Inc., which is the parent company of VEPCO. In
addition to the purchase of 50% of the stock of TCC, the Company, through its
wholly-owned subsidiary, Calpine Finance Company ("CFC"), purchased from the
existing lenders the $155.6 million of outstanding non-recourse project
financing incurred by TCC in connection with the Texas City Power Plant
(approximately $53.0 million) and the Clear Lake Power Plant (approximately
$102.6 million). The acquisition of the capital stock of TCC and the purchase of
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the outstanding debt from the existing lenders were financed with approximately
$125.0 million of non-recourse project financing provided by The Bank of Nova
Scotia and $70.0 million of equity provided by the Company. The non-recourse
project financing matures on June 22, 1998 and bears interest at London
Interbank Offered Rate ("LIBOR") plus an agreed margin, currently 7.2% per
annum. The Company currently expects to refinance this non-recourse project
financing before June 22, 1998.
Texas City Power Plant -- The Texas City Power Plant is a 450 megawatt
gas-fired cogeneration facility located in Texas City, Texas. The Texas City
Power Plant includes three Westinghouse W-501D5 combustion turbines, three
Econotherm heat recovery steam generators and one Hitachi steam turbine. The
Texas City Power Plant commenced commercial operation in June 1987. In 1997, the
Texas City Power Plant operated at an average availability of 92.9%.
Electricity generated by the Texas City Power Plant is sold under two
separate long-term agreements to (i) TUEC under a power sales agreement
terminating on September 30, 2002 and (ii) Union Carbide Company ("UCC") under a
steam and electricity services agreement terminating on June 30, 1999. Each
agreement contains payment provisions for capacity and electric energy payments.
Under a steam and electricity services agreement expiring October 19, 2003,
the Texas City Power Plant will supply UCC with 300,000 lbs/hr of steam on a
monthly average basis, with the required supply of steam not exceeding 600,000
lbs/hr at any given time. It is necessary for the Texas City Power Plant to
provide a certain amount of thermal energy to a host facility in order to
maintain its qualifying facility ("QF") status.
Natural gas requirements for the Texas City Power Plant are allocated
between UCC, DEI Texas, Inc. ("DEI"), an affiliate of Dominion Cogen Inc., and
Enron Capital & Trade Resources Corporation ("ECT") pursuant to a contractual
arrangement. UCC and DEI currently provide approximately 25% and 56%,
respectively, of the fuel requirements of the Texas City Power Plant. The three
fuel contracts are effective through June 30, 1999. Under the fuel contracts,
approximately 19% of the total fuel requirements of the Texas City Power Plant
is supplied at spot market prices. The remainder is purchased at fixed rates set
forth in the contracts.
The Texas City Power Plant is operated and maintained by the Company under
a one-year operating and maintenance agreement with automatic renewal
provisions, pursuant to which the Company is reimbursed for certain costs and is
entitled to a fixed annual fee and an incentive payment based on project
performance.
The Texas City Power Plant is located on approximately 9 acres of land in
Texas City, Texas.
During 1997, the Texas City Power Plant generated approximately
2,704,481,000 kilowatt-hours of electric energy for sale to TUEC and UCC and
approximately $197.6 million of revenue.
Clear Lake Power Plant -- The Clear Lake Power Plant is a 377 megawatt
gas/hydrogen-fired cogeneration facility located in Pasadena, Texas. The Clear
Lake Power Plant includes three Westinghouse W-501D5 combustion turbines, three
Vogt heat recovery steam generators and two Westinghouse steam turbines. The
Clear Lake Power Plant commenced commercial operation in December 1984. In 1997,
the Clear Lake Power Plant operated at an average availability of 97.4%.
Electricity generated by the Clear Lake Power Plant is sold under three
separate long-term agreements to (i) TNP under an original 20-year power sales
agreement terminating in 2004, (ii) HL&P under an original 10- year power sales
agreement terminating in 2005, and (iii) HCCG under an original 10-year power
sales agreement terminating in 2004. Each power sales agreement contains payment
provisions for capacity and energy payments.
Under a steam purchase and sale agreement expiring August 31, 2004, the
Clear Lake Power Plant will supply up to 900,000 lbs/hr of steam to HCCG. It is
necessary for the Clear Lake Power Plant to provide a certain amount of thermal
energy to a host facility in order to maintain its QF status.
The natural gas for the Clear Lake Power Plant is purchased primarily from
TCC, which receives its fuel from ECT. In addition, the facility burns hydrogen
provided by HCCG, amounting to about 5% of the Clear Lake Power Plant's total
fuel requirements.
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The Clear Lake Power Plant is operated by the Company under a one-year
operating and maintenance agreement with automatic renewal provisions, pursuant
to which the Company is reimbursed for certain costs and is entitled to a fixed
annual fee and an incentive payment based on project performance.
The Clear Lake Power Plant is located on approximately 21 acres of land in
Pasadena, Texas.
During 1997, the Clear Lake Power Plant generated approximately
2,966,250,000 kilowatt-hours of electric energy for sale to TNP, HL&P and HCCG,
and approximately $97.6 million of revenue.
The Clear Lake Power Plant is currently engaged in litigation with TNP (see
Item 3 -- Legal Proceedings).
Gordonsville and Auburndale Power Plants
On October 9, 1997, the Company completed the acquisition of 50% interests
in the Gordonsville Power Plant and the Auburndale Power Plant. The Company
acquired its interest in the Gordonsville Power Plant through the acquisition of
a 50% general partnership interest in Gordonsville Energy, L.P. from Northern
Hydro Limited ("Hydro") for approximately $14.9 million. The other 50% general
partnership interest in Gordonsville Energy, L.P. is owned by affiliates of
Edison Mission Energy, a subsidiary of Edison International Company.
Construction of the Gordonsville Power Plant was financed with non-recourse
project financing totaling $223.0 million maturing on June 1, 2009. The Company
acquired its interest in the Auburndale Power Plant through the acquisition of a
50% general partnership in Auburndale Power Partners, L.P. from Norweb Power
Services (No. 1) Limited ("Norweb") for approximately $27.5 million. The other
50% general partnership interest in Auburndale Power Partners, L.P. is owned by
affiliates of Edison Mission Energy, a subsidiary of Edison International
Company. The construction of the Auburndale Power Plant was financed with a term
loan in the amount of $126.0 million and a final maturity date of December 31,
2012.
Gordonsville Power Plant -- The Gordonsville Power Plant is a 240 megawatt
gas-fired cogeneration facility located near Gordonsville, Virginia. The
Gordonsville Power Plant consists of two General Electric Stag 107EA
combined-cycle combustion turbines, two steam turbines, two heat recovery steam
generators and an air-cooled condenser. The Gordonsville Power Plant commenced
commercial operation in 1994. In 1997, the Gordonsville Power Plant operated at
an average availability of 96.1%.
Electricity generated by the Gordonsville Power Plant is sold to VEPCO
under two 30-year power sales agreements terminating on June 1, 2024, each of
which include payment provisions for capacity and energy. The power sales
agreements provide for firm capacity payments at a price of $128 per kilowatt
year through 2008 and at a price of $102 for years 2009 through 2024. For the
term of the power sales agreements, Gordonsville is paid for firm capacity up to
217.4 megawatts in the summer and up to 287.8 megawatts in the winter. The power
sales agreements contain dispatch provisions, which allow VEPCO to control the
output of the facility.
The Gordonsville Power Plant sells steam to Rapidan Service Authority under
the terms of a steam purchase and sales agreement for treating wastewater, which
expires June 1, 2004. It is necessary for the Gordonsville Power Plant to
provide a certain amount of thermal energy to a host facility in order to
maintain its QF status.
Gordonsville has two separate natural gas supply and transportation
agreements. During the summer period, gas is supplied by Union Pacific Fuels
Inc. under a 15-year agreement expiring June 2009. During the winter period, gas
is supplied by Tejas Power under a 15-year agreement expiring June 2009, subject
to renewal for a period of five years.
The Gordonsville Power Plant is operated by Edison Mission Operations &
Maintenance Inc. ("EMOM"), under an agreement which expires on December 31,
2024. EMOM is paid on a cost-plus basis for all direct labor plus reimbursement
of certain costs, an annual operating fee and an incentive fee based on
performance.
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<PAGE> 11
The Gordonsville Power Plant is located on approximately 16.7 acres near
the town of Gordonsville, Virginia. The site is owned by and is leased from the
town of Gordonsville under a lease agreement, which expires on June 1, 2024.
During 1997, the Gordonsville Power Plant generated approximately
279,000,000 kilowatt-hours of electrical energy and approximately $38.0 million
of revenue.
Auburndale Power Plant -- The Auburndale Power Plant is a 150 megawatt
gas-fired cogeneration facility located near the city of Auburndale, Florida.
The Auburndale Power Plant consists of a single Westinghouse W501D5 combustion
turbine generator, a Mitsubishi steam turbine and a Nooter-Erickson heat
recovery steam generator. The project uses an on-site zero discharge waste water
system. The Auburndale Power Plant commenced commercial operation in July 1994.
In 1997, the Auburndale Power Plant operated at an average availability of
95.0%.
Electricity generated by the Auburndale Power Plant is sold under various
power sales agreements to Florida Power Corporation ("FPC"), Enron Power
Marketing and Sonat Power Marketing. Auburndale sells 131.18 megawatts of
capacity and energy to FPC under three power sales agreements, each terminating
at the end of 2013. The power sales agreements provide for capacity payments on
114 megawatts at a price of $185 per kilowatt year (1998 dollars) escalating at
5.1% per year. On 17 megawatts, capacity payments are based on $231 per kilowatt
year (1998 dollars) escalating at 6.33% per year.
The Auburndale Power Plant sells steam under two steam purchase and sale
agreements. One agreement is with Cutrale Citrus Juices, USA, an affiliate of
Sucocitro Cutrale LTDA, for an original term of 20 years expiring on July 1,
2014. The second agreement is with Todhunter International, Inc., doing business
as Florida Distillers Company, for an original term of 15 years expiring on July
1, 2009. It is necessary for the Auburndale Power Plant to provide a certain
amount of thermal energy to a host facility in order to maintain QF status.
The Auburndale Power Plant has an 18-year fuel supply contract with Citrus
Trading Corporation, a joint venture between Enron and Sonat Inc., for 25,100
million British thermal units ("mmbtu") per day of natural gas. The fuel supply
contract expires in June 2014.
The Auburndale Power Plant is operated by EMOM. EMOM is paid on a cost-plus
basis for all direct labor plus reimbursement of certain costs, an annual
operating fee and an incentive fee based on performance.
The Auburndale Power Plant is located on a 10-acre site near the city of
Auburndale, Florida. The site is owned by Auburndale Power Partners, L.P.
During 1997, the Auburndale Power Plant generated approximately
1,068,574,000 kilowatt-hours of electrical energy and approximately $50.0
million in revenue.
Gas Energy Inc. Power Plants
On December 19, 1997, Calpine completed the acquisition of 100% of the
capital stock of Gas Energy, Inc. ("GEI") and Gas Energy Cogeneration, Inc.
("GECI") from The Brooklyn Union Gas Company("BUG") for an aggregate purchase
price of $100.9 million (referred to as the "GEI Transaction"). GEI and GECI
indirectly own (i) a 50% general partnership interest in the Kennedy
International Airport Power Plant, a 107 megawatt gas-fired cogeneration
facility, (ii) a 50% general partnership interest in the Stony Brook Power
Plant, a 40 megawatt gas-fired cogeneration facility, (iii) a 45% general
partnership interest in the Bethpage Power Plant, a 57 megawatt gas-fired
cogeneration facility, (iv) an 11.36% limited partnership interest in the
Lockport Power Plant, a 184 megawatt gas-fired cogeneration facility, and (v) a
100% interest in three fuel management contracts. On February 5, 1998, the
Company acquired the remaining 55% interest in, and assumed the operations and
maintenance of, the Bethpage Power Plant for approximately $4.6 million.
Kennedy International Airport Power Plant -- The Kennedy International
Airport Power Plant is a 107 megawatt gas-fired cogeneration facility located at
John F. Kennedy International Airport ("JFK Airport") in Queens, New York. The
facility is owned and operated by KIAC Partners ("KIAC"). The Company owns an
indirect 50% general partner interest in KIAC. The remaining 50% general
partnership
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<PAGE> 12
interest in the project is owned by CEA KIA, Inc., an indirect special purpose
subsidiary of Community Energy Alternatives Incorporated ("CEA"), which is, in
turn, an indirect wholly-owned subsidiary of Public Service Enterprise Group
Incorporated ("PSEG"). The Kennedy International Airport Power Plant commenced
commercial operation in February 1995.
The Kennedy International Airport Power Plant consists of two 42.5 megawatt
General Electric LM6000 gas combustion turbine generators, two Deltak heat
recovery steam generators, a 26 megawatt General Electric steam turbine
generator, a renovated and expanded central heating and refrigeration plant, a
renovated and modified thermal distribution system and state-of-the-art
pollution control equipment. In 1997, the Kennedy International Airport Power
Plant operated at an average availability of 97.3%.
KIAC constructed and is operating the Kennedy International Airport Power
Plant pursuant to a lease expiring in November 2015 (the KIAC Lease Agreement).
KIAC is obligated under the lease to pay facility rental in an amount sufficient
to pay principal and interest of the $250 million of Special Port Authority
Bonds which were issued by the Port Authority in June 1996 to refinance the
original financing for the project and to reimburse a portion of the initial
equity investment. The Special Port Authority Bonds mature in 2019.
Electricity and thermal energy generated by the Kennedy International
Airport Power Plant is sold to the Port Authority, and incremental electric
power is sold to Con Ed, NYPA and other utility customers. Electric power and
chilled and hot water generated by the Kennedy International Airport Power Plant
is sold to the Port Authority under an energy purchase agreement which expires
November 2015 and is subject to an automatic four-year extension if the Port
Authority extends its lease at least four years beyond 2015 with New York City
for JFK Airport. Under the energy purchase agreement, the Port Authority is
obligated to purchase the electrical energy output generated by the Kennedy
International Airport Power Plant up to JFK Airport's requirements (subject to a
maximum of 76.3 megawatts). The purchase price for electric power under the
agreement is the prevailing rate the Port Authority would have paid to NYPA for
electric service if the project were not serving JFK Airport, plus a surcharge
of up to 5%. Under the agreement, the Port Authority is also obligated to
purchase the central terminal tenants' requirements for heating and air
conditioning at JFK Airport.
The Port Authority has a minimum thermal take requirement in an amount
sufficient to maintain the Kennedy International Airport Power Plant's QF
status. It is necessary for the Kennedy International Airport Power Plant to
provide a certain amount of thermal energy to a host facility in order to
maintain its QF status.
The natural gas requirements of the Kennedy International Airport Power
Plant are supplied by Amerada Hess Corporation under a long-term contract in
effect through November 30, 2015. Fuel is transported to the Kennedy
International Airport Power Plant under two interstate transportation contracts
with Energy Development Corporation ("EDC") and EnMark Gas Corp. ("EnMark"). The
EDC contract is effective through November 2015, with a five-year extension
option. The EnMark gas services agreement provides for transportation through
November 2010, subject to renewal at the option of KIAC, for one-year intervals,
for up to 10 years. Local transportation is provided by BUG under a
transportation services agreement, which agreement expires in January 2019,
extendible on a year-to-year basis thereafter. Fuel management and
administration services are provided by Idlewild Fuel Management Corp. ("IFM"),
a wholly-owned subsidiary of the Company, under a long-term fuel management
contract. The agreement is in effect through January 2015.
The Kennedy International Airport Power Plant is operated by CEA Kennedy
Operators, Inc., under a long-term agreement pursuant to which the operator is
reimbursed for certain costs and is entitled to a fixed fee and an incentive
payment based on performance. The agreement expires the earlier of February 2020
or the date of the expiration of the KIAC Lease Agreement.
The Kennedy International Airport Power Plant is located on a seven-acre
site within the JFK Airport. KIAC subleases the land on which the facility is
located from the Port Authority for $100,000 annually under a 20-year site lease
expiring November 30, 2015, subject to extension.
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For 1997, the Kennedy International Airport Power Plant generated
approximately 398,868,000 kilowatt-hours of electrical energy, 206,400 mmbtu of
chilled water and 197,500 mmbtu of hot water for sale to the Port Authority, and
generated approximately $46.3 million in revenue.
Stony Brook Power Plant -- The Stony Brook Power Plant is a 40 megawatt
gas-fired cogeneration facility located on the campus of the State University of
New York ("SUNY") at Stony Brook, New York. The facility is owned by Nissequogue
Cogen Partners ("NCP"). The Company owns an indirect 50% general partner
interest in NCP. The remaining 50% general partner interest is owned by CEA
Stony Brook, Inc., an indirect special purpose subsidiary of CEA, which is, in
turn, an indirect wholly-owned subsidiary of PSEG. The Stony Brook Power Plant
commenced commercial operation in April 1995.
The Stony Brook Power Plant consists of a single General Electric LM6000
aeroderivative combustion turbine generator coupled with a Nooter-Erickson heat
recovery steam generator. In 1997, the Stony Brook Power Plant operated at an
average availability of 94.9%.
On December 15, 1993, NCP entered into a lease agreement for the Stony
Brook Power Plant with the Suffolk Industrial Development Agency (the "Suffolk
IDA") concurrent with the issuance of $79 million of variable rate Industrial
Development Revenue Bonds by the Suffolk IDA to finance the construction of the
facility. The bonds mature in 2010.
Steam and electric power is sold to SUNY under a 20-year energy supply
agreement expiring April 2015. Under the energy supply agreement, SUNY is
required to purchase, and the Stony Brook Power Plant is required to provide,
all of SUNY's electric power and steam requirements up to 36.125 megawatts of
electricity and 280,000 lbs per hr of process steam. The remaining electricity
is sold to LILCo under a long-term agreement. LILCo is obligated to purchase, on
an avoided cost basis, electric power generated by the facility not required by
SUNY. SUNY's purchase price for electric power is equal to 80% of LILCo's 2-MRP
rate, which is its rate for large industrial customers. The purchase price for
steam includes a fixed monthly charge plus a variable charge per pound of steam.
SUNY is required to purchase a minimum of 402,000 klbs per year of steam,
an amount sufficient to maintain QF status of the Stony Brook Power Plant. It is
necessary for the Stony Brook Power Plant to provide a certain amount of thermal
energy to a host facility in order to maintain its QF status.
Natural Gas Clearinghouse, Inc., the successor to Chevron USA, Inc., has
guaranteed a firm supply of up to 12,000 mmbtu per day of gas to NCP for a term
of 15 years, expiring April 2010, under a supply agreement. The supply agreement
can be extended for two additional terms of five years each. Fuel management
services are provided by Stony Brook Fuel Management Corp. ("SBFM"), a
wholly-owned subsidiary of the Company, under a long-term fuel management
contract entered into on December 28, 1993. Gas is transported under gas
transportation agreements with New Jersey Natural Gas Company and LILCo under
agreements that expire in December 2010 and March 2015, respectively.
The Stony Brook Power Plant is operated by CEA Stonybrook Operators, Inc.,
an indirect wholly-owned subsidiary of CEA, under a long-term operations and
maintenance agreement expiring the earlier of either the termination of the site
permit or April 2023.
The Stony Brook Power Plant is located on two acres of leased land within
the SUNY campus in Stony Brook, New York. NCP leases the site, including all
permanent facilities constructed on the site, under a site permit agreement for
a term equivalent to that of the energy supply agreement.
For 1997, the Stony Brook Power Plant generated approximately 305,954,000
kilowatt-hours of electrical energy and 1,117,000 klbs of steam for sale to SUNY
and LILCo, and generated approximately $32.8 million in revenue.
Bethpage Power Plant -- The Bethpage Power Plant is a 57 megawatt gas-fired
cogeneration facility located adjacent to a Northrup Grumman Corporation
("Grummann") facility in Bethpage, New York. The Bethpage Power Plant commenced
commercial operation in August 1989.
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The Bethpage Power Plant consists of two General Electric LM2500
aeroderivative combustion turbines coupled with two Hollandaise Construction
Group heat recovery steam generators and a General Electric steam turbine. Since
start-up, the Bethpage Power Plant has operated at an average availability of
98%.
The Bethpage Power Plant was originally financed with a $54.5 million loan
maturing on March 31, 2004.
Electricity and steam generated by the Bethpage Power Plant are sold to
Grumman under an energy purchase agreement expiring August 2004. Under the
energy purchase agreement, the Bethpage Power Plant provides Grumman up to 30
megawatts of electric power and Grumman is obligated to purchase a minimum of
175,000 megawatt hours per year from the facility; provided, however, that
Grumman may elect to purchase less than 175,000 megawatts per year, subject to a
minimum of 75,000 megawatts per year, upon payment of a demand charge of $0.03
per kilowatt hour on the difference between 175,000 megawatts and the amount
purchased. The purchase price for electric power under the Grumman energy
purchase agreement is 82.5% of LILCo's 2-MRP rate for large industrial
consumers. Excess electricity is sold to LILCo under a 15-year generation
agreement expiring on the same date. LILCo is required to purchase all the
electric power not consumed by Grumman. LILCo's purchase price is equal to the
greater of LILCo's SC-11 capacity and energy buyback tariff rate or $0.06
per-kilowatt hour, subject in either case to a 6.0% discount.
Grumman is also obligated to purchase a minimum of 158,000 klbs of steam
per year from the Bethpage Power Plant. Grumman has an obligation to purchase a
minimum quantity of steam to maintain the QF status of the Bethpage Power Plant.
It is necessary for the Bethpage Power Plant to provide a certain amount of
thermal energy to a host facility in order to maintain its QF status.
Gas is supplied by Enron Gas Marketing Inc. ("EGM") under a long-term gas
purchase agreement with a term extending through 2004. Fuel management and
administration services are provided by Bethpage Fuel Management Inc. ("BFM"), a
wholly-owned subsidiary of the Company, under a 15-year fuel management
agreement expiring in 2004. Gas is transported under a gas services contract
with New Jersey Natural Energy ("NJNE") and a gas transportation agreement with
LILCo for local gas transportation service from the LILCo city gate to the
plant.
The Bethpage Power Plant is currently operated and maintained by General
Electric. The Company will assume operation and maintenance of the Bethpage
Power Plant no later than April 6, 1998.
The Bethpage Power Plant is located on a three-acre site adjacent to the
Grumman facility. The Company currently leases the site from Grumman, but has
entered into an agreement to purchase the site.
For 1997, the Bethpage Power Plant generated approximately 459,022,000
kilowatt-hours of electrical energy for sale to Grumman and LILCo and
approximately $34.8 million in revenue.
Lockport Power Plant -- The Lockport Power Plant is a 184 megawatt
gas-fired cogeneration facility located in Lockport, New York. The facility is
owned and operated by Lockport Energy Associates, L.P. ("LEA"). The Company owns
an indirect 11.36% limited partnership interest in LEA. The other limited
partners of LEA are: Lockport Power Cogeneration, LLC, an affiliate of Harbert
Power Corp. (19.30%); Erie Lockport Power Inc., an affiliate of UtiliCorp Power
Services (22.55%); EMPECO III, Inc., an affiliate of Continental Energy
Services, Inc. (22.31%); TPC Lockport, Inc., an affiliate of Tomen Power
Corporation (18.38%); and Lockport Power Cogeneration II, LLC, an affiliate of
Fortistar Capital, Inc. (5.0%). The 1% managing general partner is FCI Lockport
GP, Inc., an affiliate of Fortistar Capital, Inc. Affiliates of GEI, UtiliCorp
Power Services and Tomen Power Corporation also hold, in aggregate, a 0.1%
general partnership interest in LEA. The Lockport Power Plant commenced
commercial operation on December 28, 1992.
The Lockport Power Plant consists of three 41 megawatt General Electric
Frame 6 combustion turbine generators, three supplementary fired Nooter-Erickson
heat recovery steam generators, a General Electric steam turbine generator and
an auxiliary boiler. In 1997, the Lockport Power Plant operated at an average
availability of 97.0%.
The Lockport Power Plant was financed through a $177.6 million term loan
with the Chase Manhattan Bank, N.A., as agent. The loan matures in 2006.
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Electricity and steam is sold to GM under an energy sales agreement for use
at the GM Harrison plant (the "GM Plant"), which is located on a site adjacent
to the Lockport Power Plant. The energy sales agreement expires December 2007.
The energy sales agreement requires LEA to provide all of the GM Plant's steam
needs and a substantial portion of the GM Plant's electric power requirements.
Electricity is also sold to New York State Electricity and Gas Company
("NYSEG") under a power purchase agreement expiring October 2007 (the "NYSEG
Agreement"). NYSEG is required to purchase all of the electric power produced by
the Lockport Power Plant not required by GM. The price for electric power under
the NYSEG Agreement is based on fixed contractual rates for various periods. The
1997 price was 7.69c per kilowatt hour.
GM is also obligated to purchase all of its steam requirements for the GM
Plant in the amount of up to 315,800 lbs per hour from the Lockport Power Plant.
GM is obligated to purchase steam in sufficient quantities from LEA to maintain
its QF status. It is necessary for the Lockport Power Plant to produce a certain
amount of thermal energy to a host facility in order to maintain its QF status.
Natural gas for the Lockport Power Plant is supplied under three gas sales
contracts expiring October 2007 with each of (i) Aquila Energy Marketing
Corporation ("Aquila"), (ii) North American Resource Company ("NARCO"), and
(iii) ProGas Limited ("ProGas"). Tennessee Gas Pipeline Company ("Tennessee
Gas") provides firm transportation for the domestic gas from Aquila and NARCO
under a 20-year gas transportation agreement. The ProGas quantities are
transported from the Canadian border to the site by Tennessee Gas.
The Lockport Power Plant is operated by North American Energy Services
Company, an indirect 50% owned subsidiary of Montana Power Company, under an
operations and maintenance agreement terminating December 2007, with LEA having
the option to renew the term for an additional one-year period.
The Lockport Power Plant is located on a 15-acre site contiguous with the
GM Plant. LEA purchased the site from GM, leased it to the Town of Lockport
which subsequently leased it back to LEA for a term expiring on May 2025.
For 1997, the Lockport Power Plant generated approximately 1,275,233,000
kilowatt hours of electricity and had $119.6 million in revenue.
The Lockport Power Plant is involved in current litigation with NYSEG in
the Federal District Court of New York (see Item 3 -- Legal Proceedings).
Sumas Power Plant
The Sumas cogeneration facility (the "Sumas Power Plant") is a 125 megawatt
gas-fired cogeneration facility located in Sumas, Washington, near the Canadian
border. In 1991, the Company and Sumas Energy, Inc. ("SEI") formed Sumas
Cogeneration Company, L.P. ("Sumas") for the purpose of developing,
constructing, owning and operating the Sumas Power Plant. The Company is the
sole limited partner in Sumas and SEI is the general partner. On September 30,
1997, the partnership agreement governing Sumas was amended changing the
distribution percentages to the partners. As provided by the terms of the
amendment, the Company increased its percentage share of the project's cash flow
from 50% to approximately 70% through June 30, 2001. Thereafter, the Company
will receive 50% of the project's cash flow until a 24.5% pre-tax rate of return
on its original investment is achieved, at which time the Company's equity
interest in the partnership will be reduced to 0.1%. The Sumas Power Plant
commenced commercial operation in April 1993.
The Company managed the engineering, procurement and construction of the
power plant and related facilities of the Sumas Power Plant, including the gas
pipeline. The Sumas Power Plant was constructed by a Washington joint venture
formed by Industrial Power Corporation and Haskell Corporation. The Sumas Power
Plant is composed of an MS 7001EA combined cycle gas turbine manufactured by
General Electric Company, a Vogt heat recovery steam generator, a General
Electric steam turbine and a 3.5-mile gas pipeline. Since start-up in April
1993, the Sumas Power Plant has operated at an average availability of
approximately 97.4%.
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The Sumas Power Plant's $135.0 million construction and gas reserves
acquisition cost was financed through $120.0 million of construction and term
loan financing provided to Sumas and ENCO Gas, Ltd. ("ENCO"), a wholly owned
Canadian subsidiary of Sumas, by The Prudential Insurance Company of America
("Prudential") and Credit Suisse First Boston Corporation ("Credit Suisse"). The
credit facilities originally included term loans of $70.0 million at a combined
fixed interest rate of 10.28% per annum and variable rate loans of $50.0 million
currently based on the LIBOR, which are amortized over a 15-year period ending
in 2008. In September 1997, Sumas borrowed an additional $20.0 million from
Prudential and Credit Suisse.
Electrical energy generated by the Sumas Power Plant is sold to Puget Sound
Power & Light Company ("Puget") under the terms of a 20-year power sales
agreement terminating in 2013. Under the power sales agreement, Puget has agreed
to purchase an annual average of 123 megawatts of electrical energy.
The power sales agreement provides for the sale of electrical energy at a
total price equal to the sum of (i) a fixed price component and (ii) a variable
price component multiplied by an escalation factor for the year in which the
energy is delivered. The schedule of annual fixed average energy prices
(expressed in cents per kilowatt hour) in effect through 2013 under the Sumas
power sales agreement is as follows:
<TABLE>
<CAPTION>
FIXED FIXED FIXED
ENERGY ENERGY ENERGY
YEAR PRICE YEAR PRICE YEAR PRICE
---- ------ ---- ------ ---- ------
<S> <C> <C> <C> <C> <C>
1998................. 3.64c 2004........... 6.33c 2009........... 5.40c
1999................. 3.98c 2005........... 6.45c 2010........... 5.49c
2000................. 4.23c 2006........... 6.57c 2011........... 5.58c
2001................. 6.23c 2007........... 5.23c 2012........... 5.58c
2002................. 6.11c 2008........... 5.31c 2013........... 5.58c
2003................. 6.22c
</TABLE>
The variable price component is set according to a scheduled rate set forth
in the agreement, which in 1997 was 1.02c per kilowatt hour, and escalates
annually by a factor equal to the U.S. Gross National Product Implicit Price
Deflator. For 1997, the average price paid by Puget under the power sales
agreement was 4.40c per kilowatt hour. Pursuant to the power sales agreement,
Puget may displace the production of the Sumas Power Plant when the cost of
Puget's replacement power is less than the Sumas Power Plant's incremental power
generation costs. Thirty-five percent of the savings to Puget under this
displacement provision are shared with the Sumas Power Plant.
In addition to the sale of electricity to Puget, pursuant to a long-term
steam supply and dry kiln lease agreement, the Sumas Power Plant produces and
sells approximately 23,000 lbs per hour of low pressure steam to an adjacent
lumber-drying facility owned by Sumas, which has been leased to and is operated
by Socco, Inc. ("Socco"), an SEI affiliate. It is necessary to continue to
operate the dry kiln facility in order to maintain the Sumas Power Plant's QF
status.
In connection with the development of the Sumas Power Plant, Canadian
natural gas reserves located primarily in northeastern British Columbia, Canada
were acquired by Sumas through its wholly owned subsidiary, ENCO. The gas
reserves owned by ENCO totaled approximately 105 billion cubic feet as of
January 1, 1998. Firm transportation is contracted for on the Westcoast Energy
Inc. pipeline. Gas is delivered to Huntington, British Columbia, where it is
transferred into Sumas' own pipeline for transportation to the plant. ENCO is
currently supplying approximately 12,900 mmbtu per day to the Sumas Power Plant.
The remaining 12,100 mmbtu per day requirement is being supplied under a
one-year contract with West Coast Gas Services, Inc.
The Company operates and maintains the Sumas Power Plant under an operating
and maintenance agreement pursuant to which the Company is reimbursed for
certain costs and is entitled to a fixed annual fee and an incentive payment
based on project performance. This agreement has an initial term of ten years
expiring in April 2003 and provides for extensions.
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The Sumas Power Plant is located on 13.5 acres located in Sumas,
Washington, which are leased from the Port of Bellingham under the terms of a
23.5-year lease expiring in 2014, subject to renewal. The lease provides for
rental payments according to a fixed schedule.
During 1997, the Sumas Power Plant generated approximately 439,370,000
kilowatt hours of electrical energy and approximately $40.8 million of total
revenue. In 1997, the Company recognized income of approximately $8.6 million in
accordance with the terms of the Sumas partnership agreement, and recorded
revenue of $2.1 million for services performed under the operating and
maintenance agreement.
King City Power Plant
The King City cogeneration facility (the "King City Power Plant") is a 120
megawatt gas-fired combined-cycle facility located in King City, California. In
April 1996, the Company entered into a long-term operating lease for this
facility with BAF Energy ("BAF"). Under the terms of the operating lease, the
Company makes semi-annual lease payments to BAF, a portion of which is supported
by a collateral fund owned by the Company. The collateral consists of a
portfolio of investment grade and U.S. Treasury Securities that mature serially
in amounts equal to a portion of the lease payments.
The power plant consists of a General Electric Frame 7 Model EA combustion
turbine generator, a Nooter-Erickson heat recovery steam generator, an ASEA
Brown Boveri ("ABB") steam turbine generator and two Nebraska Boiler auxiliary
boilers. The King City Power Plant commenced commercial operation in 1989. Since
April 1996, the King City Power Plant has operated at an average availability of
93.4%.
Electricity generated by the King City Power Plant is sold to PG&E under a
30-year power sales agreement terminating in 2019. The power sales agreement
contains payment provisions for capacity and energy. The power sales agreement
provides for a firm capacity payment of $184 per kilowatt year for 111 megawatts
for the term of the agreement so long as the King City Power Plant delivers 80%
of the firm capacity during designated periods of the year. Additional capacity
payments are received for as-delivered capacity in excess of 111 megawatts
delivered during peak and partial peak hours. The as-delivered capacity price is
$188 per kilowatt year for 1998. Thereafter, the payment for as-delivered
capacity will be the greater of $188 per kilowatt year or PG&E's then current
as-delivered capacity rate. From January 1, 1998 through April 30, 1998,
payments for electrical energy produced are based on 100% of the interim
short-run avoided cost ("SRAC"), which is calculated pursuant to the methodology
approved by the CPUC on December 9, 1996. Following the commencement of
operations of the independent power exchange (currently scheduled for April 1,
1998), payments for electrical energy produced will be based on the energy
clearing price of the independent power exchange (referred to herein as the
"Power Exchange Price"). From May 1, 1998 through December 31, 1998, payments
for electrical energy are based on 80% of SRAC (or the Power Exchange Price,
when available) and 20% at fixed prices. The fixed average energy price in
effect for 1998 under the King City power sales agreement is 13.14c per kilowatt
hour. Thereafter, PG&E is required to pay for electrical energy actually
delivered at SRAC (or the Power Exchange Price, when available). During 1997,
SRAC averaged approximately 2.94c per kilowatt hour.
Through April 28, 1999, the power sales agreement allows for dispatchable
operation, which gives PG&E the right to curtail the number of hours per year
that the King City Power Plant operates. PG&E has an option to extend its
curtailment rights for two additional one-year terms. If PG&E exercises the
curtailment extension option, it will be required to pay an additional 0.7c per
kilowatt hour for all energy delivered from the King City Power Plant.
In addition to the sale of electricity to PG&E, the King City Power Plant
produces and sells thermal energy to a thermal host, Basic Vegetable Products,
Inc. ("BVP"), an affiliate of BAF, under a long-term contract coterminous with
the power sales agreement. It is necessary to continue to operate the host
facility in order to maintain the King City Power Plant's QF status. The BVP
facility was built in 1957 and processes between 30% and 40% of the dehydrated
onion and garlic production in the United States.
Natural gas for the King City Power Plant is supplied by Calpine Fuels
Corporation ("Calpine Fuels"), a wholly-owned subsidiary of the Company, which
purchases gas under short-term gas supply agreements.
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Natural gas is transported under a firm transportation agreement, expiring on
March 1, 1999, via a 38-mile pipeline owned and operated by PG&E.
Fee title to the premises is owned by Basic American, Inc., which has
leased the premises to an affiliate of BAF for a term equivalent to the term of
the power sales agreement for the King City Power Plant. The Company is
subleasing the premises, together with certain easements, from such affiliate of
BAF pursuant to a ground sublease for approximately 15 acres.
During 1997, the King City Power Plant generated approximately 424,879,000
kilowatt hours of electrical energy and approximately $45.8 million of total
revenue.
Gilroy Power Plant
On August 29, 1996, the Company acquired the Gilroy cogeneration facility
(the "Gilroy Power Plant"), a 120 megawatt gas-fired facility located in Gilroy,
California. The Company purchased the Gilroy Power Plant for $125.0 million plus
certain contingent consideration, which the Company currently estimates will be
approximately $24.1 million, of which $12.5 million has been paid as of December
31, 1997.
The acquisition of the Gilroy Power Plant was originally financed utilizing
non-recourse project financing in the aggregate amount of $116.0 million. Such
loan consists of a 15-year tranche in the amount of $81.0 million and an 18-year
tranche in the amount of $35.0 million and bears interest at fixed and floating
rates.
The Gilroy Power Plant consists of a General Electric Frame 7 Model EA
combustion turbine generator, an AEG-KANIS steam turbine, a Henry Vogt heat
recovery steam generator, two auxiliary boilers and an inlet chiller using a
Henry Vogt ice machine. The Gilroy Power Plant commenced commercial operation in
March 1988. Since its acquisition by the Company in August 1996, the Gilroy
Power Plant has operated at an average availability of 98.6%.
Electricity generated by the Gilroy Power Plant is sold to PG&E under an
original 30-year power sales agreement terminating in 2018. The power sales
agreement contains payment provisions for capacity and energy. The power sales
agreement provides for a firm capacity payment of $172 per kilowatt year for 120
megawatts for the term of the agreement so long as the Gilroy Power Plant
delivers 80% of the firm capacity during designated periods of the year.
Additional capacity payments are received for as-delivered capacity in excess of
120 megawatts delivered at the greater of $188 per kilowatt year or PG&E's then
current as-delivered capacity rate. In addition, through 1998 the power sales
agreement provides for payments for electrical energy actually delivered at a
price based on the SRAC (or the Power Exchange Price, when available) less
$.00132 per kilowatt hour. Thereafter, PG&E is required to pay for electrical
energy actually delivered at SRAC (or the Power Exchange Price, when available).
During 1997, SRAC averaged approximately 2.94c per kilowatt hour.
Through December 31, 1998, the power sales agreement allows for
dispatchable operation, which gives PG&E the right to curtail the number of
hours per year that the Gilroy Power Plant operates.
In addition to the sale of electricity to PG&E, the Gilroy Power Plant
produces and sells thermal energy to a thermal host, Gilroy Foods, Inc. ("Gilroy
Foods"), under a long-term contract that is coterminous with the power sales
agreement. Gilroy Foods is a recognized leader in the production of dehydrated
onions and garlic. Simultaneously with the acquisition by the Company of the
Gilroy Power Plant, Gilroy Foods was acquired by ConAgra, Inc., an international
food company. It is necessary to continue to operate the host facility in order
to maintain the Gilroy Power Plant's QF status.
Natural gas for the Gilroy Power Plant is supplied by Calpine Fuels, which
purchases gas under short-term gas supply agreements. Natural gas is transported
under a firm transportation agreement with PG&E, expiring on March 1, 1999.
The Gilroy Power Plant is located on approximately five acres of land which
are leased to the Company by Gilroy Foods. The lease term runs concurrent with
the term of the power sales agreement.
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During 1997, the Gilroy Power Plant generated approximately 485,625,000,
kilowatt hours of electrical energy for sale to PG&E and approximately $40.1
million in revenue.
Greenleaf 1 and 2 Power Plants
On April 21, 1995, Calpine completed the acquisition of the Greenleaf 1 and
2 cogeneration facilities (the "Greenleaf 1 and 2 Power Plants") for an adjusted
purchase price of $81.5 million.
On June 30, 1995, Calpine refinanced the existing debt on the Greenleaf 1
and 2 Power Plants by borrowing $76.0 million from Sumitomo Bank. The
non-recourse project financing with Sumitomo Bank is divided into two tranches,
a $60.0 million fixed rate loan facility which bears interest on the unpaid
principal at a fixed rate of 7.415% per annum, with amortization of principal
based on a fixed schedule through June 30, 2005, and a $16.0 million floating
rate loan facility which bears interest based on LIBOR plus an applicable
margin, with the amortization of principal based on a fixed schedule through
December 31, 2010.
The Company is currently negotiating to enter into a sale leaseback of the
Greenleaf 1 and 2 Power Plants. Pursuant to the sale leaseback, the Company
anticipates that the Greenleaf 1 and 2 Power Plants would be sold to an
equipment leasing finance company and the Company would enter into a 15-year
operating lease for the plants. The Company anticipates completing the sale
leaseback in the second quarter of 1998. There can be no assurance that the
Company will successfully complete the sale leaseback.
The Greenleaf 1 and 2 Power Plants have a combined natural gas requirement
of approximately 22,000 mmbtu per day. Natural gas for the Greenleaf 1 and 2
Power Plants is supplied pursuant to a gas sales agreement with Calpine Gas
Company, a wholly-owned subsidiary of the Company, expiring on the termination
of the power sales agreements for the Greenleaf 1 and 2 Power Plants.
Supplemental gas is supplied by Calpine Fuels, which purchases gas under
short-term gas supply agreements. Natural gas is transported under a firm
transportation agreement with PG&E, expiring on March 1, 1999.
Greenleaf 1 Power Plant -- The Greenleaf 1 cogeneration facility (the
"Greenleaf 1 Power Plant") is a 49.5 megawatt gas-fired cogeneration facility
located near Yuba City, California. The Greenleaf 1 Power Plant includes an
LM5000 gas turbine manufactured by General Electric, a Vogt heat recovery steam
generator and a condensing General Electric steam turbine. The Greenleaf 1 Power
Plant commenced commercial operation in March 1989. Since its acquisition by the
Company in April 1995, the Greenleaf 1 Power Plant has operated at an average
availability of approximately 91.6%.
Electricity generated by the Greenleaf 1 Power Plant is sold to PG&E under
a 30-year power sales agreement terminating in 2019 which contains payment
provisions for capacity and energy. The power sales agreement provides for a
firm capacity payment of $184 per kilowatt year for 49.2 megawatts for the term
of the agreement, so long as the Greenleaf 1 Power Plant delivers 80% of its
firm capacity during certain designated periods of the year, and an as-delivered
capacity payment for an additional 0.3 megawatts of capacity at $188 per
kilowatt year for 1998. Thereafter, the payment for as-delivered capacity will
be the greater of $188 per kilowatt year or PG&E's then current as-delivered
capacity rate. In addition, the power sales agreement provides for payments for
up to 49.5 megawatts of electrical energy actually delivered at SRAC (or the
Power Exchange Price, when available). During 1997, SRAC averaged approximately
2.94c per kilowatt hour.
In accordance with the power sales agreement, PG&E is entitled to curtail
the Greenleaf 1 Power Plant during hydro-spill periods, or during periods of
negative avoided costs. During 1997, the Greenleaf 1 Power Plant did not
experience curtailment.
In addition to the sale of electricity to PG&E, the Greenleaf 1 Power Plant
sells thermal energy, in the form of hot exhaust to dry wood waste, to a thermal
host which is owned and operated by the Company. It is necessary to continue to
operate the host facility in order to maintain the Greenleaf 1 Power Plant's QF
status.
The Greenleaf 1 Power Plant is located on 77 acres owned by the Company
near Yuba City, California.
For 1997, the Greenleaf 1 Power Plant generated approximately 255,161,000
kilowatt hours of electrical energy for sale to PG&E and approximately $15.9
million in revenue.
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Greenleaf 2 Power Plant -- The Greenleaf 2 cogeneration facility (the
"Greenleaf 2 Power Plant") is a 49.5 megawatt gas-fired cogeneration facility
located near Yuba City, California. The Greenleaf 2 Power Plant includes a STIG
LM5000 gas turbine manufactured by General Electric and a Deltak heat recovery
steam generator. The Greenleaf 2 Power Plant commenced commercial operation in
December 1989. Since its acquisition by the Company in April 1995, the Greenleaf
2 Power Plant has operated at an average availability of approximately 95.9%.
Electricity generated by the Greenleaf 2 Power Plant is sold to PG&E under
a 30-year power sales agreement terminating in 2019 which includes payment
provisions for capacity and energy. The power sales agreement provides for a
firm capacity payment of $184 per kilowatt year for 49.2 megawatts for the term
of the agreement, so long as the Greenleaf 2 Power Plant delivers 80% of its
firm capacity during certain designated periods of the year, and an as-delivered
capacity payment for an additional 0.3 megawatts of capacity at $188 per
kilowatt year through 1998. Thereafter, the payment for as-delivered capacity
will be the greater of $188 per kilowatt year or PG&E's then current
as-delivered capacity rate. In addition, the power sales agreement provides for
payments for up to 49.5 megawatts of electrical energy actually delivered at
SRAC (or the Power Exchange Price, when available). During 1997, SRAC averaged
approximately 2.94c per kilowatt hour.
In accordance with the power sales agreement, PG&E is entitled to curtail
the Greenleaf 2 Power Plant during hydro-spill periods or during any period of
negative avoided costs. During 1997, the Greenleaf 2 Power Plant did not
experience curtailment.
In addition to the sale of electricity to PG&E, the Greenleaf 2 Power Plant
sells thermal energy to Sunsweet Growers, Inc. ("Sunsweet") pursuant to a
30-year contract. Sunsweet is the largest producer of dried fruit in the United
States. It is necessary to continue to operate the host facility in order to
maintain the status of the Greenleaf 2 Power Plant as a QF.
The Greenleaf 2 Power Plant is located on 2.5 acres of land under a lease
from Sunsweet, which runs concurrent with the power sales agreement.
For 1997, the Greenleaf 2 Power Plant generated approximately 382,041,000
kilowatt hours of electrical energy for sale to PG&E and approximately $20.4
million in revenue.
Agnews Power Plant
The Agnews cogeneration facility (the "Agnews Power Plant") is a 29
megawatt gas-fired, combined-cycle cogeneration facility located on the East
Campus of the state-owned Agnews Developmental Center in San Jose, California.
Calpine holds a 20% ownership interest in GATX Calpine-Agnews, Inc., which is
the sole stockholder of O.L.S. Energy-Agnews, Inc. ("O.L.S. Energy-Agnews").
O.L.S. Energy-Agnews leases the Agnews Power Plant under a sale leaseback
arrangement. The other stockholder of GATX Calpine-Agnews, Inc. is GATX Capital
Corporation ("GATX"), which has an 80% ownership interest. In connection with
the sale leaseback arrangement, Calpine has agreed to reimburse GATX for its
proportionate share of certain payments that may be made by GATX with respect to
the Agnews Power Plant. The Company and GATX managed the development and
financing of the Agnews Power Plant, which commenced commercial operations in
December 1990.
The Company managed the engineering, construction and start-up of the
Agnews Power Plant. The construction work was performed by Power Systems
Engineering, Inc. under a turnkey contract. The power plant consists of an
LM2500 aeroderivative gas turbine manufactured by General Electric, a Deltak
unfired heat recovery steam generator and a Shin Nippon steam turbine-generator.
Since start-up, the Agnews Power Plant has operated at an average availability
of approximately 97.2%.
The total cost of the Agnews Power Plant was approximately $39.0 million.
The construction financing was provided by Credit Suisse in the amount of $28.0
million. After the commencement of commercial operation, the power plant was
sold to Nynex Credit Corporation under a sale leaseback arrangement with O.L.S.
Energy-Agnews. Under the sale leaseback, O.L.S. Energy-Agnews has entered into a
22-year lease,
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commencing March 1991, providing for the payment of a fixed base rental, renewal
options and a purchase option at fair market value at the termination of the
lease.
Electricity generated by the Agnews Power Plant is sold to PG&E under a
30-year power sales agreement terminating in 2021 which contains payment
provisions for capacity and energy. The power sales agreement provides for a
payment of $196 per kilowatt year for 24 megawatts of firm capacity for the term
of the agreement, so long as the Agnews Power Plant delivers at least 80% of its
firm capacity of 24 megawatts during certain designated periods of the year, and
an as-delivered capacity payment for an additional 4 megawatts of capacity at
$188 per kilowatt year for 1998. Thereafter, the payment for as-delivered
capacity will be the greater of $188 per kilowatt year or PG&E's then current
as-delivered capacity rate. In addition, the power sales agreement provides for
payments for up to 32 megawatts of electrical energy actually delivered at a
price equal to (i) through 1998, the product of PG&E's fixed incremental energy
rate and PG&E's utility electric generation gas cost, and (ii) thereafter, SRAC
(or the Power Exchange Price, when available). During 1997, SRAC averaged
approximately 2.94c per kilowatt hour.
Under certain circumstances, PG&E may curtail energy deliveries for up to
1,000 off-peak hours per year. During 1997, PG&E curtailed the energy purchased
under the power sales agreement by 989 hours.
In addition to the sale of electricity to PG&E, the Agnews Power Plant
produces and sells electricity and approximately 7,000 pounds per hour of steam
to the Agnews Developmental Center pursuant to a 30-year energy service
agreement. The energy service agreement provides that the State of California
will purchase from the Agnews Power Plant all of its requirements for steam (up
to a specified maximum) and for electricity for the East Campus of the Agnews
Developmental Center for the term of the agreement. Steam sales are priced at
the cost of production for the Agnews Developmental Center. Electricity sales
are priced at the rates that would otherwise be paid to PG&E by the Agnews
Developmental Center. The State of California is required to utilize the minimum
amount of steam required to maintain the Agnews Power Plant's QF status.
The supply of natural gas for the Agnews Power Plant is currently provided
under a month-to-month full requirements fuel supply agreement between O.L.S.
Energy-Agnews and Amoco Energy Trading Corporation. Natural gas is transported
under a firm gas transportation agreement with PG&E, expiring March 1, 1999.
The Agnews Power Plant is operated by the Company under an operating and
maintenance agreement pursuant to which the Company is reimbursed for certain
costs and is entitled to a fixed annual fee and an incentive payment based on
performance. This agreement expires on January 7, 2003.
The Agnews Power Plant is located on 1.4 acres of land leased from the
Agnews Development Center under the terms of a 30-year lease that expires in
2021. This lease provides for rental payments to the State of California on a
fixed payment basis until January 1, 1999, and thereafter based on the gross
revenues derived from sales of electricity by the Agnews Power Plant, as well as
a purchase option at fair market value.
During 1997, the Agnews Power Plant generated approximately 219,120,000
kilowatt hours of electrical energy and total revenue of $14.9 million. In 1997,
the Company recognized a gain of approximately $17,000 as a result of the
Company's 20% ownership interest and recorded revenue of $1.7 million for
services performed under the operating and maintenance agreement.
Watsonville Power Plant
The Watsonville cogeneration facility (the "Watsonville Power Plant") is a
28.5 megawatt gas-fire cogeneration facility located in Watsonville, California.
On June 29, 1995, the Company acquired the operating lease for this facility for
$900,000 from Ford Motor Credit Company. Under the terms of the lease, rent is
payable each month from July through December. The lease terminates on December
29, 2009. The Watsonville Power Plant commenced commercial operation in May
1990. The power plant consists of a General Electric LM2500 gas turbine, a
Deltak heat recovery steam generator and a Shin Nippon steam turbine. Since its
acquisition by the Company in June 1995, the Watsonville Power Plant has
operated at an average availability of approximately 97.0%.
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Electricity generated by the Watsonville Power Plant is sold to PG&E under
a 20-year power sales agreement terminating in 2009 which contains payment
provisions for capacity and energy. The power sales agreement provides for a
payment of $178 per kilowatt year for 20.9 megawatts of firm capacity for the
term of the agreement, so long as the Watsonville Power Plant delivers at least
80% of its firm capacity of 20.9 megawatts during certain designated periods of
the year, and an as-delivered capacity payment for all megawatts of capacity
delivered above the 20.9 megawatts of firm capacity. The power sales agreement
provides for payments of all electrical energy actually delivered. Through April
2000, 1% of energy will be sold under a fixed energy price and 99% of the energy
will be sold at SRAC (or the Power Exchange Price, when available). For 1998
through 2000, the fixed energy price is 13.90c per kilowatt hours and the
as-delivered capacity price per kilowatt year is $188. Thereafter, PG&E will pay
for energy delivered at SRAC (or the Power Exchange Price, when available) and
will pay for as-delivered capacity at the greater of $188 per kilowatt year or
PG&E's then current as-delivered capacity rate. During 1997, SRAC averaged
approximately 2.94c per kilowatt hour.
Under certain circumstances, PG&E may curtail energy deliveries for up to
400 hours between January 1 and April 15 and an additional 900 off-peak hours
from November 1 though April 30. From January 1, 1997 through December 31, 1997,
PG&E curtailed energy purchases of 1,300 hours under the power sales agreement.
During 1997, the Watsonville Power Plant produced and sold steam to Farmers
Processing, a food processor. In addition, the Watsonville Power Plant sold
process water produced from its water distillation facility to Farmer's Cold
Storage, Farmer's Processing and Cascade Properties. It is necessary to continue
to operate the host facilities in order to maintain the Watsonville Power
Plant's QF status.
Natural gas for the Watsonville Power Plant is supplied by Calpine Fuels,
which purchases gas under short-term gas supply agreements. Natural gas is
transported under a firm transportation agreement with PG&E, expiring on March
1, 1999.
The Watsonville Power Plant is located on 1.8 acres of land leased from
Norcal Foods under the terms of a 30-year lease expiring in 2010.
For 1997, the Watsonville Power Plant generated approximately 208,325,000
kilowatt hours of electrical energy for sale to PG&E and approximately $12.2
million in revenue.
West Ford Flat Power Plant
The West Ford Flat geothermal facility (the "West Ford Flat Power Plant")
consists of a 27 megawatt geothermal power plant and associated steam fields
located in the eastern portion of The Geysers area of northern California. The
West Ford Flat Power Plant includes a power plant consisting of two turbines
manufactured by Mitsubishi Heavy Industries, Inc. with rotors remanufactured by
ABB Industries, Inc., two generators manufactured by Electric Machinery, Inc.,
nine production wells and various steam leases. The West Ford Flat Power Plant
commenced commercial operation in December 1988. Since start-up, the West Ford
Flat Power Plant has operated at an average availability of approximately 98.5%.
Electricity generated by the West Ford Flat Power Plant is sold to PG&E
under a 20-year power sales agreement terminating in 2008 which contains payment
provisions for capacity and energy. The power sales agreement provides for a
firm capacity payment of $167 per kilowatt year for 27 megawatts of firm
capacity for the term of the agreement, so long as the West Ford Flat Power
Plant delivers 80% of its firm capacity during certain designated periods of the
year. In addition, the power sales agreement provides for energy payments for
electricity actually delivered based on a fixed price derived from a scheduled
forecast of energy prices over the initial ten-year term of the agreement ending
December 1998. The fixed average energy price for 1998 is 13.83c per kilowatt
hour under the West Ford Flat power sales agreement. Thereafter, PG&E is
required to pay for electrical energy actually delivered at SRAC (or the Power
Exchange Price, when available). During 1997, SRAC averaged approximately 2.94c
per kilowatt hour.
The power sales agreement provides that, under certain circumstances, PG&E
may curtail energy deliveries. During 1997, PG&E curtailed the energy purchased
under this agreement by 304 hours. Due to an
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amendment to the power sales agreement in April 1997, the Company currently does
not expect curtailment by PG&E during the remainder of the agreement.
The Company believes that the geothermal reserves that supply energy for
use by the West Ford Flat Power Plant will be sufficient to earn substantially
all of the capacity payments for the remaining term of the power sales agreement
due principally to low projected decline rates, limited development in adjacent
areas and the substantial productive acreage dedicated to the West Ford Flat
Power Plant.
The West Ford Flat Power Plant is located on 267 acres of leased land
located in The Geysers.
During 1997, the West Ford Flat Power Plant generated approximately
213,206,000 kilowatt hours of electrical energy for sale to PG&E and
approximately $35.4 million of revenue.
Bear Canyon Power Plant
The Bear Canyon facility (the "Bear Canyon Power Plant") consists of a 20
megawatt geothermal power plant and associated steam fields located in the
eastern portion of The Geysers area of northern California, two miles south of
the West Ford Flat Power Plant. The Bear Canyon Power Plant includes a power
plant consisting of two turbine generators manufactured by Mitsubishi Heavy
Industries, Inc. with rotors remanufactured by ABB Industries, Inc., as well as
nine production wells, an injection well and steam reserves. The Bear Canyon
Power Plant commenced commercial operation in October 1988. Since start-up, the
Bear Canyon Power Plant has operated at an average availability of approximately
98.2%.
Electricity generated by the Bear Canyon Power Plant is sold to PG&E under
two 10 megawatt, 20-year power sales agreements terminating in 2008 which
contain payment provisions for capacity and energy. One of the power sales
agreements provides for a firm capacity payment of $156 per kilowatt year on
four megawatts for the term of the agreement, so long as the Bear Canyon Power
Plant delivers 80% of its firm capacity during certain designated periods of the
year, and an as-delivered capacity payment for the additional six megawatts of
capacity. The other agreement provides for an as-delivered capacity payment for
the entire 10 megawatts. Both agreements provide for energy payments for
electricity actually delivered based on a fixed price basis through the initial
ten-year term of the agreement ending September 1998. The energy price is 13.83c
per kilowatt hour until September 1998 and, thereafter, PG&E will pay for energy
delivered at SRAC (or the Power Exchange Price, when available). During 1997,
SRAC averaged approximately 2.94c per kilowatt hour. The as-delivered capacity
price is $188 per kilowatt year through 1998, and, thereafter, is the greater of
$188 per kilowatt year or PG&E's then current as-delivered capacity rate.
The power sales agreement provides that, under certain circumstances, PG&E
may curtail energy deliveries. During 1997, PG&E curtailed the energy purchased
under this agreement by 304 hours. Due to an amendment to the power sales
agreement in April 1997, the Company currently does not expect curtailment by
PG&E during the remainder of the agreement.
The Company believes that the geothermal reserves for the Bear Canyon Power
Plant will be sufficient to earn substantially all of the capacity payments for
the remaining term of the power sales agreements due principally to high
reservoir pressures, low projected decline rates, limited development in
adjacent areas and the substantial productive acreage dedicated to the Bear
Canyon Power Plant.
The Bear Canyon Power Plant is located on 284 acres of land located in The
Geysers covered by two leases: one with the State of California and the other
with a private landowner.
During 1997, the Bear Canyon Power Plant generated approximately
168,285,000 kilowatt hours of electrical energy and approximately $25.3 million
of revenue.
Aidlin Power Plant
The Aidlin geothermal facility (the "Aidlin Power Plant") consists of a 20
megawatt geothermal power plant and associated steam fields located in the
western portion of The Geysers area of northern California. The Company holds an
indirect 5% ownership interest in the Aidlin Power Plant. The Company's
ownership interest is held in the form of a 10% general partnership interest in
a limited partnership (the "Aidlin
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Partnership"), which in turn owns a 50% ownership interest, as both a limited
and general partner, in Geothermal Energy Partners Ltd. ("GEP"), a limited
partnership which is the owner of the Aidlin Power Plant. MetLife Capital
Corporation owns the remaining 90% interest in the Aidlin Partnership as a
limited partner. The remaining 50% of GEP is owned by subsidiaries of Mission
Energy Company and Sumitomo Corporation. The Aidlin Power Plant commenced
commercial operation in May 1989.
The Aidlin Power Plant includes a power plant consisting of two turbine and
generator sets manufactured by Fuji Electric and ABB Industries, Inc., as well
as seven production wells and two injection wells. Since start-up, the Aidlin
Power Plant has operated at an average availability of approximately 98.9%.
The construction of the Aidlin Power Plant was financed with a $59.4
million term loan provided by Prudential, which bears interest at a fixed rate
of 10.48% per annum and matures on June 30, 2008 according to a specified
amortization schedule.
Electricity generated by the Aidlin Power Plant is sold to PG&E under two
10 megawatt, 20-year power sales agreements terminating in 2009 which contain
payment provisions for capacity and energy. The power sales agreements provide
for an aggregate firm capacity payment for 17 megawatts of $167 per kilowatt
year for the term of the agreements, so long as the Aidlin Power Plant delivers
80% of its capacity during certain designated periods of the year. In addition,
the Aidlin power sales agreements provide for energy payments for 20 megawatts
based on a schedule of fixed energy prices in effect through 1999 of 13.83c per
kilowatt hour. Thereafter, PG&E is required to pay for electrical energy
actually delivered at SRAC (or the Power Exchange Price, when available). During
1997, SRAC averaged approximately 2.94c per kilowatt hour.
Under certain circumstances, PG&E may curtail energy deliveries for up to
1,000 off-peak hours per year. During 1997, PG&E curtailed the energy purchased
under this agreement by 984 hours.
The Aidlin Power Plant is operated and maintained by the Company under an
operating and maintenance agreement pursuant to which the Company is reimbursed
for certain costs and is entitled to an incentive payment based on project
performance. This agreement expires on December 31, 1999.
The Aidlin Power Plant is located on 713.8 acres of land located in The
Geysers, which is leased by GEP from a private landowner. The lease will remain
in force so long as geothermal steam is produced in commercial quantities.
During 1997, the Aidlin Power Plant generated approximately 172,959,000
kilowatt hours of electrical energy and revenue of $25.0 million. In 1997, the
Company recognized revenue of approximately $455,000 as a result of the
Company's 5% ownership interest and $3.0 million for services performed under
the operating and maintenance agreement.
STEAM FIELDS
Thermal Power Company Steam Fields
The Company acquired Thermal Power Company ("TPC") on September 9, 1994 for
a purchase price of $66.5 million. TPC owns a 25% undivided interest in certain
geothermal steam fields located at The Geysers in northern California (the
"Thermal Power Company Steam Fields"). Union Oil Company of California ("Union
Oil") and NEC own the remaining 75% interest in the steam fields and operates
and maintains the steam fields. The Thermal Power Company Steam Fields include
the leasehold rights to 13,908 acres of steam fields which supply steam to 12
PG&E power plants located in The Geysers and include 238 production wells, 18
injection wells and 55 miles of steam-transporting pipeline. The 12 plants have
a mechanical capacity of 872 megawatts and currently have the capability to
operate at over 560 megawatts. The steam fields commenced commercial operation
in 1960.
The Thermal Power Company Steam Fields produce steam for sale to PG&E under
a long-term steam sales agreement. Under this steam sales agreement, the Company
is paid on the basis of the amount of electricity produced by the power plants
to which steam is supplied. PG&E is obligated to use its best efforts to operate
its power plants to maintain monthly and annual steam field capacity. PG&E is
contractually
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obligated to operate all of the power plants at a minimum of 40% of the field
capacity during any given year, and at 25% of the field capacity in any given
month. The price paid for steam under the steam sales agreement is determined
according to a formula that consists of the average of three indices multiplied
by a fixed price of 1.65c per kilowatt hour. The indices used are the Producer
Price Index for Crude Petroleum, the Producer Price Index for Natural Gas and
the Consumer Price Index ("CPI"). The price of steam under the steam sales
agreement in 1997 was 1.92c per kilowatt hour. The price for 1998 is estimated
to be 1.95c per kilowatt hour. In addition, TPC receives a monthly fee for
effluent disposal and maintenance. During 1997, such monthly fee was $152,000.
In March 1996, TPC, NEC and Union Oil entered into an alternative pricing
agreement with PG&E for any steam produced in excess of 40% of average field
capacity as defined in the steam sales contract. The alternative pricing
agreement is effective through December 31, 2000. Under the alternative pricing
agreement, PG&E has the option to purchase a portion of the steam that PG&E
would likely curtail under the existing steam sales agreement. The price for
this portion of steam will be set by TPC, NEC and Union Oil with the intent that
it be at competitive market prices. TPC, NEC and Union Oil will solely determine
the price and duration of these alternative prices.
The steam sales agreement with PG&E also provides for offset payments,
which constitute a remedy for insufficient steam. The offset payments are
calculated based upon a fixed amortization schedule for all power plants, which
may be adjusted for future capital expenditures, and upon the steam fields'
capacity in megawatts. In accordance with the steam sales agreement, TPC makes
offset payments at a reduced rate until total offsets calculated since July 1,
1991 equal $15.0 million. Accordingly, TPC's share of offsets in 1997 was
$582,000. In approximately 2001, when total offsets may exceed $15.0 million, in
accordance with the agreement TPC's share of offset payments to PG&E would be
approximately 3 1/2 times their current rate (as calculated at the current steam
field capacity).
The steam sales agreement with PG&E terminates two years after the closing
of the last operating power plant. In addition, PG&E may terminate the contract
earlier with a one-year written notice. If PG&E terminates in accordance with
the steam sales agreement, TPC will provide capacity maintenance services for
five years after the termination date, and will retain a right of first refusal
to purchase the PG&E facilities at PG&E's unamortized cost. Alternatively, TPC
may terminate the agreement with a two-year written notice to PG&E. If TPC
terminates, PG&E has the right to take assignment of the Thermal Power Company
Steam Fields' facilities on the date of termination. In that case, TPC would
continue to pay offset payments for three years following the date of
termination. Under the steam sales agreement, PG&E may retire older power plants
upon a minimum of six-months' notice. TPC is unable to predict PG&E's schedule
for the retirement of such power plants, which may change from time to time. If
steam is abandoned (i.e., cannot be transported to the remaining plants), the
abandoned steam may be delivered for use to other PG&E power plants, subject to
existing contract conditions, or to other customers upon closure of a PG&E power
plant.
The Thermal Power Company Steam Fields currently supply steam sufficient to
operate the PG&E power plants at approximately 60% of their combined mechanical
capacity. This percentage reflects a decline in productivity since the
commencement of operations. While it is not possible to accurately predict
long-term steam field productivity, the Company has estimated that the current
annual rate of decline in steam field productivity of the Thermal Power Company
Steam Fields is approximately 8%. The Company expects steam field productivity
to continue to decline in the future. The City of Santa Rosa, California, has
selected a proposal jointly submitted by the Company and Union Oil to construct
a water injection project utilizing tertiary treated wastewater from the City of
Santa Rosa. This project is expected to partially offset the anticipated rate of
decline in steam field productivity. The implementation of this project, if
completed, is subject to certain conditions, including the receipt of state and
federal funding.
PG&E has recently announced its intention to sell all of its power
generating facilities in The Geysers that purchase steam from TPC and the PG&E
Unit 13 and PG&E Unit 16 Steam Fields. The Company cannot predict the impact
that any such sale would have on the Company's results of operations or
financial condition.
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In conjunction with Union Oil and NEC, TPC holds a right of first refusal
to match any sales offer for PG&E's 12 power plants which are served by the
Thermal Power Company Steam Fields. It cannot be determined at this time whether
PG&E will complete the sale of the power plants or whether Union Oil, NEC and
TPC will exercise their right of first refusal. On February 13, 1998, Union Oil,
NEC and TPC filed a protest with the CPUC objecting to certain aspects of PG&E's
application to sell the power plants. In addition, Union Oil, NEC and TPC have
commenced arbitration proceedings with PG&E under the steam sales agreement in a
dispute over the interpretation of contract provisions concerning minimum
operation levels of the power plants.
During 1997, the PG&E power plants produced 3,487,592,000 kilowatt hours of
electrical energy of which the Company's 25% share is 871,898,000 kilowatt hours
for approximately $15.8 million of revenue.
PG&E Unit 13 and Unit 16 Steam Fields
The Company holds the leasehold rights to 1,631 acres of steam fields (the
"PG&E Unit 13 and Unit 16 Steam Fields") that supply steam to PG&E's Unit 13
power plant (the "Unit 13") and PG&E's Unit 16 power plant (the "Unit 16"), all
of which are located in The Geysers. The PG&E Unit 13 Steam Field includes 956
acres, 28 production wells, five injection wells and five miles of pipeline, and
commenced commercial operations in May 1980. The PG&E Unit 16 Steam Field
includes 675 acres, 19 producing wells, two injection wells, and three miles of
pipeline, and commenced commercial operation in October 1985.
The PG&E Unit 13 and Unit 16 Steam Fields produce steam for sale to PG&E
under long-term steam sales agreements. Under the steam sales agreements with
PG&E, the Company is paid for steam on the basis of the amount of electricity
produced by Unit 13 and Unit 16. The price paid for steam under the PG&E Unit 13
and Unit 16 Steam Fields agreements is determined according to a formula that is
essentially a weighted average of PG&E's fossil (oil and gas) fuel price and
PG&E's nuclear fuel price. The price of steam for 1997 was 0.95c per kilowatt
hour. The Company receives an additional 0.05c per kilowatt hour from PG&E for
the disposal of liquid effluents produced at Unit 13 and Unit 16.
During conditions of hydro-spill, PG&E may curtail energy deliveries from
Unit 13 and Unit 16 which would reduce deliveries of steam under this agreement.
Curtailments are primarily the result of a higher degree of precipitation during
the period, which results in higher levels of energy generation by hydroelectric
power facilities that supply electricity for sale by PG&E. In the event of any
such curtailment, the Company's results of operations may be materially
adversely affected. PG&E curtailed approximately 37,371,590 kilowatt hours under
the steam sales agreement during 1997.
The steam sales agreement with PG&E continues in effect for as long as
either Unit 13 or Unit 16 remains in commercial operation for PG&E, which
depends in part on maintaining the productive capacity of the respective steam
fields. However, PG&E may terminate the agreement if the quantity, quality or
purity of the steam is such that the operation of Unit 13 or Unit 16 becomes
economically impractical. No assurance can be given that the operation of either
Unit 13 or Unit 16 will not become economically impractical at any time.
The Company is required to supply a sufficient quantity of steam of
specified quality to Unit 16. If an insufficient quantity of steam is delivered,
the Company may be subject to penalty provisions, including suspension of PG&E's
obligation to pay for steam delivered. Specifically, if the Company fails to
deliver to Unit 16 in any calendar month a sufficient quantity of steam adequate
to operate the power plant at or above a capacity factor of 50%, no payment
shall be made for steam delivered to such Unit during such month until the cost
of that Unit has been completely amortized by PG&E.
In order to increase the efficiency of Unit 13 by approximately 20%, the
Company agreed to purchase new rotors for $10.8 million. In exchange, PG&E
agreed to amend the steam sales agreement to remove the penalty provision for a
failure to deliver a sufficient quantity of steam to Unit 13 and to require PG&E
to operate at variable pressure operations which will optimize production at the
PG&E Unit 13 and Unit 16 Steam Fields.
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The PG&E Unit 13 and Unit 16 Steam Fields currently supply steam sufficient
to operate Unit 13 and Unit 16 at approximately 77% of their combined nameplate
capacities. This percentage reflects a decline in the productivity of the PG&E
Unit 13 and Unit 16 Steam Fields since the commencement of operations of Unit 13
and Unit 16. While it is not possible to accurately predict long-term steam
field productivity, the Company has estimated that the annual rate of decline in
steam field productivity of the PG&E Unit 13 and Unit 16 Steam Fields was
approximately 6.0% in 1997. The Company expects steam field productivity to
continue to decline in the future, but at reduced annual rates of decline. The
Company considered these declines in steam field productivity in developing its
original projections for the PG&E Unit 13 and Unit 16 Steam Fields at the time
the Company acquired its initial interest in 1990. The Company plans to
partially offset the expected rate of decline by implementing enhanced water
injection and power plant improvements.
PG&E has recently announced its intention to sell all of its power
generating facilities in The Geysers that purchase steam from Thermal Power
Company and the PG&E Unit 13 and PG&E Unit 16 Steam Fields. The Company cannot
predict the impact that any such sale would have on the Company's results of
operations or financial condition.
The Company has filed a protest with the CPUC challenging certain aspects
of PG&E's application to sell Units 13 and 16. In addition, the Company has
filed an action in state court seeking a declaratory judgment and injunctive
relief to prohibit PG&E from assigning the steam contract to a third party
through its sale of the power plants.
During 1997, the PG&E Unit 13 and Unit 16 Steam Fields produced sufficient
steam to permit Unit 13 and Unit 16 to produce approximately 1,295,000,000
kilowatt hours of electrical energy and approximately $13.0 million of revenue.
SMUDGEO #1 Steam Fields
The Company holds the leasehold rights to 394 acres of steam fields that
supply steam to the power plant for the Sacramento Municipal Utility District
("SMUD") SMUDGEO #1 steam fields (the "SMUDGEO #1 Steam Fields"). The SMUD power
plant has a nameplate capacity of 72 megawatts and currently operates at an
output of 50 megawatts. The SMUDGEO #1 Steam Fields include 19 producing wells,
one injection well and two and one half miles of pipeline. Commercial operation
of the SMUD power plant commenced in October 1983.
The steam sales agreement with SMUD provides that SMUD will pay for steam
based upon the quantity of steam delivered to the SMUD power plant. The current
price paid for steam delivered under the steam sales agreement is $1.818 per
thousand pounds of steam, which is adjusted semi-annually based on changes in
the Gross National Product Implicit Price Deflator Index and Producers Price
Index for Fuels, Related Products and Power. SMUD may suspend payments for steam
in any month if the Company is unable to deliver 50% of the steam requirement
until the cost of the plant and related facilities have been completely
amortized by the value of such steam delivered to the plant. The Company
receives an additional 0.15c. per kilowatt hour from SMUD for the disposal of
liquid effluents produced at the SMUDGEO #1 Steam Fields.
The steam sales agreement with SMUD continues until the expiration or
termination of the geothermal lease covering the SMUDGEO #1 Steam Fields, which
continues for so long as steam is produced in commercial quantities. The Company
and SMUD each have the right to terminate the agreement if their respective
operations become economically impractical. In the event that SMUD exercises its
right to terminate, the Company will have no further obligation to deliver steam
to the power plants.
The SMUDGEO #1 Steam Fields currently supply steam sufficient to operate
the SMUD power plant at approximately 69% of its nameplate capacity. This
percentage reflects a decline in the productivity of the SMUDGEO #1 Steam Fields
since commencement of operations.
During 1997, the SMUDGEO #1 Steam Fields produced approximately 6,924,000
thousand pounds of steam and approximately $13.1 million of revenue.
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Cerro Prieto Steam Fields
In 1995, the Company entered into a series of agreements with Constructora
y Perforadora Latina, S.A. de C.V. ("Coperlasa") and certain of Coperlasa's
creditors pursuant to which the Company has agreed to invest up to $20 million
in the Cerro Prieto steam fields (the "Cerro Prieto Steam Fields") located in
Baja California, Mexico. The Cerro Prieto Steam Fields provide geothermal steam
to three geothermal power plants owned and operated by Comision Federal de
Electricidad ("CFE"), the Mexican national utility.
The Company's investment consists of a loan of $18.5 million and a $1.5
million payment for an option to purchase a 29% equity interest in Coperlasa for
$5.8 million.
The $18.5 million loan was made in installments throughout 1995 and 1996,
which provided capital to Coperlasa to fund the drilling of new wells and the
repair of existing wells to meet its performance under the agreement with CFE.
The loan matures in November 1999 and bears interest at an effective rate of
18.9% per annum. The Company is deferring the recognition of income on this loan
until the Cerro Prieto project generates sufficient cash flows available for
distribution to support the collectibility of interest earned.
Pursuant to a technical services agreement, the Company receives fees for
its technical services provided to Coperlasa. In addition, if the Company is
successful in assisting Coperlasa in producing steam at a lower cost, the
Company will receive 30% of the savings, if any.
The Cerro Prieto Steam Fields are located near the city of Mexicali, Baja
California, at the border of Baja California and the State of California. The
Cerro Prieto geothermal resource, which has been commercially produced by CFE
since 1973, provides approximately 70% of Baja California's electricity
requirements since this region is not connected to the Mexican national power
grid.
The steam sales agreement between Coperlasa and CFE was entered into in May
1991. Under this agreement, CFE pays for steam delivered up to 1,600 tons per
hour plus 10%. Payments for the steam delivered are made in Mexican pesos and
are adjusted on a specific unit-of-production basis by a formula that accounts
for the increases in inflation in Mexico and the United States, as well as for
the devaluation of the peso against the U.S. dollar. This agreement has a
termination date of October 2000.
GAS FIELDS
Montis Niger Gas Fields
On January 31, 1997, the Company purchased Montis Niger, Inc. a gas
production and pipeline company operating primarily in the Sacramento Basin in
northern California. On July 25, 1997, Montis Niger, Inc. was renamed Calpine
Gas Company. As of January 1, 1998, Calpine Gas Company had approximately 8.1
billion cubic feet of proven natural gas reserves and approximately 16,094 gross
acres and 15,037 net acres under lease in the Sacramento Basin. In addition,
Calpine Gas Company owns and operates an 80-mile pipeline delivering gas to the
Greenleaf 1 and 2 Power Plants which had been either produced by Calpine Gas
Company or purchased from third parties. Calpine Gas Company currently supplies
approximately 80% of the fuel requirements for the Greenleaf 1 and 2 Power
Plants.
PROJECT DEVELOPMENT AND ACQUISITION
The Company is actively engaged in the development and acquisition of power
generation projects. The Company has historically focused principally on the
development and acquisition of interests in gas-fired and geothermal power
projects, although the Company also considers projects that utilize other power
generation technologies. The Company has significant expertise in a variety of
power generation technologies and has substantial capabilities in each aspect of
the development and acquisition process, including design, engineering,
procurement, construction management, fuel and resource acquisition and
management, financing and operations.
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PROJECT DEVELOPMENT
The development of power generation projects involves numerous elements,
including evaluating and selecting development opportunities, designing and
engineering the project, obtaining power and steam sales agreements, acquiring
necessary land rights, permits and fuel resources, obtaining financing, and
managing construction. The Company intends to focus primarily on development
opportunities where the Company is able to capitalize on its expertise in
implementing an innovative and fully integrated approach to project development
in which the Company controls the entire development process. Utilizing this
approach, the Company believes that it is able to enhance the value of its
projects throughout each stage of development in an effort to maximize its
return on investment.
The Company is pursuing the development of highly efficient, low-cost
merchant power plants that seek to take advantage of inefficiencies in the
electricity market. The Company intends to sell all or a portion of the power
generated by such merchant plants into the competitive market through a
portfolio of short-, medium-and long-term power sales agreements. The Company
expects that these projects will represent a prototype for future merchant plant
developments by the Company. The Company currently plans to develop additional
low-cost, gas-fired facilities in California, Texas, New England and other high
priced power markets.
The development of power generation facilities is subject to substantial
risks. In connection with the development of a power generation facility, the
Company must generally obtain power and/or steam sales agreements, governmental
permits and approvals, fuel supply and transportation agreements, sufficient
equity capital and debt financing, electrical transmission agreements, site
agreements and construction contracts, and there can be no assurance that the
Company will be successful in doing so. In addition, project development is
subject to certain environmental, engineering and construction risks relating to
cost-overruns, delays and performance. Although the Company may attempt to
minimize the financial risks in the development of a project by securing a
favorable long-term power sales agreement, entering into power marketing
transactions, obtaining all required governmental permits and approvals and
arranging adequate financing prior to the commencement of construction, the
development of a power project may require the Company to expend significant
sums for preliminary engineering, permitting and legal and other expenses before
it can be determined whether a project is feasible, economically attractive or
financeable. If the Company were unable to complete the development of a
facility, it would generally not be able to recover its investment in such a
facility. The process for obtaining initial environmental, siting and other
governmental permits and approvals is complicated and lengthy, often taking more
than one year, and is subject to significant uncertainties. As a result of
competition, it may be difficult to obtain a power sales agreement for a
proposed project, and the prices offered in new power sales agreements for both
electric capacity and energy may be less than the prices in prior agreements.
There can be no assurance that the Company will be successful in the development
of power generation facilities in the future.
Pasadena Power Plant
Calpine has entered into a development agreement with Phillips Petroleum
Company ("Phillips") to construct and operate a 240 megawatt, gas-fired
cogeneration project at the Phillips Houston Chemical Complex ("HCC") located in
Pasadena, Texas (the "Pasadena Power Plant"). On December 19, 1996, the Company
entered into an Energy Sales Agreement with Phillips pursuant to which Phillips
will purchase all of the HCC's steam and electricity requirements of
approximately 90 megawatts. It is anticipated that the remainder of available
electricity output will be sold into the competitive market through Calpine's
power sales activities. On December 20, 1996, the Company entered into a credit
agreement with ING U.S. Capital Corporation to provide $151.8 million of
construction loans and $98.6 million of term loan non-recourse project financing
for the Pasadena Power Plant. In accordance with the terms of the agreement,
Calpine contributed $53.1 million in equity to the project. The Company
commenced construction in February 1997, with commercial operation scheduled to
begin in July 1998.
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Dighton and Tiverton Power Plants
In October 1997, Calpine entered into agreements with Energy Management
Inc. ("EMI"), a New England based power developer, to invest in the development
of two merchant power plants in New England, including a 169 megawatt gas-fired
combined-cycle merchant power plant to be located in Dighton, Massachusetts (the
"Dighton Power Plant") and a 265 megawatt gas-fired power plant to be located in
Tiverton, Rhode Island (the "Tiverton Power Plant"). The Company intends to
invest $43.0 million of equity in the development of the Tiverton Power Plant.
In October 1997, the Company invested $16.0 million in the development of the
Dighton Power Plant. This investment, which is structured as subordinated debt,
will provide the Company with a preferred payment stream at a rate of 12.07% per
annum for a period of twenty years from the commercial operation date. The
Dighton Power Plant is being developed by EMI. It is estimated that the
development of the Dighton Power Plant will cost approximately $120.0 million,
which is being financed, in part, with $104.0 million of non-recourse
construction financing. Upon commercial operation, EMI is expected to contribute
$2.0 million of equity and the construction financing will convert to a $102.0
million term loan non-recourse project financing. Construction commenced in the
fourth quarter of 1997 and commercial operation is scheduled to begin in early
1999. Upon completion, the Dighton Power Plant will be operated by EMI and will
sell its output into the New England Power Pool and to wholesale and retail
customers in the northeastern United States.
Pursuant to a letter agreement with EMI providing for an exclusivity period
for negotiations through March 31, 1998, the Company intends to invest up to
$43.0 million of equity in the development of the Tiverton Power Plant. The
Tiverton Power Plant is being developed by EMI. It is estimated that the
development of the Tiverton Power Plant will cost approximately $173.0 million.
Construction is currently scheduled to commence in late 1998 and commercial
operation is scheduled for early 2000. Upon completion, the Tiverton Power Plant
will be operated by EMI and will sell its output in the New England Power Pool
and to wholesale and retail customers in the northeastern United States.
Magic Valley Power Plant
On January 21, 1998, Calpine announced that it had been selected by Magic
Valley Electric Cooperative, Inc., located in South Texas, to begin final
negotiations to supply its electric needs from 2001 through 2021. The Company
expects the electricity will be supplied by a 700 megawatt gas-fired merchant
power plant currently under development by the Company in Edinburg, Texas.
Sutter Power Plant
In February 1997, the Company announced plans to develop a 500 megawatt
gas-fired combined cycle project in Sutter County, in northern California (the
"Sutter Power Plant"). The Sutter Power Plant would be northern California's
first newly constructed merchant power plant. The Sutter Power Plant is expected
to provide electricity to the deregulated California power market commencing in
the year 2000. The Company is currently pursuing regulatory agency permits for
this project. On January 21, 1998, the Company announced that the Sutter Power
Plant has met the California Energy Commission's Data Adequacy requirements in
its Application for Certification.
ACQUISITIONS
The Company will consider the acquisition of an interest in operating
projects as well as projects under development where Calpine would assume
responsibility for completing the development of the project. In the acquisition
of power generation facilities, Calpine generally seeks to acquire an ownership
interest in facilities that offer the Company attractive opportunities for
revenue and earnings growth, that have existing, favorable long-term power sales
agreements with major electric utilities or major users of power (i.e.,
industrial facilities), and that permit the Company to assume sole
responsibility for the operation and maintenance of the facility. In evaluating
and selecting a project for acquisition, the Company considers a variety of
factors, including the type of power generation technology utilized, the
location of the project, the terms of any existing power or thermal energy sales
agreements, gas supply and transportation agreements and wheeling
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agreements, the quantity and quality of any geothermal or other natural resource
involved, and the actual condition of the physical plant. In addition, the
Company assesses the past performance of an operating project and prepares
financial projections to determine the profitability of the project. The Company
generally seeks to obtain a significant equity interest in a project and to
obtain the operation and maintenance contract for that project.
The Company has grown substantially in recent years as a result of
acquisitions of interests in power generation facilities and steam fields. The
Company believes that although the domestic power industry is undergoing
consolidation and that significant acquisition opportunities are available, the
Company is likely to confront significant competition for acquisition
opportunities. In addition, there can be no assurance that the Company will
continue to identify attractive acquisition opportunities at favorable prices
or, to the extent that any opportunities are identified, that the Company will
be able to consummate such acquisitions.
Pittsburg Power Plant
On February 18, 1998, the Company announced that it has entered into
exclusive negotiations for a four month period ending May 31, 1998, with The Dow
Chemical Company ("Dow") to acquire its 70 megawatt gas-fired power plant and a
natural gas pipeline system located adjacent to Dow's chemical plant in
Pittsburg, California. The pipeline delivers low-cost fuel to the plant from
Sacramento Basin gas fields. As part of the transaction, The Company will enter
into long-term agreements with Dow to provide electricity and steam to its
chemical facility and steam to the nearby USS-POSCO Industries steel mill. In
addition, the Company will acquire rights to a site at the Dow chemical facility
suitable for future expansion. The Company expects to complete the acquisition
during the second quarter of 1998.
GOVERNMENT REGULATION
The Company is subject to complex and stringent energy, environmental and
other governmental laws and regulations at the federal, state and local levels
in connection with the development, ownership and operation of its energy
generation facilities. Federal laws and regulations govern transactions by
electrical and gas utility companies, the types of fuel which may be utilized by
an electric generating plant, the type of energy which may be produced by such a
plant and the ownership of a plant. State utility regulatory commissions must
approve the rates and, in some instances, other terms and conditions under which
public utilities purchase electric power from independent producers and sell
retail electric power. Under certain circumstances where specific exemptions are
otherwise unavailable, state utility regulatory commissions may have broad
jurisdiction over non-utility electric power plants. Energy producing projects
also are subject to federal, state and local laws and administrative regulations
which govern the emissions and other substances produced, discharged or disposed
of by a plant and the geographical location, zoning, land use and operation of a
plant. Applicable federal environmental laws typically have both 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 the commencement of construction or operation of an energy-
producing facility and that the facility then operate in compliance with such
permits and approvals.
FEDERAL ENERGY REGULATION
PURPA
The enactment of the Public Utility Regulatory Policies Act of 1978, as
amended ("PURPA") and the adoption of regulations thereunder by FERC provided
incentives for the development of cogeneration facilities and small power
production facilities (those utilizing renewable fuels and having a capacity of
less than 80 megawatts).
A domestic electricity generating project must be a QF under FERC
regulations in order to take advantage of certain rate and regulatory incentives
provided by PURPA. PURPA exempts owners of QFs from the Public Utility Holding
Company Act of 1935, as amended ("PUHCA"), and exempts QFs from most provisions
of the Federal Power Act (the "FPA") and, except under certain limited
circumstances, state
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laws concerning rate or financial regulation. These exemptions are important to
the Company and its competitors. The Company believes that each of the
electricity generating projects in which the Company owns an interest currently
meets the requirements under PURPA necessary for QF status. Most of the projects
which the Company is currently planning or developing are also expected to be
QFs.
PURPA provides two primary benefits to QFs. First, QFs generally are
relieved of compliance with extensive federal, state and local regulations that
control the financial structure of an electric generating plant and the prices
and terms on which electricity may be sold by the plant. Second, the FERC's
regulations promulgated under PURPA require that electric utilities purchase
electricity generated by QFs at a price based on the purchasing utility's
"avoided cost," and that the utility sell back-up power to the QF on a non-
discriminatory basis. The term "avoided cost" is defined as the incremental cost
to an electric utility of electric energy or capacity, or both, which, but for
the purchase from QFs, such utility would generate for itself or purchase from
another source. The FERC regulations also permit QFs and utilities to negotiate
agreements for utility purchases of power at rates lower than the utility's
avoided costs. Due to increasing competition for utility contracts, the current
practice is for most power sales agreements to be awarded at a rate below
avoided cost. While public utilities are not explicitly required by PURPA to
enter into long-term power sales agreements, PURPA helped to create a regulatory
environment in which it has been common for long-term agreements to be
negotiated.
In order to be a QF, a cogeneration facility must produce not only
electricity, but also useful thermal energy for use in an industrial or
commercial process for heating or cooling applications in certain proportions to
the facility's total energy output and must meet certain energy efficiency
standards. Finally, a QF (including a geothermal or hydroelectric QF or other
qualifying small power producer) must not be controlled or more than 50% owned
by an electric utility or by most electric utility holding companies, or a
subsidiary of such a utility or holding company or any combination thereof.
The Company endeavors to develop its projects, monitor compliance by the
projects with applicable regulations and choose its customers in a manner which
minimizes the risks of any project losing its QF status. Certain factors
necessary to maintain QF status are, however, subject to the risk of events
outside the Company's control. For example, loss of a thermal energy customer or
failure of a thermal energy customer to take required amounts of thermal energy
from a cogeneration facility that is a QF could cause the facility to fail
requirements regarding the level of useful thermal energy output. Upon the
occurrence of such an event, the Company would seek to replace the thermal
energy customer or find another use for the thermal energy which meets PURPA's
requirements, but no assurance can be given that this would be possible.
If one of the projects in which the Company has an interest should lose its
status as a QF, the project would no longer be entitled to the exemptions from
PUHCA and the FPA. This could trigger certain rights of termination under the
power sales agreement, could subject the project to rate regulation as a public
utility under the FPA and state law and could result in the Company
inadvertently becoming a public utility holding company by owning more than 10%
of the voting securities of, or controlling, a facility that would no longer be
exempt from PUHCA. This could cause all of the Company's remaining projects to
lose their qualifying status, because QFs may not be controlled or more than 50%
owned by such public utility holding companies. Loss of QF status may also
trigger defaults under covenants to maintain QF status in the projects' power
sales agreements, steam sales agreements and financing agreements and result in
termination, penalties or acceleration of indebtedness under such agreements
such that loss of status may be on a retroactive or a prospective basis.
If a project were to lose its QF status, the Company could attempt to avoid
holding company status (and thereby protect the QF status of its other projects)
on a prospective basis by restructuring the project, by changing its voting
interest in the entity owning the non-qualifying project to nonvoting or limited
partnership interests and selling the voting interest to an individual or
company which could tolerate the lack of exemption from PUHCA, or by otherwise
restructuring ownership of the project so as not to become a holding company.
These actions, however, would require approval of the Securities and Exchange
Commission ("SEC") or a no-action letter from the SEC, and would result in a
loss of control over the non-qualifying project, could result in a reduced
financial interest therein and might result in a modification of the Company's
operation and
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maintenance agreement relating to such project. A reduced financial interest
could result in a gain or loss on the sale of the interest in such project, the
removal of the affiliate through which the ownership interest is held from the
consolidated income tax group or the consolidated financial statements of the
Company, or a change in the results of operations of the Company. Loss of QF
status on a retroactive basis could lead to, among other things, fines and
penalties being levied against the Company and its subsidiaries and claims by
utilities for refund of payments previously made.
Under the Energy Policy Act of 1992, if a project can be qualified as an
exempt wholesale generator ("EWG"), it will be exempt from PUHCA even if it does
not qualify as a QF. Therefore, another response to the loss or potential loss
of QF status would be to apply to have the project qualified as an EWG. However,
assuming this changed status would be permissible under the terms of the
applicable power sales agreement, rate approval from FERC and approval of the
utility would be required. In addition, the project would be required to cease
selling electricity to any retail customers (such as the thermal energy
customer) and could become subject to state regulation of sales of thermal
energy.
Currently, Congress is considering proposed legislation that would amend
PURPA by eliminating the requirement that utilities purchase electricity from
QFs at avoided costs. The Company does not know whether such legislation will be
passed or what form it may take. The Company believes that if any such
legislation is passed, it would apply to new projects. As a result, although
such legislation may adversely affect the Company's ability to develop new
projects, the Company believes it would not affect the Company's existing QFs.
There can be no assurance, however, that any legislation passed would not
adversely impact the Company's existing projects.
Public Utility Holding Company Regulation
Under PUHCA, any corporation, partnership or other legal entity which owns
or controls 10% or more of the outstanding voting securities of a "public
utility company" or a company which is a "holding company" for a public utility
company is subject to registration with the SEC and regulation under PUHCA,
unless eligible for an exemption. A holding company of a public utility company
that is subject to registration is required by PUHCA to limit its utility
operations to a single integrated utility system and to divest any other
operations not functionally related to the operation of that utility system.
Approval by the SEC is required for nearly all important financial and business
dealings of the holding company. Under PURPA, most QFs are not public utility
companies under PUHCA.
The Energy Policy Act of 1992, among other things, amends PUHCA to allow
EWGs, under certain circumstances, to own and operate non-QFs without subjecting
those producers to registration or regulation under PUHCA. The expected effect
of such amendments would be to enhance the development of non-QFs which do not
have to meet the fuel, production and ownership requirements of PURPA. The
Company believes that the amendments could benefit the Company by expanding its
ability to own and operate facilities that do not qualify for QF status, but may
also result in increased competition by allowing utilities to develop such
facilities which are not subject to the constraints of PUHCA.
Federal Natural Gas Transportation Regulation
The Company has an ownership interest in and operates ten gas-fired
cogeneration projects. The cost of natural gas is ordinarily the largest expense
(other than debt costs) of a project and is critical to the project's economics.
The risks associated with using natural gas can include the need to arrange
transportation of the gas from great distances, including obtaining removal,
export and import authority if the gas is transported from Canada; the
possibility of interruption of the gas supply or transportation (depending on
the quality of the gas reserves purchased or dedicated to the project, the
financial and operating strength of the gas supplier, and whether firm or
non-firm transportation is purchased); and obligations to take a minimum
quantity of gas and pay for it (i.e., take-and-pay obligations).
Pursuant to the Natural Gas Act, FERC has jurisdiction over the
transportation and storage of natural gas in interstate commerce. With respect
to most transactions that do not involve the construction of pipeline
facilities, regulatory authorization can be obtained on a self-implementing
basis. However, pipeline rates for
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such services are subject to continuing FERC oversight. Order No. 636, issued by
FERC in April 1992, mandates the restructuring of interstate natural gas
pipeline sales and transportation services and will result in changes in the
terms and conditions under which interstate pipelines will provide
transportation services, as well as the rates pipelines may charge for such
services. The restructuring required by the rule includes (i) the separation
(unbundling) of a pipeline's sales and transportation services, (ii) the
implementation of a straight fixed-variable rate design methodology under which
all of a pipeline's fixed costs are recovered through its reservation charge,
(iii) the implementation of a capacity releasing mechanism under which holders
of firm transportation capacity on pipelines can release that capacity for
resale by the pipeline and (iv) the opportunity for pipelines to recover 100% of
their prudently incurred costs (transition costs) associated with implementing
the restructuring mandated by the rule. Pipelines were required to file tariff
sheets implementing Order No. 636 by December 31, 1992. FERC affirmed the major
components of Order No. 636 in Order Nos. 636A and B issued in August and
November 1992. The restructuring required by the rule became effective in late
1993.
STATE REGULATION
State public utility commissions ("PUCs") have historically had broad
authority to regulate both the rates charged by, and the financial activities
of, electric utilities and to promulgate regulation for implementation of PURPA.
Since a power sales agreement becomes a part of a utility's cost structure
(generally reflected in its retail rates), power sales agreements with
independent electricity producers are potentially under the regulatory purview
of PUCs and in particular the process by which the utility has entered into the
power sales agreements. If a PUC has approved the process by which a utility
secures its power supply, a PUC is generally inclined to "pass through" the
expense associated with an independent power contract to the utility's retail
customer. However, a regulatory commission under certain circumstances may
disallow the full reimbursement to a utility for the cost to purchase power from
a QF. In addition, retail sales of electricity or thermal energy by an
independent power producer may be subject to PUC regulation depending on state
law. Independent power producers which are not QFs under PURPA, or EWGs pursuant
to the Energy Policy Act of 1992, are considered to be public utilities in many
states and are subject to broad regulation by a PUC, ranging from requirement of
certificate of public convenience and necessity to regulation of organizational,
accounting, financial and other corporate matters. States may assert
jurisdiction over the siting and construction of electric generating facilities
including QFs and, with the exception of QFs, over the issuance of securities
and the sale or other transfer of assets by these facilities.
The California Public Utilities Commission ("CPUC") and the California
Joint Legislative Committee on Lowering the Cost of Electric Services commenced
proceedings and hearings related to the restructure of the California electric
services industry in 1994. The proceedings and hearings were initiated as a
result of the CPUC study and Order Instituting Rulemaking and Order Instituting
Investigation on the Commission's Proposed Policies Governing Restructuring
California's Electric Services Industry and Reforming Regulation, issued by the
CPUC on April 20, 1994. The FERC, as authorized under the Energy Policy Act of
1992, has also initiated proceedings and continues to hold workshops and
hearings on policy issues related to a more competitive electric services
industry. Though the state of California appears to be at the forefront, many
other states are in various stages of review and interest in deregulation,
moving toward a more competitive electric services industry.
On December 20, 1995, the CPUC issued its decision on California electric
industry restructure which envisioned commencement of deregulation and
implementation of customer choice beginning January 1, 1998, with all customers
participating by 2003. The decision provided for phased-in customer choice,
development of a non-discriminatory market structure, full recovery of utility
stranded costs, sanctity of existing contracts, and continuation of existing
public purpose programs including promotion of fuel diversity through a
renewable energy purchase requirement. On February 5, 1996, the CPUC issued a
procedural plan to facilitate the transition of the electric generation market
to competition. The electric restructuring roadmap focused on the multiple and
interrelated tasks to be accomplished and set forth the process to achieve the
necessary procedural milestones to be completed in order to meet the restructure
implementation goal.
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In 1996, the Joint Legislative Conference Committee held hearings related
to electric industry restructure and drafted legislation, AB 1890 (the "Bill"),
which was approved by the legislature in August 1996 and signed by the Governor
on September 23, 1996. The legislation codifies much of the December CPUC
decision as modified in January 1996 and directed the CPUC to proceed with
resolve of outstanding issues resulting in implementation of restructure no
later than January 1, 1998. The Bill accelerated the transition period in which
utilities are allowed to recover their stranded costs from five years to four
years, continued to provide for sanctity of existing contracts with provisions
for voluntary restructure, established an electricity rate freeze for the
transition period and mandated a 10% rate reduction effective January 1, 1998
for small commercial and residential customers through issuance of rate
reduction bonds, and replaced the CPUC renewable technology purchase requirement
with funds specified for use in public service programs.
On December 20, 1996, the CPUC responded to the legislation and issued an
updated procedural roadmap consistent with provisions included in the Bill.
Proceedings are ongoing at the CPUC and FERC for establishment of an Independent
Systems Operator ("ISO") responsible for centralized control and efficient and
reliable operation of the state-wide electric transmission grid, and a Power
Exchange ("PX") responsible for an efficient competitive electric energy auction
open on a non-discriminatory basis to all electric services providers. Other
proceedings now ongoing include the quantification and qualification of utility
stranded costs to be eligible for recovery through competitive transition
charges ("CTC"), market power mitigation through utility divestiture of fossil
generation plants (Pacific Gas & Electric 50%; Southern California Edison,
100%), the unbundling and establishment of rate structure for historical utility
functions, the continuation of public purpose programs and issues related to
issuance of rate reduction bonds. On May 6, 1997, the CPUC issued decisions
which eliminated phase-in and provided for implementation of direct access for
all customers beginning January 1, 1998, and the unbundling of revenue cycle
services, thereby allowing all electric service providers to participate in
metering and billing services. The CPUC has subsequently extended the
implementation date to April 1, 1998.
The California Energy Commission ("CEC") and Legislature have
responsibility for development of a competitive market mechanism for allocation
and distribution of funds made available by the legislation for enhancement of
in-state renewable resource technologies and public interest research and
development programs. Funds are to be available through the four-year transition
period to a fully competitive electric services industry.
In addition to the significant opportunity provided for power producers
such as Calpine through implementation of customer choice (direct access), the
CPUC decision and the AB 1890 restructuring legislation both recognize the
sanctity of existing contracts, provide for mitigation of utility horizontal
market power through divestiture of fossil generation and provide funds for
continuation of public services programs including fuel diversity through
enhancement for in-state renewable technologies (includes geothermal) for the
four-year transition period to a fully competitive electric services industry.
State PUCs also have jurisdiction over the transportation of natural gas by
local distribution companies ("LDCs"). Each state's regulatory laws are somewhat
different; however, all generally require the LDC to obtain approval from the
PUC for the construction of facilities and transportation services if the LDC's
generally applicable tariffs do not cover the proposed transaction. LDC rates
are usually subject to continuing PUC oversight.
REGULATION OF CANADIAN GAS
The Canadian natural gas industry is subject to extensive regulation by
governmental authorities. At the federal level, a party exporting gas from
Canada must obtain an export license from the Canadian National Energy Board
("NEB"). The NEB also regulates Canadian pipeline transportation rates and the
construction of pipeline facilities. Gas producers also must obtain a removal
permit or license from provincial authorities before natural gas may be removed
from the province, and provincial authorities may regulate intra-provincial
pipeline and gathering systems. In addition, a party importing natural gas into
the United States first must obtain an import authorization from the U.S.
Department of Energy.
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ENVIRONMENTAL REGULATIONS
The exploration for and development of geothermal resources and the
construction and operation of power projects are subject to extensive federal,
state and local laws and regulations adopted for the protection of the
environment and to regulate land use. The laws and regulations applicable to the
Company primarily involve the discharge of emissions into the water and air and
the use of water, but can also include wetlands preservation, endangered
species, waste disposal and noise regulations. These laws and regulations in
many cases require a lengthy and complex process of obtaining licenses, permits
and approvals from federal, state and local agencies.
Noncompliance with environmental laws and regulations can result in the
imposition of civil or criminal fines or penalties. In some instances,
environmental laws also may impose clean-up or other remedial obligations in the
event of a release of pollutants or contaminants into the environment. The
following federal laws are among the more significant environmental laws as they
apply to the Company. In most cases, analogous state laws also exist that may
impose similar, and in some cases more stringent, requirements on the Company as
those discussed below.
Clean Air Act
The Federal Clean Air Act of 1970 (the "Clean Air Act") provides for the
regulation, largely through state implementation of federal requirements, of
emissions of air pollutants from certain facilities and operations. As
originally enacted, the Clean Air Act sets guidelines for emissions standards
for major pollutants (i.e., sulfur dioxide and nitrogen oxide) from newly built
sources. In late 1990, Congress passed the Clean Air Act Amendments (the "1990
Amendments"). The 1990 Amendments attempt to reduce emissions from existing
sources, particularly previously exempted older power plants. The Company
believes that all of the Company's operating plants are in compliance with
federal performance standards mandated for such plants under the Clean Air Act
and the 1990 Amendments. With respect to its Aidlin geothermal plant and one of
its steam field pipelines, the Company's operations have, in certain instances,
necessitated variances under applicable California air pollution control laws.
However, the Company believes that it is in compliance with such laws with
respect to such facilities.
Clean Water Act
The Federal Clean Water Act (the "Clean Water Act") establishes rules
regulating the discharge of pollutants into waters of the United States. The
Company is required to obtain a wastewater and storm water discharge permit for
wastewater and runoff, respectively, from certain of the Company's facilities.
The Company believes that, with respect to its geothermal operations, it is
exempt from newly promulgated federal storm water requirements. The Company
believes that it is in compliance with applicable discharge requirements under
the Clean Water Act.
Resource Conservation and Recovery Act
The Resource Conservation and Recovery Act ("RCRA") regulates the
generation, treatment, storage, handling, transportation and disposal of solid
and hazardous waste. The Company believes that it is exempt from solid waste
requirements under RCRA. However, particularly with respect to its solid waste
disposal practices at the power generation facilities and steam fields located
at The Geysers, the Company is subject to certain solid waste requirements under
applicable California laws. The Company believes that its operations are in
compliance with such laws.
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
authorizes the United States Environmental Protection Agency ("EPA") to take any
necessary response action at Superfund sites, including ordering potentially
responsible parties ("PRPs") liable for the release to take or pay for such
actions. PRPs are broadly defined under CERCLA to
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include past and present owners and operators of, as well as generators of
wastes sent to, a site. As of the present time, the Company is not subject to
liability for any Superfund matters. However, the Company generates certain
wastes, including hazardous wastes, and sends certain of its wastes to
third-party waste disposal sites. As a result, there can be no assurance that
the Company will not incur liability under CERCLA in the future.
RISK FACTORS
SUBSTANTIAL LEVERAGE
The Company is substantially leveraged as a result of outstanding
indebtedness of the Company and non-recourse debt financing of certain of the
Company's subsidiaries incurred to finance the acquisition and development of
power generation facilities. As of December 31, 1997, the Company's total
consolidated indebtedness was $855.9 million, its total consolidated assets were
$1.4 billion and its stockholders' equity was $240.0 million. The ability of the
Company to meet its debt service obligations and to repay outstanding
indebtedness according to its terms will be dependent primarily upon the
performance of the power generation facilities in which the Company has an
interest.
On September 25, 1996, the Company entered into a $50.0 million three-year
revolving credit facility with The Bank of Nova Scotia as agent (the "Revolving
Credit Facility"). The Revolving Credit Facility contains certain restrictions
that significantly limit or prohibit, among other things, the ability of the
Company or its subsidiaries to incur indebtedness, make prepayments of certain
indebtedness, pay dividends, make investments, engage in transactions with
affiliates, create liens, sell assets and engage in mergers and consolidations.
The Company believes that, based on current levels of operations and
anticipated growth, cash flow from operations, together with other available
sources of funds, including borrowings under the Company's existing borrowing
arrangements, will be adequate to make required payments of principal and
interest on the Company's debt, including the 8 3/4% Senior Notes, the 10 1/2%
Senior Notes and the 9 1/4% Senior Notes, and to enable the Company to comply
with the terms of its Indentures and other debt agreements, although there can
be no assurance that this will be the case. If the Company is unable to comply
with the terms of its Indentures and other debt agreements and fails to generate
sufficient cash flow from operations in the future, the Company may be required
to refinance all or a portion of its existing debt or to obtain additional
financing. There can be no assurance that any such refinancing would be possible
or that any additional financing could be obtained, particularly in view of the
Company's high levels of debt and the debt incurrence restrictions under
existing Indentures and other debt agreements. If cash flow is insufficient and
no such refinancing or additional financing is available, the Company may be
forced to default on its debt obligations. In the event of a default under the
terms of any of the indebtedness of the Company, subject to the terms of such
indebtedness, the obligees thereunder would be permitted to accelerate the
maturity of such obligations, which could cause defaults under other obligations
of the Company.
POSSIBLE UNAVAILABILITY OF FINANCING
Each power generation facility acquired or developed by the Company will
require substantial capital investment. The Company's ability to arrange
financing and the cost of such financing are dependent upon numerous factors,
including general economic and capital market conditions, conditions in energy
markets, regulatory developments, credit availability from banks or other
lenders, investor confidence in the industry and the Company, the continued
success of the Company's current power generation facilities, and provisions of
tax and securities laws that are conducive to raising capital. There can be no
assurance that financing for new facilities will be available to the Company on
acceptable terms in the future.
The Company's power generation facilities have been financed using a
variety of leveraged financing structures, primarily consisting of non-recourse
project financing and lease obligations. As of December 31, 1997, the Company
had approximately $855.9 million of total consolidated indebtedness, of which
approximately 35% represented non-recourse project financing. Each non-recourse
project financing and lease
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obligation is structured to be fully paid out of cash flow provided by the
facility or facilities, the assets of which (together with pledges of stock or
partnership interests in the entity owning the facility) collateralize such
obligations, without any claim against the Company's general corporate funds.
Such leveraged financing permits the development of larger facilities, but also
increases the risk to the Company that its interest in a particular facility
could be impaired or that fluctuations in revenues could adversely affect the
Company's ability to meet its lease or debt obligations. The debt collateralized
by the interests of the Company in each operating facility reduces the liquidity
of such assets since any sale or transfer of a facility would be subject both to
the lien securing the facility indebtedness and to transfer restrictions in the
financing agreements. While the Company intends to utilize non-recourse or lease
financing when appropriate, there can be no assurance that market conditions and
other factors will permit the same limited equity investment by the Company or
the same substantially non-recourse nature of financings for future facilities.
In the event of a default under a financing agreement, and assuming the Company
or the other equity investors in a facility are unable or choose not to cure
such default within applicable cure periods, if any, the lenders or lessors
would generally have rights to the facility, any related geothermal resource or
natural gas reserves, related contracts and cash flows and all licenses and
permits necessary to operate the facility. In the event of foreclosure after
such a default, the Company might not retain any interest in such facility. The
Company does not believe the existence of non-recourse or lease financing will
materially affect its ability to continue to borrow funds in the future in order
to finance new facilities. There can be no assurance, however, that the Company
will continue to be able to obtain the financing required to develop its power
generation facilities on terms satisfactory to the Company.
The Company has from time to time guaranteed certain obligations of its
subsidiaries and other affiliates. There can be no assurance that, in respect of
any financings of facilities in the future, lenders or lessors will not require
the Company to guarantee the indebtedness of such future facilities, rendering
the Company's general corporate funds vulnerable in the event of a default by
such facility or related subsidiary.
IMPACT OF AVOIDED COST PRICING; ENERGY PRICE FLUCTUATIONS
PG&E pays a fixed price for each unit of electrical energy according to
schedules set forth in the long-term power sales agreements for the Bear Canyon
(20 megawatts) and West Ford Flat (27 megawatts) Power Plants. The fixed price
periods under these power sales agreements expire in September and December
1998, respectively. After the fixed price periods expire, while the basis for
the capacity and capacity bonus payments under these power sales agreements
remains the same, the energy payments adjust to interim short-run avoided cost
("SRAC"), which is calculated pursuant to the methodology approved by the CPUC
on December 9, 1996, and will continue at SRAC until the independent power
exchange has commenced operations and is functioning properly. The independent
power exchange is currently scheduled to commence operations on April 1, 1998.
Thereafter, SRAC will become the energy clearing price of the independent power
exchange (referred to herein as the "Power Exchange Price"). During 1997, SRAC
averaged approximately 2.94c per kilowatt hour. As a result, while SRAC does not
affect capacity payments under the power sales agreements, the Company's energy
revenue under these power sales agreements is expected to be materially reduced
at the expiration of the fixed price period. Such reduction may have a material
adverse effect on the Company's results of operations. The Company expects the
forecasted decline in energy revenues will be mitigated by decreased royalty
expenses and planned operating cost reductions at the facilities. In addition,
the Company will continue its strategy of offsetting such reductions through its
acquisition and development program. In addition, prices paid for the steam
delivered by the Company's steam fields are based on a formula that partially
reflects the price levels of nuclear and fossil fuels, and, therefore, a
reduction in the price levels of such fuels may reduce revenue under the steam
sales agreements for the steam fields.
POWER PROJECT DEVELOPMENT AND ACQUISITION RISKS
The development of power generation facilities is subject to substantial
risks. In connection with the development of a power generation facility, the
Company must generally obtain governmental permits and
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approvals, fuel supply and transportation agreements, sufficient equity capital
and debt financing, electrical transmission agreements, site agreements and
construction contracts, and there can be no assurance that the Company will be
successful in doing so. In addition, project development is subject to certain
environmental, engineering and construction risks relating to cost-overruns,
delays and performance. Although the Company may attempt to minimize the
financial risks in the development of a project by securing a favorable
long-term power sales agreement, entering into power marketing transactions,
obtaining all required governmental permits and approvals and arranging adequate
financing prior to the commencement of construction, the development of a power
project may require the Company to expend significant sums for preliminary
engineering, permitting, legal and other expenses before it can be determined
whether a project is feasible, economically attractive or financeable. If the
Company were unable to complete the development of a facility, it would
generally not be able to recover its investment in such a facility. The process
for obtaining initial environmental, siting and other governmental permits and
approvals is complicated and lengthy, often taking more than one year, and is
subject to significant uncertainties. As a result of competition, it may be
difficult to obtain a power sales agreement for a proposed project, and the
prices offered in new power sales agreements for both electric capacity and
energy may be less than the prices in prior agreements. There can be no
assurance that the Company will be successful in the development of power
generation facilities in the future.
The Company has grown substantially in recent years as a result of
acquisitions of interests in power generation facilities and steam fields. The
Company believes that although the domestic power industry is undergoing
consolidation and that significant acquisition opportunities are available, the
Company is likely to confront significant competition for acquisition
opportunities. In addition, there can be no assurance that the Company will
continue to identify attractive acquisition opportunities at favorable prices
or, to the extent that any opportunities are identified, that the Company will
be able to consummate such acquisitions.
START-UP RISKS
The commencement of operation of a newly constructed power plant or steam
field involves many risks, including start-up problems, the breakdown or failure
of equipment or processes and performance below expected levels of output or
efficiency. New plants have no operating history and may employ recently
developed and technologically complex equipment. Insurance is maintained to
protect against certain of these risks, warranties are generally obtained for
limited periods relating to the construction of each project and its equipment
in varying degrees, and contractors and equipment suppliers are obligated to
meet certain performance levels. Such insurance, warranties or performance
guarantees may not be adequate to cover lost revenues or increased expenses and,
as a result, a project may be unable to fund principal and interest payments
under its financing obligations and may operate at a loss. A default under such
a financing obligation could result in the Company losing its interest in such
power generation facility or steam field.
In addition, power sales agreements, which are typically entered into with
a utility early in the development phase of a project, often enable the utility
to terminate such agreement, or to retain security posted as liquidated damages,
in the event that a project fails to achieve commercial operation or certain
operating levels by specified dates or fails to make certain specified payments.
In the event such a termination right is exercised, a project may not commence
generating revenues, the default provisions in a financing agreement may be
triggered (rendering such debt immediately due and payable) and the project may
be rendered insolvent as a result.
GENERAL OPERATING RISKS
The Company currently operates 16 out of 23 of the power generation
facilities and steam fields in which it has an interest. The continued operation
of power generation facilities and steam fields involves many risks, including
the breakdown or failure of power generation equipment, transmission lines,
pipelines or other equipment or processes and performance below expected levels
of output or efficiency. To date, the Company's power generation facilities have
operated at an average availability of approximately 97%, and although from time
to time the Company's power generation facilities and steam fields have
experienced certain equipment breakdowns or failures, such breakdowns or
failures have not had a material adverse effect on the operation of such
facilities or on the Company's results of operations. Although the Company's
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facilities contain certain redundancies and back-up mechanisms, there can be no
assurance that any such breakdown or failure would not prevent the affected
facility or steam field from performing under applicable power and/or steam
sales agreements. In addition, although insurance is maintained to protect
against certain of these operating risks, the proceeds of such insurance may not
be adequate to cover lost revenues or increased expenses, and, as a result, the
entity owning such power generation facility or steam field may be unable to
service principal and interest payments under its financing obligations and may
operate at a loss. A default under such a financing obligation could result in
the Company losing its interest in such power generation facility or steam
field.
RISKS RELATED TO THE DEVELOPMENT AND OPERATION OF GEOTHERMAL ENERGY RESOURCES
The development and operation of geothermal energy resources are subject to
substantial risks and uncertainties similar to those experienced in the
development of oil and gas resources. The successful exploitation of a
geothermal energy resource ultimately depends upon the heat content of the
extractable fluids, the geology of the reservoir, the total amount of
recoverable reserves and operational factors relating to the extraction of
fluids, including operating expenses, energy price levels and capital
expenditure requirements relating primarily to the drilling of new wells. In
connection with the development of a project, the Company estimates the
productivity of the geothermal resource and the expected decline in such
productivity. The productivity of a geothermal resource may decline more than
anticipated, resulting in insufficient recoverable reserves being available for
sustained generation of the electrical power capacity desired. An incorrect
estimate by the Company or an unexpected decline in productivity could have a
material adverse effect on the Company's results of operations.
Geothermal reservoirs are highly complex, and, as a result, there exist
numerous uncertainties in determining the extent of the reservoirs and the
quantity and productivity of the steam reserves. Reservoir engineering is an
inexact process of estimating underground accumulations of steam or fluids that
cannot be measured in any precise way, and depends significantly on the quantity
and accuracy of available data. As a result, the estimates of other reservoir
specialists may differ materially from those of the Company. Estimates of
reserves are generally revised over time on the basis of the results of
drilling, testing and production that occur after the original estimate was
prepared. While the Company has extensive experience in the operation and
development of geothermal energy resources and in preparing such estimates,
there can be no assurance that the Company will be able to successfully manage
the development and operation of its geothermal reservoirs or that the Company
will accurately estimate the quantity or productivity of its steam reserves.
DEPENDENCE ON THIRD PARTIES
The nature of the Company's power generation facilities is such that each
facility generally relies on one power or steam sales agreement with a single
electric utility customer for substantially all, if not all, of such facility's
revenue over the life of the project. During 1997, approximately 80% and 5% of
the Company's total revenue was attributable to revenue received pursuant to
power and steam sales agreements with PG&E and SMUD, respectively. The power and
steam sales agreements are generally long-term agreements, covering the sale of
electricity or steam for initial terms of 20 or 30 years. However, the loss of
any one power or steam sales agreement with any of these utility customers could
have a material adverse effect on the Company's results of operations. In
addition, any material failure by any utility customer to fulfill its
obligations under a power or steam sales agreement could have a material adverse
effect on the cash flow available to the Company and, as a result, on the
Company's results of operations. PG&E has recently announced its intention to
sell all of its power generating facilities in The Geysers that purchase steam
from TPC and the PG&E Unit 13 and PG&E Unit 16 Steam Fields. Although there can
be no assurance, the Company does not expect that such sale, if consummated,
would have a material adverse impact on the Company's results of operations or
financial condition.
Furthermore, each power generation facility may depend on a single or
limited number of entities to purchase thermal energy, or to supply or transport
natural gas to such facility. The failure of any one utility customer, steam
host, gas supplier or gas transporter to fulfill its contractual obligations
could have a material adverse effect on a power project and on the Company's
business and results of operations.
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INTERNATIONAL INVESTMENTS
The Company has made an investment in the Cerro Prieto geothermal steam
fields located in Mexico and may pursue additional international investments, in
selected countries. Such investments are subject to risks and uncertainties
relating to the political, social and economic structures of those countries.
Risks specifically related to investments in non-United States projects may
include risks of fluctuations in currency valuation, currency inconvertibility,
expropriation and confiscatory taxation, increased regulation and approval
requirements and governmental policies limiting returns to foreign investors.
GOVERNMENT REGULATION
The Company's activities are subject to complex and stringent energy,
environmental and other governmental laws and regulations. The construction and
operation of power generation facilities require numerous permits, approvals and
certificates from appropriate federal, state and local governmental agencies, as
well as compliance with environmental protection legislation and other
regulations. While the Company believes that it has obtained the requisite
approvals for its existing operations and that its business is operated in
accordance with applicable laws, the Company remains subject to a varied and
complex body of laws and regulations that both public officials and private
individuals may seek to enforce. There can be no assurance that existing laws
and regulations will not be revised or that new laws and regulations will not be
adopted or become applicable to the Company that may have a material adverse
effect on the Company's business or results of operations, nor can there be any
assurance that the Company will be able to obtain all necessary licenses,
permits, approvals and certificates for proposed projects or that completed
facilities will comply with all applicable permit conditions, statutes or
regulations. In addition, regulatory compliance for the construction of new
facilities is a costly and time consuming process, and intricate and changing
environmental and other regulatory requirements may necessitate substantial
expenditures to obtain permits and may create a significant risk of expensive
delays or significant loss of value in a project if the project is unable to
function as planned due to changing requirements or local opposition.
The Company's operations are subject to the provisions of various energy
laws and regulations, including PURPA, PUHCA, and state and local regulations.
PUHCA provides for the extensive regulation of public utility holding companies
and their subsidiaries. PURPA provides to QFs and owners of QFs certain
exemptions from certain federal and state regulations, including rate and
financial regulations.
Under present federal law, the Company is not and will not be subject to
regulation as a holding company under PUHCA as long as the power plants in which
it has an interest are QFs under PURPA or are subject to another exemption. In
order to be a QF, a facility must be not more than 50% owned by an electric
utility or electric utility holding company. A QF that is a cogeneration
facility must produce not only electricity, but also useful thermal energy for
use in an industrial or commercial process or heating or cooling applications in
certain proportions to the facility's total energy output, and it must meet
certain energy efficiency standards. Therefore, loss of a thermal energy
customer could jeopardize a cogeneration facility's QF status. All geothermal
power plants up to 80 megawatts that meet PURPA's ownership requirements and
certain other standards are considered QFs. If one of the power plants in which
the Company has an interest were to lose its QF status and not otherwise receive
a PUHCA exemption, the project subsidiary or partnership in which the Company
has an interest owning or leasing that plant could become a public utility
company, which could subject the Company to significant federal, state and local
laws, including rate regulation and regulation as a public utility holding
company under PUHCA. This loss of QF status, which may be prospective or
retroactive, in turn, could cause all of the Company's other power plants to
lose QF status because, under FERC regulations, a QF cannot be owned by an
electric utility or electric utility holding company. In addition, a loss of QF
status could, depending on the power sales agreement, allow the power purchaser
to cease taking and paying for electricity or to seek refunds of past amounts
paid and thus could cause the loss of some or all contract revenues or otherwise
impair the value of a project and could trigger defaults under provisions of the
applicable project contracts and financing agreements (rendering such debt
immediately due and payable). If a power purchaser ceased taking and paying for
electricity or sought to obtain refunds of past amounts paid, there can be no
assurance that the costs incurred in connection with the project could be
recovered through sales to other purchasers.
39
<PAGE> 42
Currently, Congress is considering proposed legislation that would amend
PURPA by eliminating the requirement that utilities purchase electricity from
QFs at avoided costs. The Company does not know whether such legislation will be
passed or what form it may take. The Company believes that if any such
legislation is passed, it would apply to new projects. As a result, although
such legislation may adversely affect the Company's ability to develop new
projects, the Company believes it would not affect the Company's existing QFs.
There can be no assurance, however, that any legislation passed would not
adversely impact the Company's existing projects.
Many states are implementing or considering regulatory initiatives designed
to increase competition in the domestic power generation industry. In a December
20, 1995 policy decision, the CPUC outlined a new market structure that would
provide for a competitive power generation industry and direct access to
generation for all consumers within five years. The CPUC has issued decisions
which provide for direct access for all customers beginning April 1, 1998, and
the unbundling of all electric services. As part of its policy decision, the
CPUC indicated that power sales agreements of existing QFs would be honored. The
Company cannot predict the final form or timing of the proposed restructuring
and the impact, if any, that such restructuring would have on the Company's
existing business or results of operations.
SEISMIC DISTURBANCES
Areas in which the Company operates and is developing many of its
geothermal and gas-fired projects are subject to frequent low-level seismic
disturbances, and more significant seismic disturbances are possible. While the
Company's existing power generation facilities are built to withstand relatively
significant levels of seismic disturbances, and the Company believes it
maintains adequate insurance protection, there can be no assurance that
earthquake, property damage or business interruption insurance will be adequate
to cover all potential losses sustained in the event of serious seismic
disturbances or that such insurance will continue to be available to the Company
on commercially reasonable terms.
AVAILABILITY OF NATURAL GAS
To date, the Company's fuel acquisition strategy has included various
combinations of Company-owned gas reserves, gas prepayment contracts and short,
medium and long-term supply contracts. In its gas supply arrangements, the
Company attempts to match the fuel cost with the fuel component included in the
facility's power sales agreements, in order to minimize a project's exposure to
fuel price risk. The Company believes that there will be adequate supplies of
natural gas available at reasonable prices for each of its facilities when
current gas supply agreements expire. There can be no assurance, however, that
gas supplies will be available for the full term of the facilities' power sales
agreements, or that gas prices will not increase significantly. If gas is not
available, or if gas prices increase above the fuel component of the facilities'
power sales agreements, there could be a material adverse impact on the
Company's results of operations.
COMPETITION
The power generation industry is characterized by intense competition, and
the Company encounters competition from utilities, industrial companies and
other power producers. In recent years, there has been increasing competition in
an effort to obtain power sales agreements, and this competition has contributed
to a reduction in electricity prices. In addition, many states are implementing
or considering regulatory initiatives designed to increase competition in the
domestic power industry. In California, the CPUC has issued decisions which
provide for direct access for all customers beginning April 1, 1998. Regulatory
initiatives are also being considered in other states, including Texas, New York
and states in New England. This competition has put pressure on electric
utilities to lower their costs, including the cost of purchased electricity, and
increasing competition in the future will increase this pressure.
40
<PAGE> 43
DEPENDENCE ON SENIOR MANAGEMENT
The Company's success is largely dependent on the skills, experience and
efforts of its senior management. The loss of the services of one or more
members of the Company's senior management could have a material adverse effect
on the Company's business and development. To date, the Company generally has
been successful in retaining the services of its senior management.
QUARTERLY FLUCTUATIONS; SEASONALITY
The Company's quarterly operating results have fluctuated in the past and
may continue to do so in the future as a result of a number of factors,
including but not limited to the timing and size of acquisitions, the completion
of development projects, the timing and amount of curtailment, if any, and
variations in levels of production. Furthermore, the majority of capacity
payments under certain of the Company's power sales agreements are received
during the months of May through October.
EMPLOYEES
As of December 31, 1997, the Company employed 356 people. None of the
Company's employees are covered by collective bargaining agreements, and the
Company has never experienced a work stoppage, strike or labor dispute. The
Company considers relations with its employees to be good.
ITEM 2. PROPERTIES
The Company's principal executive office is located in San Jose, California
under a lease that expires in June 2001.
The Company, through its ownership of CGC and TPC, has leasehold interests
in 109 leases comprising 27,263 acres of federal, state and private geothermal
resource lands in The Geysers area in northern California. These leases comprise
its West Ford Flat Power Plant, Bear Canyon Power Plant, PG&E Unit 13 and Unit
16 Steam Fields, SMUDGEO #1 Steam Fields TPC's 25% undivided interest in the TPC
Steam Fields which are operated by Union Oil. In the Glass Mountain and Medicine
Lake areas in northern California, the Company holds leasehold interests in 18
leases comprising approximately 25,028 acres of federal geothermal resource
lands.
In general, under the leases, the Company has the exclusive right to drill
for, produce and sell geothermal resources from these properties and the right
to use the surface for all related purposes. Each lease requires the payment of
annual rent until commercial quantities of geothermal resources are established.
After such time, the leases require the payment of minimum advance royalties or
other payments until production commences, at which time production royalties
are payable. Such royalties and other payments are payable to landowners, state
and federal agencies and others, and vary widely as to the particular lease. The
leases are generally for initial terms varying from 10 to 20 years or for so
long as geothermal resources are produced and sold. Certain of the leases
contain drilling or other exploratory work requirements. In certain cases, if a
requirement is not fulfilled, the lease may be terminated and in other cases
additional payments may be required. The Company believes that its leases are
valid and that it has complied with all the requirements and conditions material
to their continued effectiveness. A number of the Company's leases for
undeveloped properties may expire in any given year. Before leases expire, the
Company performs geological evaluations in an effort to determine the resource
potential of the underlying properties. No assurance can be given that the
Company will decide to renew any expiring leases.
The Company, through its ownership of the Greenleaf 1 Power Plant, owns 77
acres in Sutter County, California.
The Company owns the Calpine Gas Company, which includes 112 leases
covering approximately 16,094 gross acres and 15,037 net acres. The Company
believes that its properties are adequate for its current operations.
41
<PAGE> 44
ITEM 3. LEGAL PROCEEDINGS
On September 30, 1997, a lawsuit was filed by Indeck North American Power
Fund ("Indeck") in the Circuit Court of Cook County, Illinois against Norweb
plc. and certain other parties, including the Company. Some of Indeck's claims
relate to Calpine Gordonsville, Inc.'s acquisition of a 50% interest in
Gordonsville Energy L.P. from Northern Hydro Limited and Calpine Auburndale,
Inc.'s acquisition of a 50% interest in Auburndale Power Partners Limited
Partnership from Norweb Power Services (No. 1) Limited. Indeck is claiming that
Calpine Gordonsville, Inc., Calpine Auburndale, Inc. and the Company tortiously
interfered with Indeck's contractual rights to purchase such interests and
conspired with other parties to do so. Indeck is seeking $25.0 million in
compensatory damages, $25.0 million in punitive damages, and the recovery of
attorneys' fees and costs. All of the defendants have filed motions to dismiss
such claims, which are currently pending. The Company believes that the claims
of Indeck are without merit and that the resolution of this matter will not have
a material adverse effect on the Company's financial position or results of
operations.
On February 17, 1998, the Company filed an action in the Superior Court of
California, Sonoma County, seeking injunctive and declaratory relief to prevent
PG&E from unilaterally assigning the Company's steam sales contract to the
prospective winning bidder in PG&E's recently announced auction of its power
plants in The Geysers. On January 14, 1998, PG&E filed an application with the
CPUC pursuant to Public Utilities Code Section 851 ("851 Filing"), in which it
seeks authorization to sell five electric generating plants and related assets.
Included in this proposed sale are The Geysers Geothermal Power Plants
(including Units 13 and 16) and certain of PG&E's fossil fueled steam-electric
generating plants. In PG&E's 851 Filing, PG&E announced its intention to assign
its rights and to delegate its duties under the Company's steam contract to the
successful third party purchaser of the Unit 13 and Unit 16 Power Plants. The
Company has been informed by PG&E that it will attempt to make such assignment
and delegation without first seeking and obtaining the approval and consent of
the Company. The Company is challenging the continued validity of the price term
of the steam sales contract following the proposed divestiture by PG&E of 98% of
its fossil fueled steam-electric generating plants, as the price term of the
steam sales contract is based on a complex formula that reflects PG&E's weighted
average cost of fossil and nuclear fuel from the preceding year.
In a related action, the Company has filed a protest with the CPUC which
raises issues similar to those addressed in the above-referenced lawsuit and, in
addition, challenges certain inaccuracies contained in portions of PG&E's 851
Filings related to Unit 13 and Unit 16. As no discovery has been conducted in
either matter, nor has any answer been filed in the lawsuit, the Company is
unable to predict the outcome of these cases.
An action was filed against Lockport Energy Associates, L.P. ("LEA") on
August 7, 1997 by New York State Electricity and Gas Company ("NYSEG") in the
Federal District Court for the Northern District of New York. NYSEG has
requested the Court to direct the Federal Energy Regulatory Commission (the
"FERC") and the New York Public Service Commission ("NYPSC"), to modify contract
rates to be paid to the Lockport Power Plant. On October 14, 1997, NYPSC, a
named defendant in the NYSEG action, filed a cross-claim alleging that the FERC
violated PURPA and the Federal Power Act by failing to reform the NYSEG contract
which was previously approved by the NYPSC. LEA continues to vigorously defend
this action, although it is unable to predict the outcome of this case. The
Company retains the right to require The Brooklyn Union Gas Company ("BUG") to
purchase the Company's interest in the Lockport Power Plant for $18.9 million,
less equity distributions received by the Company, at any time before December
19, 2001. In the event the NYSEG's action is successful, the Company may choose
to exercise its right to require BUG to purchase its interest in the Lockport
Power Plant.
There is currently a dispute between Texas-New Mexico Power Company ("TNP")
and Clear Lake Cogeneration Limited Partnership ("CLC"), which owns the Clear
Lake Power Plant, regarding certain costs and other amounts that TNP has
withheld from payments due under the power sales agreement. As of December 31,
1997, TNP has withheld approximately $5.4 million related to transmission
charges and has continued to withhold approximately $450,000 per month
thereafter. CLC filed a petition for declaratory order with the Texas Public
Utilities Commission ("Texas PUC") on October 2, 1997 requesting that the Texas
PUC declare that TNP's
42
<PAGE> 45
withholding is in error. This matter is pending before the Texas PUC. In
addition, as of December 31, 1997, TNP has withheld approximately $4.4 million
of standby power charges and has continued to withhold approximately $270,000
per month thereafter. CLC has filed a lawsuit in Texas against TNP claiming that
TNP is in breach of certain provisions of the power sales agreement, including
the provisions involved in the disputes described above, and is seeking in
excess of $15.0 million in damages. A trial is scheduled to begin on June 1,
1998. The Company is unable to predict the outcome of either of these
proceedings.
The Company is involved in various other claims and legal actions arising
out of the normal course of business. The Company does not expect that the
outcome of these proceedings will have a material adverse effect on the
Company's financial position or results of operations, although no assurance can
be given in this regard.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The information required hereunder is set forth under "Quarterly
Consolidated Financial Data" included in Appendix F, Note 29 of the Notes to
Consolidated Financial Statements to this report. The Company made no sales of
unregistered equity securities in the last three years.
ITEM 6. SELECTED FINANCIAL DATA
The information required hereunder is set forth under "Selected
Consolidated Financial Data" included in Appendix F to this report.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The information required hereunder is set forth under "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
included in Appendix F to this report.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required hereunder is set forth under "Report of
Independent Public Accountants," "Consolidated Balance Sheets," "Consolidated
Statements of Operations," "Consolidated Statements of Shareholder's Equity,"
"Consolidated Statements of Cash Flows," and "Notes to Consolidated Financial
Statements" included in Appendix F of this report. Other financial information
and schedules are included in Appendix F of this report.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS AND FINANCIAL DISCLOSURE
None.
ITEM 10. EXECUTIVE OFFICERS, DIRECTORS AND KEY EMPLOYEES
Incorporated by reference from Proxy Statement relating to the 1998 Annual
Meeting of Shareholders.
ITEM 11. EXECUTIVE COMPENSATION
Incorporated by reference from Proxy Statement relating to the 1998 Annual
Meeting of Shareholders.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Incorporated by reference from Proxy Statement relating to the 1998 Annual
Meeting of Shareholders.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
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<PAGE> 46
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(A)-1. FINANCIAL STATEMENTS AND OTHER INFORMATION
The following items appear in Appendix F of this report:
Selected Consolidated Financial Data
Management's Discussion and Analysis of Financial Condition and Results
of Operations
Report of Independent Public Accountants
Consolidated Balance Sheets, December 31, 1997 and 1996
Consolidated Statements of Operations for the Years Ended December 31,
1997, 1996 and 1995
Consolidated Statements of Stockholders' Equity for the Years Ended
December 31, 1997, 1996 and 1995
Consolidated Statements of Cash Flows for the Years Ended December 31,
1997, 1996 and 1995
Notes to Consolidated Financial Statements for the Years Ended December
31, 1997, 1996 and 1995
(A)-2. FINANCIAL STATEMENTS AND SCHEDULES
The following items appear in Appendix F of this report:
CALPINE CORPORATION
I Condensed Financial Information of Registrant
Report of Independent Public Accountants
Balance Sheets, December 31, 1997 and 1996
Statements of Operations for the Years Ended December 31, 1997, 1996
and 1995
Statements of Cash Flows for the Years Ended December 31, 1997, 1996
and 1995
Notes to Condensed Financial Statements for the Years Ended December
31, 1997, 1996 and 1995
II Valuation and Qualifying Accounts
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
Independent Auditor's Report
Consolidated Balance Sheet, December 31, 1997 and 1996
Consolidated Statement of Income for the Years Ended December 31,
1997, 1996 and 1995
Consolidated Statements of Changes in Partners' Equity for the Years
Ended December 31, 1997, 1996 and 1995
Consolidated Statements of Cash Flows for the Years Ended December
31, 1997, 1996 and 1995
Notes to Consolidated Financial Statements for the Year Ended
December 31, 1997
All other schedules for which provision is made in the applicable
accounting regulation of the Securities and Exchange Commission are not required
under the related instructions or are inapplicable, and therefore have been
omitted.
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(A)-3. EXHIBITS
The following exhibits are filed herewith unless otherwise indicated:
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<S> <C> <C>
3.1 -- Amended and Restated Certificate of Incorporation of Calpine
Corporation, a Delaware corporation.(l)
3.2 -- Amended and Restated Bylaws of Calpine Corporation, a
Delaware corporation.(l)
4.1 -- Indenture dated as of February 17, 1994 between the Company
and Shawmut Bank of Connecticut, National Association, as
Trustee, including form of Notes.(a)
4.2 -- Indenture dated as of May 16, 1996 between the Company and
Fleet National Bank, as Trustee, including form of Notes.(m)
10.1 -- Financing Agreements
10.1.1 -- Term and Working Capital Loan Agreement, dated as of June 1,
1990, between Calpine Geysers Company, L.P. (formerly Santa
Rosa Geothermal Company, L.P.) and Deutsche Bank AG, New
York Branch.(a)
10.1.2 -- First Amendment to Term and Working Capital Loan Agreement,
dated as of June 29, 1990, between Calpine Geysers Company,
L.P. (formerly Santa Rosa Geothermal Company, L.P.) and
Deutsche Bank AG, New York Branch.(a)
10.1.3 -- Second Amendment to Term and Working Capital Loan Agreement,
dated as of December 1, 1990, between Calpine Geysers
Company, L.P. (formerly Santa Rosa Geothermal Company, L.P.)
and Deutsche Bank AG, New York Branch.(a)
10.1.4 -- Third Amendment to Term and Working Capital Loan Agreement,
dated as of June 26, 1992, between Calpine Geysers Company,
L.P. (formerly Santa Rosa Geothermal Company, L.P.),
Deutsche Bank AG, New York Branch, National Westminster Bank
PLC, Union Bank of Switzerland, New York Branch, and The
Prudential Insurance Company of America.(a)
10.1.5 -- Fourth Amendment to Term and Working Capital Loan Agreement,
dated as of April 1, 1993, between Calpine Geysers Company,
L.P. (formerly Santa Rosa Geothermal Company, L.P.),
Deutsche Bank AG, New York Branch, National Westminster Bank
PLC, Union Bank of Switzerland, New York Branch, and The
Prudential Insurance Company of America.(a)
10.1.6 -- Construction and Term Loan Agreement, dated as of January
30, 1992, between Sumas Cogeneration Company, L.P., The
Prudential Insurance Company of America and Credit Suisse,
New York Branch.(a)
10.1.7 -- Amendment No. 1 to Construction and Term Loan Agreement,
dated as of May 24, 1993, between Sumas Cogeneration
Company, L.P., The Prudential Insurance Company of America
and Credit Suisse, New York Branch.(a)
10.1.8 -- Credit Agreement Construction Loan and Term Loan Facility,
dated as of January 10, 1990, between Credit Suisse and
O.L.S. Energy-Agnews.(a)
10.1.9 -- Amendment No. 1 to Credit Agreement Construction Loan and
Term Loan Facility, dated as of December 5, 1990, between
Credit Suisse and O.L.S. Energy-Agnews.(a)
10.1.10 -- Participation Agreement, dated as of December 1, 1990,
between O.L.S. Energy-Agnews, Nynex Credit Company, Credit
Suisse, Meridian Trust Company of California and GATX
Capital Corporation.(a)
10.1.11 -- Facility Lease Agreement, dated as of December 1, 1990,
between Meridian Trust Company of California and O.L.S.
Energy-Agnews.(a)
</TABLE>
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<PAGE> 48
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<S> <C> <C>
10.1.12 -- Project Revenues Agreement, dated as of December 1, 1990,
between O.L.S. Energy-Agnews, Meridian Trust Company of
California and Credit Suisse.(a)
10.1.13 -- Project Credit Agreement, dated as of June 30, 1995, between
Calpine Greenleaf Corporation, Greenleaf Unit One
Associates, Greenleaf Unit Two Associates, Inc. and The
Sumitomo Bank, Limited.(g)
10.1.14 -- Lease dated as of April 24, 1996 between BAF Energy A
California Limited Partnership, Lessor, and Calpine King
City Cogen, LLC, Lessee.(j)
10.1.15 -- Credit Agreement, dated as of August 28, 1996, among Calpine
Gilroy Cogen, L.P. and Banque Nationale de Paris.(l)
10.1.16 -- Credit Agreement, dated as of September 25, 1996, among
Calpine Corporation and The Bank of Nova Scotia.(m)
10.1.17 -- Credit Agreement, dated December 20, 1996, among Pasadena
Cogeneration L.P. and ING (U.S.) Capital Corporation and The
Bank Parties Hereto.(n)
10.2 -- Purchase Agreements
10.2.1 -- Purchase Agreement, dated as of April 1, 1993, between
Sonoma Geothermal Partners, L.P., Healdsburg Energy Company,
L.P. and Freeport-McMoRan Resource Partners, Limited
Partnership.(a)
10.2.2 -- Stock Purchase Agreement, dated as of June 27, 1994, between
Maxus International Energy Company, Natomas Energy Company,
Calpine Corporation and Calpine Thermal Power, Inc., and
amendment thereto dated July 28, 1994.(b)
10.2.3 -- Share Purchase Agreement dated March 30, 1995 between
Calpine Corporation, Calpine Greenleaf Corporation, Radnor
Power Corp. and LFC Financial Corp.(e)
10.2.4 -- Asset Purchase Agreement, dated as of August 28, 1996, among
Gilroy Energy Company, McCormick & Company, Incorporated and
Calpine Gilroy Cogen, L.P.(m)
10.2.5 -- Noncompetition/Earnings Contingency Agreement, dated as of
August 28, 1996, among Gilroy Energy Company, McCormick &
Company, Incorporated and Calpine Gilroy Cogen, L.P.(m)
10.3 -- Power Sales Agreements
10.3.1 -- Long-Term Energy and Capacity Power Purchase Agreement
relating to the Bear Canyon Facility, dated November 30,
1984, between Pacific Gas & Electric and Calpine Geysers
Company, L.P. (formerly Santa Rosa Geothermal Company,
L.P.), Amendment dated October 17, 1985, Second Amendment
dated October 19, 1988, and related documents.(a)
10.3.2 -- Long-Term Energy and Capacity Power Purchase Agreement
relating to the Bear Canyon Facility, dated November 29,
1984, between Pacific Gas & Electric and Calpine Geysers
Company, L.P. (formerly Santa Rosa Geothermal Company,
L.P.), and Modification dated November 29, 1984, Amendment
dated October 17, 1985, Second Amendment dated October 19,
1988, and related documents.(a)
10.3.3 -- Long-Term Energy and Capacity Power Purchase Agreement
relating to the West Ford Flat Facility, dated November 13,
1984, between Pacific Gas & Electric and Calpine Geysers
Company, L.P. (formerly Santa Rosa Geothermal Company,
L.P.), and Amendments dated May 18, 1987, June 22, 1987,
July 3, 1987 and January 21, 1988, and related documents.(a)
10.3.4 -- Agreement for Firm Power Purchase, dated as of February 24,
1989, between Puget Sound Power & Light Company and Sumas
Energy, Inc. and Amendment thereto dated September 30,
1991.(a)
</TABLE>
46
<PAGE> 49
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<S> <C> <C>
10.3.5 -- Long-Term Energy and Capacity Power Purchase Agreement,
dated April 16, 1985, between O.L.S. Energy-Agnews and
Pacific Gas & Electric Company and amendment thereto dated
February 24, 1989.(a)
10.3.6 -- Long-Term Energy and Capacity Power Purchase Agreement,
dated November 15, 1984, between Geothermal Energy Partners,
Ltd. and Pacific Gas & Electric Company, and related
documents.(a)
10.3.7 -- Long-Term Energy and Capacity Power Purchase Agreement,
dated November 15, 1984, between Geothermal Energy Partners,
Ltd. and Pacific Gas & Electric Company (see Exhibit 10.3.6
for related documents).(a)
10.3.8 -- Long-Term Energy and Capacity Power Purchase Agreement,
dated December 12, 1984, between Greenleaf Unit One
Associates, Inc. and Pacific Gas and Electric Company.(f)
10.3.9 -- Long-Term Energy and Capacity Power Purchase Agreement,
dated December 12, 1984, between Greenleaf Unit Two
Associates, Inc. and Pacific Gas and Electric Company.(f)
10.3.10 -- Long-Term Energy and Capacity Power Purchase Agreement,
dated December 5, 1985, between Calpine Gilroy Cogen, L.P.
and Pacific Gas and Electric Company, and Amendments thereto
dated December 19, 1993, July 18, 1985, June 9, 1986, August
18, 1988 and June 9, 1991.(l)
10.3.11 -- Amended and Restated Energy Sales Agreement, dated December
16, 1996, between Phillips Petroleum Company and Pasadena
Cogeneration, L.P.(n)
10.4 -- Steam Sales Agreements
10.4.1 -- Geothermal Steam Sales Agreement, dated July 19, 1979,
between Calpine Geysers Company, L.P. (formerly Santa Rosa
Geothermal Company, L.P.), and Sacramento Municipal Utility
District, and related documents.(a)
10.4.2 -- Agreement for the Sale and Purchase of Geothermal Steam,
dated March 23, 1973, between Calpine Geysers Company, L.P.
(formerly Santa Rosa Geothermal Company, L.P.) and Pacific
Gas & Electric Company, and related letter dated May 18,
1987.(a)
10.4.3 -- Thermal Energy and Kiln Lease Agreement, dated as of January
16, 1992, between Sumas Cogeneration Company, L.P. and
Socco, Inc., and Amendment thereto dated May 24, 1993.(a)
10.4.4 -- Amended and Restated Energy Service Agreement, dated as of
December 1, 1990, between the State of California and O.L.S.
Energy-Agnews.(a)
10.4.5 -- Agreement for the Sale of Geothermal Steam, dated as of July
28, 1992, between Thermal Power Company and Pacific Gas &
Electric Company.(c)
10.4.6 -- Amendment to the Agreement for the Sale of Geothermal Steam,
dated as of August 9, 1995, between Union Oil Company of
California, NEC Acquisition Company, Thermal Power Company,
and Pacific Gas and Electric Company.(h)
10.5 -- Service Agreements
10.5.1 -- Operation and Maintenance Agreement, dated as of April 5,
1990, between Calpine Operating Plant Services, Inc.
(formerly Calpine-Geysers Plant Services, Inc.) and Calpine
Geysers Company, L.P. (formerly Santa Rosa Geothermal
Company, L.P.).(a)
10.5.2 -- Amended and Restated Operating and Maintenance Agreement,
dated as of January 24, 1992, between Calpine Operating
Plant Services, Inc. and Sumas Cogeneration Company, L.P.(a)
10.5.3 -- Amended and Restated Operation and Maintenance Agreement,
dated as of December 31, 1990, between O.L.S. Energy-Agnews
and Calpine Operating Plant Services, Inc. (formerly Calpine
Cogen-Agnews, Inc.).(a)
</TABLE>
47
<PAGE> 50
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<S> <C> <C>
10.5.4 -- Operating and Maintenance Agreement, dated as of January 1,
1995, between Calpine Corporation and Geothermal Energy
Partners, Ltd.(h)
10.5.5 -- Amended and Restated Operating Agreement for the Geysers,
dated as of December 31, 1993, by and between Magma-Thermal
Power Project, a joint venture composed of NEC Acquisition
Company and Thermal Power Company, and Union Oil Company of
California.(c)
10.6 -- Gas Supply Agreements
10.6.1 -- Gas Sale and Purchase Agreement, dated as of December 23,
1991, between ENCO Gas, Ltd. and Sumas Cogeneration Company,
L.P.(a)
10.6.2 -- Gas Management Agreement, dated as of December 23, 1991,
between Canadian Hydrocarbons Marketing Inc., ENCO Gas, Ltd.
and Sumas Cogeneration Company, L.P.(a)
10.6.4 -- Natural Gas Sales Agreement, dated as of November 1, 1993,
between O.L.S. Energy-Agnews, Inc. and Amoco Energy Trading
Corporation.(a)
10.6.5 -- Natural Gas Service Agreement, dated November 1, 1993,
between Pacific Gas & Electric Company and O.L.S.
Energy-Agnews, Inc.(a)
10.7 -- Agreements Regarding Real Property
10.7.1 -- Office Lease, dated March 15, 1991, between 50 West San
Fernando Associates, L.P. and Calpine Corporation.(a)
10.7.2 -- First Amendment to Office Lease, dated April 30, 1992,
between 50 West San Fernando Associates, L.P. and Calpine
Corporation.(a)
10.7.3 -- Geothermal Resources Lease CA 1862, dated July 25, 1974,
between the United States Bureau of Land Management and
Calpine Geysers Company, L.P. (formerly Santa Rosa
Geothermal Company, L.P.).(a)
10.7.4 -- Geothermal Resources Lease PRC 5206.2, dated December 14,
1976, between the State of California and Calpine Geysers
Company, L.P. (formerly Santa Rosa Geothermal Company,
L.P.).(a)
10.7.5 -- First Amendment to Geothermal Resources Lease PRC 5206.2,
dated April 20,1994, between the State of California and
Calpine Geysers Company, L.P. (formerly Santa Rosa
Geothermal Company, L.P.).(a)
10.7.6 -- Industrial Park Lease Agreement, dated December 18, 1990,
between Port of Bellingham and Sumas Energy, Inc.(a)
10.7.7 -- First Amendment to Industrial Park Lease Agreement, dated as
of July 16, 1991, between Port of Bellingham, Sumas Energy,
Inc., and Sumas Cogeneration Company, L.P.(a)
10.7.8 -- Second Amendment to Industrial Park Lease Agreement, dated
as of December 17, 1991, between Port of Bellingham and
Sumas Cogeneration Company, L.P.(a)
10.7.9 -- Amended and Restated Cogeneration Lease, dated as of
December 1, 1990, between the State of California and O.L.S.
Energy-Agnews.(a)
10.8 -- General
10.8.1 -- Limited Partnership Agreement of Sumas Cogeneration Company,
L.P., dated as of August 28, 1991, between Sumas Energy,
Inc. and Whatcom Cogeneration Partners, L.P.(a)
10.8.2 -- First Amendment to Limited Partnership Agreement of Sumas
Cogeneration Company, L.P., dated as of January 30, 1992,
between Whatcom Cogeneration Partners, L.P. and Sumas
Energy, Inc.(a)
</TABLE>
48
<PAGE> 51
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<S> <C> <C>
10.8.3 -- Second Amendment to Limited Partnership Agreement of Sumas
Cogeneration Company, L.P., dated as of May 24, 1993,
between Whatcom Cogeneration Partners, L.P. and Sumas
Energy, Inc.(a)
10.8.4 -- Second Amended and Restated Shareholders' Agreement, dated
as of October 22, 1993, among GATX Capital Corporation,
Calpine Agnews, Inc., JGS-Agnews, Inc., and
GATX/Calpine-Agnews, Inc.(a)
10.8.5 -- Amended and Restated Reimbursement Agreement, dated October
22, 1993, between GATX Capital Corporation, Calpine Agnews,
Inc., JGS-Agnews, Inc., GATX/Calpine Agnews, Inc., and
O.L.S. Energy-Agnews, Inc.(a)
10.8.6 -- Amended and Restated Limited Partnership Agreement of
Geothermal Energy Partners Ltd., L.P., dated as of May 19,
1989, between Western Geothermal Company, L.P., Sonoma
Geothermal Company, L.P., and Cloverdale Geothermal
Partners, L.P.(a)
10.8.7 -- Assignment and Security Agreement, dated as of January 10,
1990, between O.L.S.Energy-Agnews and Credit Suisse.(a)
10.8.8 -- Pledge Agreement, dated as of January 10, 1990, between
GATX/Calpine-Agnews, Inc., and Credit Suisse.(a)
10.8.9 -- Equity Support Agreement, dated as of January 10, 1990,
between Calpine Corporation and Credit Suisse.(a)
10.8.10 -- Assignment and Security Agreement, dated as of December 1,
1990, between O.L.S. Energy-Agnews and Meridian Trust
Company of California.(a)
10.8.11 -- First Amended and Restated Limited Partner Pledge and
Security Agreement, dated as of April 1, 1993, between
Sonoma Geothermal Partners, L.P., Healdsburg Energy Company,
L.P., Calpine Geysers Company, L.P. (formerly Santa Rosa
Geothermal Company, L.P.), Freeport-McMoRan Resource
Partners, L.P., and Meridian Trust Company of California.(a)
10.8.12 -- Management Services Agreement, dated January 1, 1995,
between Calpine Corporation and Electrowatt Ltd.(k)
10.8.13 -- Guarantee Fee Agreement, dated January 1, 1995, between
Calpine Corporation and Electrowatt Ltd.(g)
10.9.1 -- Calpine Corporation Stock Option Program and forms of
agreements thereunder.(a)
10.9.2 -- Calpine Corporation 1996 Stock Incentive Plan and forms of
agreements thereunder.(l)
10.9.3 -- Calpine Corporation Employee Stock Purchase Plan and forms
of agreements thereunder.(l)
10.10.1 -- Amended and Restated Employment Agreement between Calpine
Corporation and Mr. Peter Cartwright.(l)
10.10.2 -- Senior Vice President Employment Agreement between Calpine
Corporation and Ms. Ann B. Curtis.(l)
10.10.3 -- Senior Vice President Employment Agreement between Calpine
Corporation and Mr. Lynn A. Kerby.(l)
10.10.4 -- Vice President Employment Agreement between Calpine
Corporation and Mr. Ron A.Walter.(l)
10.10.5 -- Vice President Employment Agreement between Calpine
Corporation and Mr. Robert D.Kelly.(l)
10.10.6 -- First Amended and Restated Consulting Contract between
Calpine Corporation and Mr. George J. Stathakis.(l)
</TABLE>
49
<PAGE> 52
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<S> <C> <C>
10.11 -- Form of Indemnification Agreement for directors and
officers. (l)
21.1 -- Subsidiaries of the Company.(m)
27.0 -- Financial Data Schedule.*
</TABLE>
- ---------------
(a) Incorporated by reference to Registrant's Registration Statement on Form
S-1 (Registration Statement No. 33-73160).
(b) Incorporated by reference to Registrant's Current Report on Form 8-K dated
September 9, 1994 and filed on September 26, 1994.
(c) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q
dated September 30, 1994 and filed on November 14, 1994.
(d) Incorporated by reference to Registrant's Annual Report on Form 10-K dated
December 31, 1994 and filed on March 29, 1995.
(e) Incorporated by reference to Registrant's Current Report on Form 8-K dated
April 21, 1995 and filed on May 5, 1995.
(f) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q
dated March 31, 1995 and filed on May 12, 1995.
(g) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q
dated June 30, 1995 and filed on August 14, 1995.
(h) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q
dated September 30, 1995 and filed on November 14, 1995.
(i) Incorporated by reference to Registrant's Annual Report on Form 10-K dated
December 31, 1995 and filed on March 29, 1996.
(j) Incorporated by reference to Registrant's Current Report on Form 8-K dated
May 1, 1996 and filed on May 14, 1996.
(k) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q
dated March 31, 1996 and filed on May 15, 1996.
(l) Incorporated by reference to Registrant's Registration Statement on Form
S-1 (Registration Statement No. 333-07497).
(m) Incorporated by reference to Registrant's Current Report on Form 8-K dated
August 29, 1996 and filed on September 13, 1996.
(n) Incorporated by reference to Registrant's Annual Report on Form 10-K dated
December 31, 1996, filed on March 27, 1996.
* Filed herewith.
(B) REPORTS ON FORM 8-K
No reports on Form 8-K were filed during the period from October 1, 1997 to
December 31, 1997.
50
<PAGE> 53
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this Report to be signed on
its behalf by the undersigned thereunto duly authorized.
Date: March 6, 1998 CALPINE CORPORATION
By /s/ PETER CARTWRIGHT
------------------------------------
Peter Cartwright
President, Chief Executive Officer
and
Chairman of the Board
POWER OF ATTORNEY
KNOW ALL PERSONS BY THESE PRESENTS:
That the undersigned officers and directors of Calpine Corporation do
hereby constitute and appoint Peter Cartwright and Ann B.Curtis, and each of
them, the lawful attorney and agent or attorneys and agents with power and
authority to do any and all acts and things and to execute any and all
instruments which said attorneys and agents, or either of them, determine may be
necessary or advisable or required to enable Calpine Corporation to comply with
the Securities and Exchange Act of 1934, as amended, and any rules or
regulations or requirements of the Securities and Exchange Commission in
connection with this Form 10-K Annual Report. Without limiting the generality of
the foregoing power and authority, the powers granted include the power and
authority to sign the names of the undersigned officers and directors in the
capacities indicated below to this Form 10-K Annual Report or amendments or
supplements thereto, and each of the undersigned hereby ratifies and confirms
all that said attorneys and agents, or either of them, shall do or cause to be
done by virtue hereof. This Power of Attorney may be signed in several
counterparts.
IN WITNESS WHEREOF, each of the undersigned has executed this Power of
Attorney as of the date indicated opposite the name.
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<S> <C> <C>
/s/ PETER CARTWRIGHT President, Chief Executive March 6, 1998
- -------------------------------------- Officer and Chairman of the Board
Peter Cartwright (Principal Executive Officer)
/s/ ANN B. CURTIS Senior Vice President and March 6, 1998
- -------------------------------------- Director (Principal Financial Officer)
Ann B. Curtis
/s/ JEFFREY E. GARTEN Director March 6, 1998
- --------------------------------------
Jeffrey E. Garten
/s/ SUSAN C. SCHWAB Director March 6, 1998
- --------------------------------------
Susan C. Schwab
/s/ GEORGE J. STATHAKIS Director March 6, 1998
- --------------------------------------
George J. Stathakis
/s/ JOHN O. WILSON Director March 6, 1998
- --------------------------------------
John O. Wilson
/s/ ORVILLE WRIGHT Director March 6, 1998
- --------------------------------------
V. Orville Wright
/s/ GLORIA S. GEE Controller (Principal Accounting March 6, 1998
- -------------------------------------- Officer)
Gloria S. Gee
</TABLE>
51
<PAGE> 54
CALPINE CORPORATION AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
AND OTHER INFORMATION
DECEMBER 31, 1997
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
CALPINE CORPORATION AND SUBSIDIARIES
Selected Consolidated Financial Data........................ F-2
Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. F-4
Report of Independent Public Accountants.................... F-13
Consolidated Balance Sheets December 31, 1997 and 1996...... F-14
Consolidated Statements of Operations for the Years Ended
December 31, 1997, 1996 and 1995.......................... F-15
Consolidated Statements of Stockholders' Equity for the
Years Ended December 31, 1997, 1996 and 1995.............. F-16
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1997, 1996 and 1995.......................... F-17
Notes to Consolidated Financial Statements for the Years
Ended December 31, 1997, 1996 and 1995.................... F-18
CALPINE CORPORATION
Report of Independent Public Accountants.................... F-43
Schedule I: Condensed Financial Information of Registrant
Balance Sheets, December 31, 1997 and 1996................ F-44
Condensed Statements of Operations for the Years Ended
December 31, 1997, 1996 and 1995....................... F-45
Condensed Statements of Cash Flows for the Years Ended
December 31, 1997, 1996 and 1995....................... F-46
Notes to Condensed Financial Statements for
December 31, 1997...................................... F-47
Schedule II: Valuation and Qualifying Accounts.............. F-52
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
Independent Auditor's Report................................ F-53
Consolidated Balance Sheets, December 31, 1997 and 1996..... F-54
Consolidated Statement of Income for the Years Ended
December 31, 1997, 1996 and 1995.......................... F-55
Consolidated Statement of Changes in Partners' Equity for
the Years Ended
December 31, 1997, 1996 and 1995.......................... F-56
Consolidated Statement of Cash Flows for the Years Ended
December 31, 1997, 1996 and 1995.......................... F-57
Notes to Consolidated Financial Statements for the Year
Ended December 31, 1997................................... F-58
</TABLE>
F-1
<PAGE> 55
CALPINE CORPORATION AND SUBSIDIARIES
SELECTED CONSOLIDATED FINANCIAL DATA
(IN THOUSANDS, EXCEPT RATIO DATA)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------
1993 1994 1995 1996 1997
---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenue:
Electricity and steam sales................. $ 53,000 $ 90,295 $ 127,799 $ 199,464 $ 237,277
Service contract revenue from related
parties.................................. 16,896 7,221 7,153 6,455 10,177
Income (loss) from unconsolidated
investments in power projects............ 19 (2,754) (2,854) 6,537 15,819
Interest income on loans to power
projects................................. -- -- -- 2,098 13,048
---------- ---------- ---------- ---------- ----------
Total revenue....................... 69,915 94,762 132,098 214,554 276,321
Cost of revenue............................... 42,501 52,845 77,388 129,200 153,308
---------- ---------- ---------- ---------- ----------
Gross profit.................................. 27,414 41,917 54,710 85,354 123,013
Project development expenses.................. 1,280 1,784 3,087 3,867 7,537
General and administrative expenses........... 5,080 7,323 8,937 14,696 18,289
Provision for write-off of project development
costs....................................... -- 1,038 -- -- --
---------- ---------- ---------- ---------- ----------
Income from operations...................... 21,054 31,772 42,686 66,791 97,187
Interest expense.............................. 13,825 23,886 32,154 45,294 61,466
Interest income............................... (693) (1,058) (1,555) (8,604) (14,285)
Other (income) expense........................ (440) (930) (340) 2,345 (3,153)
---------- ---------- ---------- ---------- ----------
Income before provision for income taxes and
cumulative effect of change in accounting
principle................................ 8,362 9,874 12,427 27,756 53,159
Provision for income taxes.................... 4,195 3,853 5,049 9,064 18,460
---------- ---------- ---------- ---------- ----------
Income before cumulative effect of change in
accounting principle..................... 4,167 6,021 7,378 18,692 34,699
Cumulative effect of adoption of SFAS No.
109......................................... (413) -- -- -- --
---------- ---------- ---------- ---------- ----------
Net income.................................. $ 3,754 $ 6,021 $ 7,378 $ 18,692 $ 34,699
========== ========== ========== ========== ==========
Basic earnings per common share(1)
Weighted average shares of common stock
outstanding.............................. 10,388 10,388 10,388 12,903 19,946
Basic earnings per common share............. $ 0.36 $ 0.58 $ 0.71 $ 1.45 $ 1.74
Diluted earnings per common share(1)..........
Weighted average shares of common stock
outstanding.............................. 10,879 10,921 10,957 14,879 21,016
Diluted earnings per common share........... $ 0.35 $ 0.55 $ 0.67 $ 1.26 $ 1.65
OTHER FINANCIAL DATA AND RATIOS:
Depreciation and amortization................. $ 12,540 $ 21,580 $ 26,896 $ 40,551 $ 48,935
EBITDA(2)..................................... $ 42,370 $ 53,707 $ 69,515 $ 117,379 $ 172,616
EBITDA to Consolidated Interest Expense(3).... 2.98x 2.23x 2.11x 2.41x 2.60x
Total debt to EBITDA.......................... 6.24x 6.23x 5.87x 5.12x 4.96x
Ratio of earnings to fixed charges(4)......... 2.09x 1.52x 1.46x 1.45x 1.64x
</TABLE>
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
--------------------------------------------------------------
1993 1994 1995 1996 1997
---------- ---------- ---------- ---------- ----------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
BALANCE SHEET
Cash and cash equivalents..................... $ 6,166 $ 22,527 $ 21,810 $ 95,970 $ 48,513
Property, plant and equipment, net............ 251,070 335,453 447,751 648,208 719,721
Total assets.................................. 302,256 421,372 554,531 1,031,397 1,380,956
Total liabilities............................. 288,827 402,723 529,304 828,270 1,141,000
Total stockholders' equity.................... 13,429 18,649 25,227 203,127 239,956
</TABLE>
(The information contained in the Selected Consolidated Financial Data is
derived from the audited consolidated financial statements of Calpine
Corporation and Subsidiaries.)
(See footnotes on next page)
F-2
<PAGE> 56
- ---------------
(1) In 1997, the Company adopted Statement of Financial Accounting Standards
("SFAS") No. 128, "Earnings per Share," and subsequently, in February 1998,
Staff Accounting Bulletin ("SAB") No. 98 on Computations of Earnings per
Share. In accordance with SFAS No. 128, basic earnings per common share for
all periods was computed by dividing net income by the weighted average
shares of common stock outstanding during the year. Diluted earnings per
common share for all periods was also computed in conformance with SFAS No.
128 by dividing net income by the weighted average shares of common stock
outstanding during the year and the additional number of shares that would
have been outstanding during the year if the Company's dilutive potential
shares had been issued. The treasury stock method was used to calculate the
potential number of dilutive shares associated with the Company's
outstanding stock options (see Note 2 of Notes to Consolidated Financial
Statements).
(2) EBITDA is defined as income from operations plus depreciation, capitalized
interest, other income, non-cash charges and cash received from investments
in power projects, reduced by the income from unconsolidated investments in
power projects. EBITDA is presented not as a measure of operating results,
but rather as a measure of the Company's ability to service debt. EBITDA
should not be construed as an alternative to either (i) income from
operations (determined in accordance with generally accepted accounting
principles) or (ii) cash flows from operating activities (determined in
accordance with generally accepted accounting principles).
(3) Consolidated Interest Expense is defined as total interest expense plus
one-third of all operating lease obligations, capitalized interest,
dividends paid in respect of preferred stock and cash contributions to any
employee stock ownership plan used to pay interest on loans incurred to
purchase capital stock of the Company.
(4) Earnings are defined as income before provision for taxes, extraordinary
item and cumulative effect of change in accounting principle plus cash
received from investments in power projects and fixed charges reduced by the
equity in income from investments in power projects and capitalized
interest. Fixed charges consist of interest expense, capitalized interest,
amortization of debt issuance costs and the portion of rental expenses
representative of the interest expense component.
F-3
<PAGE> 57
CALPINE CORPORATION AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Except for historical financial information contained herein, the matters
discussed in this annual report may be considered forward-looking statements
within the meaning of Section 27A of the Securities Act of 1933, as amended, and
Section 21E of the Securities Exchange Act of 1934, as amended and subject to
the safe harbor created by the Securities Litigation Reform Act of 1995. Such
statements include declarations regarding the intent, belief or current
expectations of the Company and its management. Prospective investors are
cautioned that any such forward-looking statements are not guarantees of future
performance and involve a number of risks and uncertainties; actual results
could differ materially from those indicated by such forward-looking statements.
Among the important factors that could cause actual results to differ materially
from those indicated by such forward-looking statements are: (i) that the
information is of a preliminary nature and may be subject to further adjustment,
(ii) the possible unavailability of financing, (iii) risks related to the
development, acquisition and operation of power plants, (iv) the impact of
avoided cost pricing, energy price fluctuations and gas price increases, (v) the
impact of curtailment, (vi) the seasonal nature of the Company's business, (vii)
start-up risks, (viii) general operating risks, (ix) the dependence on third
parties, (x) risks associated with international investments, (xi) risks
associated with the power marketing business, (xii) changes in government
regulation, (xiii) the availability of natural gas, (xiv) the effects of
competition, (xv) the dependence on senior management, (xvi) volatility in the
Company's stock price, (xvii) fluctuations in quarterly results and seasonality,
and (xviii) other risks identified from time to time in the Company's reports
and registration statements filed with the Securities and Exchange Commission.
GENERAL
Calpine Corporation ("Calpine") a Delaware corporation, and subsidiaries
(collectively, the "Company") is engaged in the acquisition, development,
ownership and operation of power generation facilities and the sale of
electricity and steam principally in the United States. The Company currently
has interests in 23 power plants and steam fields, having an aggregate capacity
of 2,613 megawatts. The Company currently sells electricity and steam to 16
utility and other customers, principally under long term power and steam sales
agreements, generated by power generation facilities located in six states and
Mexico. In addition, the Company has a 240 megawatt gas-fired power plant
currently under construction in Pasadena, Texas and an investment in a 169
megawatt gas-fired power plant currently under construction in Dighton,
Massachusetts. Since its inception in 1984, the Company has developed
substantial expertise in all aspects of electric power generation. The Company's
vertical integration has resulted in significant growth in recent years as the
Company has applied its extensive engineering, construction management,
operations, fuel management and financing capabilities to successfully implement
its acquisition and development program. The Company's strategy is to capitalize
on opportunities in the power market through an ongoing program to acquire,
develop, own and operate electric power generation facilities, as well as
marketing power and energy services to utilities and other end users.
The Company's net interest in power generation facilities has increased
from 297 megawatts in 1992 to 1981 megawatts at December 31, 1997, including the
power plants currently under construction. Total assets have increased from
$55.4 million as of December 31, 1992 to $1.4 billion as of December 31, 1997.
The Company's revenue has increased to $276.3 million for 1997, representing a
5-year compound annual growth rate of 48% since 1992. The Company's EBITDA (see
Selected Consolidated Financial Data) for 1997 increased to $172.6 million from
$9.9 million in 1992, representing a 5-year compound annual growth rate of 77%.
In January 1995, the Company purchased the working interest in certain of
the geothermal properties at the Pacific Gas & Electric Company ("PG&E") Unit 13
and Unit 16 Steam Fields from a third party for a purchase price of $6.75
million. On April 21, 1995, the Company acquired the stock of certain companies
that own 100% of the Greenleaf 1 and 2 Power Plants, consisting of two 49.5
megawatt gas-fired cogeneration facilities, for an adjusted purchase price of
$81.5 million. On June 29, 1995, the Company acquired the operating lease for
the Watsonville Power Plant, a 28.5 megawatt gas-fired cogeneration facility,
for a
F-4
<PAGE> 58
purchase price of $900,000. On November 17, 1995, the Company entered into a
series of agreements to invest up to $20.0 million in the Cerro Prieto Steam
Fields.
In April 1996, the Company entered into a lease transaction for the King
City Power Plant, a 120 megawatt gas-fired cogeneration facility, which required
an investment of $108.3 million, primarily related to the collateral fund
requirements. On August 29, 1996, the Company acquired the Gilroy Power Plant, a
120 megawatt gas-fired cogeneration facility, for a purchase price of $125.0
million plus certain contingent consideration, which the Company currently
estimates will amount to approximately $24.1 million, of which $12.5 million has
been paid as of December 31, 1997.
On January 31, 1997, the Company paid approximately $7.1 million to acquire
the stock of Montis Niger, Inc. (subsequently renamed Calpine Gas Company).
Calpine Gas Company has 8.1 billion cubic feet of estimated proven gas reserves
and an 80-mile pipeline system which provide gas to the Company's Greenleaf 1
and 2 Power Plants.
In February 1997, the Company commenced construction of the Pasadena Power
Plant, a 240 megawatt gas-fired cogeneration facility at the Phillips Houston
Chemical Complex ("HCC") located in Pasadena, Texas. The Company has entered
into an agreement to supply HCC with approximately 90 megawatts of electricity
(see Note 3 of Notes to Consolidated Financial Statements), with the remainder
of available electricity output to be sold into the competitive market. The
Pasadena Power Plant is the first merchant power plant to be financed with
non-recourse project financing and is scheduled to be operational in July 1998.
On June 23, 1997, the Company completed the acquisition of a 50% equity
interest in two gas-fired cogeneration facilities, the 450 megawatt Texas City
Power Plant and the 377 megawatt Clear Lake Power Plant, for an aggregate
purchase price of $35.4 million. As a part of that acquisition, the Company
entered into a $125.0 million non-recourse project financing agreement with The
Bank of Nova Scotia, the proceeds of which were utilized for the acquisition of
the 50% equity interest and the purchase of $155.6 million of outstanding
non-recourse project financing associated with the Texas City and Clear Lake
Power Plants.
On October 9, 1997, the Company completed the acquisition of 50% interests
in the Gordonsville Power Plant, a 240 megawatt gas-fired cogeneration facility
located in Gordonsville, Virginia, and the Auburndale Power Plant, a 150
megawatt gas-fired cogeneration facility located in Auburndale, Florida, for an
aggregate purchase price of $42.4 million.
On October 10, 1997, the Company entered into agreements with Energy
Management Inc. to invest in the development of two merchant power plants,
including the 169 megawatt gas-fired combined-cycle Dighton Power Plant to be
located in Dighton, Massachusetts, and the 265 megawatt gas-fired combined-cycle
Tiverton Power Plant to be located in Tiverton, Rhode Island. In October 1997,
the Company invested $16.0 million in the Dighton Power Plant (see Note 3 of
Notes to Consolidated Financial Statements). The Company intends to invest up to
$42.0 million of equity in the development of the Tiverton Power Plant. There
can be no assurances that the Dighton or Tiverton Power Plants will be
successfully developed.
On December 19, 1997, the Company completed the acquisition of 100% of the
capital stock of Gas Energy, Inc. ("GEI") and Gas Energy Cogeneration Inc.
("GECI") from The Brooklyn Union Gas Company for an aggregate purchase price of
$100.9 million, subject to final adjustments. GEI and GECI indirectly own (i) a
50% general partnership interest in the Kennedy International Airport Power
Plant, a 107 megawatt gas-fired cogeneration facility located at the John F.
Kennedy International Airport in Queens, New York, (ii) a 50% general
partnership interest in the Stony Brook Power Plant, a 40 megawatt gas-fired
cogeneration facility located on the campus of the State University of New York
in Stony Brook, New York, (iii) a 45% general partnership interest in the
Bethpage Power Plant, a 57 megawatt gas-fired cogeneration facility located in
Bethpage, New York, (iv) an 11.36% limited partnership interest in the Lockport
Power Plant, a 184 megawatt gas-fired cogeneration facility located in Lockport,
New York, and (v) a 100% interest in three fuel management contracts.
On February 5, 1998, the Company acquired the remaining 55% interest in,
and assumed operations and maintenance of, the Bethpage Power Plant. The Company
purchased the remaining interests for approximately $4.6 million.
F-5
<PAGE> 59
On February 18, 1998, the Company announced that it had entered into
exclusive negotiations to acquire a 70 megawatt gas-fired power plant and
natural gas pipeline system from The Dow Chemical Company located in Pittsburg,
California. There can be no assurance that the Company will successfully
complete this acquisition.
Each of the Company's power plants produces electricity for sale to a
utility or other third party purchasers. Thermal energy produced by the
gas-fired cogeneration facilities is sold to governmental and industrial users,
and steam produced by the geothermal steam fields is sold to utility-owned power
plants. The electricity, thermal energy and steam generated by these facilities
are typically sold pursuant to long-term, take-and-pay power or steam sales
agreements, generally having original terms of 20 or 30 years.
PG&E pays a fixed price for each unit of electrical energy according to
schedules set forth in the long-term power sales agreements for Bear Canyon (20
megawatts) and West Ford Flat (27 megawatts) Power Plants. The fixed price
periods under these power sales agreements expire in September and December
1998, respectively. After the fixed price periods expire, while the basis for
the capacity and capacity bonus payments under these power sales agreements
remains the same, the energy payments adjust to interim short-run avoided cost
("SRAC"), which is calculated pursuant to the methodology approved by the
California Public Utilities Commission ("CPUC") on December 9, 1996, and will
continue at SRAC until the independent power exchange has commenced operations
and is functioning properly. The independent power exchange is currently
scheduled to commence operations on April 1, 1998. Thereafter, SRAC will
eventually become the energy-clearing price of the independent power exchange.
During 1997, SRAC averaged approximately 2.94c per kilowatt-hour. As a result,
while SRAC does not affect capacity payments under the power sales agreements,
the Company's energy revenue under these power sales agreements is expected to
be materially reduced at the expiration of the fixed price period. Such
reduction may have a material adverse effect on the Company's results of
operations. The Company expects the forecasted decline in energy revenues will
be mitigated by decreased royalty expenses and planned operating cost reductions
at the facilities. The Company expects to continue its strategy of replacing
decreased revenues through its acquisition and development program. In addition,
prices paid for the steam delivered by the Company's steam fields are based on a
formula that partially reflects the price levels of nuclear and fossil fuels,
and, therefore, a reduction in the price levels of such fuels may reduce revenue
under the steam sales agreements for the steam fields.
Certain of the Company's power and steam sales agreements contain
curtailment provisions under which the purchasers of energy or steam are
entitled to reduce the number of hours of energy or amount of steam purchased
thereunder. For the year ended December 31, 1996, certain of the Company's power
generation facilities experienced maximum curtailment primarily as a result of
low gas prices and a high degree of precipitation during the period, which
resulted in high levels of energy generation by hydroelectric power plants that
supply electricity. For the year ended December 31, 1997, such plants
experienced a reduced amount of curtailment compared to the same period in 1996.
Due to an amendment to certain of the power sales agreements executed in May
1997, the Company currently does not expect curtailment during the remainder of
the terms of the power sales agreements for these power plants.
Many states are implementing or considering regulatory initiatives designed
to increase competition in the domestic power generation industry. In December
1995, the CPUC issued an electric industry restructuring decision, which
envisioned commencement of deregulation and implementation of customer choice of
electricity supplier by January 1, 1998. Legislation implementing this decision
was adopted in September 1996. The CPUC subsequently extended the implementation
date to April 1, 1998. As part of its policy decision, the CPUC indicated that
power sales agreements of existing qualifying facilities would be honored. The
Company cannot predict the final form or timing of the proposed restructuring
and the impact, if any, that such restructuring would have on the Company's
existing business or results of operations. The Company believes that any such
restructuring would not have a material effect on its power sales agreements
and, accordingly, believes that its existing business and results of operations
would not be materially adversely affected, although there can be no assurance
in this regard.
F-6
<PAGE> 60
SELECTED OPERATING INFORMATION
Set forth below is certain selected operating information for the power
plants and steam fields, for which results are consolidated in the Company's
Consolidated Statements of Operations. The information set forth under power
plants consists of the results for the West Ford Flat Power Plant, the Bear
Canyon Power Plant, the Greenleaf 1 and 2 Power Plants since their acquisitions
on April 21, 1995, the Watsonville Power Plant since the acquisition of the
lease on June 29, 1995, the King City Power Plant since the effective date of
the lease on May 2, 1996, and the Gilroy Power Plant since its acquisition on
August 29, 1996. The information set forth under steam fields consists of the
results for the PG&E Unit 13 and Unit 16 Steam Fields, the SMUDGEO #1 Steam
Fields and, for 1994 through 1997, the Thermal Power Company Steam Fields since
the acquisition of Thermal Power Company ("TPC") on September 9, 1994. The
information provided for the other interest included under steam revenue prior
to 1995 represents revenue attributable to a working interest that was held by a
third party in the PG&E Unit 13 and Unit 16 Steam Fields. In January 1995, the
Company purchased this working interest. Prior to the Company's acquisition of
the remaining interest in the Bear Canyon and West Ford Flat Power Plants, the
PG&E Unit 13 and Unit 16 Steam Fields and the SMUDGEO #1 Steam Fields on April
19, 1993, the Company's revenue from these facilities was accounted for under
the equity method and, therefore, does not represent the actual revenue of the
Company from these facilities for the periods set forth below.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------
1993 1994 1995 1996 1997
---------- ---------- ---------- ---------- ----------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
POWER PLANTS:
Electricity revenue (1):
Energy..................... $ 37,088 $ 45,912 $ 54,886 $ 93,851 $ 110,879
Capacity................... $ 7,834 $ 7,967 $ 30,485 $ 65,064 $ 84,296
Megawatt hours produced.... 378,035 447,177 1,033,566 1,985,404 2,158,008
Average energy price per
kilowatt hour(2)........ 9.811c 10.267c 5.310c 4.727c 5.138c
STEAM FIELDS:
Steam revenue:
Calpine.................... $ 31,066 $ 32,631 $ 39,669 $ 40,549 $ 42,102
Other interest............. $ 2,143 $ 2,051 $ -- $ -- $ --
Megawatt hours produced.... 2,014,758 2,156,492 2,415,059 2,528,874 2,641,422
Average price per kilowatt
hour.................... 1.648c 1.608c 1.643c 1.603c 1.594c
</TABLE>
- ---------------
(1) Electricity revenue is composed of fixed capacity payments, which are not
related to production, and variable energy payments, which are related to
production.
(2) Represents variable energy revenue divided by the kilowatt-hours produced.
The significant increase in capacity revenue and the accompanying decline in
average energy price per kilowatt-hour since 1994 reflects the increase in
the Company's megawatt hour production as a result of acquisitions of
gas-fired power plants by the Company.
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996
Revenue -- Total revenue increased 29% to $276.3 million in 1997 compared
to $214.6 million in 1996. Electricity and steam sales revenue increased 19% to
$237.3 million in 1997 compared to $199.5 million in 1996. Electricity and steam
sales revenue for 1997 reflected a full year of operation at the Gilroy and King
City Power Plants which contributed to increases in electricity and steam sales
revenue in 1997 compared to 1996 of $25.4 million, and $4.3 million,
respectively. Electricity and steam sales revenue for 1997 compared to 1996 was
also $6.0 million higher at the Bear Canyon and West Ford Flat Power Plants as a
result of increased production and an increase in fixed energy prices to 13.83c
per kilowatt-hour. During 1996, the Bear Canyon and West Ford Flat Power Plants
experienced the maximum curtailment allowed under their power sales agreements
with PG&E. In May 1997, the power sales agreements for the Bear Canyon and West
Ford Flat Power Plants were modified to remove curtailment. Without such
curtailment, these plants generated an
F-7
<PAGE> 61
additional $4.2 million in revenues in 1997 as compared to 1996. In addition,
TPC also contributed $2.7 million more revenue for 1997 than 1996, primarily due
to increased steam sales under the alternative pricing agreement entered into
with PG&E in March 1996. Service contract revenue increased to $10.2 million in
1997 compared to $6.5 million in 1996. Service contract revenue during 1996
reflected a $2.8 million loss from the Company's electricity trading operations.
The increase in service contract revenue for 1997 was also attributable to $2.8
million of revenue from the Texas City and Clear Lake Power Plants, which were
acquired in June 1997. Income from unconsolidated investments in power projects
increased to $15.8 million in 1997 compared to $6.5 million during 1996. The
increase in 1997 compared to 1996 was primarily due to equity income of $6.3
million from the Company's June 1997 investment in the Texas City and Clear Lake
Power Plants (see Note 3 of Notes to Consolidated Financial Statements), and an
increase in equity income of $2.2 million from the Company's investment in Sumas
Cogeneration Company, L.P. ("Sumas") (see Note 5 of Notes to Consolidated
Financial Statements). In accordance with a power sales agreement with Puget
Sound Power and Light Company, operations at Sumas were significantly displaced
from February to July 1997, and, in exchange, the Sumas Power Plant received a
higher price for energy sold and certain other payments. In addition, the
partnership agreement governing Sumas was amended in September 1997 to increase
the Company's percentage of distributions. Interest income on loans to power
projects increased to $13.0 million in 1997 compared to $2.1 million in 1996.
The increase was primarily related to interest income on the loans made by
Calpine Finance Company, a wholly-owned subsidiary of the Company, to the Texas
City and Clear Lake Power Plants, and to interest income on the loans to the
sole shareholder of Sumas Energy, Inc., the Company's partner in Sumas (see Note
6 of Notes to Consolidated Financial Statements).
Cost of revenue -- Cost of revenue increased 19% to $153.3 million in 1997
compared to $129.2 million in 1996. Plant operating, depreciation, and operating
lease expenses at the Gilroy and King City Power Plants for 1997 reflected a
full year of operations, which contributed to increases in cost of revenue in
1997 compared to 1996 of $13.0 million and $8.3 million, respectively.
Project development expenses -- Project development expenses increased 92%
to $7.5 million in 1997 compared to $3.9 million in 1996, due primarily to
expanded acquisition and development activities.
General and administrative expenses -- General and administrative expenses
increased 24% to $18.3 million in 1997 compared to $14.7 million in 1996. The
increases were primarily due to additional personnel and related expenses
necessary to support the Company's expanding operations.
Interest expense -- Interest expense increased 36% to $61.5 million in 1997
from $45.3 million in 1996. The increase was attributable to: (i) $10.8 million
of interest expense related to the 8 3/4% Senior Notes Due 2007 issued in July
and September 1997, (ii) a $7.3 million increase in interest expense related to
the 10 1/2% Senior Notes Due 2006 issued May 1996, (iii) a $6.4 million increase
in interest expense on debt related to the Gilroy Power Plant acquired in August
1996 and (iv) $5.4 million of interest expense on debt related to the
acquisition of the Texas City and Clear Lake Power Plants. These increases were
offset by $6.2 million of interest capitalized for the development and
construction of power plants, and a $7.6 million decrease in interest expense at
Calpine Geysers Company, L.P. ("CGC") and TPC due to repayment of debt.
Interest income -- Interest income increased 66% to $14.3 million for 1997
compared with $8.6 million for 1996. Interest income earned on collateral
securities purchased in April 1996 in connection with the King City Power Plant
contributed to an increase in interest income of $1.2 million in 1997 as
compared to 1996. In addition, higher cash and cash equivalent balances
resulting from the issuance of the 8 3/4% Senior Notes Due 2007 during 1997
resulted in higher interest income for 1997 as compared to 1996.
Other income, net -- Other income, net, increased to $3.2 million for 1997
compared with expense of $2.3 million for 1996. In 1997, the Company recorded a
$1.1 million gain on the sale of a note receivable (see Note 6 of Notes to
Consolidated Financial Statements) and received a refund of $961,000 from PG&E.
In 1996, the Company recorded a $3.7 million loss for uncollectible amounts
related to an acquisition project.
Provision for income taxes -- The effective rate for the income tax
provision was approximately 35% in 1997 and 33% in 1996. The reductions from the
statutory tax rate were primarily due to depletion in excess of
F-8
<PAGE> 62
tax basis benefits at the Company's geothermal facilities, a decrease in the
California taxes paid due to the Company's expansion into states other than
California, and a revision of prior years' tax estimates.
YEAR ENDED DECEMBER 31, 1996 COMPARED TO YEAR ENDED DECEMBER 31, 1995
Revenue -- Total revenue increased 62% to $214.6 million in 1996 compared
to $132.1 million in 1995. Electricity and steam sales revenue increased 56% to
$199.5 million in 1996 compared to $127.8 million in 1995. The King City and
Gilroy Power Plants contributed revenues of $41.5 million and $14.7 million,
respectively, to electricity and steam revenues during 1996. Revenue for 1996
also reflected a full year of operation at the Greenleaf 1 and 2 Power Plants
and the Watsonville Power Plant, which contributed to increases in electricity
and steam revenues in 1996 compared to 1995 of $9.1 million and $4.7 million,
respectively. During 1996 and 1995, the Company experienced the maximum
curtailment allowed under the power sales agreements with PG&E for the Bear
Canyon and West Ford Flat Power Plants. Without such curtailment, the Bear
Canyon and West Ford Flat Power Plants would have generated an additional $5.2
million and $5.7 million of revenue in 1996 and 1995, respectively. Service
contract revenue decreased to $6.5 million in 1996 compared to $7.2 million in
1995, reflecting a $2.8 million loss related to the Company's electricity
trading operations, offset by increased revenue during 1996 related to overhauls
at the Aidlin and Agnews Power Plants, and to technical services performed for
the Cerro Prieto project. Income from unconsolidated investments in power
projects increased to $6.5 million in 1996 compared to losses of $2.9 million
during 1995. The increase is primarily attributable to $6.4 million of equity
income generated by the Company's investment in Sumas during 1996 compared to a
$3.0 million loss in 1995. The increase in Sumas' profitability during 1996 is
primarily attributable to a contractual increase in the energy price in
accordance with the power sales agreement with Puget Sound Power & Light
Company. Interest income on loans to power projects was $2.1 million in 1996 as
a result of the recognition of interest income on loans to the sole shareholder
of the general partner in Sumas.
Cost of revenue -- Cost of revenue increased 67% to $129.2 million in 1996
as compared to $77.4 million in 1995. The increase was primarily due to plant
operating, depreciation, and operating lease expenses attributable to: (i) a
full year of operation during 1996 at the Greenleaf 1 and 2 Power Plants, which
were purchased on April 21, 1995, (ii) a full year of operation during 1996 at
the Watsonville Power Plant, for which the Company acquired the operating lease
on June 29, 1995, (iii) operations at the King City Power Plant subsequent to
May 2, 1996, and (iv) operations at the Gilroy Power Plant subsequent to
acquisition on August 29, 1996. Cost of revenue also increased due to service
contract expenses related to the Cerro Prieto Steam Fields, partially offset by
lower operating expenses at the Company's other existing power generation
facilities and steam fields.
Project development expenses -- Project development expenses increased to
$3.9 million in 1996 compared to $3.1 million in 1995, due to project
development activities.
General and administrative expenses -- General and administrative expenses
were $14.7 million in 1996 compared to $8.9 million in 1995. The increases were
primarily due to additional personnel and related expenses necessary to support
the Company's expanding operations, including the Company's power marketing
operations. The Company also incurred an employee bonus expense of $1.4 million
in September 1996 related to the initial public offering.
Interest expense -- Interest expense increased 41% to $45.3 million in 1996
from $32.2 million in 1995. Approximately $11.8 million of the increase was
attributable to interest on the Company's 10 1/2% Senior Notes Due 2006 issued
in May 1996, $2.7 million of interest expense related to the Gilroy Power Plant
acquired on August 29, 1996, and $1.6 million of higher interest expense related
to the Greenleaf 1 and 2 Power Plants acquired on April 21, 1995, offset in part
by a $3.0 million decrease in interest expense as a result of repayments of
principal on certain non-recourse project financing.
Interest income -- Interest income increased to $8.6 million for 1996
compared with $1.6 million for 1995. The increase was primarily due to $4.5
million of interest income on collateral securities purchased in connection with
the acquisition of the King City operating lease, and higher interest income for
the period due to increased cash balances as a result of sales of equity and
debt securities.
F-9
<PAGE> 63
Other income, net -- Other income, net decreased to $2.3 million of expense
for 1996 compared with $340,000 of income for 1995. The decrease was primarily
due to a $3.7 million loss for a dispute related to uncollectible amounts from
an acquisition project offset by $1.4 million in net proceeds from a development
project settlement.
Provision for income taxes -- The effective rate for the income tax
provision was approximately 33% in 1996 and 41% in 1995. In 1996, the Company
decreased its deferred income tax liability by $769,000 to reflect the change in
California's state income tax rate from 9.3% to 8.8% effective January 1, 1997.
In addition, depletion in excess of tax basis benefits at the Company's
geothermal facilities and a revision of prior years' tax estimates reduced the
Company's effective tax rate for 1996.
LIQUIDITY AND CAPITAL RESOURCES
To date, the Company has obtained cash from its operations, borrowings
under its credit facilities and other working capital lines, sale of debt and
equity, and proceeds from non-recourse project financing. The Company utilized
this cash to fund its operations, service debt obligations, fund the
acquisition, development and construction of power generation facilities,
finance capital expenditures and meet its other cash and liquidity needs.
The following table summarizes the Company's cash flow activities for the
periods indicated:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------
1995 1996 1997
--------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Cash flows from:
Operating activities.......... $ 26,346 $ 59,944 $ 108,461
Investing activities.......... (38,190) (330,937) (402,158)
Financing activities.......... 11,127 345,153 246,240
--------- --------- ---------
Total................. $ (717) $ 74,160 $ (47,457)
========= ========= =========
</TABLE>
Operating activities in 1997 provided $108.5 million, consisting of
approximately $34.7 million of net income from operations, $46.8 million of
depreciation and amortization, $15.1 million of deferred income taxes, $23.0
million of distributions (see Note 5 of Notes to Consolidated Financial
Statements), and a $4.7 million net decrease in operating assets and
liabilities, offset by $15.8 million of income from unconsolidated investments
in power projects.
Investing activities used $402.2 million during 1997, primarily due to
$191.0 million for the acquisition of interests in the Texas City and Clear Lake
Power Plants and the related notes receivable, $100.9 million for the
acquisition of the capital stock of GEI and GECI, $42.4 million for the
acquisition of interests in the Auburndale and Gordonsville Power Plants, $16.0
million for the investment in the Dighton Power Plant, $77.6 million of capital
expenditures related to the construction of the Pasadena Power Plant, $29.5
million of other capital expenditures, $6.2 million of interest capitalized on
construction projects, $6.0 million of capitalized project development costs,
offset by $200,000 of deferred project costs, $7.2 million of additional
investment in the Clear Lake Power Plant, $7.1 million for the acquisition of
Calpine Gas Company, offset by the receipt of $23.1 million of loan payments,
$10.0 million from the sale of loans (see Note 6 of Notes to Consolidated
Financial Statements), $5.4 million of maturities of collateral securities in
connection with the King City Power Plant and a $43.7 million decrease in
restricted cash, primarily related to the Pasadena Power Plant and CGC.
Financing activities provided $246.2 million of cash during 1997 consisting
of $125.0 million of borrowings for the acquisition of the interests in the
Texas City and Clear Lake Power Plants and the related notes receivable, $6.6
million of borrowings for contingent consideration in connection with the
acquisition of the Gilroy Power Plant and $275.0 million of proceeds from the
issuance of the 8 3/4% Senior Notes Due 2007, offset by $144.5 million in
repayment of non-recourse project financing, $7.1 million in repayment of notes
payable and $9.7 million of costs associated with financing activities.
F-10
<PAGE> 64
At December 31, 1997, cash and cash equivalents were $48.5 million and
negative working capital was $12.0 million. For the twelve months ended December
31, 1997, cash and cash equivalents decreased by $47.5 million and working
capital decreased by $102.7 million as compared to December 31, 1996.
As a developer, owner and operator of power generation facilities, the
Company may be required to make long-term commitments and investments of
substantial capital for its projects. The Company historically has financed
these capital requirements with borrowings under its credit facilities, other
lines of credit, non-recourse project financing or long-term debt.
At December 31, 1997, the Company had $105.0 million of outstanding 9 1/4%
Senior Notes Due 2004, which mature on February 1, 2004 and bear interest
payable semi-annually on February 1 and August 1 of each year. In addition, the
Company had $180.0 million of outstanding 10 1/2% Senior Notes Due 2006, which
mature on May 15, 2006 and bear interest payable semi-annually on May 15 and
November 15 of each year. During 1997, the Company issued $275.0 million of
8 3/4% Senior Notes Due 2007, which mature on July 15, 2007 and bear interest
payable semi-annually on January 15 and July 15 of each year. Under the
provisions of the applicable indentures, the Company may, under certain
circumstances, be limited in its ability to make restricted payments, as
defined, which includes dividends and certain purchases and investments, incur
additional indebtedness and engage in certain transactions.
At December 31, 1997, the Company had $192.5 million of non-recourse
project financing associated with the Greenleaf 1 and 2 Power Plants and the
Gilroy Power Plant. The annual maturities for such non-recourse project
financing are $9.6 million for 1998, $8.7 million for 1999, $10.4 million for
2000, $10.6 million for 2001, $11.1 million for 2002 and $142.1 million
thereafter.
At December 31, 1997, the Company had $103.4 million of non-recourse
borrowings from The Bank of Nova Scotia in connection with the acquisition of
the notes receivable from the Texas City and Clear Lake Power Plants. Such
borrowings mature on June 22, 1998. The Company expects to refinance such
borrowings before the maturity date.
The Company currently has a $50.0 million revolving credit agreement with a
consortium of commercial lending institutions led by The Bank of Nova Scotia,
with borrowings bearing interest at either the London Inter Bank Offering Rate
or at The Bank of Nova Scotia base rate, plus a mutually agreed margin. At
December 31, 1997, the Company had no borrowings outstanding and $9.4 million of
letters of credit outstanding under the revolving credit facility (see Note 7 of
Notes to Consolidated Financial Statements). The Bank of Nova Scotia credit
facility contains certain restrictions that limit or prohibit, among other
things, the ability of the Company or its subsidiaries to incur indebtedness,
make payments of certain indebtedness, pay dividends, make investments, engage
in transactions with affiliates, create liens, sell assets and engage in mergers
and consolidations.
The Company has a $1.2 million working capital line with a commercial
lender that may be used to fund short-term working capital commitments and
letters of credit. At December 31, 1997, the Company had no borrowings under
this working capital line and $74,000 of letters of credit outstanding.
Borrowings are at prime plus 1%.
Where appropriate, the Company may use non-recourse project financing for
new projects. The debt agreements of the Company's subsidiaries and other
affiliates governing the non-recourse project financing generally restrict their
ability to pay dividends, make distributions or otherwise transfer funds to the
Company. The dividend restrictions in such agreements generally require that,
prior to the payment of dividends, distributions or other transfers, the
subsidiary or other affiliate must provide for the payment of other obligations,
including operating expenses, debt service and reserves. However, the Company
does not believe that such restrictions will adversely affect its ability to
meet its debt obligations.
At December 31, 1997, the Company had commitments for capital expenditures
in 1998 totaling $19.8 million related to the Pasadena Power Plant (see Note 3
of Notes to Consolidated Financial Statements). The Company intends to fund
capital expenditures for the ongoing operation and development of the Company's
power generation facilities primarily through the operating cash flow of such
facilities, non-recourse project financing and corporate financing. Capital
expenditures for the twelve months ended
F-11
<PAGE> 65
December 31, 1997 of $107.1 million included $77.6 million for the construction
of the Pasadena Power Plant, $12.1 million related to the geothermal facilities,
$2.5 million related to the development of other merchant power plants and the
remaining $14.9 million at certain of the Company's gas-fired power plants.
The Company continues to pursue the acquisition and development of new
power plants. The Company expects to commit significant capital in future years
for the acquisition and development of these power plants. The Company's actual
capital expenditures may vary significantly during any year.
The Company believes that it will have sufficient liquidity from cash flow
from operations, borrowings available under the lines of credit, and working
capital to satisfy all obligations under outstanding indebtedness, to finance
anticipated capital expenditures and to fund working capital requirements
through December 31, 1998.
NEW ACCOUNTING STANDARDS
In June 1997, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 130, "Reporting
Comprehensive Income," which establishes standards for reporting comprehensive
income and its components (revenues, expenses, gains and losses) in financial
statements. SFAS No. 130 requires classification of other comprehensive income
in a financial statement, and the display of the accumulated balance of other
comprehensive income separately from retained earnings and additional paid-in
capital. SFAS No. 130 is effective for fiscal years beginning after December 15,
1997. The Company believes this pronouncement will not have a material effect on
its financial statements.
In June 1997, the FASB also issued SFAS No. 131, "Disclosures about
Segments of an Enterprise and Related Information," which established standards
for reporting information about operating segments in annual financial
statements and requires that enterprises report selected information about
operating segments in interim financial reports to shareholders. SFAS No. 131
also establishes standards for related disclosures about products and services,
geographic areas and major customers. SFAS No. 131 is effective for fiscal years
beginning after December 15, 1997, although earlier application is encouraged.
The Company believes this pronouncement will not have a material effect on its
financial statements.
YEAR 2000 COMPLIANCE
To ensure that the Company's computer systems are Year 2000 compliant, the
Company has begun preparing for the Year 2000 issue. The Company has been
reviewing each of its financial and operating systems to identify those that
contain two-digit year codes. The Company is assessing the amount of programming
required to upgrade or replace each of the affected programs with the goal of
completing all relevant internal software remediation and testing by 1998, with
continuing Year 2000 compliance efforts through 1999. In addition, the Company
is actively working with all of its partnerships to assess their compliance
efforts and the Company's exposure resulting from Year 2000 issues.
Based upon current information, the Company does not anticipate costs
associated with the Year 2000 issue to have a material financial impact.
However, there can be no assurances that there will not be interruptions or
other limitations of financial and operating systems functionality or that the
Company will not incur significant costs to avoid such interruptions or
limitations. The costs incurred relating to the Year 2000 issue will be expensed
by the Company during the period in which they are incurred. The Company's
expectations about future costs associated with the Year 2000 issue are subject
to uncertainties that could cause actual results to have a greater financial
impact than currently anticipated. Factors that could influence the amount and
timing of future costs include the success of the Company in identifying systems
and programs that contain two-digit year codes, the nature and amount of
programming required to upgrade or replace each of the affected programs, the
rate and magnitude of related labor and consulting costs, and the success of the
Company's partnerships in addressing the Year 2000 issue.
F-12
<PAGE> 66
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To The Board of Directors
of Calpine Corporation:
We have audited the accompanying consolidated balance sheets of Calpine
Corporation (a Delaware corporation) and subsidiaries as of December 31, 1997
and 1996, and the related consolidated statements of operations, stockholders'
equity and cash flows for each of the three years in the period ended December
31, 1997. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits. We did not audit the financial statements of
Sumas Cogeneration Company, L.P. ("Sumas"), the investment in which is reflected
in the accompanying financial statements using the equity method of accounting.
The investment in Sumas represents approximately 1% of the Company's total
assets at December 31, 1996. There is no investment balance as of December 31,
1997. The Company has recorded income of $8.6 million and $6.4 million and
losses of $3.0 million representing its share of the net income or loss of Sumas
for the years ended December 31, 1997, 1996 and 1995, respectively. The
financial statements of Sumas were audited by other auditors whose report has
been furnished to us and our opinion, insofar as it relates to the amounts
included for Sumas, is based solely on the report of the other auditors.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits and the report of the other auditors provide a
reasonable basis for our opinion.
In our opinion, based on our audits and the report of the other auditors,
the financial statements referred to above present fairly, in all material
respects, the financial position of Calpine Corporation and subsidiaries as of
December 31, 1997 and 1996, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 1997, in
conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
San Jose, California
February 10, 1998
(except for Note 16 as
to which the date is
February 17, 1998)
F-13
<PAGE> 67
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 1997 AND 1996
(IN THOUSANDS)
<TABLE>
<CAPTION>
1997 1996
---------- ----------
<S> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents................................. $ 48,513 $ 95,970
Accounts receivable from related parties.................. 7,672 2,826
Accounts receivable....................................... 35,133 39,962
Collateral securities, current portion.................... 6,036 5,470
Loans receivable from related parties, current portion.... 30,507 --
Prepaid operating lease................................... 13,652 12,668
Inventories............................................... 6,015 5,375
Other current assets...................................... 19,050 8,171
---------- ----------
Total current assets.............................. 166,578 170,442
Property, plant and equipment, net.......................... 719,721 648,208
Investments in power projects............................... 239,160 13,936
Project development costs................................... 4,614 86
Collateral securities, net of current portion............... 87,134 89,806
Loans receivable from related parties, net of current
portion................................................... 101,304 --
Notes receivable from related parties....................... 16,053 36,143
Restricted cash............................................. 15,584 59,259
Other assets................................................ 30,808 13,517
---------- ----------
Total assets...................................... $1,380,956 $1,031,397
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Notes payable and short term borrowings................... -- 6,865
Current portion of non-recourse project financing......... 112,966 30,627
Accounts payable.......................................... 30,441 18,363
Accrued payroll and related expenses...................... 4,950 3,912
Accrued interest payable.................................. 18,025 7,332
Other current liabilities................................. 12,204 12,621
---------- ----------
Total current liabilities......................... 178,586 79,720
Non-recourse project financing, net of current portion...... 182,893 278,640
Senior Notes................................................ 560,041 285,000
Deferred income taxes, net.................................. 142,050 100,385
Deferred lease incentive.................................... 71,383 74,952
Other liabilities........................................... 6,047 9,573
---------- ----------
Total liabilities................................. 1,141,000 828,270
---------- ----------
Stockholders' equity:
Common stock, $0.001 par value per share; authorized
100,000,000 shares in 1997 and 1996; issued and
outstanding 20,060,705 shares in 1997 and 19,843,400
shares in 1996......................................... 20 20
Additional paid-in capital................................ 167,542 165,412
Retained earnings......................................... 72,394 37,695
---------- ----------
Total stockholders' equity........................ 239,956 203,127
---------- ----------
Total liabilities and stockholders' equity........ $1,380,956 $1,031,397
========== ==========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-14
<PAGE> 68
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
1997 1996 1995
-------- -------- --------
<S> <C> <C> <C>
Revenue:
Electricity and steam sales.............................. $237,277 $199,464 $127,799
Service contract revenue from related parties............ 10,177 6,455 7,153
Income (loss) from unconsolidated investments in power
projects.............................................. 15,819 6,537 (2,854)
Interest income on loans to power projects............... 13,048 2,098 --
-------- -------- --------
Total revenue.................................... 276,321 214,554 132,098
-------- -------- --------
Cost of revenue:
Plant operating expenses................................. 72,366 61,894 33,162
Depreciation............................................. 47,501 39,818 26,264
Production royalties..................................... 10,803 10,793 10,574
Operating lease expenses................................. 14,031 9,295 1,542
Service contract expenses................................ 8,607 7,400 5,846
-------- -------- --------
Total cost of revenue............................ 153,308 129,200 77,388
-------- -------- --------
Gross profit............................................... 123,013 85,354 54,710
Project development expenses............................... 7,537 3,867 3,087
General and administrative expenses........................ 18,289 14,696 8,937
-------- -------- --------
Income from operations........................... 97,187 66,791 42,686
Interest expense:
Related parties.......................................... -- 894 1,663
Other.................................................... 61,466 44,400 30,491
Interest income............................................ (14,285) (8,604) (1,555)
Other (income) expense..................................... (3,153) 2,345 (340)
-------- -------- --------
Income before provision for income taxes......... 53,159 27,756 12,427
Provision for income taxes................................. 18,460 9,064 5,049
-------- -------- --------
Net income....................................... $ 34,699 $ 18,692 $ 7,378
======== ======== ========
Basic earnings per common share:
Weighted average shares of common stock outstanding...... 19,946 12,903 10,388
Basic earnings per common share.......................... $ 1.74 $ 1.45 $ 0.71
Diluted earnings per common share:
Weighted average shares of common stock outstanding...... 21,016 14,879 10,957
Diluted earnings per common share........................ $ 1.65 $ 1.26 $ 0.67
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-15
<PAGE> 69
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
(IN THOUSANDS)
<TABLE>
<CAPTION>
ADDITIONAL
PREFERRED COMMON PAID IN RETAINED
STOCK STOCK CAPITAL EARNINGS TOTAL
--------- -------- ---------- -------- --------
<S> <C> <C> <C> <C> <C>
Balance of 10,387,692 shares of common stock
at December 31, 1994...................... $ -- $ 10 $ 6,214 $ 12,425 $ 18,649
Dividend ($0.40 per share)................ -- -- -- (800) (800)
Net income................................ -- -- -- 7,378 7,378
-------- -------- -------- -------- --------
Balance, December 31, 1995.................. -- 10 6,214 19,003 25,227
Issuance of 5,000,000 shares of preferred
stock.................................. 50 -- 49,950 -- 50,000
Conversion of 5,000,000 shares of
preferred stock to 2,179,487 shares of
common stock........................... (50) 3 47 -- --
Issuance of 7,276,221 shares of common
stock, net............................. -- 7 109,172 -- 109,179
Tax benefit from stock options
exercised.............................. -- -- 29 -- 29
Net income................................ -- -- -- 18,692 18,692
-------- -------- -------- -------- --------
Balance, December 31, 1996.................. -- 20 165,412 37,695 203,127
Issuance of 217,305 shares of common
stock, net............................. -- -- 1,022 -- 1,022
Tax benefit from stock options exercised
and other.............................. -- -- 1,108 -- 1,108
Net income................................ -- -- -- 34,699 34,699
-------- -------- -------- -------- --------
Balance, December 31, 1997.................. $ -- $ 20 $167,542 $ 72,394 $239,956
======== ======== ======== ======== ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-16
<PAGE> 70
CALPLNE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
(IN THOUSANDS)
<TABLE>
<CAPTION>
1997 1996 1995
--------- --------- ---------
<S> <C> <C> <C>
Cash flows from operating activities:
Net income.......................................... $ 34,699 $ 18,692 $ 7,378
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization, net............... 46,819 36,600 25,931
Deferred income taxes, net....................... 15,082 2,028 (1,027)
(Income) loss from unconsolidated investments in
power projects................................. (15,819) (6,537) 2,854
Distributions from unconsolidated power
projects....................................... 22,950 1,274 --
Change in operating assets and liabilities:
Accounts receivable............................ 7,249 (12,652) (3,354)
Inventories.................................... (632) 256 --
Other current assets........................... (9,304) 55 (9,542)
Other assets................................... (13,203) 63 (307)
Accounts payable and accrued expenses.......... 17,464 16,818 6,847
Other liabilities.............................. 3,156 3,347 (2,434)
--------- --------- ---------
Net cash provided by operating activities... 108,461 59,944 26,346
--------- --------- ---------
Cash flows from investing activities:
Acquisition of property, plant and equipment........ (107,094) (24,057) (17,434)
Acquisitions........................................ (108,671) (149,640) (14,336)
Investments in unconsolidated power projects........ (100,968) -- --
Assumption of loan receivable....................... (155,622) -- --
(Increase) decrease in notes receivable............. 33,110 (10,176) (6,348)
Investment in collateral securities................. -- (98,446) --
Maturities of collateral securities................. 5,350 2,900 --
Project development costs........................... (11,938) (5,887) (1,258)
Decrease (increase) in restricted cash.............. 43,675 (45,631) 1,186
--------- --------- ---------
Net cash used in investing activities....... (402,158) (330,937) (38,190)
--------- --------- ---------
Cash flows from financing activities:
Payment of dividends................................ -- -- (800)
Borrowings from line of credit...................... 14,300 46,861 34,851
Repayment of borrowings from line of credit......... (14,300) (66,712) (15,000)
Borrowings from non-recourse project financing...... 131,600 119,760 76,026
Repayments of non-recourse project financing........ (144,529) (84,708) (79,388)
Proceeds from notes payable and short-term
borrowings....................................... -- 45,000 2,683
Repayments of notes payable and short-term
borrowings....................................... (7,131) (46,177) (6,006)
Proceeds from issuance of Senior Notes.............. 275,000 180,000 --
Proceeds from issuance of preferred stock........... -- 50,000 --
Proceeds from issuance of common stock.............. 1,022 109,208 --
Financing costs..................................... (9,722) (8,079) (1,239)
--------- --------- ---------
Net cash provided by financing activities... 246,240 345,153 11,127
--------- --------- ---------
Net increase (decrease) in cash and cash
equivalents......................................... (47,457) 74,160 (717)
Cash and cash equivalents, beginning of period........ 95,970 21,810 22,527
--------- --------- ---------
Cash and cash equivalents, end of period.............. $ 48,513 $ 95,970 $ 21,810
========= ========= =========
Cash paid during the year for:
Interest............................................ $ 42,746 $ 43,805 $ 32,162
Income taxes........................................ $ 9,795 $ 6,947 $ 4,294
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-17
<PAGE> 71
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
1. ORGANIZATION AND OPERATIONS OF THE COMPANY
Calpine Corporation ("Calpine"), a Delaware corporation, and subsidiaries
(collectively, the "Company") is engaged in the development, acquisition,
ownership and operation of power generation facilities and the sale of
electricity and steam in the United States and selected international markets.
The Company has ownership interests in and operates gas-fired cogeneration
facilities, geothermal steam fields and geothermal power generation facilities
in northern California, Washington, Texas and various locations on the East
Coast. Each of the generation facilities produces and markets electricity for
sale to utilities and other third party purchasers. Thermal energy produced by
the gas-fired cogeneration facilities is primarily sold to governmental and
industrial users and steam produced by geothermal steam fields is sold to
utility-owned power plants. For the year ended December 31, 1997, primarily all
electricity and steam sales revenue from consolidated subsidiaries was derived
from sales to two customers in northern California (see Note 15), of which 43%
related to geothermal activities.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation -- The accompanying consolidated financial
statements include accounts of the Company. Wholly-owned and majority-owned
subsidiaries are consolidated. Less-than-majority-owned subsidiaries, and
subsidiaries for which control is deemed to be temporary, are accounted for
using the equity method. For equity method investments, the Company's share of
income is calculated according to the Company's equity ownership or according to
the terms of the appropriate partnership agreement (see Note 5). All significant
intercompany accounts and transactions are eliminated in consolidation. The
Company uses the proportionate consolidation method to account for Thermal Power
Company's ("TPC") 25% interest in jointly owned geothermal properties.
Use of Estimates in Preparation of Financial Statements -- 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. The most significant estimates with regard to these
financial statements relate to future development costs and total productive
resources of the geothermal facilities (see Property, Plant and Equipment), and
the realization of deferred income taxes (see Note 11). Additionally, the
Company believes that certain industry restructuring (see Note 16, Regulation
and CPUC Restructuring) will not have a material effect on existing power sales
agreements and, accordingly, will not have a material effect on existing
business or results of operations.
Revenue Recognition -- Revenue from electricity and steam sales is
recognized upon transmission to the customer. Revenues from contracts entered
into or acquired since May 21, 1992 are recognized at the lesser of amounts
billable under the contract or amounts recognizable at an average rate over the
term of the contract. The Company's power sales agreements related to Calpine
Geyser's Company, L.P. ("CGC") were entered into prior to May 1992. Had the
Company applied the methodology described above to the CGC power sales
agreements, the revenues recorded for the years ended December 31, 1997, 1996
and 1995, would have been approximately $20.1 million, $16.1 million, and $12.6
million less, respectively.
The Company performs operations and maintenance services for all
consolidated projects in which it has an interest, except for TPC. Revenue from
investees is recognized on these contracts when the services are performed.
Cash and Cash Equivalents -- The Company considers all highly liquid
investments with an original maturity of three months or less to be cash
equivalents. The carrying amount of these instruments approximates fair value
because of their short maturity.
F-18
<PAGE> 72
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
Restricted Cash -- The Company is required to maintain cash balances that
are restricted by provisions of its debt agreements and by regulatory agencies.
The Company's debt agreements specify restrictions based on debt service
payments and drilling costs for the following year. Regulatory agencies require
cash to be restricted to ensure that funds will be available to restore property
to its original condition. Restricted cash is invested in accounts earning
market rates; therefore, the carrying value approximates fair value. Such cash
is excluded from cash and cash equivalents for the purposes of the consolidated
statements of cash flows.
Inventories -- Operating supplies are valued at the lower of cost or
market. Cost for large replacement parts is determined using the specific
identification method. For the remaining supplies, cost is determined using the
weighted average cost method.
Collateral Securities -- The Company maintains certain investments in
investment grade collateral securities which are classified as held-to-maturity
and stated at amortized cost. The investments in debt securities mature at
various dates through August 2018 in amounts equal to a portion of the King City
Power Plant lease payment (see Note 3, "King City Transaction"). The fair value
of held-to-maturity securities was determined based on the quoted market prices
at the reporting date for the securities.
The components of held-to-maturity securities by major security type as of
December 31, 1997 and 1996 are as follows (in thousands):
<TABLE>
<CAPTION>
UNREALIZED
AMORTIZED AGGREGATE HOLDING
COST FAIR VALUE GAINS
1997 --------- ---------- ----------
<S> <C> <C> <C>
Debt securities issued by the United States
government............................... $ 58,312 $ 63,174 $ 4,862
Corporate debt securities.................. 34,858 37,485 2,627
-------- -------- --------
Total............................ $ 93,170 $100,659 $ 7,489
======== ======== ========
</TABLE>
<TABLE>
<CAPTION>
1996
<S> <C> <C> <C>
Debt securities issued by the United States
government............................... $ 54,826 $ 56,737 $ 1,911
Corporate debt securities.................. 40,450 40,499 49
-------- -------- --------
Total............................ $ 95,276 $ 97,236 $ 1,960
======== ======== ========
</TABLE>
Concentration of Credit Risk -- Financial instruments which potentially
subject the Company to concentrations of credit risk consist primarily of cash,
accounts receivable, notes receivable, and loans receivable. The Company's cash
accounts are held by seven FDIC insured banks. The Company's accounts, notes and
loans receivable are concentrated within entities engaged in the energy industry
(see Note 15), mainly within the United States, some of which are related
parties. The Company also maintains a note receivable with a company in Mexico
(see Note 6, "Calpine Vapor Inc."). The Company generally does not require
collateral for accounts receivable.
Property, Plant and Equipment, net -- Property, plant and equipment, net
are stated at cost less accumulated depreciation and amortization.
The Company capitalizes costs incurred in connection with the development
of geothermal properties, including costs of drilling wells and overhead
directly related to development activities, together with the costs of
production equipment, the related facilities and the operating power plants.
Geothermal properties include the value attributable to the geothermal resources
of CGC and all of the property, plant and equipment of TPC. Proceeds from the
sale of geothermal properties are applied against capitalized costs, with no
gain or loss recognized. At December 31, 1997 and 1996, the Company had $4.0
million of geothermal leases at Glass Mountain in northern California recorded
as property, plant and equipment, net in the accompanying
F-19
<PAGE> 73
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
consolidated balance sheets. The Company is continuing to pursue the development
of Glass Mountain, and expects to recover the cost of such leases from the
future development of the resource.
Geothermal costs, including an estimate of future development costs to be
incurred and the estimated costs to dismantle, are amortized by the units of
production method based on the estimated total productive output over the
estimated useful lives of the related steam fields. Depreciation of the
buildings and roads is computed using the straight-line method over their
estimated useful lives. It is reasonably possible that the estimate of useful
lives, total units of production or total capital costs to be amortized using
the units of production method could differ materially in the near term from the
amounts assumed in arriving at current depreciation expense. These estimates are
affected by such factors as the ability of the Company to continue selling steam
and electricity to customers at estimated prices, changes in prices of
alternative sources of energy such as hydro-generation and gas, and changes in
the regulatory environment.
Gas-fired power production facilities include the cogeneration plants and
related equipment and are stated at cost. Depreciation is recorded utilizing the
straight-line method over the estimated original useful life of up to 30 years.
The value of the above-market pricing provided in power sales agreements
acquired is recorded in property, plant and equipment, net and is amortized over
the above market pricing period in the power sales agreement with lives of 22
and 23 years. When assets are disposed of, the cost and related accumulated
depreciation are removed from the accounts, and the resulting gains or losses
are included in results of operations.
As of December 31, 1997 and 1996, the components of property, plant and
equipment, net are as follows (in thousands):
<TABLE>
<CAPTION>
1997 1996
--------- ---------
<S> <C> <C>
Geothermal properties........................ $ 307,152 $ 297,002
Buildings, machinery and equipment........... 299,018 275,459
Power sales agreements....................... 145,957 145,957
Other assets................................. 11,629 11,555
--------- ---------
763,756 729,973
Less accumulated depreciation and
amortization............................... (148,390) (100,674)
--------- ---------
615,366 629,299
Land......................................... 754 754
Construction in progress..................... 103,601 18,155
--------- ---------
Property, plant and equipment,
net.............................. $ 719,721 $ 648,208
========= =========
</TABLE>
Construction in progress includes costs primarily attributable to the
development and construction of the Pasadena Power Plant.
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. Generally this occurs upon
the execution of a memorandum of understanding or a letter of intent for a power
or steam sales agreement. These costs include professional services, salaries,
permits and other costs directly related to the development of a new project.
Outside services and other third party costs are capitalized for acquisition
projects. Upon the start-up of plant operations or the completion of an
acquisition, these costs are generally transferred to property, plant and
equipment, net and amortized over the estimated useful life of the project.
Capitalized project costs are charged to expense when the Company determines
that the project will not be consummated or is impaired.
F-20
<PAGE> 74
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
Capitalized Interest -- The Company capitalizes interest on projects during
the construction period. For the year ended December 31, 1997, the Company
capitalized $6.2 million of interest in connection with the construction of its
power plants. No interest was capitalized prior to 1997.
Other Assets -- Other assets consist of the following at December 31, (in
thousands):
<TABLE>
<CAPTION>
1997 1996
------- -------
<S> <C> <C>
Deferred financing costs......................... $20,493 $13,396
Prepaid operating lease, long term portion....... 9,808 --
Other............................................ 507 121
------- -------
Other assets........................... $30,808 $13,517
======= =======
</TABLE>
Deferred financing costs are amortized over the term of the related
financings, which range from 12 to 180 months.
Derivative Financial Instruments -- The Company engages in activities to
manage risks associated with changes in interest rates. The Company has entered
into swap agreements to reduce exposure to interest rate fluctuations in
connection with certain debt commitments. The instruments' cash flows mirror
those of the underlying exposure. Unrealized gains and losses relating to the
instruments are being deferred over the lives of the contracts. The premiums
paid on the instruments, as measured at inception, are being amortized over
their respective lives as components of interest expense. Any gains or losses
realized upon the early termination of these instruments are deferred and
recognized in income over the remaining life of the underlying exposure. At
December 31, 1997, the Company had $239.1 million of interest rate swaps on non-
recourse project financing.
Power Marketing -- The Company, through its wholly-owned subsidiary Calpine
Power Services Company ("CPSC"), markets power and energy services to utilities,
wholesalers, and end users. CPSC provides these services by entering into
contracts to purchase or supply electricity at specified delivery points and
specified future dates. In some cases, CPSC utilizes option agreements to manage
its exposure to market fluctuations. At December 31, 1997, CPSC held option
contracts with two entities for the purchase and sale of up to 50 megawatts each
for the period from June 1, 1998 to September 30, 1998.
Net open positions may exist due to the origination of new transactions and
the Company's evaluation of changing market conditions. An open position exposes
the Company to the risk that fluctuating market prices may adversely impact its
financial position or results of operations. However, any net open positions are
actively managed. The impact of such transactions on the Company's financial
position is not necessarily indicative of the impact of price fluctuations
throughout the year. CPSC values its portfolio using the aggregate lower of cost
or market method. An allowance is recorded for net aggregate losses of the
entire portfolio resulting from the effect of market changes on net open
positions. Net gains are recognized when realized.
The Company's credit risk associated with power contracts results from the
risk of loss as a result of non-performance by counter parties. The Company
reviews and assesses counter party risk to limit any material impact to its
financial position and results of operations. The Company does not anticipate
non-performance by the counter parties. The Company sets credit limits prior to
entering into transactions and has not obtained collateral or security.
Basic and Diluted Earnings Per Share -- In 1997, the Company adopted
Statement of Financial Accounting Standards ("SFAS") No. 128, "Earnings per
Share." In February 1998, the Securities and Exchange Commission ("SEC") staff
released Staff Accounting Bulletin ("SAB") No. 98, "Computations of Earnings per
Share." SAB No. 98 revises prior SEC guidance concerning presentation of
earnings per share information for companies going public, and requires all
companies to present earnings per share for all periods
F-21
<PAGE> 75
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
for which income statement information is presented in accordance with SFAS No.
128. Basic earnings per share were computed using the weighted average number of
common shares outstanding. Diluted earnings per share were computed using the
weighted average number of common shares and the common equivalent shares that
would have been outstanding if the Company's dilutive potential shares had been
issued. The treasury stock method was used to calculate the potential number of
dilutive shares associated with the Company's outstanding stock options.
New Accounting Pronouncements -- In June 1997, the Financial Accounting
Standards Board ("FASB") issued SFAS No. 130, "Reporting Comprehensive Income,"
which establishes standards for reporting comprehensive income and its
components (revenues, expenses, gains and losses) in financial statements. SFAS
No. 130 requires classification of other comprehensive income in a financial
statement, and the display of the accumulated balance of other comprehensive
income separately from retained earnings and additional paid-in capital. SFAS
No. 130 is effective for fiscal years beginning after December 15, 1997. The
Company believes this pronouncement will not have a material effect on its
financial statements.
In June 1997, the FASB also issued SFAS No. 131, "Disclosures about
Segments of an Enterprise and Related Information." This pronouncement
established standards for reporting information about operating segments in
annual financial statements and requires that enterprises report selected
information about operating segments in interim financial reports to
shareholders. SFAS No. 131 also establishes standards for related disclosures
about products and services, geographic areas and major customers. SFAS No. 131
is effective for fiscal years beginning after December 15, 1997, although
earlier application is encouraged. The Company believes this pronouncement will
not have a material effect on its financial statements.
Reclassifications -- Certain prior years' amounts in the consolidated
financial statements have been reclassified where necessary to conform to the
1997 presentation.
3. ACQUISITIONS AND INVESTMENTS
The following acquisitions and investments were consummated during the
three years ended December 31, 1997:
GREENLEAF TRANSACTION
In April 1995, the Company acquired the outstanding capital stock of
Portsmouth Leasing Corporation, LFC No. 38 Corp. and LFC No. 60 Corp.
(collectively, the "Acquired Companies") for $80.5 million. The purchase price
included a cash payment of $20.3 million and the assumption of project debt
totaling $60.2 million. In April 1996, the Company finalized the purchase price
at $81.5 million.
The Acquired Companies own 100% of the assets of two 49.5 megawatt
gas-fired cogeneration facilities Greenleaf 1 and Greenleaf 2 (collectively, the
"Greenleaf Power Plants"), located in Yuba City in northern California.
Electrical energy generated by the Greenleaf Power Plants is sold to Pacific Gas
and Electric Company ("PG&E") pursuant to two long-term power sales agreement
(expiring in 2019) at prices equal to PG&E's full short-run avoided operating
costs, adjusted annually. The power sales agreement also includes payment
provisions for firm capacity payments through 2019 for up to 49.2 megawatts on
each unit and as-delivered capacity on excess deliveries. PG&E, at its
discretion, may curtail purchases of electricity from the Greenleaf Power Plants
due to hydro-spill or uneconomic cost conditions. Thermal energy generated is
utilized by thermal hosts adjacent to the Greenleaf Power Plants.
Gas for the Greenleaf Power Plants is supplied by Calpine Gas Company (see
"Montis Niger Transaction").
F-22
<PAGE> 76
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
KING CITY TRANSACTION
In April 1996, the Company entered into a long-term operating lease with
BAF Energy, a California Limited Partnership ("BAF"), for a 120 megawatt
gas-fired cogeneration power plant located in King City, California. The power
plant generates electricity for sale to PG&E pursuant to a long-term power sales
agreement through 2019. The Company recorded the value of the above-market
pricing in the power sales agreement of $82.1 million as an asset, which is
included in property, plant and equipment, net and is being amortized over the
remaining life of the above market pricing period. The Company makes semi-annual
lease payments to BAF on February 15 and August 15, a portion of which is
supported by a $93.2 million collateral fund owned by the Company (see Note 2,
Collateral Securities). As of December 31, 1997, future rent payments are $23.8
million for 1998, $19.4 million for 1999, $20.1 million for 2000, $20.8 million
for 2001, $21.6 million for 2002, and $161.6 million thereafter. Included in the
accompanying December 31, 1997 balance sheet is approximately $23.5 million of
unamortized prepaid lease costs. The Company also recorded a deferred lease
incentive of $75.0 million at December 31, 1997 equal to the value of the
above-market payments to be received. Lease expense, net of amortization of the
deferred lease incentive, was $13.7 million and $9.1 million in 1997 and 1996,
respectively.
GILROY TRANSACTION
In August 1996, the Company acquired a 120 megawatt gas-fired cogeneration
power plant located in Gilroy, California. The cost of the Gilroy Power Plant
was $125.0 million plus certain contingent consideration, which is expected to
be $24.1 million, of which $12.5 million had been paid as of December 31, 1997.
In addition, the Company recorded the value of the above-market pricing in the
power sales agreement of $63.9 million as an asset, which is included in
property, plant and equipment, net, and is being amortized over the remaining
life of 22 years.
Electricity generated by the Gilroy Power Plant is sold to PG&E pursuant to
a long-term power sales agreement terminating in 2018. The power sales agreement
contains payment provisions for capacity and energy. The Gilroy power plant also
produces and sells thermal energy to ConAgra, Inc.
Pro Forma Consolidated Results
The following unaudited pro forma consolidated results for the Company give
effect to: (i) the King City Transaction and (ii) the Gilroy Transaction as if
such transactions had occurred on January 1, 1996. Unaudited pro forma
consolidated results are also provided for the effects of the above transactions
and (iii) the Watsonville operating lease acquired on June 28, 1995, and (iv)
the Greenleaf transaction, as if such had occurred on January 1, 1995 (in
thousands, except per share amount).
<TABLE>
<CAPTION>
1996 1995
-------- --------
<S> <C> <C>
Revenue...................................... $237,924 $221,447
Net income................................... $ 18,954 $ 11,288
Diluted earnings per share................... $ 1.27 $ 1.03
</TABLE>
PASADENA COGENERATION PROJECT
In December 1996, the Company entered into a development agreement with
Phillips Petroleum Company ("Phillips") to construct and operate a 240 megawatt
gas-fired cogeneration project at the Phillips Houston Chemical Complex ("HCC")
located in Pasadena, Texas. Additionally, the Company entered into an energy
sales agreement with Phillips pursuant to which Phillips will purchase all of
HCC's steam and electricity requirements of approximately 90 megawatts. It is
anticipated that the remainder of available electricity output will be sold into
the competitive market (see Note 2, Power Marketing). The Company also
F-23
<PAGE> 77
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
entered into a credit agreement with ING U.S. Capital Corporation ("ING") to
provide $151.8 million of construction financing to the project. At December 31,
1997, the Company had no borrowings against this credit agreement. In January
1998, the Company borrowed $35.9 million from ING in accordance with the terms
of the credit agreement.
MONTIS NIGER TRANSACTION
In January 1997, the Company paid approximately $7.1 million for 100% of
the stock of Montis Niger, Inc. (subsequently renamed Calpine Gas Company).
Calpine Gas Company owns gas fields with 8.1 billion cubic feet of estimated
proven gas reserves and an 80-mile pipeline system, which provides gas to the
Company's Greenleaf Power Plants.
TEXAS CITY AND CLEAR LAKE TRANSACTION
In June 1997, the Company acquired a 50% equity interest in the Texas City
Power Plant and the Clear Lake Power Plant for a total purchase price of $35.4
million, subject to final adjustments. The Company acquired its 50% interest in
these plants through the acquisition of 50% of the capital stock of Enron
Dominion Cogen Corp. ("EDCC") from Enron Power Corp. EDCC was subsequently
renamed Texas Cogeneration Company ("TCC"). The remaining 50% shareholder
interest in TCC is owned by Dominion Cogen, Inc. In addition to the purchase of
the stock of TCC, the Company purchased from existing lenders the $155.6 million
of outstanding non-recourse project financing of the Texas City Power Plant
(approximately $53.0 million) and the Clear Lake Power Plant (approximately
$102.6 million) (see Note 6, "Texas City and Clear Lake Power Plants").
The Company accounts for its investment in TCC under the equity method. The
Texas City and Clear Lake Power Plants are operated by the Company under a
one-year contract with automatic renewal provisions.
Texas City Power Plant -- The Texas City Power Plant is a 450 megawatt
gas-fired cogeneration facility located in Texas City, Texas. The plant
commenced commercial operation in June 1987.
Electricity generated by the Texas City Power Plant is sold under two
separate long-term agreements to: (i) Texas Utilities Electric Company ("TUEC")
under an original 12-year power sales agreement terminating in June 1999, which
has been extended to September, 2002, and (ii) Union Carbide Company ("UCC")
under an original 12-year power sales agreement terminating in June 1999. Each
power sales agreement contains provisions for capacity and energy payments. The
TUEC power sales agreement provides for a firm capacity payment for 410
megawatts. The UCC power sales agreement provides for a firm capacity payment
for 20 megawatts.
Clear Lake Power Plant -- The Clear Lake Power Plant is a 377 megawatt
gas/hydrogen-fired cogeneration facility located in Pasadena, Texas. The plant
commenced commercial operation in December 1984.
Electricity generated by the Clear Lake Power Plant is sold under three
separate long-term agreements to: (i) Texas New Mexico Power Company ("TNP")
under an original 20-year power sales agreement terminating in 2004, (ii)
Houston Light & Power Company under an original 10-year power sales agreement
terminating in 2005, and (iii) Hoescht Celanese Chemical Group under an original
10-year power sales agreement terminating in 2004. Each power sales agreement
contains provisions for capacity and energy payments.
DIGHTON TRANSACTION
In October 1997, the Company executed agreements with Energy Management,
Inc. ("EMI") to invest in the development of two merchant power plants slated
for start-up in 1999 and early 2000. The Company
F-24
<PAGE> 78
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
invested $16.0 million in a 169 megawatt gas-fired combined-cycle plant to be
built in Dighton, Massachusetts. The Company will receive a preferred payment
stream at a rate of approximately 12% on its investment.
The Company accounts for its investment in Dighton under the equity method
of accounting. During construction of the facility, the Company capitalizes
interest on the investment at a rate equal to the average corporate cost of
debt.
Under the terms of the above agreements, the Company has also been granted
an exclusive option to purchase an ownership interest in, and to partner with,
EMI on the 265 megawatt gas-fired plant under development in Tiverton, Rhode
Island. EMI and the Company would be co-general partners for the project. The
Company intends to invest up to $43.0 million of equity in the development of
the Tiverton Power Plant.
AUBURNDALE AND GORDONSVILLE TRANSACTION
In October 1997, the Company acquired a 50% interest in both the Auburndale
Power Plant and the Gordonsville Power Plant for a total purchase price of $42.4
million, subject to final adjustments. The Company acquired its interest in
these plants from Norweb Power Services Limited and Northern Hydro Limited, both
wholly-owned subsidiaries of Norweb PLC. The Company accounts for its investment
in the Auburndale Power Plant and Gordonsville Power Plant under the equity
method.
Auburndale Power Plant -- The Auburndale Power Plant is a 150 megawatt
gas-fired cogeneration facility located outside of Orlando, Florida. The
Auburndale Power Plant commenced commercial operation in July 1994 and sells
capacity and energy to Florida Power Corporation under three 20-year power sales
agreements terminating in December 2013.
Gordonsville Power Plant -- The Gordonsville Power Plant is a 240 megawatt
gas-fired cogeneration facility located near Gordonsville, Virginia. The
Gordonsville Power Plant commenced commercial operations in June 1994 and sells
capacity and energy to Virginia Electric and Power Company under two 30-year
power sales agreements terminating in 2024.
The Gordonsville and Auburndale Power Plants are operated by Edison Mission
Operations & Maintenance, Inc. ("EMOM"), an affiliate of Edison Mission Energy.
The operating agreements between EMOM and the two facilities expire in December
2013. EMOM is paid on a cost-plus basis for all direct labor plus reimbursement
of certain costs, an operating fee and an incentive based upon performance.
GAS ENERGY INC. AND GAS ENERGY COGENERATION INC. TRANSACTION
In December 1997, the Company acquired 100% of the capital stock of Gas
Energy Inc. ("GEI") and Gas Energy Cogeneration Inc. ("GECI") from The Brooklyn
Union Gas Company ("BUG"), for a total purchase price of $100.9 million, subject
to final adjustments. GEI and GECI were both wholly-owned subsidiaries of BUG
and have (i) a 50% interest in the Kennedy International Airport Cogeneration
Power Plant, (ii) a 50% interest in the Stony Brook Power Plant, (iii) a 45%
interest in the Bethpage Power Plant, (iv) an 11.36% interest in the Lockport
Power Plant and (v) a 100% interest in three fuel management contracts. The
Company accounts for its investments in the above power plants under the equity
method.
The Kennedy International Airport Cogeneration Power Plant is a 107
megawatt gas-fired cogeneration facility located in Queens, New York. Steam and
electricity generated by the Kennedy International Airport Cogeneration Power
Plant are sold to the Port Authority of New York and New Jersey to service the
John F. Kennedy International Airport under a 20-year power sales agreement
terminating in 2015.
The Stony Brook Power Plant is a 40 megawatt gas-fired cogeneration
facility located at the State University of New York in Stony Brook, New York.
Steam and electricity generated by the Stony Brook
F-25
<PAGE> 79
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
Power Plant are sold to the State University of New York at Stony Brook under a
20-year power sales agreement terminating in 2015, and excess electricity is
sold to Long Island Lighting Company ("LILCo").
The Bethpage Power Plant is a 57 megawatt gas-fired cogeneration facility
located in Bethpage, New York. Steam and electricity generated by the Bethpage
Power Plant are sold to the Northrop Grumman Corporation under a 15-year power
sales agreement expiring in 2004, and excess electricity is sold to LILCo. On
February 5, 1998, the Company purchased the remaining 55% interest in the
Bethpage Power Plant for approximately $4.6 million.
The Lockport Power Plant is a 184 megawatt gas-fired cogeneration facility
located in Lockport, New York. Steam and electricity generated by the Lockport
Power Plant are sold to a General Motors plant under a 15-year power sales
agreement terminating in 2007, and excess electricity is sold to New York State
Electric and Gas ("NYSEG").
4. ACCOUNTS RECEIVABLE
At December 31, 1997, accounts receivable totaled $42.8 million, which
included $7.7 million receivable from related parties. Accounts receivable from
related parties at December 31, 1997 and 1996 include the following (in
thousands):
<TABLE>
<CAPTION>
DECEMBER 31,
----------------
1997 1996
------ ------
<S> <C> <C>
Nisseqougue Cogen Partners................................. $4,140 $ --
TBG Cogen Partners......................................... 1,490 --
Texas Cogeneration Company................................. 903 --
Sumas Cogeneration Company, L.P............................ 527 590
Geothermal Energy Partners, Ltd............................ 275 350
O.L.S. Energy-Agnews, Inc.................................. 269 687
KIAC Partners.............................................. 68 --
Electrowatt Ltd. and subsidiaries.......................... -- 1,199
------ ------
Accounts receivable from related parties............ $7,672 $2,826
====== ======
</TABLE>
At December 31, 1996, the $1.2 million receivable from Electrowatt Ltd.
(the previous indirect sole owner of the Company) was for reimbursement of costs
for the sale of Electrowatt Ltd.'s ownership of the Company's common stock
during the Company's initial public offering in September 1996.
5. RESULTS OF UNCONSOLIDATED INVESTMENTS
The Company has unconsolidated investments in power projects which are
accounted for under the equity method. Investments in less-than-majority-owned
affiliates and the nature and extent of these
F-26
<PAGE> 80
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
investments change over time. The combined results of operations and financial
position of the Company's equity-basis affiliates are summarized below (in
thousands):
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------------------------
1997 1996 1995
---------- ---------- ----------
<S> <C> <C> <C>
Condensed Statement of Operations:
Operating revenue.................... $ 271,494 $ 77,417 $ 63,981
Net income (loss).................... 30,264 14,021 (1,043)
Condensed Balance Sheet:
Assets............................... 1,693,454 235,682 239,149
Liabilities.......................... 1,276,922 200,667 213,850
Investments (see Note 2)............. 237,241 13,061 7,306
Project development costs............ 1,919 875 912
---------- ---------- ----------
Total investments............ 239,160 13,936 8,218
========== ========== ==========
Company's share of net income (loss)... $ 15,819 $ 6,537 $ (2,854)
</TABLE>
The following details the Company's income from investments in
unconsolidated power projects and the service contract revenue recorded by the
Company related to those power projects (in thousands):
<TABLE>
<CAPTION>
INCOME FROM UNCONSOLIDATED
INVESTMENTS IN POWER PROJECTS SERVICE CONTRACT REVENUE
----------------------------- ------------------------
FOR THE YEARS ENDED DECEMBER 31,
COMPANY'S --------------------------------------------------------
OWNERSHIP 1997 1996 1995 1997 1996 1995
PERCENTAGE -------- ------- -------- ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C>
Sumas Cogeneration Company, L.P.... (1) $ 8,565 $6,396 $(3,049) $2,073 $2,034 $2,021
O.L.S. Energy-Agnews, Inc.......... 20% 17 (190) (82) 1,712 1,954 1,515
Geothermal Energy Partners, Ltd.... 5% 454 331 277 3,024 3,990 3,547
Texas Cogeneration Company......... 50% 6,331 -- -- 2,782 -- --
Auburndale Power Partners, L.P..... 50% (245) -- -- -- -- --
Gordonsville Energy, L.P........... 50% 404 -- -- -- -- --
KIAC Partners...................... 50% (190) -- -- -- -- --
Nissequogue Cogen Partners......... 50% 60 -- -- -- -- --
TBG Cogen Partners................. 45% 223 -- -- -- -- --
Lockport Energy Associates, L.P.... 11% 200 -- -- -- -- --
------- ------ ------- ------ ------ ------
$15,819 $6,537 $(2,854) $9,591 $7,978 $7,083
======= ====== ======= ====== ====== ======
</TABLE>
The Company received $20.3 million and $1.3 million in distributions from
Sumas for the years ended December 31, 1997 and 1996, respectively. The Company
received $767,000 in distributions from Lockport Energy Associates, L.P. for the
year ended December 31, 1997.
- ---------------
(1) On September 30, 1997, the partnership agreement governing Sumas
Cogeneration Company, L.P. ("Sumas") was amended changing the distribution
percentages to the partners. As provided for in the amendment, the Company's
percentage share of the project's cash flow increased from 50% to
approximately 70% through June 30, 2001, based on certain specified
payments. Thereafter, the Company will receive 50% of the project's cash
flow until a 24.5% pre-tax rate of return on its original investment is
achieved, at which time the Company's equity interest in the partnership
will be reduced to 0.1%. As a result of the amendment of the partnership
agreement and the receipt of certain distributions during 1997, the
Company's investment in Sumas was reduced to zero. Because the investment
has been reduced to zero and there are no continuing obligations of the
Company related to Sumas, the Company expects that income recorded in future
periods will approximate the amount of cash received from partnership
distributions.
F-27
<PAGE> 81
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
6. NOTES AND LOANS RECEIVABLE
SUMAS POWER PLANT
In May 1993, in accordance with the Sumas partnership agreement, the
Company was entitled to receive a distribution of $1.5 million and Sumas Energy,
Inc. ("SEI"), the Company's partner in Sumas, was required to make a capital
contribution of $1.5 million. In order to meet SEI's $1.5 million capital
contribution requirement, the Company loaned $1.5 million to the sole
shareholder of SEI, who in turn loaned the funds to SEI, who in turn contributed
the capital to Sumas. The interest rate on the loan was 20% and was secured by a
security interest in the loan between SEI and its sole shareholder. The Company
received all principal plus accrued interest totaling $2.8 million in 1997.
In March 1994, the Company loaned $10.0 million to the sole shareholder of
SEI. The interest rate on the loan was 16.25%. The loan was secured by a pledge
to Calpine of SEI's interest in Sumas. The Company deferred the recognition of
interest income from these notes until Sumas generated net income.
During 1997, the $10.0 million loan was sold to a third party. The Company
received all unpaid principal and interest related to both loans and recognized
a total of $6.9 million of the interest income during 1997 (of which $3.5
million was previously deferred). In addition, the Company recorded a $1.1
million gain upon the sale of the $10.0 million loan, which was recorded in
Other (income) expense. In 1996, the Company recognized $2.1 million of interest
income related to the above two loans, which represents the portion of Sumas'
earnings not recognized by the Company related to its equity investment in
Sumas.
In September 1997, the Company entered into a loan agreement with SEI's
sole shareholder wherein the Company agreed to make available a line of credit
up to $15.0 million, the proceeds of which are required to be used to develop a
new project. SEI has guaranteed the payment and performance of obligations under
this agreement and borrowings under the agreement will be collateralized by the
new project and the sole shareholder's 100% interest in SEI. The loan agreement
will expire on December 31, 2003.
TEXAS CITY AND CLEAR LAKE POWER PLANTS
In connection with the acquisition of TCC, the Company purchased from the
existing lenders the $155.6 million of outstanding project debt of the Texas
City Power Plant (approximately $53.0 million) and the Clear Lake Power Plant
(approximately $102.6 million). At December 31, 1997, there were loans
receivable of $37.1 million from Texas City and $94.7 million from Clear Lake
(of these amounts $30.5 million is current and $101.3 million is long term). The
effective interest rate on the loan to Texas City including the effect of the
swap arrangement, was approximately 7.9% at December 31, 1997; the loan matures
June 30, 1999. The effective interest rate on the loan to Clear Lake, including
the effect of the existing swap arrangement, was approximately 8.3%; the loan
matures December 31, 2003. Both notes are secured by the assets of the
respective partnerships.
CALPINE VAPOR INC.
In November 1995, Calpine Vapor Inc. ("Vapor") entered into agreements with
Constructora y Perforadora Latina, S.A. de C.V. ("Coperlasa") and certain
Mexican bank lenders to loan $18.5 million to Coperlasa in connection with a
geothermal steam production contract at the Cerro Prieto geothermal resource
("Cerro Prieto Project") in Baja California, Mexico (see Note 2, Concentration
of Credit Risks). The resource currently produces electricity from geothermal
power plants owned and operated by Comision Federal de Electricidad ("CFE"),
Mexico's national utility. The steam field contract is between Coperlasa and
CFE. Vapor receives fees for technical services provided to the project. At
December 31, 1997 and 1996, notes receivable were $16.1 million and $18.0
million, respectively. Interest accrues on the outstanding notes receivable at
approximately 18.9%. The Company is deferring the recognition of interest income
from this note
F-28
<PAGE> 82
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
until the Cerro Prieto Project generates sufficient cash flows available for
distribution to support the collectibility of accrued interest.
7. REVOLVING CREDIT FACILITY AND LINES OF CREDIT
At December 31, 1997 and 1996, the Company had a $50.0 million credit
facility available with a consortium of commercial lending institutions which
include The Bank of Nova Scotia, ING, Sumitomo Bank of California and Canadian
Imperial Bank of Commerce. As of December 31, 1997, the Company had no
borrowings and $9.4 million of letters of credit outstanding. This amount
reflects $6.0 million to secure performance with the Clear Lake Power Plant,
$1.5 million to secure performance under a purchase power agreement, and $1.9
million related to operating expenses at the Watsonville Power Plant. At
December 31, 1996, the Company had no borrowings and $5.9 million of letters of
credit outstanding, which reflected $3.0 million to secure performance with the
Pasadena Power Plant and $2.9 million related to operating expenses at the
Watsonville Power Plant. Borrowings bear interest at The Bank of Nova Scotia's
base rate or at the London InterBank Offering Rate ("LIBOR"), plus an applicable
margin. Interest is paid on the last day of each interest period for such loans,
but not less often than quarterly, based on the principal amount outstanding
during the period for base rate loans, and on the last day of each applicable
interest period, but not less often than 90 days, for LIBOR loans. The credit
agreement expires in September 1999. The credit agreement specified that the
Company maintain certain covenants with which the Company was in compliance.
Commitment fees related to this line of credit are charged based on 0.50% of
committed unused credit.
At December 31, 1997 and 1996, the Company had a loan facility with
available borrowings totaling $1.2 million. As of December 31, 1997, the Company
had no borrowings and $74,000 of letters of credit outstanding. There were no
borrowings and $900,000 of letters of credit outstanding as of December 31,
1996.
8. NON-RECOURSE PROJECT FINANCING
The components of non-recourse project financing as of December 31, 1997
and 1996 are (in thousands):
<TABLE>
<CAPTION>
1997 1996
-------- --------
<S> <C> <C>
Senior-term loans:
Fixed rate portion........................... $ -- $ 73,000
Variable rate portion........................ -- 20,000
Premium on debt.............................. -- 1,824
-------- --------
Total senior-term loans.............. -- 94,824
Junior-term loan............................... -- 19,965
Notes payable to banks......................... 295,859 194,478
-------- --------
Total long-term debt................. 295,859 309,267
Less current portion................. 112,966 30,627
-------- --------
Long-term debt, less current
portion............................ $182,893 $278,640
======== ========
</TABLE>
Senior-Term and Junior-Term Loans -- The Company entered into Senior-Term
and Junior-Term Loans in connection with the Company's acquisition of CGC in
1993. On July 8, 1997, the Company repaid all Senior-Term and Junior-Term Loans
before their maturity date from the proceeds of the 8 3/4% Senior Notes Due
2007. In connection with this transaction, the Company terminated one swap
transaction and retained one swap transaction, which was redesignated to other
floating rate financings. The Company had entered into swap transactions to
minimize the impact of changes in interest rates on a portion of the Senior-
Term loans. At December 31, 1997, the remaining swap had an effective interest
rate of 9.9%. The Company
F-29
<PAGE> 83
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
is potentially exposed to credit risk in an event of non-performance by the
other parties to the swap agreements.
Notes Payable to Banks -- In June 1995, the Company entered into an
agreement with Sumitomo Bank to finance the acquisition of the Greenleaf Power
Plants. Of the $71.9 million debt outstanding at December 31, 1997, $56.8
million bears interest fixed at 7.4%, with the remaining floating rate portion
accruing interest at LIBOR, plus an applicable margin (6.5% at December 31,
1997). At December 31, 1996, $74.7 million of debt was outstanding, of which
$59.0 million was at the fixed interest rate of 7.4%, with the remaining
floating rate portion accruing interest at approximately 6.2%. This debt is
secured by all of the assets of the Greenleaf Power Plants. Interest on the
floating rate portion may be at Sumitomo's base rate plus an applicable margin
or at LIBOR plus an applicable margin. Interest on base rate loans is paid at
the end of each calendar quarter, and interest on LIBOR based loans is paid on
each maturity date, but not less often than quarterly, based on the principal
amount outstanding during the period. At the Company's discretion, the LIBOR
based loans may be held for various maturity periods of at least 1 month up to
12 months. The $71.9 million debt is being repaid quarterly, with a final
maturity date of December 31, 2010. The credit agreement specifies that the
Company maintain certain covenants in which the Company was in compliance at
December 31, 1997.
On August 29, 1996, the Company entered into an agreement with Banque
Nationale de Paris ("BNP") to finance the acquisition of the Gilroy Power Plant.
As of December 31, 1997, BNP had provided a $120.5 million loan consisting of a
15-year tranche in the amount of $86.9 million and an 18-year tranche in the
amount of $33.6 million. As of December 31, 1996, BNP had provided a $119.8
million loan consisting of a 15-year tranche in the amount of $84.8 million and
an 18-year tranche in the amount of $35.0 million. The debt is secured by all of
the assets of the Gilroy Power Plant. A portion of the BNP notes bears interest
fixed at a weighted average of 6.6% as of December 31, 1997 and 1996 (see
discussion below), with the remainder accruing interest at floating rate.
Interest on the floating rate portion may be at BNP's base rate plus an
applicable margin or at LIBOR plus an applicable margin (7.1% and 6.6% at
December 31, 1997 and 1996, respectively). Interest on the loans is payable not
less often than quarterly. Interest on LIBOR based loans is paid on each
maturity date, but not less often than quarterly. At the Company's discretion,
LIBOR based loans may be held for various maturity periods of at least 1 month
and up to 12 months. The $120.5 million debt is repaid semi-annually with a
final maturity date of August 28, 2011. Commitment fees are charged based on 1%
to 1.125% of committed unused credit. The Company entered into four interest
rate swap agreements to minimize the impact of changes in interest rates. These
agreements fix the interest on $85.1 million of principal at a weighted average
interest rate of 6.6%. The interest rate swap agreements mature through August
2011. The Company is exposed to credit risk in the event of non-performance by
the other parties to the swap agreements.
On June 23, 1997, the Company entered into a $125.0 million non-recourse
project financing with The Bank of Nova Scotia. Proceeds were utilized for the
acquisition of the 50% interest in TCC and the purchase from the lenders of
$155.6 million of outstanding non-recourse project financing. The $125.0 million
non-recourse project financing matures on June 22, 1998. The Company expects to
refinance this non-recourse project financing prior to maturity. On December 31,
1997, $103.4 million of borrowings were outstanding which bear interest at The
Bank of Nova Scotia's base rate or LIBOR, plus an applicable margin
(approximately 7.2% at December 31, 1997). The Company utilized swap
arrangements to minimize the impact of potential changes in interest rates on
the project debt. The effective interest rate, including the effect of the swap
arrangement, was approximately 7.1% at December 31, 1997. The interest rate swap
agreements mature in June 1998. The Company has potential exposure to credit
risk in the event of non-performance by other parties to the swap agreements.
The credit agreement specifies that the Company maintain certain covenants in
which the Company was in compliance at December 31, 1997.
F-30
<PAGE> 84
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
At December 31, 1997, the Company held a credit agreement with ING to
provide $151.8 million of non-recourse project financing for the Pasadena Power
Plant (see Note 3, "Pasadena Cogeneration Project"). Interest is payable at
ING's base rate or the Federal Funds Rate plus an applicable margin on the last
day of each calendar quarter, or at LIBOR plus an applicable margin upon
maturity of the loan, but not less often than quarterly. All interest is due and
payable upon conversion of the construction loan to a term loan. Subject to the
terms of the credit agreement, all or part of the construction loan will be
converted to a term loan upon completion of construction. Commitment fees are
charged based on 0.375% of committed unused credit. No borrowings were
outstanding at December 31, 1997 and 1996. In January 1998, the Company borrowed
$35.9 million in accordance with the terms of the credit agreement. Beginning in
June 1997, the Company was obligated to enter into several hedge transactions
pursuant to the credit agreement, the notional values of which range from $25.0
million to $75.0 million, all of which were hedged at 7.2%.
The annual principal maturities of the non-recourse project financing
outstanding at December 31, 1997 are as follows (in thousands):
<TABLE>
<S> <C>
1998.............................. $112,966
1999.............................. 8,683
2000.............................. 10,352
2001.............................. 10,631
2002.............................. 11,132
Thereafter........................ 142,095
--------
Total................... $295,859
========
</TABLE>
The non-recourse project financing is held by subsidiaries of Calpine. The
debt agreements governing the non-recourse project financing generally restrict
their ability to pay dividends, make distributions or otherwise transfer funds.
The dividend restrictions in such agreements generally require that, prior to
the payment of dividends, distributions or other transfers, the subsidiary or
other affiliate must provide for the payment of other obligations, including
operating expenses, debt service and reserves.
9. NOTES PAYABLE
At December 31, 1996, the Company had a non-interest bearing promissory
note for $6.5 million payable to Natomas Energy Company, a wholly-owned
subsidiary of Maxus Energy Company. This note had been discounted to yield 8.0%
per annum, due September 9, 1997, and had a carrying value of $6.2 million at
December 31, 1996. On July 8, 1997, the Company repaid the promissory note
before its maturity date from the proceeds of the 8 3/4% Senior Notes Due 2007
(see Note 10).
10. SENIOR NOTES
On July 8, 1997, the Company issued $200.0 million aggregate principal
amount of 8 3/4% Senior Notes Due 2007. Transaction costs of $9.7 million
incurred in connection with the debt offering were capitalized and are included
in Other assets and amortized over the ten-year life of the 8 3/4% Senior Notes
Due 2007.
On September 10, 1997, the Company issued an additional $75.0 million
aggregate principal amount of 8 3/4% Senior Notes Due 2007.
In May and June 1997, the Company executed five interest rate hedging
transactions related to debt. The notional value of the debt was $182.0 million
and was designed to eliminate interest rate risk for the period from May 1997 to
July 1997 when the $200.0 million of 8 3/4% Senior Notes Due 2007 were priced.
These interest rate hedging transactions were designated as a hedge of the
anticipated bond offering, and the resulting $3.0 million cost resulting from
the hedges is being amortized over the life of the bonds. The effective
F-31
<PAGE> 85
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
interest rate on the $275.0 million aggregate principal amount after the hedging
transactions and the amortization of transaction costs was 9.1%.
The 8 3/4% Senior Notes Due 2007 will mature on July 15, 2007. The Company
has no sinking fund or mandatory redemption obligations with respect to the
8 3/4% Senior Notes Due 2007. Interest is payable semi-annually on January 15
and July 15 of each year while the 8 3/4% Senior Notes Due 2007 are outstanding,
commencing on January 15, 1998. Based on the traded yield to maturity, the
approximate fair market value of the 8 3/4% Senior Notes Due 2007 was $280.5
million as of December 31, 1997.
On May 16, 1996, the Company issued $180.0 million aggregate principal
amount of 10 1/2% Senior Notes Due 2006. Transaction costs of $5.1 million
incurred in connection with the public debt offering were recorded in Other
assets and amortized over the ten-year life of the 10 1/2% Senior Notes Due
2006. The effective interest rate of the $180.0 million aggregate principal
amount after the amortization of transaction costs was 10.7%.
The 10 1/2% Senior Notes Due 2006 will mature on May 15, 2006. The Company
has no sinking fund or mandatory redemption obligations with respect to the
10 1/2% Senior Notes Due 2006. Interest is payable semi-annually on May 15 and
November 15. Based on the traded yield to maturity, the approximate fair market
value of the 10 1/2% Senior Notes Due 2006 was $196.2 million as of December 31,
1997.
The 9 1/4% Senior Notes Due 2004 will mature on February 1, 2004. The
Company has no sinking fund or mandatory redemption obligations with respect to
the 9 1/4% Senior Notes Due 2004. Interest is payable semi-annually on February
1 and August 1. Based on the traded yield to maturity, the approximate fair
market value of the 9 1/4% Senior Notes Due 2004 was $108.7 million as of
December 31, 1997. The effective interest rate on the $105.0 million aggregate
principal amount after amortization of transaction costs was 9.6%.
The Senior Note indentures specify that the Company maintains certain
covenants with which the Company was in compliance. The Company may, under
certain circumstances, be limited in its ability to make restricted payments, as
defined, which include dividends and certain purchases and investments, incur
additional indebtedness and engage in certain transactions.
11. PROVISION FOR INCOME TAXES
The Company follows the liability method of accounting for income taxes
whereby deferred income taxes are recognized for the tax consequences of
"temporary differences" to the extent they are not reduced by net operating loss
and tax credit carryforwards by applying enacted statutory rates.
The components of the deferred tax liability as of December 31, 1997 and
1996 are (in thousands):
<TABLE>
<CAPTION>
1997 1996
--------- ---------
<S> <C> <C>
Expenses deductible in a future period............... $ 4,122 $ 3,329
Net operating loss and credit carryforwards.......... 20,260 19,856
Other differences.................................... 2,524 494
--------- ---------
Deferred tax asset................................. 26,906 23,679
--------- ---------
Property differences................................. (156,526) (119,842)
Difference in taxable income and income from
investments recorded on the equity method.......... (5,798) (2,753)
Other differences.................................... (6,632) (1,469)
--------- ---------
Deferred tax liabilities........................... (168,956) (124,064)
--------- ---------
Net deferred tax liability...................... $(142,050) $(100,385)
========= =========
</TABLE>
F-32
<PAGE> 86
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
The net operating loss and credit carryforwards consist of federal net
operating loss carryforwards which expire 2005 through 2010 and federal and
state alternative minimum tax credit carryforwards which can be carried forward
indefinitely. At December 31, 1997, the federal net operating loss carryforwards
were approximately $11.3 million. At December 31, 1997, state net operating
losses have been fully utilized. At December 31, 1997, federal and state
alternative minimum tax credit carryforwards were approximately $10.6 million
and $3.6 million, respectively. In 1997 and 1996, the Company decreased its
deferred income tax liability by $2.1 million and $769,000 to reflect the change
in the California state income tax rate from 9.3% to 8.8% effective January 1,
1997 and to reflect the decrease in the California tax rate due to the Company's
expansion into states other than California.
Realization of the deferred tax assets and federal net operating loss
carryforwards is dependent, in part, on generating sufficient taxable income
prior to expiration of the loss carryforwards. In September 1996, the Company
underwent an ownership change as a result of the initial public offering of the
Company's common stock. This ownership change limits the amount of net operating
loss and credit carryforwards available to offset current tax liabilities.
Although realization is not assured, management believes it is more likely than
not that all of the deferred tax asset will be realized based on estimates of
future taxable income. The amount of the deferred tax asset considered
realizable, however, could be reduced in the near term if estimates of future
taxable income during the carryforward period are reduced.
The provision for income taxes for the years ended December 31, 1997, 1996
and 1995 consists of the following (in thousands):
<TABLE>
<CAPTION>
1997 1996 1995
------- ------- -------
<S> <C> <C> <C>
Current:
Federal..................................... $ 1,892 $ 5,671 $ 3,085
State....................................... 917 1,805 1,163
Deferred:
Federal..................................... 14,989 3,890 816
State....................................... 2,897 (801) (15)
Adjustment in state tax rate (net of
federal benefit)....................... (2,113) (769) --
Revision in prior years' tax estimates... (122) (732) --
------- ------- -------
Total provision..................... $18,460 $ 9,064 $ 5,049
======= ======= =======
</TABLE>
The Company's effective rate for income taxes for the years ended December
31, 1997, 1996 and 1995 differs from the United States statutory rate, as
reflected in the following reconciliation.
<TABLE>
<CAPTION>
1997 1996 1995
---- ---- ----
<S> <C> <C> <C>
United States statutory tax rate....................... 35.0% 35.0% 35.0%
State income tax, net of federal benefit............... 5.0 6.0 6.0
Depletion allowance.................................... (2.1) (2.3) (0.3)
Effect of change in state tax rates, net of federal
benefit.............................................. -- (3.0) --
Decrease in California deferred tax due to Company's
expansion into other states, net of federal
benefit.............................................. (4.1) -- --
Revision in prior years' tax estimates................. -- (2.6) --
Other, net............................................. 0.9 (0.4) (0.1)
---- ---- ----
Effective income tax rate.................... 34.7% 32.7% 40.6%
==== ==== ====
</TABLE>
F-33
<PAGE> 87
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
12. RETIREMENT SAVINGS PLAN
The Company has a defined contribution savings plan under Section 401(a)
and 501(a) of the Internal Revenue Code. The plan provides for tax deferred
salary deductions and after-tax employee contributions. Employees automatically
become participants on the first quarterly entry date after completion of three
months of service. Contributions include employee salary deferral contributions
and a 3% employer profit-sharing contribution. Employer profit-sharing
contributions in 1997, 1996, and 1995 totaled $588,000, $485,000 and $350,000,
respectively.
13. STOCKHOLDERS' EQUITY
Common Stock
In September 1996, the Company completed an initial public offering of
18,045,000 shares of its common stock with $0.001 par value per share (the
"Common Stock Offering"). In the Common Stock Offering, the Company issued and
sold 5,477,820 shares of common stock and Electrowatt Ltd. ("Electrowatt") sold
12,567,180 shares of common stock, representing its entire ownership interest in
the Company. As a result of the Common Stock Offering, Electrowatt no longer
owns any interest in the Company. The Company received approximately $82.1
million of net proceeds from the Common Stock Offering. In October 1996, the
Company issued an additional 1,793,400 shares of common stock to cover
over-allotments of shares in connection with the Common Stock Offering and
received approximately $27.1 million of net proceeds. In connection with the
Common Stock Offering, the Company completed a 5.194-for-1 stock split of the
Company's common stock and converted the Company's outstanding Series A
Preferred Stock into shares of common stock. The accompanying financial
statements reflect the stock split retroactively for all periods presented.
Preferred Stock and Preferred Share Purchase Rights
The Company had 5,000,000 authorized shares of Series A Preferred Stock,
all of which were issued on March 21, 1996 to Electrowatt. The shares of Series
A Preferred Stock were not publicly traded. No dividends were payable on the
Series A Preferred Stock. The Series A Preferred Stock contained provisions
regarding liquidation and conversion rights. Upon the consummation of the Common
Stock Offering, all of the Series A Preferred Stock were converted into
approximately 2.2 million shares of common stock and sold to the public in the
Common Stock Offering by Electrowatt.
On June 5, 1997, the Board of Directors adopted a Stockholders Rights Plan
("Rights Plan") to strengthen the Board of Directors ability to protect the
Company's stockholders. The Rights Plan is designed to protect against abusive
or coercive takeover tactics that are not in the best interests of the Company
and its stockholders. To implement the Rights Plan, the Board of Directors
declared a dividend of one preferred share purchase right (a "Right") for each
outstanding share of common stock, par value $0.001 per share, held on record as
of June 18, 1997. On December 31, 1997, there were 19,905,233 Rights
outstanding. Each Right initially represents a contingent right to purchase,
under certain circumstances, one one-thousandth of a share (a "Unit") of Series
A Junior Participating Preferred Stock, par value $0.001 per share (the
"Preferred Stock"), of the Company at a price of $80.00 per Unit, subject to
adjustment. The Rights become exercisable and trade independently from the
Company's common stock upon the public announcement of the acquisition by a
person or group of 15% or more of the Company's common stock, or ten days after
commencement of a tender or exchange offer that would result in the acquisition
of 15% or more of the Company's common stock. Each Unit of Preferred Stock
purchased upon exercise of the Rights will be entitled to a dividend equal to
any dividend declared per share of common stock and will have one vote, voting
together with the common stock. In the event of liquidation, each share of
Preferred Stock will be entitled to any payment made per share of common stock.
F-34
<PAGE> 88
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
If the Company is acquired in a merger or other business combination
transaction after a person or group has acquired 15% or more of the Company's
common stock, each Right will entitle its holder to purchase at the Right's
exercise price a number of the acquiring company's common shares having a market
value of twice such exercise price. In addition, if a person or group acquires
15% or more of the Company's common stock, each Right will entitle its holder
(other than the acquiring person or group) to purchase, at the Right's exercise
price, a number of fractional shares of the Company's Preferred Stock or shares
of common stock having a market value of twice such exercise price.
The Rights expire June 18, 2007 unless redeemed earlier by the Company's
Board of Directors. The Board of Directors can redeem the Rights at a price of
$0.01 per Right at any time before the Rights become exercisable, and thereafter
only in limited circumstances.
14. STOCK-BASED COMPENSATION PROGRAMS
1996 Employee Stock Purchase Plan
The Company adopted the 1996 Employee Stock Purchase Plan ("ESPP") in July
1996. Eligible employees may purchase up to 275,000 shares of common stock at
semi-annual intervals through periodic payroll deductions. Purchases are limited
to 15 percent of an employee's eligible compensation, up to a maximum of $25,000
per year. Shares are purchased on January 31 and July 31 of each year. Under the
ESPP, 54,149 shares were issued at a weighted average fair value of $13.65 per
share in 1997. On January 30, 1998, employees participating in the ESPP
purchased an additional 30,385 shares at a weighted average fair value of $13.39
per share. The purchase price is 85% of the lower of (i) the fair market value
of the common stock on the participant's entry date into the offering period, or
(ii) the fair market value on the semi-annual purchase date.
1996 Stock Incentive Plan
The Company adopted the 1996 Stock Incentive Plan ("SIP") in September
1996. The SIP succeeded the Company's previously adopted stock option program.
The Company accounts for the SIP under Accounting Principles Board Opinion No.
25, "Accounting for Stock Issued to Employees" under which no compensation cost
has been recognized. Had compensation cost for the SIP been determined
consistent with the methodology of SFAS No. 123, "Accounting for Stock-Based
Compensation", the Company's net income and earnings per share would have been
reduced to the following pro forma amounts (in thousands, except per share
amounts):
<TABLE>
<CAPTION>
1997 1996 1995
------- ------- -------
<S> <C> <C> <C> <C>
Net income As reported $34,699 $18,692 $ 7,378
Pro Forma $33,528 $18,145 $ 7,232
Basic earnings per share As reported $ 1.74 $ 1.45 $ 0.71
Pro Forma $ 1.68 $ 1.41 $ 0.70
Diluted earnings per share As reported $ 1.65 $ 1.26 $ 0.67
Pro Forma $ 1.60 $ 1.22 $ 0.66
</TABLE>
The fair value of options granted in 1995, 1996 and 1997 was $1.23, $3.29
and $10.28 on the date of grant using the Black-Scholes option pricing model
with the following weighted-average assumptions: expected dividend yields of 0%,
expected volatility of 44%, 27% and 0% for 1997, 1996 and 1995, risk-free
interest rates of 5.8%, 6.2% and 5.4% for 1997, 1996 and 1995, respectively, and
expected lives of 3 years for 1995 and 1996, and 7 years for 1997.
Because the SFAS No. 123 methodology of accounting has not been applied to
options granted prior to January 1, 1995, the resulting pro forma compensation
cost may not be representative of that to be expected in
F-35
<PAGE> 89
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
future years. The Company may grant options for up to 4,041,858 shares under the
SIP. As of December 31, 1997, the Company had granted options to purchase
2,519,803 shares of common stock. Under the SIP, the option exercise price
equals the stock's fair market value on date of grant. The SIP options generally
vest after four years and expire after 10 years. Changes in options outstanding,
granted, exercisable and cancelled by the Company during the years 1997, 1996,
and 1995, whether under the option or purchase plan were as follows:
<TABLE>
<CAPTION>
AVAILABLE FOR WEIGHTED
OPTION OR NUMBER OF AVERAGE
AWARD SHARES EXERCISE PRICE
------------- --------- --------------
(IN THOUSANDS)
<S> <C> <C> <C>
Beginning Balance January 1, 1995................ 1,160,782 1,436,141 $ 1.53
Granted..................................... (444,333) 444,333 4.91
Cancelled................................... 25,963 (25,963) 2.13
--------- --------- ---------
Outstanding December 31, 1995.................... 742,412 1,854,511 2.34
Additional shares reserved..................... 1,444,935 -- --
Granted..................................... (547,579) 547,579 8.71
Exercised................................... -- (5,000) 1.85
Cancelled................................... 56,796 (56,796) 7.90
--------- --------- ---------
Outstanding December 31, 1996.................... 1,696,564 2,340,294 3.69
Granted..................................... (394,217) 394,217 18.31
Exercised................................... -- (163,156) 1.33
Cancelled................................... 51,552 (51,552) 8.55
--------- --------- ---------
Outstanding December 31, 1997.................... 1,353,899 2,519,803 $ 6.03
========= ========= =========
Options exercisable:
December 31, 1995................................ 1,217,340 $ 1.15
December 31, 1996................................ 1,445,746 1.71
December 31, 1997................................ 1,635,469 3.23
</TABLE>
The following tables summarizes information concerning outstanding and
exercisable options at December 31, 1997:
<TABLE>
<CAPTION>
OUTSTANDING OPTIONS
---------------------------------------------------- OPTIONS EXERCISABLE
WEIGHTED AVERAGE --------------------------------
REMAINING WEIGHTED WEIGHTED
RANGE OF NUMBER OF CONTRACTUAL LIFE AVERAGE NUMBER OF AVERAGE
EXERCISE PRICES SHARES IN YEARS EXERCISE PRICE SHARES EXERCISE PRICE
--------------- -------------- ---------------- -------------- -------------- --------------
(IN THOUSANDS) (IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
$ 0.50 - $ 0.50........... 841,220 5.00 $ 0.50 841,220 $ 0.50
$ 1.85 - $ 1.85........... 117,887 5.25 1.85 117,887 1.86
$ 4.57 - $ 4.91........... 692,228 7.48 4.77 489,737 4.71
$ 6.83 - $ 6.83........... 1,317 9.00 6.83 1,317 6.83
$ 8.57 - $ 8.57........... 474,251 9.00 8.57 117,808 8.57
$16.00 - $20.50........... 382,900 9.22 18.19 57,500 19.27
$20.75 - $20.75........... 10,000 9.04 20.75 10,000 20.75
--------- --------- --------- --------- ---------
Total........... 2,519,803 7.10 $ 6.03 1,635,469 $ 3.23
========= ========= ========= ========= =========
</TABLE>
15. SIGNIFICANT CUSTOMERS
The Company's electricity and steam sales revenue is primarily from two
sources -- PG&E and the Sacramento Municipal Utility District ("SMUD").
F-36
<PAGE> 90
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
Revenues earned from these sources for the years ended, December 31, 1997,
1996 and 1995 were as follows (in thousands):
<TABLE>
<CAPTION>
1997 1996 1995
REVENUES: -------- -------- --------
<S> <C> <C> <C>
PG&E....................................... $221,457 $183,531 $112,522
SMUD....................................... 13,223 14,609 12,345
</TABLE>
Accounts receivable at December 31, 1997 and 1996 were as follows (in
thousands):
<TABLE>
<CAPTION>
1997 1996
ACCOUNTS RECEIVABLE: -------- --------
<S> <C> <C> <C>
PG&E....................................... $ 29,631 $ 27,534
SMUD....................................... 1,019 1,137
</TABLE>
Industry restructuring and deregulation (see Note 16, "Regulation and CPUC
Restructuring") will also affect PG&E, the Company's primary customer.
16. COMMITMENTS AND CONTINGENCIES
Capital Projects -- The Company has 1998 commitments of $19.8 million
related to the construction of the Pasadena Power Plant (see Note 3, "Pasadena
Cogeneration Project").
Royalties and Leases -- The Company is committed under several geothermal
leases and right-of-way, easement and surface agreements. The geothermal leases
generally provide for royalties based on production revenue with reductions for
property taxes paid. The right-of-way, easement and surface agreements are based
on flat rates and are not material. Under the terms of certain geothermal
leases, royalties accrue at rates ranging from 7% to 12.5% of steam and effluent
revenue. Certain properties also have net profits and overriding royalty
interests ranging from approximately 1.45% to 28%, which are in addition to the
land royalties. Most lease agreements contain clauses providing for minimum
lease payments to lessors if production temporarily ceases or if production
falls below a specified level.
Expenses under these agreements for the years ended December 31, 1997, 1996
and 1995 are (in thousands):
<TABLE>
<CAPTION>
1997 1996 1995
------- ------- -------
<S> <C> <C> <C>
Production Royalties.................. $10,803 $10,793 $10,574
Lease payments........................ 222 246 225
</TABLE>
Natural Gas Purchases -- The Company enters into short-term gas purchase
contracts with third parties to supply gas to its gas-fired cogeneration
projects.
Watsonville Operating Lease -- In June 1995, the Company acquired a 14.5
year operating lease (through December 2009) for the 28.5 megawatt natural
gas-fired cogeneration power plant located in Watsonville, California. Under the
terms of the lease, basic and contingent rents are payable each month during the
period from July through December. As of December 31, 1997, future basic rent
payments have remained the same from prior years at $2.9 million for 1996 and
1997, respectively. Future payment from 1998 to 2001 will continue at the
current rate of $2.9 million, and $24.4 million thereafter through December
2009. Contingent rent expense for 1997 and 1996 was $864,000 and $671,000,
respectively. This expense is based on the net of revenues less all operating
expenses, fees, reserve requirements, basic rent and supplemental rent payments.
Of the remaining balance, 60% is payable to the lessor and 40% is payable to the
Company.
F-37
<PAGE> 91
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
Office and Equipment Leases -- The Company leases its corporate office,
Santa Rosa office facilities and certain office equipment under noncancellable
operating leases expiring through 2002. Future minimum lease payments under
these leases are (in thousands):
<TABLE>
<S> <C>
1998................................ $1,409
1999................................ 1,211
2000................................ 1,128
2001................................ 564
2002................................ 114
Thereafter.......................... --
------
$4,426
======
</TABLE>
Lease payments are subject to adjustments for the Company's pro rata
portion of annual increases or decreases in building operating costs. In 1997,
1996, and 1995 rent expenses for noncancellable operating leases amounted to
$1.2 million, $1.0 million and $733,000, respectively.
Regulation and CPUC Restructuring -- Electricity and steam sales agreements
with PG&E are regulated by the California Public Utilities Commission ("CPUC").
In December 1995, the CPUC issued a decision which proposed the transition of
the regulated electric generation market to a competitive generation market
beginning January 1, 1998. Since the proposed restructure represented a
widespread impact on the market structure, requiring participation and oversight
of the Federal Energy Regulatory Commission (the "FERC"), the CPUC sought and
built a California consensus coalition which resulted in filings at the FERC
which permitted the CPUC and the FERC to collectively proceed with
implementation of the new competitive market structure. In late 1996,
comprehensive legislation, AB 1890 ("the Bill"), was signed into California law
which adopted the basic tenets of the CPUC electric industry restructure
decision and directed the CPUC to proceed with implementation of restructure
with customer choice of electricity supplier available no later than January 1,
1998. The Bill provided for market power mitigation by utility divestiture of
fossil generation plants, provided a four year transition period for utility
recovery of stranded costs, provided for sanctity of existing qualifying
facility ("QF") contracts with provision for voluntary restructure, established
an electricity rate freeze for the four year transition period for certain
customers, mandated a 10% rate reduction beginning January 1, 1998 and
continuing through the transition period for small commercial and residential
customers financed by issuance of rate reduction bonds, and provided specified
funds for continued public service programs including public interest research
and development and enhancement of in-state renewable energy resources, which
includes geothermal operations. In late 1997, the CPUC and the FERC issued
decisions which provided for January 1, 1998 implementation of the California
Independent Systems Operator ("ISO") responsible for centralized control and
reliable operation of the state-wide electric transmission grid and the Power
Exchange ("PX") responsible for the competitive electric energy auction. In late
1997, CPUC-approved sales of certain utility-owned fossil generation plants were
completed and applications were pending at the CPUC for sales of the remaining
utility-owned California fossil and geothermal power plants. Investor-owned
utilities, though transferring control to the ISO, will continue to own and
collect revenue from their transmission facilities and will continue to be
regulated utility distribution companies ("UDC") for all electric service
providers with default electric supplier responsibility.
In December 1997, mechanics for operation of the ISO and PX were not yet
fully perfected and implementation of deregulation was delayed to April 1, 1998.
The California Energy Commission ("CEC") was directed by the Bill to develop a
competitive mechanism for allocation and distribution of funds made available
for public interest research and development and enhancement of in-state
renewable resources. The CEC, in late 1997, issued its draft guidelines for
selective allocation and distribution of the funds which are to be available
over the four year transition period to a fully competitive electric services
industry. Though the
F-38
<PAGE> 92
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
Company believes that implementation of electric industry restructure can
provide significant opportunity for independent power producers, the ultimate
impact of both increased competition and the changing regulatory environment on
the Company's future results from operations is uncertain.
A domestic electricity generating project must be a QF under the FERC
regulations in order to take advantage of certain rate and regulatory incentives
provided by the Public Utility Regulatory Policies Act of 1978, as amended
("PURPA"). PURPA exempts owners of QFs from the Public Utility Holding Company
Act of 1935, as amended ("PUHCA"), and exempts QFs from most provisions of the
Federal Power Act (the "FPA") and state laws concerning rate or financial
regulation. PURPA also requires that electric utilities purchase electricity
generated by QFs at a price based on the utility's "avoided cost", and that the
utility sell back-up power to the QF on a non-discriminatory basis. If one of
the projects in which the Company has an interest should lose its status as a
QF, the project would no longer be entitled to the exemptions from PUHCA and the
FPA. This could trigger certain rights of termination under the power sales
agreement, could subject the project to rate regulation as a public utility
under the FPA and state laws and could result in the Company inadvertently
becoming a public utility holding company. The Company believes that each of the
electricity generating projects in which the Company owns an interest currently
meets the requirements under PURPA necessary for QF status.
Litigation
On September 30, 1997, a lawsuit was filed by Indeck North American Power
Fund ("Indeck") in the Circuit Court of Cook County, Illinois against Norweb
plc. and certain other parties, including the Company. Some of Indeck's claims
relate to Calpine Gordonsville, Inc.'s acquisition of a 50% interest in
Gordonsville Energy L.P. from Northern Hydro Limited and Calpine Auburndale,
Inc.'s acquisition of a 50% interest in Auburndale Power Plant Partners Limited
Partnership from Norweb Power Services (No. 1) Limited. Indeck is claiming that
Calpine Gordonsville, Inc., Calpine Auburndale, Inc. and the Company tortiously
interfered with Indeck's contractual rights to purchase such interests and
conspired with other parties to do so. Indeck is seeking $25.0 million in
compensatory damages, $25.0 million in punitive damages, and the recovery of
attorneys' fees and costs. All the defendants filed motions to dismiss such
claims, which are currently pending. The Company believes that the claims of
Indeck are without merit and that the resolution of this matter will not have a
material adverse effect on the Company's financial position or results of
operations.
On February 17, 1998, the Company filed an action in the Superior Court of
California, Sonoma County, seeking injunctive and declaratory relief to prevent
PG&E from unilaterally assigning the Company's steam sales contract to the
prospective winning bidder in PG&E's recently announced auction of its power
plants in The Geysers. On January 14, 1998, PG&E filed an application with the
CPUC pursuant to Public Utilities Code Section 851 ("851 Filing"), in which it
seeks authorization to sell five electric generating plants and related assets.
Included in this proposed sale are The Geysers Geothermal Power Plants
(including Units 13 and 16) and certain of PG&E's fossil fueled steam-electric
generating plants. In PG&E's 851 Filing, PG&E announced its intention to assign
its rights and to delegate its duties under the Company's steam contract to the
successful third party purchaser of the Unit 13 and Unit 16 Power Plants. The
Company has been informed by PG&E that it will attempt to make such assignment
and delegation without first seeking and obtaining the approval and consent of
the Company. The Company is challenging the continued validity of the price term
of the steam sales contract following the proposed divestiture by PG&E of 98% of
its fossil fueled steam-electric generating plants, as the price term of the
steam sales contract is based on a complex formula that reflects PG&E's weighted
average cost of fossil and nuclear fuel from the preceding year.
In a related action, the Company has filed a protest with the CPUC which
raises issues similar to those addressed in the above-referenced lawsuit and, in
addition, challenges certain inaccuracies contained in
F-39
<PAGE> 93
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
portions of PG&E's 851 Filings related to Unit 13 and Unit 16. As no discovery
has been conducted in either matter, nor has any answer been filed in the
lawsuit, the Company is unable to predict the outcome of these cases.
An action was filed against Lockport Energy Associates, L.P. ("LEA") on
August 7, 1997 by New York State Electricity and Gas Company ("NYSEG") in the
Federal District Court for the Northern District of New York. NYSEG has
requested the Court to direct the FERC and the New York Public Service
Commission ("NYPSC"), to modify contract rates to be paid to the Lockport Power
Plant. On October 14, 1997, NYPSC, a named defendant in the NYSEG action, filed
a cross-claim alleging that the FERC violated PURPA and the Federal Power Act by
failing to reform the NYSEG contract which was previously approved by the NYPSC.
LEA continues to vigorously defend this action, although it is unable to predict
the outcome of this case. The Company retains the right to require BUG to
purchase the Company's interest in the Lockport Power Plant for $18.9 million,
less equity distributions received by the Company, at any time before December
19, 2001. In the event the NYSEG's action is successful, the Company may choose
to exercise its right to require BUG to purchase its interest in the Lockport
Power Plant.
There is currently a dispute between Texas-New Mexico Power Company ("TNP")
and Clear Lake Cogeneration Limited Partnership ("CLC"), which owns the Clear
Lake Power Plant, regarding certain costs and other amounts that TNP has
withheld from payments due under the power sales agreement. As of December 31,
1997, TNP has withheld approximately $5.4 million related to transmission
charges and has continued to withhold approximately $450,000 per month
thereafter. CLC filed a petition for declaratory order with the Texas Public
Utilities Commission ("Texas PUC") on October 2, 1997 requesting that the Texas
PUC declare that TNP's withholding is in error. This matter is pending before
the Texas PUC. In addition, as of December 31, 1997, TNP has withheld
approximately $4.4 million of standby power charges and has continued to
withhold approximately $270,000 per month thereafter. CLC has filed a lawsuit in
Texas against TNP claiming that TNP is in breach of certain provisions of the
power sales agreement, including the provisions involved in the disputes
described above, and is seeking in excess of $15.0 million in damages. A trial
is scheduled to begin on June 1, 1998. The Company is unable to predict the
outcome of either of these proceedings.
The Company is involved in various other claims and legal actions arising
out of the normal course of business. The Company does not expect that the
outcome of these proceedings will have a material adverse effect on the
Company's financial position or results of operations, although no assurance can
be given in this regard.
F-40
<PAGE> 94
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
17. EARNINGS PER SHARE
The Company adopted SFAS No. 128 as of December 31, 1997. The
reconciliation of the numerators and denominators of the basic and diluted
earnings per share computation are as follows:
<TABLE>
<CAPTION>
INCOME SHARES PER SHARE
(NUMERATOR) (DENOMINATOR) AMOUNT
FOR THE YEAR 1995 ----------- ------------- ---------
<S> <C> <C> <C>
BASIC EARNINGS PER SHARE
Income available to common stockholders............ $ 7,378 10,388 $ 0.71
=======
Common shares issuable upon exercise of stock
options using treasury stock method.............. -- 569
------- -------
DILUTED EARNINGS PER SHARE
Income available to common stockholders plus
assumed conversions.............................. $ 7,378 10,957 $ 0.67
======= ======= =======
FOR THE YEAR 1996
BASIC EARNINGS PER SHARE
Income available to common stockholders............ $18,692 12,903 $ 1.45
=======
Common shares issuable upon exercise of stock
options using treasury stock method.............. -- 886
Common shares outstanding assumed conversion of
preferred stock (1).............................. -- 1,090
------- -------
DILUTED EARNINGS PER SHARE
Income available to common stockholders plus
assumed conversion............................... $18,692 14,879 $ 1.26
======= ======= =======
FOR THE YEAR 1997
BASIC EARNINGS PER SHARE
Income available to common stockholders............ $34,699 19,946 $ 1.74
=======
Common shares issuable upon exercise of stock
options using treasury stock method.............. -- 1,070
------- -------
DILUTED EARNINGS PER SHARE
Income available to common stockholders plus
assumed conversions.............................. $34,699 21,016 $ 1.65
======= ======= =======
</TABLE>
Basic earnings per share for the year ended December 31, 1996 was computed
using the weighted average number of common shares outstanding. Diluted earnings
per share was computed using the weighted average number of common and common
equivalent shares for outstanding stock options. Options to purchase
approximately 385,000 shares of common stock at a weighted average price of
$18.00 per share were outstanding during the fourth quarter of 1997. These
options were not included in the computation of diluted earnings per share
because the options' exercise price was greater than the average market price of
common shares. The change in the way the Company previously reported earnings
per share for financial reporting purposes is in part due to the adoption of
SFAS No. 128 and subsequently, SAB No. 98 on "Computations of Earnings per
Share" which became effective in February 1998.
18. QUARTERLY CONSOLIDATED FINANCIAL DATA (UNAUDITED)
The Company's quarterly operating results have fluctuated in the past and
may continue to do so in the future as a result of a number of factors,
including, but not limited to, the timing and size of acquisitions, the
completion of development projects, the timing and amount of curtailment, and
variations in levels of production. Furthermore, the majority of capacity
payments under certain of the Company's power sales agreements are received
during the months of May through October.
F-41
<PAGE> 95
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
The Company's common stock has been traded on the New York stock exchange
since September 19, 1996. There were 45 common stockholders of record at
December 31, 1997. No dividends were paid for the years ended December 31, 1997
and 1996.
<TABLE>
<CAPTION>
QUARTER ENDED
-------------------------------------------------------
DECEMBER 31 SEPTEMBER 30 JUNE 30 MARCH 30
------------- -------------- --------- ----------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C>
1997
Total revenue..................................... $76,441 $92,905 $67,744 $39,231
Income from operations............................ $27,154 $43,384 $24,379 $ 2,270
Net income (loss)................................. $10,192 $19,147 $ 9,400 $(4,040)
Basic earnings per share.......................... $ 0.51 $ 0.96 $ 0.47 $ (0.20)
Diluted earnings per share........................ $ 0.48 $ 0.91 $ 0.45 $ (0.20)
Common stock price per share
High............................................ $ 21.25 $ 22.94 $ 20.88 $ 22.75
Low............................................. $ 12.38 $ 16.50 $ 15.75 $ 17.13
1996
Total revenue..................................... $61,663 $70,897 $50,321 $31,673
Income from operations............................ $14,303 $29,097 $16,203 $ 7,188
Net income (loss)................................. $ 3,537 $10,732 $ 4,717 $ (294)
Basic earnings per share.......................... $ 0.18 $ 0.95 $ 0.45 $ (0.03)
Diluted earnings per share........................ $ 0.17 $ 0.76 $ 0.35 $ (0.03)
Common stock price per share
High............................................ $ 20.00 $ 16.38 $ -- $ --
Low............................................. $ 16.00 $ 16.00 $ -- $ --
</TABLE>
F-42
<PAGE> 96
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
We have audited in accordance with generally accepted auditing standards,
the consolidated financial statements of Calpine Corporation and subsidiaries
included in this Form 10-K and have issued our report thereon dated February 10,
1998. Our audit was made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The schedules listed in the index of
financial statement schedules are the responsibility of the Company's management
and are presented for purposes of complying with the Securities and Exchange
Commission's rules and are not part of the basic financial statements. These
schedules have been subjected to the auditing procedures applied in the audit of
the basic financial statements and, in our opinion, fairly state 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
San Jose, California
February 10, 1998
(except for Note 5 as to which the date is February 17, 1998)
F-43
<PAGE> 97
CALPINE CORPORATION
SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF REGISTRANT
BALANCE SHEETS
DECEMBER 31, 1997 AND 1996
(IN THOUSANDS)
<TABLE>
<CAPTION>
1997 1996
ASSETS -------- --------
<S> <C> <C>
Current assets:
Cash and cash equivalents................................. $(55,070) $ 33,150
Accounts receivable from related parties.................. 6,164 4,534
Accounts receivable....................................... 2,168 5,024
Other current assets...................................... 714 1,603
-------- --------
Total current assets.............................. (46,024) 44,311
Property, plant and equipment, net.......................... 6,617 5,711
Investments in power projects............................... 246,090 141,816
Intercompany receivables.................................... 632,188 302,230
Notes receivable from related parties....................... -- 18,182
Deferred charges............................................ 16,282 8,326
Other assets................................................ 133 122
-------- --------
Total assets...................................... $855,286 $520,698
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable.......................................... $ 11,699 $ 504
Accrued payroll and related expenses...................... 4,208 3,477
Accrued interest payable.................................. 17,960 6,462
Other current liabilities................................. 3,409 5,385
-------- --------
Total current liabilities......................... 37,276 15,828
Senior Notes................................................ 560,041 285,000
Deferred income taxes, net.................................. 18,013 11,230
Deferred revenue............................................ -- 5,513
-------- --------
Total liabilities................................. 615,330 317,571
Stockholders' equity:
Common stock, $0.001 par value............................ 20 20
Additional paid-in capital................................ 167,542 165,412
Retained earnings......................................... 72,394 37,695
-------- --------
Total stockholders' equity........................ 239,956 203,127
-------- --------
Total liabilities and stockholders' equity........ $855,286 $520,698
======== ========
</TABLE>
The accompanying notes are an integral part of these condensed financial
statements.
F-44
<PAGE> 98
CALPINE CORPORATION
SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF REGISTRANT
STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
(IN THOUSANDS)
<TABLE>
<CAPTION>
1997 1996 1995
-------- -------- --------
<S> <C> <C> <C>
Revenue:
Service contract revenue from related parties............ $ 43,936 $ 36,582 $ 28,733
Income from unconsolidated investments in power
projects.............................................. 103,898 66,625 32,397
-------- -------- --------
Total revenue.................................... 147,834 103,207 61,130
Cost of revenue:
Service contract expenses................................ 42,014 34,953 27,433
-------- -------- --------
Gross profit............................................... 105,820 68,254 33,697
Project development expenses............................... 7,537 3,867 3,087
General and administrative expenses........................ 16,968 13,651 8,081
-------- -------- --------
Income from operations........................... 81,315 50,736 22,529
Interest expense........................................... 40,790 23,036 10,479
Interest income............................................ (11,470) (4,313) (71)
Other (income) expense..................................... (1,164) 4,257 (306)
-------- -------- --------
Income before provision for income taxes......... 53,159 27,756 12,427
Provision for income taxes................................. 18,460 9,064 5,049
-------- -------- --------
Net income....................................... $ 34,699 $ 18,692 $ 7,378
======== ======== ========
Basic earnings per common share:
Weighted average shares of common stock outstanding...... 19,946 12,903 10,388
Basic earnings per common share.......................... $ 1.74 $ 1.45 $ 0.71
Diluted earnings per common share:
Weighted average shares of common stock outstanding...... 21,016 14,879 10,957
Diluted earnings per common share........................ $ 1.65 $ 1.26 $ 0.67
</TABLE>
The accompanying notes are an integral part of these condensed financial
statements.
F-45
<PAGE> 99
CALPINE CORPORATION
SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF REGISTRANT
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
(IN THOUSANDS)
<TABLE>
<CAPTION>
1997 1996 1995
--------- --------- ---------
<S> <C> <C> <C>
Net cash used in operating activities................... $(360,783) $(281,828) $ (8,997)
--------- --------- ---------
Cash flows from investing activities:
Acquisition of property, plant and equipment.......... (1,316) (5,321) (368)
Investments in power projects......................... (4,172) -- (1,262)
Decrease (increase) in notes receivable, net.......... 11,500 2,750 (10,337)
--------- --------- ---------
Net cash provided by (used in) investing activities..... 6,012 (2,571) (11,967)
--------- --------- ---------
Cash flows from financing activities:
Payment of dividend................................... -- -- (800)
Borrowings from line of credit........................ 14,300 46,861 14,000
Repayment of borrowings under line of credit.......... (14,300) (60,861) --
Proceeds from Senior Notes............................ 275,041 180,000 --
Proceeds from issuance of preferred stock............. -- 50,000 --
Proceeds from issuance of common stock................ 1,022 109,208 --
Financing costs....................................... (9,512) (5,688) 279
--------- --------- ---------
Net cash provided by financing activities..... 266,551 319,520 13,479
--------- --------- ---------
Net increase (decrease) in cash and cash equivalents.... (88,220) 35,121 (7,485)
Cash and cash equivalents, beginning of period.......... 33,150 (1,971) 5,514
--------- --------- ---------
Cash and cash equivalents, end of period................ $ (55,070) $ 33,150 $ (1,971)
========= ========= =========
Cash paid during the period for:
Interest.............................................. $ 19,218 $ 19,763 $ 9,945
Income taxes.......................................... $ 9,795 $ 6,947 $ 4,294
</TABLE>
The accompanying notes are an integral part of these condensed financial
statements.
F-46
<PAGE> 100
CALPINE CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS
DECEMBER 31, 1997, 1996 AND 1995
1. ORGANIZATION AND OPERATION OF CALPINE
Calpine Corporation ("Calpine"), a Delaware Corporation, is engaged in the
development, acquisition, ownership and operation of power generation facilities
in the United States. Calpine has ownership interests in and operates geothermal
steam fields, geothermal power generation facilities, and natural gas-fired
cogeneration facilities through subsidiaries and investees.
In July 1996, Calpine's Board of Directors authorized the reincorporation
of Calpine in Delaware in connection with Calpine's initial public offering. In
addition, the Board of Directors approved a stock split of approximately
5.194-for-1. In September 1996, the reincorporation of Calpine and the stock
split became effective. The accompanying financial statements reflect the
reincorporation and the stock split as if such transactions had been effective
for all periods.
For the purposes of these registrant-only financial statements, Calpine's
wholly-owned subsidiaries are accounted for under the equity method and are
included in investments in power projects in the accompanying balance sheets.
These financial statements should be read in conjunction with Calpine
Corporation and Subsidiaries Consolidated Financial Statements.
2. SENIOR NOTES
On July 8, 1997, the Company issued $200.0 million aggregate principal
amount of 8 3/4% Senior Notes Due 2007. Transaction costs of $9.7 million
incurred in connection with the debt offering were capitalized and are included
in Other assets and are amortized over the ten-year life of the 8 3/4% Senior
Notes Due 2007.
On September 10, 1997, the Company issued an additional $75.0 million
aggregate principal amount of 8 3/4% Senior Notes Due 2007. The net proceeds
were for general corporate purposes.
In May and June 1997, the Company executed five interest rate hedging
transactions related to debt. The notional value of the debt was $182.0 million
and was designed to eliminate interest rate risk for the period from May 1997 to
July 1997 when the $200.0 million of 8 3/4% Senior Notes Due 2007 were priced.
These interest rate hedging transactions were designated as a hedge of the
anticipated bond offering, and the resulting $3.0 million cost resulting from
the hedges is being amortized over the life of the bonds. The effective interest
rate on the $275.0 million aggregate principal amount after the hedging
transactions and the amortization of transaction costs was 9.1%.
The 8 3/4% Senior Notes Due 2007 will mature on July 15, 2007. The Company
has no sinking fund or mandatory redemption obligations with respect to the
8 3/4% Senior Notes Due 2007. Interest is payable semi-annually on January 15
and July 15 of each year while the 8 3/4% Senior Notes Due 2007 are outstanding,
commencing on January 15, 1998. Based on the traded yield to maturity, the
approximate fair market value of the 8 3/4% Senior Notes Due 2007 was $280.5
million as of December 31, 1997.
On May 16, 1996, the Company issued $180.0 million aggregate principal
amount of 10 1/2% Senior Notes Due 2006. Transaction costs of $5.1 million
incurred in connection with the public debt offering were recorded as other
assets and are amortized over the ten-year life of the 10 1/2% Senior Notes Due
2006. The effective interest rate of the $180.0 million aggregate principal
amount after the amortization of transaction costs was 10.7%.
The 10 1/2% Senior Notes Due 2006 will mature on May 15, 2006. The Company
has no sinking fund or mandatory redemption obligations with respect to the
10 1/2% Senior Notes Due 2006. Interest is payable semi-annually on May 15 and
November 15. Based on the traded yield to maturity, the approximate fair market
value of the 10 1/2% Senior Notes Due 2006 was $196.2 million as of December 31,
1997.
F-47
<PAGE> 101
CALPINE CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
The 9 1/4% Senior Notes Due 2004 will mature on February 1, 2004. The
Company has no sinking fund or mandatory redemption obligations with respect to
the 9 1/4% Senior Notes Due 2004. Interest is payable semi-annually on February
1 and August 1. Based on the traded yield to maturity, the approximate fair
market value of the 9 1/4% Senior Notes Due 2004 was $108.7 million as of
December 31, 1997. The effective interest rate on the $105.0 million aggregate
principal amount after amortization of transaction costs was 9.6%.
The Senior Note indentures specify that the Company maintains certain
covenants with which the Company was in compliance. The Company may, under
certain circumstances, be limited in its ability to make restricted payments, as
defined, which include dividends and certain purchases and investments, incur
additional indebtedness and engage in certain transactions.
3. NOTES RECEIVABLE
In May 1993, in accordance with the Sumas Cogeneration, L.P. ("Sumas")
partnership agreement, the Company was entitled to receive a distribution of
$1.5 million and Sumas Energy, Inc. ("SEI"), the Company's partner in Sumas, was
required to make a capital contribution of $1.5 million. In order to meet SEI's
$1.5 million capital contribution requirement, the Company loaned $1.5 million
to the sole shareholder of SEI, who in turn loaned the funds to SEI, who in turn
contributed the capital to Sumas. The interest rate on the loan was 20% and was
secured by a security interest in the loan between SEI and its sole shareholder.
The Company received all principal plus accrued interest totaling $2.8 million
in 1997.
In March 1994, the Company loaned $10.0 million to the sole shareholder of
SEI. The interest rate on the loan was 16.25%. The loan was secured by a pledge
to Calpine of SEI's interest in Sumas. The Company deferred the recognition of
interest income from these notes until Sumas generated net income.
In September 1997, the Company entered into a loan agreement with SEI's
sole shareholder wherein the Company agreed to make available a line of credit
up to $15.0 million, the proceeds of which are required to be used to develop a
new project. SEI has guaranteed the payment and performance of obligations under
this agreement and borrowings under the agreement will be collateralized by the
new project and the sole shareholder's 100% interest in SEI. The loan agreement
will expire on December 31, 2003.
During 1997, the $10.0 million loan was sold to a third party. The Company
received all unpaid principal and interest related to both loans and recognized
a total of $6.9 million of the interest income during 1997 (of which $3.5
million was previously deferred). In addition, the Company recorded a $1.1
million gain upon the sale of the $10.0 million loan, which was recorded in
Other (income) expense. In 1996, the Company recognized $2.1 million of interest
income related to the above two loans, which represents the portion of Sumas'
earnings not recognized by the Company related to its equity investment in
Sumas.
4. REVOLVING CREDIT FACILITY AND LINE OF CREDIT
At December 31, 1997 and 1996, Calpine had a $50.0 million credit facility
available with a consortium of commercial lending institutions which include The
Bank of Nova Scotia, ING U.S. Capital Corporation, Sumitomo Bank of California
and Canadian Imperial Bank of Commerce. As of December 31, 1997, the Company had
no borrowings and $9.4 million of letters of credit outstanding. This amount
reflects $6.0 million to secure performance with the Clear Lake Power Plant,
$1.5 million to secure performance under a purchase power agreement, and $1.9
million related to operating expenses at Calpine Monterey Cogeneration Inc.,
("CMCI"). At December 31, 1996, Calpine had no borrowings and $5.9 million of
letters of credit outstanding, which reflected $3.0 million to secure
performance with the Pasadena Power Plant and $2.9 million related to operating
expenses at CMCI. Borrowings bear interest at The Bank of Nova Scotia's base
rate plus an applicable margin or at the London Interbank Offered Rate ("LIBOR")
plus an applicable margin. Interest is paid on the last day of each interest
period for such loans, but not less often than quarterly,
F-48
<PAGE> 102
CALPINE CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
based on the principal amount outstanding during the period for base rate loans,
and on the last day of each applicable interest period, but not less often than
90 days, for LIBOR loans. The credit agreement expires in September 1999. The
credit agreement specified that Calpine maintain certain covenants with which
Calpine was in compliance. Commitment fees related to this line of credit are
charged based on 0.50% of committed unused credit.
At December 31, 1997 and 1996, Calpine had a loan facility with available
borrowings totaling $1.2 million. As of December 31, 1997, Calpine had no
borrowings and $74,000 of letters of credit outstanding. There were no
borrowings and $900,000 of letters of credit outstanding as of December 31,
1996.
5. COMMITMENTS AND CONTINGENCIES
Office and Equipment Leases -- The Company leases its corporate office,
Santa Rosa office facilities and certain office equipment under noncancellable
operating leases expiring through 2002. Future minimum lease payments under
these leases are (in thousands).
<TABLE>
<S> <C>
1998...................................... $1,409
1999...................................... 1,211
2000...................................... 1,128
2001...................................... 564
2002...................................... 114
Thereafter.................................. --
------
$4,426
======
</TABLE>
Lease payments are subject to adjustments for the Company's pro rata
portion of annual increases or decreases in building operating costs. In 1997,
1996, and 1995, rent expenses for noncancellable operating leases amounted to
$1.2 million, $1.0 million and $733,000, respectively.
Regulation and CPUC Restructuring -- Electricity and steam sales agreements
with Pacific Gas and Electric Company ("PG&E") are regulated by the California
Public Utilities Commission ("CPUC"). In December 1995, the CPUC issued a
decision which proposed the transition of the regulated electric generation
market to a competitive generation market beginning January 1, 1998. Since the
proposed restructure represented a widespread impact on the market structure
requiring participation and oversight of the Federal Energy Regulatory
Commission ("the FERC"), the CPUC sought and built a California consensus
coalition which resulted in filings at the FERC which permitted the CPUC and the
FERC to collectively proceed with implementation of the new competitive market
structure. In late 1996, comprehensive legislation, (AB 1890 (the "Bill")), was
signed into California law which adopted the basic tenets of the CPUC electric
industry restructure decision and directed the CPUC to proceed with
implementation of restructure with customer choice of electricity supplier
available no later than January 1, 1998. The Bill provided for market power
mitigation by utility divestiture of fossil generation plants, provided a four
year transition period for utility recovery of stranded costs, provided for
sanctity of existing contracts with provision for voluntary restructure,
established an electricity rate freeze for the four year transition period,
mandated a 10% rate reduction beginning January 1, 1998 and continuing through
the transition period for small commercial and residential customers financed by
issuance of rate reduction bonds, and provided specified funds for continued
public service programs including public interest research and development and
enhancement of in-state renewable energy resources, which includes geothermal
operations. In late 1997 the CPUC and FERC issued decisions which provided for
the January 1, 1998 implementation of the California Independent Systems
Operator ("ISO"), responsible for centralized control and reliable operation of
the state-wide electric transmission grid, and the Power Exchange ("PX"),
responsible for the competitive electric energy auction. In late 1997,
CPUC-approved sales of certain utility-owned fossil generation plants were
completed and applications were pending at the CPUC for sales of the remaining
utility-owned
F-49
<PAGE> 103
CALPINE CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
California fossil and geothermal power plants. Investor-owned utilities, though
transferring control to the ISO, will continue to own and collect revenue from
their transmission facilities and will continue to be regulated utility
distribution companies ("UDC") for all electric service providers with default
electric supplier responsibility.
In December 1997, mechanics for operation of the ISO and PX were not yet
fully perfected and implementation of deregulation was delayed to April 1, 1998.
The California Energy Commission ("CEC") was directed by the Bill to develop a
competitive mechanism for allocation and distribution of funds made available
for public interest research and development and enhancement of in-state
renewable resources. The CEC in late 1997 issued its draft guidelines for
selective allocation and distribution of the funds which are to be available
over the four year transition period to a fully competitive electric services
industry. Though Calpine believes that implementation of electric industry
restructure can provide significant opportunity for independent power producers,
the ultimate impact of both increased competition and the changing regulatory
environment on Calpine's future results from operations is uncertain.
A domestic electricity generating project must be a qualifying facility
("QF") under FERC regulations in order to take advantage of certain rate and
regulatory incentives provided by the Public Utility Regulatory Policies Act of
1978, as amended ("PURPA"). PURPA exempts owners of QFs from the Public Utility
Holding Company Act of 1935, as amended ("PUHCA"), and exempts QFs from most
provisions of the Federal Power Act ("FPA") and state laws concerning rate or
financial regulation. PURPA also requires that electric utilities purchase
electricity generated by QFs at a price based on the utility's "avoided cost",
and that the utility sell back-up power to the QF on a non-discriminatory basis.
If one of the projects in which Calpine has an interest should lose its status
as a QF, the project would no longer be entitled to the exemptions from PUHCA
and the FPA. This could trigger certain rights of termination under the power
sales agreement, could subject the project to rate regulation as a public
utility under the FPA and state laws and could result in Calpine inadvertently
becoming a public utility holding company. Calpine believes that each of the
electricity generating projects in which Calpine owns an interest currently
meets the requirements under PURPA necessary for QF status.
LITIGATION --
On September 30, 1997, a lawsuit was filed by Indeck North American Power
Fund ("Indeck") in the Circuit Court of Cook County, Illinois against Norweb
plc. and certain other parties, including the Company. Some of Indeck's claims
relate to Calpine Gordonsville, Inc.'s acquisition of a 50% interest in
Gordonsville Energy L.P. from Northern Hydro Limited and Calpine Auburndale,
Inc.'s acquisition of a 50% interest in Auburndale Power Plant Partners Limited
Partnership from Norweb Power Services (No. 1) Limited. Indeck is claiming that
Calpine Gordonsville, Inc., Calpine Auburndale, Inc. and the Company tortiously
interfered with Indeck's contractual rights to purchase such interests and
conspired with other parties to do so. Indeck is seeking $25.0 million in
compensatory damages, $25.0 million in punitive damages, and the recovery of
attorneys' fees and costs. All the defendants has filed motions to dismiss such
claims, which are currently pending. Calpine believes that the claims of Indeck
are without merit and that the resolution of this matter will not have a
material adverse effect on its financial position or results of operations.
On February 17, 1998, Calpine filed an action in the Superior Court of
California, Sonoma County, seeking injunctive and declaratory relief to prevent
PG&E from unilaterally assigning Calpine's steam sales contract to the
prospective winning bidder in PG&E's recently announced auction of its power
plants in The Geysers. On January 14, 1998, PG&E filed an application with the
CPUC pursuant to Public Utilities Code Section 851 ("851 Filing"), in which it
seeks authorization to sell five electric generating plants and related assets.
Included in this proposed sale are The Geysers Geothermal Power Plants
(including Units 13 and 16) and certain of PG&E's fossil fueled steam-electric
generating plants. In PG&E's 851 Filing, PG&E
F-50
<PAGE> 104
CALPINE CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1997, 1996 AND 1995
announced its intention to assign its rights and to delegate its duties under
Calpine's steam contract to the successful third party purchaser of the Unit 13
and Unit 16 Power Plants. Calpine has been informed by PG&E that it will attempt
to make such assignment and delegation without first seeking and obtaining the
approval and consent of Calpine. Calpine is challenging the continued validity
of the price term of the steam sales contract following the proposed divestiture
by PG&E of 98% of its fossil fueled steam-electric generating plants, as the
price term of the steam sales contract is based on a complex formula that
reflects PG&E's weighted average cost of fossil and nuclear fuel from the
preceding year.
In a related action, Calpine and CGC have filed a protest with the CPUC
which raises issues similar to those addressed in the above-referenced lawsuit
and, in addition, challenges certain inaccuracies contained in portions of
PG&E's 851 Filings related to Unit 13 and Unit 16. As no discovery has been
conducted in either matter, nor has any answer been filed in the lawsuit,
Calpine is unable to predict the outcome of these cases.
An action was filed against Lockport Energy Associates, L.P. ("LEA") on
August 7, 1997 by New York State Electricity and Gas Company ("NYSEG") in the
Federal District Court for the Northern District of New York. NYSEG has
requested the Court to direct the Federal Energy Regulatory Commission (the
"FERC") and the New York Public Service Commission ("NYPSC"), to modify contract
rates to be paid to the Lockport Power Plant. On October 14, 1997, NYPSC, a
named defendant in the NYSEG action, filed a cross-claim alleging that the FERC
violated PURPA and the Federal Power Act by failing to reform the NYSEG contract
which was previously approved by the NYPSC. LEA continues to vigorously defend
this action, although it is unable to predict the outcome of this case. Calpine
retains the right to require The Brooklyn Union Gas Company ("BUG") to purchase
Calpine's interest in the Lockport Power Plant for $18.9 million, less equity
distributions received by Calpine, at any time before December 19, 2001. In the
event the NYSEG's action is successful, Calpine may choose to exercise its right
to require BUG to purchase its interest in the Lockport Power Plant.
There is currently a dispute between Texas-New Mexico Power Company ("TNP")
and Clear Lake Cogeneration Limited Partnership ("CLC"), which owns the Clear
Lake Power Plant, regarding certain costs and other amounts that TNP has
withheld from payments due under the power sales agreement. As of December 31,
1997, TNP has withheld approximately $5.4 million related to transmission
charges and has continued to withhold approximately $450,000 per month
thereafter. CLC filed a petition for declaratory order with the Texas Public
Utilities Commission ("Texas PUC") on October 2, 1997 requesting that the Texas
PUC declare that TNP's withholding is in error. This matter is pending before
the Texas PUC. In addition, as of December 31, 1997, TNP has withheld
approximately $4.4 million of standby power charges and has continued to
withhold approximately $270,000 per month thereafter. CLC has filed a lawsuit in
Texas against TNP claiming that TNP is in breach of certain provisions of the
power sales agreement, including the provisions involved in the disputes
described above, and is seeking in excess of $15.0 million in damages. A trial
is scheduled to begin on June 1, 1998. Calpine is unable to predict the outcome
of either of these proceedings.
Calpine and its affiliates are involved in various other claims and legal
actions arising out of the normal course of business. Calpine does not expect
that the outcome of these proceedings will have a material adverse effect on
their financial position or results of operations, although no assurance can be
given in this regard.
F-51
<PAGE> 105
CALPINE CORPORATION
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
(IN THOUSANDS)
FOR THE YEAR ENDED DECEMBER 31, 1997
<TABLE>
<CAPTION>
ADDITIONS
--------------------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING OF COSTS AND OTHER END OF
DESCRIPTION PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD
----------- ------------ ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Reserve for capitalized costs.............. $ 1,838 $ -- $ -- $(1,600) $ 238
Allowance for uncollectible accounts....... 238 -- -- -- 238
</TABLE>
FOR THE YEAR ENDED DECEMBER 31, 1996
<TABLE>
<CAPTION>
ADDITIONS
--------------------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING OF COSTS AND OTHER END OF
DESCRIPTION PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD
----------- ------------ ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Reserve for capitalized costs.............. $ 1,838 $ -- $ -- $ -- $ 1,838(1)
Allowance for uncollectible accounts....... 238 -- -- -- 238
</TABLE>
FOR THE YEAR ENDED DECEMBER 31, 1995
<TABLE>
<CAPTION>
ADDITIONS
--------------------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING OF COSTS AND OTHER END OF
DESCRIPTION PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD
----------- ------------ ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
Reserve for capitalized costs.............. $ 1,838 $ -- $ -- $ -- $ 1,838(1)
Allowance for uncollectible accounts....... 238 -- -- -- 238
</TABLE>
- ---------------
(1) Provision for write-off of project development expenses.
F-52
<PAGE> 106
INDEPENDENT AUDITOR'S REPORT
To the Partners
Sumas Cogeneration Company, L.P. and Subsidiary
We have audited the accompanying consolidated balance sheet of Sumas
Cogeneration Company, L.P. and Subsidiary as of December 31, 1997 and 1996, and
the related consolidated statements of income, changes in partners' deficit, and
cash flows for each of the three years ended December 31, 1997. These
consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these consolidated
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audits to obtain
reasonable assurance about whether the consolidated financial statements are
free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the consolidated financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
consolidated financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Sumas
Cogeneration Company, L.P. and Subsidiary as of December 31, 1997 and 1996, and
the results of their operations and cash flows for each of the three years ended
December 31, 1997, in conformity with generally accepted accounting principles.
MOSS ADAMS LLP
Everett, Washington
January 22, 1998
F-53
<PAGE> 107
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
CONSOLIDATED BALANCE SHEET
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------
1997 1996
------------ ------------
<S> <C> <C>
Current assets
Cash and cash equivalents................................. $ 208,776 $ 317,196
Current portion of restricted cash and cash equivalents... 6,094,892 5,787,121
Accounts receivable....................................... 4,502,790 4,605,135
Prepaid expenses.......................................... 181,048 220,130
------------ ------------
Total current assets.............................. 10,987,506 10,929,582
Restricted cash and cash equivalents,....................... 6,214,000 15,666,647
Property, plant and equipment, at cost, net................. 90,459,854 91,737,933
Other assets................................................ 10,819,238 10,938,732
------------ ------------
Total assets...................................... $118,480,598 $129,272,894
============ ============
LIABILITIES AND PARTNERS' EQUITY
Current liabilities
Accounts payable and accrued liabilities.................. 2,780,693 2,988,207
Related party distributions and payables.................. 490,676 476,390
National Energy Systems Company payable................ 1,415 1,490
Partner distributions.................................. 1,736,612 3,517,491
Current portion of long-term debt......................... 4,200,000 3,600,000
------------ ------------
Total current liabilities......................... 9,209,396 10,583,578
Long-term debt, net of current portion...................... 129,200,004 113,400,003
Future removal and site restoration costs................... 731,184 679,600
Deferred income taxes....................................... 396,926 988,400
Commitments................................................. -- --
Partners' equity (deficit).................................. (21,056,912) 3,621,313
------------ ------------
Total liabilities and partners' equity............ $118,480,598 $129,272,894
============ ============
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-54
<PAGE> 108
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
CONSOLIDATED STATEMENT OF INCOME
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------
1997 1996 1995
------------ ------------ ------------
<S> <C> <C> <C>
Revenues
Power sales.................................... $ 38,309,558 $ 43,488,465 $ 30,603,018
Natural gas sales, net......................... 2,483,862 434,611 893,690
Other.......................................... -- 169,146 29,146
------------ ------------ ------------
Total revenues......................... 40,793,420 44,092,222 31,525,854
------------ ------------ ------------
Costs and expenses
Operating and production costs................. 11,211,812 16,852,253 18,493,245
Depletion, depreciation and amortization....... 6,898,111 5,702,310 6,965,496
General and administrative..................... 1,949,365 2,481,470 1,400,129
------------ ------------ ------------
Total costs and expenses............... 20,059,288 25,036,033 26,858,870
------------ ------------ ------------
Income from operations........................... 20,734,132 19,056,189 4,666,984
------------ ------------ ------------
Other income (expense)
Interest income................................ 1,190,133 406,537 490,071
Interest expense............................... (10,782,823) (10,678,618) (11,006,056)
Other expense.................................. (68,258) (133,958) (60,664)
------------ ------------ ------------
Total other expense.................... (9,660,948) (10,406,039) (10,576,649)
------------ ------------ ------------
Income (loss) before provision for income
taxes.......................................... 11,073,184 8,650,150 (5,909,665)
Provision for income taxes....................... 525,642 (155,951) (188,387)
------------ ------------ ------------
Net income (loss)...................... $ 11,598,826 $ 8,494,199 $ (6,098,052)
============ ============ ============
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-55
<PAGE> 109
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
<TABLE>
<S> <C>
Partners' Equity, December 31, 1994......................... $ 5,523,136
Net loss.................................................... (6,098,052)
------------
Partners' Deficit, December 31, 1995........................ (574,916)
Net income.................................................. 8,494,199
Distributions to partners................................... (4,297,970)
------------
Partners' Equity, December 31, 1996......................... 3,621,313
Net income.................................................. 11,598,826
Distributions to partners................................... (36,277,051)
------------
Partners' Deficit, December 31, 1997........................ $(21,056,912)
============
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-56
<PAGE> 110
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
CONSOLIDATED STATEMENT OF CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------
1997 1996 1995
------------ ------------ ------------
<S> <C> <C> <C>
Cash flows from operating activities
Net income (loss).............................. $ 11,598,826 $ 8,494,199 $ (6,098,052)
Adjustments to reconcile net income (loss) to
net cash from operating activities
Depletion, depreciation and amortization.... 6,898,111 6,571,522 6,965,496
Deferred income taxes....................... (591,474) 80,600 134,000
Change in operating assets and liabilities
accounts receivable....................... 102,345 (1,514,922) 1,017,993
Prepaid expenses............................ 39,082 2,698 9,497
Accounts payable and accrued liabilities.... (155,930) 1,114,029 (1,407,621)
Related party distributions and payables.... 14,211 (437,524) 425,479
------------ ------------ ------------
Net cash from operating activities..... 17,905,171 14,310,602 1,046,792
------------ ------------ ------------
Cash flows from investing activities
Decrease (increase) in restricted cash and cash
equivalents................................. 9,144,876 (10,498,126) 2,908,466
Acquisition of property, plant and equipment... (3,772,579) (913,970) (3,710,025)
Other assets................................... (1,727,958) -- --
------------ ------------ ------------
Net cash from investing activities..... 3,644,339 (11,412,096) (801,559)
------------ ------------ ------------
Cash flows from financing activities
Repayment of long-term debt.................... (3,600,000) (2,000,000) (400,000)
Proceeds from long-term debt................... 20,000,000 -- --
Distributions to partners...................... (38,057,930) (780,479) --
------------ ------------ ------------
Net cash from financing activities..... (21,657,930) (2,780,479) (400,000)
------------ ------------ ------------
Net increase (decrease) in cash and cash
equivalents.................................... (108,420) 118,027 (154,767)
Cash and cash equivalents, beginning of year..... 317,196 199,169 353,936
------------ ------------ ------------
Cash and cash equivalents, end of year........... 208,776 317,196 199,169
------------ ------------ ------------
Supplementary disclosure of cash flow information
Cash paid for interest during the year......... $ 10,782,823 $ 10,678,618 $ 11,006,056
============ ============ ============
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-57
<PAGE> 111
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1997
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
General -- Sumas Cogeneration Company, L.P. (the Partnership) is a Delaware
limited partnership formed in 1991 between Sumas Energy, Inc. ("SEI"), the
general partner which currently holds a 50% interest in the profits and losses
of the Partnership, and Whatcom Cogeneration Partners, L.P. ("Whatcom"), the
sole limited partner which holds the remaining 50% Partnership interest. In
addition, Whatcom is entitled certain additional distribution amounts through
June 30, 2001, representing 20% of forecasted cash flows. Whatcom is owned
through affiliated companies by Calpine Corporation ("Calpine"). The Partnership
has a wholly-owned Canadian subsidiary, ENCO Gas, Ltd. ("Enco"), which is
incorporated in New Brunswick, Canada. The consolidated financial statements
include the accounts of the Partnership and ENCO (collectively, the Company).
All intercompany profits, transactions and balances have been eliminated in
consolidation.
The Partnership owns and operates an electrical generation facility (the
"Generation Facility") in Sumas, Washington. The Generation Facility is a
natural gas-fired combined cycle electrical generation plant which has a
nameplate capacity of approximately 125 megawatts. Commercial operation of the
Generation Facility commenced in April 1993. The Generation Facility includes a
lumber dry kiln facility and a 3.5 mile private natural gas pipeline.
ENCO owns and operates a portfolio of natural gas reserves in British
Columbia and Alberta, Canada, which provide a dedicated fuel supply for the
Generation Facility (collectively, the Project). ENCO produces and supplies
natural gas to the Generation Facility with off-sales to third parties. The
Generation Facility also receives a portion of its fuel under contracts with
third parties.
The Partnership produces and sells its entire electrical output to Puget
Sound Energy, Inc. ("Puget") under a 20-year electricity sales contract. The
electricity sales contract provides for the sale of electrical output at stated
prices through 2012. The stated price includes a fixed and a variable component.
The fixed and variable components are stated amounts per kilowatt hour in each
contract year. The variable component is adjusted annually based on an index of
inflation. The electricity sales contract also provides for the electrical
output of the Generation Facility to be displaced when the cost of Puget's
replacement power is less than the Company's incremental power generation costs.
The Company receives a share of the net savings from displacement. During 1997,
the Generation Facility was displaced approximately six months. Under the
electricity sales contract, the Partnership is required to be certified as a
qualifying cogeneration facility as established by the Public Utility Regulatory
Policy Act of 1978, as amended, and as administered by the Federal Energy
Regulatory Commission.
The Generation Facility produced and sold kilowatt hours of electricity to
Puget as follows:
<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31, KILOWATT HOURS
------------ --------------
<S> <C>
1997..................... 439,370,000
1996..................... 1,031,900,000
1995..................... 1,026,000,000
</TABLE>
The Partnership leases a kiln facility and sells steam under a 20-year
agreement for the purchase and sale of steam and lease of the kiln (see Note 6)
to Socco, Inc. ("Socco"), a custom lumber drying operation owned by an affiliate
of the Partnership. Steam use requirements under the agreement with Socco were
established to maintain the qualifying cogeneration facility status of the
Generation Facility.
The Partnership -- SEI assigned all its rights, title, and interest in the
Project, including the Puget contract, to the Partnership in exchange for its
Partnership interest. During 1997, all preferential distributions were fully
paid and the Partnership Agreement was amended. SEI and Whatcom are both
currently entitled to a 50% interest in the profits, losses and cash flow of the
Partnership. In addition, Whatcom is entitled to an additional allocation of
profits, losses and cash flows of a stated amount equal to 20% of forecasted
cash flows
F-58
<PAGE> 112
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1997
for the period through June 30, 2001. After Whatcom has received cumulative
distributions representing a fixed rate-of-return of 24.5% on its equity
investment, exclusive of certain of the preferential distributions referred to
above, SEI's share of operating distributions will increase to 99.9% and
Whatcom's share of operating distributions will decrease to 0.1%.
Distributions -- Distributions of operating cash flows are permitted
quarterly after required deposits are made and minimum cash balances are met,
and are subject to certain other restrictions. For the year ended December 31,
1997, distributions totaling $36,277,051 were paid or accrued. On January 30,
1998, the December 31, 1997 accrued distributions in the amount of $1,736,612
will be paid. For the year ended December 31, 1996, distributions totaling
$4,297,970 were paid or accrued. On January 31, 1997, the December 31, 1996
accrued distributions in the amount of $3,517,491 were paid. No distributions
were paid or accrued for the year ended December 31, 1995.
Revenue recognition -- Revenue from the sale of electricity is recognized
based on kilowatt hours generated and delivered to Puget at contractual rates.
Revenue from displacement is recognized in the period to which the displacement
relates. Revenue from the sale of natural gas is recognized based on volumes
delivered to customers at contractual delivery points and rates. The costs
associated with the generation of electricity and the delivery of gas, including
operating and maintenance costs, gas transportation and royalties, are
recognized in the same period in which the related revenue is earned and
recorded.
Gas acquisition and development costs -- ENCO follows the full cost method
of accounting for gas acquisition and development expenditures, wherein all
costs related to the development of gas reserves in Canada are initially
capitalized. Costs capitalized include land acquisition costs, geological and
geophysical expenditures, rentals on undeveloped properties, cost of drilling
productive and nonproductive wells, and well equipment. Gains or losses are not
recognized upon disposition or abandonment of natural gas properties unless a
disposition or abandonment would significantly alter the relationship between
capitalized costs and proven reserves.
All capitalized costs of gas properties, including the estimated future
costs to develop proven reserves, are depleted using the unit-of-production
method based on estimated proven gas reserves as determined by independent
engineers. ENCO has not assigned any value to its investment in unproven gas
properties and, accordingly, no costs have been excluded from capitalized costs
subject to depletion.
Costs subject to depletion under the full cost include estimated future
costs of dismantlement and abandonments of ENCO of $3,560,000 in 1997,
$3,718,000 in 1996 and $3,748,000 in 1995. This includes the cost of production
equipment removal and environmental cleanup based upon current regulations and
economic circumstances. The provisions for future removal and site restoration
costs of $168,000 in 1997, $177,000 in 1996 and $193,000 in 1995 are included in
depletion expense.
Capitalized costs are subject to a ceiling test which limits such costs to
the aggregate of the net present value of the estimated future cash flows from
the related proven gas reserves. The ceiling test calculation is made by
estimating the future net cash flows, based on current economic operating
conditions, plus the lower of cost or fair market value of unproven reserves,
and discounting those cash flows at an annual rate of 10%.
Joint venture accounting -- A significant portion of ENCO's natural gas
production activities are conducted jointly with others and, accordingly, these
consolidated financial statements reflect only ENCO's proportionate interest in
such activities.
Foreign exchange gains and losses -- Foreign exchange gains and losses as a
result of translating Canadian dollar transactions and Canadian dollar
denominated cash, accounts receivable and accounts payable transactions are
recognized in the statement of income.
F-59
<PAGE> 113
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1997
Cash and cash equivalents -- For purposes of the statement of cash flows,
cash and cash equivalents consist of cash and short-term investments in highly
liquid instruments such as certificates of deposit, money market accounts and
U.S. treasury bills with an original maturity of three months or less.
Concentration of credit risk -- Financial instruments, which potentially
subject the Company to concentrations of credit risk, consist primarily of cash
and short-term investments in highly liquid instruments such as certificates of
deposit, money market accounts and U.S. treasury bills with maturities of three
months or less, and accounts receivable. The Company's cash and cash equivalents
are primarily held with two financial institutions. Accounts receivable are
primarily due from Puget.
Depreciation -- The Company provides for depreciation of property, plant
and equipment using the straight-line method over estimated useful lives which
range from 7 to 40 years for plant and equipment and 3 to 7 years for furniture
and fixtures.
Amortization of other assets -- The Company provides for amortization of
other assets using the straight-line method as follows:
<TABLE>
<S> <C>
Organization, start-up and development costs... 5 - 30 years
Financing costs................................ 10 - 15 years
Gas contract costs............................. 20 years
</TABLE>
Income taxes -- Profits or losses of the Partnership are allocated directly
to the partners for income tax purposes. ENCO is subject to Canadian income
taxes and accounts for income taxes on the liability method. The liability
method recognizes the amount of tax payable at the date of the consolidated
financial statements, as a result of all events that have been recognized in the
consolidated financial statements, as measured by currently enacted tax laws and
rates. Deferred income taxes are provided for temporary differences in
recognition of revenues and expenses for financial and income tax reporting
purposes.
Use of estimates -- The preparation of the consolidated financial
statements in conformity with generally accepted accounting principles requires
management to make estimates and assumptions that affect the amounts reported in
the consolidated financial statements and accompanying notes. Actual results
could differ from those estimates.
Reclassifications -- Certain 1996 amounts have been reclassified to conform
with the 1997 presentation.
2. PROPERTY, PLANT AND EQUIPMENT
<TABLE>
<CAPTION>
1997 1996
------------ ------------
<S> <C> <C>
Land and land improvements.............. $ 381,071 $ 381,071
Plant and equipment..................... 84,888,500 84,152,257
Acquisition of gas properties, including
development thereon................... 28,691,894 25,838,035
Furniture and fixtures.................. 221,394 211,116
------------ ------------
114,182,859 110,582,479
Less accumulated depreciation and
depletion............................. 23,723,005 18,844,546
------------ ------------
Total.............................. $ 90,459,854 $ 91,737,933
============ ============
</TABLE>
Depreciation expense was $3,188,859 in 1997, $3,159,774 in 1996 and
$3,316,748 in 1995. Depletion expense was $1,861,800 in 1997, $1,606,000 in 1996
and $1,843,000 in 1995.
F-60
<PAGE> 114
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1997
3. OTHER ASSETS
<TABLE>
<CAPTION>
1997 1996
------------ ------------
<S> <C> <C>
Organization, start-up and development costs.... $ 4,568,404 $ 4,844,015
Financing costs............................... 4,394,946 3,909,886
Gas contract costs............................ 1,855,888 2,184,831
------------ ------------
Total................................. $ 10,819,238 $ 10,938,732
============ ============
</TABLE>
4. LONG-TERM DEBT
The Partnership and ENCO have loan agreements with The Prudential Insurance
Company of America ("Prudential") and Credit Suisse First Boston ("Credit
Suisse"), (collectively, "the Lenders"). Through September 1996, Credit Suisse
was an affiliate of Whatcom. On September 30, 1997, the Partnership entered into
a new additional loan agreement with the Lenders, the Secured Subordinated Loan
(the Subordinated Loan) and made certain minor amendments to its existing Term
Loans. The Subordinated Loan provided an additional $20 million in loans and a
$1 million line of credit facility. At December 31, 1997 and 1996, amounts
outstanding under the loan agreements, by entity, were as follows:
<TABLE>
<CAPTION>
1997 1996
------------ ------------
<S> <C> <C>
Sumas Cogeneration Company, L.P.
Term Loan............................. $ 89,926,204 $ 92,781,003
Sumas Cogeneration Company, L.P.
Subordinated Loan..................... 20,000,000 --
ENCO Gas, Ltd........................... 23,473,800 24,219,000
------------ ------------
133,400,004 117,000,003
Less current portion.................... 4,200,000 3,600,000
------------ ------------
Total......................... $129,200,004 $113,400,003
============ ============
</TABLE>
Scheduled annual principal payments under the loan agreements as of
December 31, 1997 are as follows:
<TABLE>
<CAPTION>
YEAR ENDING
DECEMBER 31, AMOUNT
------------ ------------
<S> <C>
1998......................... $ 4,200,000
1999......................... 5,400,000
2000......................... 6,900,000
2001......................... 12,600,000
2002......................... 15,000,000
Thereafter................... 89,300,004
------------
Total.............. $133,400,004
============
</TABLE>
The Partnership's loans are comprised of the Term Loans and the
Subordinated Loans. The Subordinated Loans were entered into on September 30,
1997. The Partnership's Term Loans are comprised of a fixed rate loan in the
original amount of $55,510,000 and a variable rate loan in the original amount
of $39,650,000. Interest is payable quarterly on the fixed rate loan at a rate
of 10.35%. Interest on the variable rate loan is payable monthly at either the
London Interbank Offered Rate ("LIBOR"), certificate of deposit rate or Credit
Suisse's base rate, plus an applicable margin which ranges from 0.5% to 1.25% as
stated in the loan agreement. During the year ended December 31, 1997, interest
rates on the variable rate loan ranged from 6.66% to 7.31%. The Term Loans
mature in May 2008.
The Partnership's Subordinated Loans are comprised of a fixed rate loan in
the original amount of $12,000,000, a variable rate loan in the original amount
of $8,000,000 and a Revolving Line of Credit in the
F-61
<PAGE> 115
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1997
amount of $1,000,000. Interest is payable quarterly on the fixed rate loan at a
rate of 7.85%. Interest is payable monthly on the variable rate loan at either
the LIBOR, certificate of deposit rate or Credit Suisse's base rate, plus an
applicable margin which ranges from 1.00% to 1.75%. During the period from
September 30, 1997 to December 31, 1997, interest rates on the variable rate
Subordinated Loan ranged from 7.16% to 7.19%. The Subordinated Loans mature in
May 2008. The Revolving Line of Credit is renewable annually at the discretion
of the Lenders and is to be used for working capital purposes. Interest is
payable monthly at either the LIBOR, certificate of deposit rate or Credit
Suisse's base rate, plus an applicable margin which ranges from 1.00% to 1.75%.
Through December 31, 1997 no borrowings were made under the Revolving Line of
Credit.
ENCO's loans are comprised of a fixed rate loan in the original amount of
$14,490,000 and a variable rate loan in the original amount of $10,350,000.
Interest is payable quarterly on the fixed rate loan at a rate of 9.99%.
Interest on the variable rate loan is payable monthly at either the LIBOR,
certificate of deposit rate or Credit Suisse's base rate, plus an applicable
margin which ranges from .5% to 1.25% as stated in the loan agreement. During
the year ended December 31, 1997, interest rates on the variable rate loan
ranged from 6.66% to 7.31%. The loans mature in May 2008.
The Partnership pays Prudential an agency fee of $50,000 per year until the
loans mature. The Partnership pays Credit Suisse an agency fee of $40,000 per
year, adjusted annually by an inflation index, until the loans mature. The loans
are collateralized by substantially all the Company's assets and interests in
the Project. Additionally, the Company's rights under all contractual agreements
are assigned as collateral. The Partnership and ENCO loans are
cross-collateralized and contain cross-default provisions.
Under the terms of the loan agreements and the deposit and disbursement
agreements with the Lenders, the Company is required to establish and fund
certain accounts held by Credit Suisse and Royal Trust as security agents. The
accounts require specified minimum deposits and funding levels to meet current
and future operating, maintenance and capital costs, and to provide certain
other reserves for payment of principal, interest and other contingencies. These
accounts are presented as restricted cash and cash equivalents and include cash,
certificates of deposit, money market accounts and U.S. treasury bills, all with
maturities of 3 months or less. The current portion of restricted cash and cash
equivalents is based on the amount of current liabilities for obligations which
may be funded from the restricted accounts. The balance of restricted cash and
cash equivalents has been classified as a non-current asset.
5. INCOME TAXES
The provision for income taxes represents Canadian taxes which consist of
the following:
<TABLE>
<CAPTION>
1997 1996 1995
--------- -------- --------
<S> <C> <C> <C>
Current
Federal large corporation tax............. $ 30,708 $ 41,340 $ 34,625
British Columbia capital taxes............ 35,124 34,011 19,762
65,832 75,351 54,387
Deferred.................................. (591,474) 79,744 135,400
(525,642) 155,095 189,787
Utilization of loss carryforwards for
Canadian income tax purposes............ -- -- 47,700
Reduction of (increase) in Canadian loss
carryforwards due to foreign exchange
and other adjustments................... -- 856 (49,100)
--------- -------- --------
$(525,642) $155,951 $188,387
========= ======== ========
</TABLE>
F-62
<PAGE> 116
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1997
The principal sources of temporary differences resulting in deferred tax
assets and liabilities are as follows:
<TABLE>
<CAPTION>
1997 1996
----------- -----------
<S> <C> <C>
Deferred tax asset
Canadian net operating loss carryforwards........... $(1,906,396) $ (919,400)
Deferred tax liabilities
Acquisition and development costs of gas
Deducted for tax purposes in excess of
amounts...................................... -- --
Deducted for financial reporting purposes...... 2,303,322 1,907,800
----------- -----------
Net deferred tax liability................ $ 396,926 $ 988,400
=========== ===========
</TABLE>
The Company believes, based upon available information, that all deferred
assets will be realized in the normal course of business and no valuation
allowance is necessary.
The provision for income taxes differs from the Canadian statutory rate
principally due to the following:
<TABLE>
<CAPTION>
1997 1996 1995
----------- ----------- -----------
<S> <C> <C> <C>
Canadian statutory rate............. 44.62% 44.62% 44.62%
Income taxes based on statutory
rate.............................. $ (887,037) $ (45,824) $ (33,852)
Capital taxes, net of deductible
portion........................... 49,710 60,175 47,028
Non-deductible provincial royalties,
net of resource allowance......... 216,931 123,464 95,671
Depletion on gas properties with no
tax basis......................... 33,436 36,488 44,641
Foreign exchange adjustments........ 63,931 16,362 14,860
Other............................... (2,613) (35,570) 21,439
----------- ----------- -----------
$ (525,642) $ 155,095 $ 189,787
=========== =========== ===========
</TABLE>
As of December 31, 1997, ENCO has non-capital loss carryforwards of
approximately $4,273,000, which may be applied against taxable income of future
periods which expire as follows:
<TABLE>
<S> <C>
1999........................... $1,518,000
2000........................... 233,000
2003........................... 244,000
2004........................... 2,278,000
</TABLE>
6. RELATED PARTY TRANSACTIONS AND COMMITMENTS
Administrative services -- As managing partner of the Partnership, SEI
receives a fee of $250,000 per year through December 1995 and $300,000 per year
for periods after December 1995. The fee is subject to annual adjustment based
upon an inflation index. Approximately $333,000 in 1997, $311,000 in 1996 and
$258,000 in 1995 was paid to SEI under this agreement.
Operating and maintenance services -- The Partnership has an operating and
maintenance agreement with a related party to operate, repair and maintain the
Project. For these services, the Partnership pays a fixed fee of $1,140,000 per
year adjustable based on the Consumer Price Index, an annual base fee of
$150,000 per year, also adjustable based on the Consumer Price Index, and
certain other reimbursable expenses as defined in the agreement. In addition,
the agreement provides for an annual performance bonus of up to $400,000,
adjustable based on the Consumer Price Index, based on the achievement of
certain annual performance levels. Payment of the performance bonus is
subordinated to the payment of operating expenses, debt service and required
deposits, and minimum balances under the loan agreements, and deposit and
disbursement agreements. This agreement expires on the date Whatcom receives its
24.5% cumulative return or the tenth
F-63
<PAGE> 117
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1997
anniversary of the Project completion date, subject to renewal terms.
Approximately $2,074,000 in 1997, $2,014,000 in 1996 and $2,031,000 in 1995 was
earned under this agreement.
Thermal energy and kiln lease -- The Partnership has a 20-year thermal
energy and kiln lease agreement with Socco. Under this agreement, Socco leases
the premises and the kiln and purchases certain amounts of thermal energy
delivered to dry lumber. Income recorded from Socco was approximately $9,000 in
1996 and $19,000 in 1995.
Consulting services -- ENCO has an agreement with National Energy Systems
Company ("NESCO"), an affiliate of SEI, to provide consulting services for
$8,000 per month, adjustable based upon an inflation index. The agreement
automatically renews for one-year periods unless written notice of termination
is served by either party. Approximately $119,000 in 1997, $107,000 in 1996 and
$100,000 in 1995 was paid under this agreement.
Fuel supply and purchase agreements -- The Partnership has a fixed price
natural gas sale and purchase agreement with ENCO. The agreement requires ENCO
to deliver up to a maximum daily contract quantity of 12,000 mmbtu's of natural
gas per day which may be increased to 24,000 mmbtu's per day in accordance with
the agreement. Partnership payments to ENCO under the agreement are eliminated
in consolidation. The agreement expires on the twentieth anniversary of the date
of commercial operation.
The Partnership has a gas supply agreement with Engage Energy Canada, L.P.
("Engage") to provide the Partnership with 12,850 mmbtu per day of firm gas. The
gas supply agreement with Engage will terminate on October 31, 1998.
The Partnership and ENCO have a gas management agreement with Engage. The
gas management agreement was assigned to Engage by Westcoast Gas Services, Inc.
during 1997. Engage is paid a gas management fee for each mmbtu of gas delivered
to the Generation Facility. The gas management fee is adjusted annually based on
the British Columbia Consumer Price Index. The gas management agreement expires
October 31, 2008 unless terminated earlier as provided for in the agreement.
As collateral for the obligations of the Company under the gas supply and
gas management agreements with Engage, the Partnership has in place an
irrevocable standby letter of credit with Credit Suisse in favor of Engage. As
of December 31, 1997 and 1996, the letter of credit had a face amount of
$500,000.
ENCO is committed to the utilization of gathering, processing and pipeline
capacity on the Westcoast Energy Inc. ("WEI") system. These firm capacity
commitments are under contracts of varying lengths. Firm capacity has been
accepted at an annual cost of approximately $3,553,000 in 1997, $3,526,000 in
1996 and $2,569,000 in 1995.
Future minimum capacity commitments at December 31, 1997 are as follows:
<TABLE>
<CAPTION>
YEAR ENDING
DECEMBER 31, AMOUNT
------------ -----------
<S> <C>
1998............................ $ 2,848,000
1999............................ 5,619,000
2000............................ 2,939,000
2001............................ 2,978,000
2002............................ 2,939,000
Thereafter...................... 11,048,000
-----------
Total................. $28,371,000
===========
</TABLE>
F-64
<PAGE> 118
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1997
As collateral for the obligations of ENCO under the capacity contracts with
WEI, the Partnership has in place an irrevocable standby letter of credit with
Credit Suisse in favor of WEI. As of December 31, 1997 and 1996, the letter of
credit had a face amount of approximately $384,000 (Canadian).
Utility services -- The Partnership has an agreement for utility services
with the City of Sumas, Washington. The City of Sumas has agreed to provide a
guaranteed supply of water at its wholesale rate charged to external association
customers. Should the Partnership fail to purchase the daily average minimum of
550 gallons per minute from the City of Sumas during the first 10 years of
commercial operation, except for uncontrollable forces or reasonable and
necessary shutdowns, the Partnership shall make up the lost revenue to the City
of Sumas in accordance with the agreement.
During 1997, the Partnership obtained a $700,000 letter of credit in favor
of the City of Sumas to support a future sewer charge which will be payable to
the City of Sumas. The City of Sumas is undertaking a sewer expansion project
which will allow the Generation Facility to discharge its cooling tower blowdown
water into the City's sewer system. The sewer expansion is expected to be
completed in late 1998. When sewer service commences, the Partnership will be
obligated to pay a water discharge capacity payment of approximately $12,000 per
month.
The Partnership has an agreement for waste water disposal with the City of
Bellingham, Washington. The City of Bellingham has agreed to accept up to 70,000
gallons of waste water daily at a rate of one cent per gallon. The agreement
expires on December 31, 1998.
The Partnership has a permit for waste water disposal from the Washington
State Department of Ecology which expires June 30, 2000.
Lease commitments -- In December 1990, the Partnership entered into a
23.5-year land lease which may be renewed for five consecutive five-year
periods. Rental expense was approximately $55,600 in 1997, $56,600 in 1996 and
$48,400 in 1995.
In 1997, ENCO signed an operating lease for office space which expires in
March 2001. Monthly rental expense is approximately $1,846. Rental expense was
approximately $19,000 in 1997, $20,400 in 1996 and $17,700 in 1995.
Future minimum land and office lease commitments as of December 31, 1997
are as follows:
<TABLE>
<CAPTION>
YEAR ENDING
DECEMBER 31, AMOUNT
------------ ----------
<S> <C>
1998.................................. $ 71,500
1999.................................. 71,500
2000.................................. 74,700
2001.................................. 61,300
2002.................................. 55,700
Thereafter............................ 756,800
----------
Total....................... $1,091,500
==========
</TABLE>
Affiliate loan -- In 1994, the sole shareholder of SEI obtained a loan from
Calpine in the amount of $10,000,000. During 1997, Calpine assigned the loan to
a third party. The sole shareholder of SEI entered into an amended and restated
loan agreement with the new lender.
Affiliate revolving line of credit -- In 1997, the sole shareholder of SEI
entered into a Revolving Loan Agreement with Calpine. The loan agreement
provides for Calpine to loan up to $15,000,000 to the SEI shareholder. Loans
bear interest at LIBOR plus 3.5% and are due in full on December 31, 2003. As of
December 31, 1997, no borrowings had been made under the loan.
F-65
<PAGE> 119
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1997
7. FAIR VALUES OF FINANCIAL INSTRUMENTS
The carrying amount of all cash and cash equivalents, accounts receivable
and accounts payable reported in the consolidated balance sheet is estimated by
the Company to approximate their fair value.
The Company is not able to estimate the fair value of its debt with a
carrying amount of $133,400,004 and $117,000,003 at December 31, 1997 and 1996,
respectively. There is no ability to assess current market interest rates of
similar borrowing arrangements for similar projects because the terms of each
such financing arrangement is the result of substantial negotiations among
several parties.
F-66
<PAGE> 120
EXHIBIT INDEX
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION OF DOCUMENT
------- ------------------------------------------------------------
<S> <C> <C>
27 Exhibit Index
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
The Schedule contains summary financial information extracted from
Calpine Corporation's Consolidated Balance Sheet as of December 31, 1997
and from the Consolidated Statement of Operations for the twelve months
ended December 31, 1997 and is qualified in its entirety by reference
to such financial statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> DEC-31-1997
<CASH> 48,513
<SECURITIES> 0
<RECEIVABLES> 42,805
<ALLOWANCES> 0
<INVENTORY> 6,015
<CURRENT-ASSETS> 166,578
<PP&E> 868,111
<DEPRECIATION> 148,390
<TOTAL-ASSETS> 1,380,956
<CURRENT-LIABILITIES> 178,586
<BONDS> 742,934
0
0
<COMMON> 20
<OTHER-SE> 239,936
<TOTAL-LIABILITY-AND-EQUITY> 1,380,956
<SALES> 237,277
<TOTAL-REVENUES> 276,321
<CGS> 144,701
<TOTAL-COSTS> 153,308
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 61,466
<INCOME-PRETAX> 53,159
<INCOME-TAX> 18,460
<INCOME-CONTINUING> 34,699
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 34,699
<EPS-PRIMARY> 1.74
<EPS-DILUTED> 1.65
</TABLE>
