Back to GetFilings.com
1
================================================================================
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 [FEE REQUIRED]
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1996
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, $0.01 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 21, 1997: $367.6 million
Common stock outstanding as of March 21, 1997: 19,869,219
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 1997 Annual
Meeting of Shareholders:....................................................
Part III (Items 10, 11, 12 and 13)
================================================================================
2
CALPINE CORPORATION
FORM 10-K
ANNUAL REPORT
FOR THE YEAR ENDED DECEMBER 31, 1996
TABLE OF CONTENTS
PAGE
-----
PART I
ITEM 1. Business................................................................ 1
ITEM 2. Properties.............................................................. 33
ITEM 3. Legal Proceedings....................................................... 34
ITEM 4. Submission of Matters To A Vote of Security Holders..................... 34
PART II
ITEM 5. Market for Registrant's Common Equity and Related Stockholder Matters... 34
ITEM 6. Selected Financial Data................................................. 34
ITEM 7. Management's Discussion and Analysis of Financial Condition and Results 34
of Operations...........................................................
ITEM 8. Financial Statements and Supplementary Data............................. 34
ITEM 9. Changes In and Disagreements with Accountants and Financial 34
Disclosure..............................................................
PART III
ITEM 10. Executive Officers, Directors and Key Employees......................... 35
ITEM 11. Executive Compensation.................................................. 35
ITEM 12. Security Ownership of Certain Beneficial Owners and Management.......... 35
ITEM 13. Certain Relationships and Related Transactions.......................... 35
PART IV
ITEM 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K......... 36
Signatures.......................................................................... 43
Index to Consolidated Financial Statements and Schedules............................ F-1
Schedule 11 Calculation of Earnings Per Share
Exhibit Index
i
3
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. 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 risks
and uncertainties 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, and (iii) 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 and its subsidiaries (the "Company" or "Calpine") is
engaged in the acquisition, development, 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 interests in 15 power
generation facilities and steam fields having an aggregate capacity of 1,047
megawatts. Since its inception in 1984, Calpine has developed substantial
expertise in all aspects of electric power generation. The Company's vertical
integration has resulted in significant growth over the last five years as
Calpine has applied its extensive engineering, construction management,
operations, fuel management and financing capabilities to successfully implement
its acquisition and development program. During the last five years, Calpine has
expanded substantially, from $55.4 million of total assets as of December 31,
1992 to $1.0 billion of total assets as of December 31, 1996. Calpine's revenue
for 1996 increased to $214.6 million, representing a compound annual growth rate
of 52.6% since 1992. The Company's EBITDA for 1996 increased to $117.4 million
(see Item 6. Selected Financial Data). Calpine's strategy is to capitalize on
opportunities in the power market through an ongoing program to acquire,
develop, own and operate electric generation facilities, as well as marketing
power and energy services to utilities and other end users.
STRATEGY
Calpine's objective is to become a leading power company by capitalizing on
emerging market opportunities in the domestic and international 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 Calpine believes provides it
with a competitive advantage. By pursuing this strategy, the Company has
significantly expanded and diversified its project portfolio. Since 1993, the
Company has completed transactions involving five gas-fired cogeneration
facilities and two steam fields. As a result of these transactions, the Company
has more than doubled its aggregate power generation capacity and substantially
diversified its fuel mix.
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, rather than exclusively
through long-term power sales agreements. As part of Calpine's initial effort to
develop merchant plants, the Company entered into an agreement with Phillips
Petroleum Company to develop a gas-fired cogeneration project with a capacity of
240 megawatts. Under this agreement, approximately 90 megawatts of electricity
will be sold to the Phillips Houston Chemical Complex, with the remainder to be
sold into the competitive market through
1
4
Calpine's power marketing activities. The Company expects that this project will
represent a prototype for future merchant plant developments. The development of
this project is subject to the satisfaction of various conditions including
required approvals. See "Development and Future Projects."
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 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.
Continue to develop an integrated power marketing capability. The Company
is developing an integrated power marketing capability, conducted through its
wholly owned subsidiary, Calpine Power Services Company ("CPSC"). In 1995, CPSC
received approval from the Federal Energy Regulatory Commission ("FERC") to
conduct power marketing activities. The Company believes that a power marketing
capability complements its business strategy of providing low cost power
generation services. CPSC's power marketing activities will focus on the
development of long-term customer service relationships, supported primarily by
generating assets that are owned, operated or controlled by Calpine. CPSC will
aggregate the Company's own resources, the resources of its customers, power
pool resources, and market power supply to provide the customized services
demanded by its customers at a competitive price.
Selectively expand into international markets. Internationally, the
Company intends to utilize its geothermal and gas-fired expertise in selected
markets of Southeast Asia and Latin America, where demand for power is rapidly
growing and private investment is encouraged. In November 1995, the Company made
a loan to Coperlasa, which operates the Cerro Prieto Steam Fields located in
Baja California, Mexico. In March 1996, the Company entered into a joint venture
agreement to pursue the development of a geothermal resource in Indonesia with
an estimated potential capacity in excess of 500 megawatts. Calpine believes
that its investments in these projects will effectively position it for future
expansion in Southeast Asia and Latin America.
DESCRIPTION OF POWER PLANTS
The Company has interests in 15 power generation facilities and steam
fields with a current aggregate capacity of approximately 1,047 megawatts,
consisting of seven natural gas-fired cogeneration power plants with a total
capacity of 522 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 458 megawatts. Each of the power generation
facilities produces electricity for sale to a utility. 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 natural 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 all
power generation facilities in which the Company has an interest, except for the
Thermal Power Company Steam Fields and the Cerro Prieto Steam Fields. 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
2
5
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
debt for the project.
In order to provide fuel for the gas-fired power generation projects 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
structures 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
projects. 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. See
Item 2. Properties.
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 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 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. See
"Governmental Regulation."
3
6
The table below sets forth certain information regarding the Company's
power generation facilities and steam fields currently in operation.
POWER GENERATION FACILITIES
COMMENCEMENT TERM OF
POWER NAMEPLATE CALPINE CALPINE NET OF POWER
GENERATION CAPACITY INTEREST INTEREST COMMERCIAL UTILITY SALES
POWER PLANT TECHNOLOGY (MEGAWATTS)(1) (PERCENTAGE) (MEGAWATTS) OPERATION PURCHASER AGREEMENT
- --------------- ------------- -------------- ------------ ----------- ------------ -------------- ---------
Sumas Gas-Fired Puget Sound
Cogeneration 125 75%(2) 93.8 1993 Power & Light 2013
King City Gas-Fired Pacific Gas &
Cogeneration 120 100% 120 1989 Electric 2019
Gilroy Gas-Fired Pacific Gas &
Cogeneration 120 100% 120 1988 Electric 2018
Greenleaf 1 Gas-Fired Pacific Gas &
Cogeneration 49.5 100% 49.5 1989 Electric 2019
Greenleaf 2 Gas-Fired Pacific Gas &
Cogeneration 49.5 100% 49.5 1989 Electric 2019
Agnews Gas-Fired Pacific Gas &
Cogeneration 29 20% 5.8 1990 Electric 2021
Watsonville Gas-Fired Pacific Gas &
Cogeneration 28.5 100% 28.5 1990 Electric 2009
West Ford Flat Geothermal Pacific Gas &
27 100% 27 1988 Electric 2008
Bear Canyon Geothermal Pacific Gas &
20 100% 20 1988 Electric 2008
Aidlin Geothermal Pacific Gas &
20 5% 1 1989 Electric 2009
STEAM FIELDS
COMMENCEMENT
APPROXIMATE CALPINE CALPINE NET OF
CAPACITY INTEREST INTEREST COMMERCIAL UTILITY ESTIMATED
STEAM FIELD (MEGAWATTS)(3) (PERCENTAGE) (MEGAWATTS) OPERATION PURCHASER LIFE(4)
- ----------- -------------- ------------ ----------- ------------ --------------------- ---------
Thermal 151 100% 151 1960 Pacific Gas & 2018
Power Electric
Company
PG&E Unit 86 100% 86 1980 Pacific Gas & 2018
13 Electric
PG&E Unit 82 100% 82 1985 Pacific Gas & 2018
16 Electric
SMUDGEO #1 59 100% 59 1983 Sacramento Municipal 2018
Utility District
Cerro 80 100%(5) 80 1973 Comision Federal 2000(6)
Prieto de Electricidad
- ---------------
(1) Nameplate capacity may not represent the actual output for a facility at any
particular time.
(2) See "Power Generation Facilities -- Sumas Power Plant" for a description of
the Company's interest in the Sumas partnership and current sales of power
by the Sumas Power Plant.
(3) Capacity is expected to gradually diminish as the production of the related
steam fields declines. See "Steam Fields."
(4) Other than for the Cerro Prieto Steam Fields, 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. See "Steam Fields."
(5) 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
Fields.
(6) Represents the actual termination of the steam sales agreement. See "Steam
Fields -- Cerro Prieto Steam Fields."
4
7
Power Generation Facilities
Sumas Power Plant
The Sumas cogeneration facility (the "Sumas Power Plant") is a 125 megawatt
natural gas-fired, combined cycle 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. The
Company currently holds a 50% interest in Sumas and SEI holds the other 50%
interest. At the time the Company receives a 24.5% pre-tax rate of return on its
partnership investment in Sumas, the Company's interest will be reduced to
11.33% and SEI's interest will increase to 88.67%. Further, the Company receives
an additional 25% of the cash flow of the Sumas Power Plant to repay principal
and interest on $11.5 million of loans to the sole shareholder of SEI. A $1.5
million loan bears interest at 20% and matures in 2003 and a $10.0 million loan
bears interest at 16.25% and matures in 2004. 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 comprised of an MS 7001EA combined cycle gas turbine manufactured by
General Electric Company ("General Electric"), 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%.
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. 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 London Interbank
Offered Rate ("LIBOR"), which are amortized over a 15-year period ending in
2008.
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:
FIXED FIXED FIXED
ENERGY ENERGY ENERGY
YEAR PRICE YEAR PRICE YEAR PRICE
------------- ------ ------------- ------ ------------- ------
1997......... 3.38c 2003......... 6.22c 2009......... 5.40c
1998......... 3.64c 2004......... 6.33c 2010......... 5.49c
1999......... 3.98c 2005......... 6.45c 2011......... 5.58c
2000......... 4.23c 2006......... 6.57c 2012......... 5.58c
2001......... 6.23c 2007......... 5.23c 2013......... 5.58c
2002......... 6.11c 2008......... 5.31c
The variable price component is set according to a scheduled rate set forth
in the agreement, which in 1996 was 0.99c per kilowatt hour, and escalates
annually by a factor equal to the U.S. Gross National Product Implicit Price
Deflator. For 1996, the average price paid by Puget under the power sales
agreement was 4.166c 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
5
8
shared with the Sumas Power Plant. In 1996, the Sumas Power Plant's net profit
increased by $501,000 as a result of the displacement provision.
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 pounds 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
qualified facility ("QF") status. See "Government Regulation."
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 130 billion cubic feet as of January 1, 1997.
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 million British thermal units per day ("mmbtu/day") to the
Sumas Power Plant. The remaining 12,100 mmbtu/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.
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 1996, the Sumas Power Plant generated approximately 1,032,000,000
kilowatt hours of electrical energy and approximately $44.0 million of total
revenue. In 1996, the Company recognized income of approximately $6.4 million in
accordance with the terms of the Sumas partnership agreement, and recorded
revenue of $2.0 million for services performed under the operating and
maintenance agreement.
King City Power Plant
The King City cogeneration power plant (the "King City Power Plant") is a
120 megawatt natural 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/Eriksen 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 and
has operated at an average availability of approximately 99%.
Electricity generated by the King City Power Plant is sold to Pacific Gas
and Electric Company ("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. As-delivered capacity prices are $188 per kilowatt year for 1997 and
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.
Through 1998, payments for electrical energy produced are based on 100% of
PG&E's avoided cost of energy for the period of January 1 through April 30, and
80% at avoided cost and 20% at fixed prices for the period of May 1 through
December 31. The fixed average energy price in effect for 1997 and 1998 under
the
6
9
King City power sales agreement is 13.14c per kilowatt hour. Thereafter, PG&E is
required to pay for electrical energy actually delivered at prices equal to
PG&E's then avoided cost of energy (as determined by the California Public
Utilities Commission ("CPUC")). PG&E's avoided cost of energy varies from month
to month and has ranged from an annual average of 1.84c to 2.96c per kilowatt
hour since 1992. During 1996, PG&E's avoided cost of energy averaged
approximately 2.26c 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. See
"Government Regulation." 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 pursuant to a
contract with Chevron U.S.A. Inc. ("Chevron"), expiring June 30, 1997. Natural
gas is transported under a firm transportation agreement, expiring June 30,
1997, via a dedicated 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 1996, the King City Power Plant generated approximately 411,977,000
kilowatt hours of electrical energy and approximately $41.5 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.
The acquisition of the Gilroy Power Plant was originally financed utilizing
a non-recourse project loan 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 (see Note 18 of the Notes to Consolidated Financial Statements).
The power plant consists of a General Electric Frame 7 Model EA combustion
turbine generator, an AEG-KANIS (ABB) 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 power plant has
operated at an average availability of 94%.
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 $188 per kilowatt year for 1997. 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 electrical energy actually delivered during
the
7
10
period of dispatchable operation at a price equal to PG&E's avoided cost of
energy excluding adders. Thereafter, during the period of baseload operation,
PG&E is required to pay for electrical energy actually delivered at prices equal
to PG&E's then avoided cost of energy. PG&E's avoided cost of energy has varied
from month to month and has ranged from an annual average of 1.84c to 2.96c per
kilowatt hour since 1992. During 1996, PG&E's avoided cost of energy averaged
approximately 2.26c 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 with 1995 revenues of approximately $24.1 billion. It is necessary
to continue to operate the host facility in order to maintain the Gilroy Power
Plant's QF status. See "Government Regulation."
Natural gas for the Gilroy Power Plant is supplied pursuant to a contract
with Amoco Energy Trading Corporation ("Amoco") expiring July 31, 1997. Natural
gas is transported under a firm transportation agreement, expiring July 1, 1997.
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.
From August 29, 1996 through December 31, 1996, the Gilroy Power Plant
generated approximately 231,365,000 kilowatt hours of electrical energy for sale
to PG&E and approximately $14.7 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 Greenleaf 1 and 2 Power Plants have a combined natural gas requirement
of approximately 22,000 mmbtu/day. The Company, through its wholly owned
subsidiary Calpine Fuels Corporation ("Calpine Fuels"), entered into a gas
supply agreement with Montis Niger, Inc. ("MNI"), an affiliate of LFC, which
owns and operates a local gas field connected to the facilities. On January 31,
1997, the Company purchased the stock of MNI. Calpine Fuels supplements the MNI
gas supply with a short-term contract with Coastal Gas Marketing Company, which
expires on April 30, 1997. This gas is delivered over PG&E's intrastate pipeline
which is directly connected to each facility. The Greenleaf 1 and 2 Power Plants
have interruptible transportation agreements with PG&E, expiring in June 1997.
Greenleaf 1 Power Plant. The Greenleaf 1 cogeneration facility (the
"Greenleaf 1 Power Plant") is a 49.5 megawatt natural 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 power plant has operated at an
average availability of approximately 92.5%.
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
8
11
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 1997. 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 a price equal to
PG&E's avoided cost of energy (as determined by the CPUC). PG&E's avoided cost
of energy varies from month to month and has ranged from an annual average of
1.84c to 2.96c per kilowatt hour since 1992. During 1996, PG&E's avoided cost of
energy averaged approximately 2.26c 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 1996, the Greenleaf 1 Power Plant did not
experience curtailment. PG&E may also interrupt or reduce deliveries if
necessary to repair its system or because of system emergencies, forced outages,
force majeure and compliance with prudent electrical practices.
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. See "Government Regulation."
The Greenleaf 1 Power Plant is located on 77 acres owned by the Company
near Yuba City, California.
For 1996, the Greenleaf 1 Power Plant generated approximately 354,182,000
kilowatt hours of electrical energy for sale to PG&E and approximately $18.1
million in revenue.
Greenleaf 2 Power Plant. The Greenleaf 2 cogeneration facility (the
"Greenleaf 2 Power Plant") is a 49.5 megawatt natural 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 power plant has operated at an average availability of approximately 96%.
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 1997. 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 a
price equal to PG&E's avoided cost of energy (as determined by the CPUC). PG&E's
avoided cost of energy varies from month to month and has ranged from an annual
average of 1.84c to 2.96c per kilowatt hour since 1992. During 1996, PG&E's
avoided cost of energy averaged approximately 2.26c 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 1996, the Greenleaf 2 Power Plant did not
experience curtailment. PG&E may also interrupt or reduce deliveries if
necessary to repair its system or because of system emergencies, forced outages,
force majeure and compliance with prudent electrical practices.
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. See "Government
Regulation."
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.
9
12
For 1996, the Greenleaf 2 Power Plant generated approximately 399,707,000
kilowatt hours of electrical energy for sale to PG&E and approximately $19.3
million in revenue.
Agnews Power Plant
The Agnews cogeneration facility (the "Agnews Power Plant") is a 29
megawatt natural 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%.
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, 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 1997 and 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, PG&E's avoided cost of energy (as determined by the CPUC).
PG&E's avoided cost of energy varies from month to month and has ranged from an
annual average of 1.84c to 2.96c per kilowatt hour since 1992. During 1996,
PG&E's avoided cost of energy averaged approximately 2.26c per kilowatt hour.
Under certain circumstances, PG&E may curtail energy deliveries for up to
1,000 off-peak hours per year. During 1996, PG&E curtailed the energy purchased
under the power sales agreement by 995 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 (which has historically been less
than one megawatt per year) 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. See "Government
Regulation."
10
13
The supply of natural gas for the Agnews Power Plant is currently provided
under a full requirements fuel supply agreement between O.L.S. Energy-Agnews and
Amoco Energy Trading Corporation ("Amoco") which expires June 30, 1997.
Intrastate transportation is provided under a firm gas transportation agreement
with PG&E, expiring in June 1997.
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 had an initial term of six years, expiring on
December 31, 1996, and was renewed for an additional six-year term effective
January 1, 1997.
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 1996, the Agnews Power Plant generated approximately 205,838,000
kilowatt hours of electrical energy and total revenue of $11.0 million. In 1996,
the Company recognized a loss of approximately $190,000 as a result of the
Company's 20% ownership interest and recorded revenue of $2.0 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 natural gas-fired, combined cycle 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 power
plant has operated at an average availability of approximately 97%.
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 the fixed energy price schedule set forth
below, and 99% of the energy will be sold at PG&E's avoided cost of energy. The
following schedule sets forth the fixed average energy prices (expressed in
cents per kilowatt hour) and the as-delivered capacity prices per kilowatt year
through 2000 for energy deliveries under the Watsonville Power Plant power sales
agreement:
ENERGY AS-DELIVERED
YEAR PRICE CAPACITY PRICE
--------------------------------------------------- ------ --------------
1997............................................... 13.14c $188
1998............................................... 13.90c $188
1999............................................... 13.90c $188
2000............................................... 13.90c $188
Thereafter, PG&E will pay for energy delivered at prices equal to PG&E's
avoided cost of energy (as determined by the CPUC), 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. PG&E's avoided cost of energy varies from
month to month and has ranged from an annual average of 1.84c to 2.96c per
kilowatt hour since 1992. During 1996, PG&E's avoided cost of energy averaged
approximately 2.26c per kilowatt hour.
11
14
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 October 1 though April 30. From January 1, 1996 through December 31, 1996,
PG&E curtailed energy purchases of 1,290 hours under the power sales agreement.
In addition to the sale of electricity to PG&E, during 1996 the Watsonville
Power Plant produced and sold steam to two thermal hosts, Norcal Frozen Foods,
Inc. ("Norcal") and Farmers Processing, both food processors. In August 1995,
Norcal sold its facility to a subsidiary of Dean Foods ("Dean Foods"), which
closed the facility on February 9, 1996. The lessor of the Watsonville Power
Plant has constructed a water distillation facility on the site of the
Watsonville Power Plant to replace the Dean Foods food processing facility. This
facility commenced operations in August 1996 and is operated by the Company. It
is necessary to continue to operate the host facilities in order to maintain the
Watsonville Power Plant's QF status. See "Government Regulation."
Amoco is the supplier of natural gas to the Watsonville Power Plant. The
Company has negotiated a contract with Amoco which will be effective through
June 30, 1997. The Company's current contract is on a month-to-month basis with
Amoco. PG&E provides firm gas transportation to the Watsonville Power Plant
under a contract expiring June 30, 1997.
The Watsonville Power Plant is located on 1.8 acres of land leased from
Dean Foods under the terms of a 30-year lease expiring in 2010.
For 1996, the Watsonville Power Plant generated approximately 205,942,000
kilowatt hours of electrical energy for sale to PG&E and approximately $10.6
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.,
and seven production wells and 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%.
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 1997 and 1998 is 13.83c cents
per kilowatt hour under the West Ford Flat power sales agreement. Thereafter,
PG&E is required to pay for electrical energy actually delivered at prices equal
to PG&E's avoided cost of energy (as determined by the CPUC). PG&E's avoided
cost of energy varies from month to month and has ranged from an annual average
of 1.84c to 2.96c per kilowatt hour since 1992. During 1996, PG&E's avoided cost
of energy averaged approximately 2.26c per kilowatt hour. The Company cannot
accurately predict the avoided cost of energy prices that will be in effect at
the expiration of the fixed price period under this agreement.
Under certain circumstances, PG&E may curtail energy deliveries for up to
1,000 off-peak hours per year. During 1996, PG&E curtailed the energy purchased
under this agreement by 1,000 hours. In the event of such curtailment, the
Company's results of operations may be materially adversely affected. The
Company currently expects the maximum amount of curtailment allowed under the
agreement during 1997.
The Company believes that the geothermal reserves that supply energy for
use by the West Ford Flat Power Plant will be sufficient to operate at full
capacity for the entire term of the power sales agreement due
12
15
principally to high reservoir pressures, 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. For a description of the leases covering the properties
located in The Geysers, see Item 2. Properties.
During 1996, the West Ford Flat Power Plant generated approximately
219,849,000 kilowatt hours of electrical energy for sale to PG&E and
approximately $31.9 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%.
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 and
as-delivered capacity prices through 1998 are 13.83c per kilowatt hour and $188
per kilowatt year, respectively. Thereafter, PG&E will pay for energy delivered
at prices equal to PG&E's avoided cost of energy (as determined by the CPUC),
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. PG&E's avoided cost of energy
varies from month to month and has ranged from an annual average of 1.84c to
2.96c per kilowatt hour since 1992. During 1996, PG&E's avoided cost of energy
averaged approximately 2.26c per kilowatt hour. The Company cannot accurately
predict the avoided cost of energy prices that will be in effect at the
expiration of the fixed price period under this agreement.
Under certain circumstances, PG&E may curtail energy deliveries for up to
1,000 off-peak hours per year. During 1996, PG&E curtailed the energy purchased
under this agreement by 1,000 hours. In the event of any such curtailment, the
Company's results of operations may be materially adversely affected. The
Company currently expects the maximum amount of curtailment allowed under the
agreement during 1997.
The Company believes that the geothermal reserves for the Bear Canyon Power
Plant will be sufficient to operate at full capacity for substantially all of
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. For a description of the leases covering the
properties located at The Geysers, see Item 2. Properties.
During 1996, the Bear Canyon Power Plant generated approximately
161,785,000 kilowatt hours of electrical energy and approximately $22.8 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
13
16
interest is held in the form of a 10% general partnership interest in a limited
partnership (the "Aidlin 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 99%.
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 prices equal to PG&E's avoided cost of energy (as
determined by the CPUC). PG&E's avoided cost of energy varies from month to
month and has ranged from an annual average of 1.84c to 2.96c per kilowatt hour
since 1992. During 1996, PG&E's avoided cost of energy averaged approximately
2.26c per kilowatt hour. The Company cannot accurately predict the avoided cost
of energy that will be in effect at the expiration of the fixed price period
under this agreement.
Under certain circumstances, PG&E may curtail energy deliveries for up to
1,000 off-peak hours per year. During 1996, PG&E curtailed the energy purchased
under this agreement by 1,000 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 1996, the Aidlin Power Plant generated approximately 167,804,000
kilowatt hours of electrical energy and revenue of $22.3 million. In 1996, the
Company recognized revenue of approximately $331,000 as a result of the
Company's 5% ownership interest and $4.0 million for services performed under
the operating and maintenance agreement.
Steam Fields
Thermal Power Company Steam Fields
The Company acquired Thermal Power Company on September 9, 1994 for a
purchase price of $66.5 million. Thermal Power Company 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") owns 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 over 240 production
wells, 18 injection wells and 55 miles of steam-transporting pipeline. See Item
2. Properties. The 12 plants have a nameplate capacity of 978 megawatts and
currently have the capability to operate at over 600 megawatts. The steam fields
commenced commercial operation in 1960.
14
17
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. 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 1996
was 1.622c per kilowatt hour. The price for 1997 is expected to be approximately
1.907c per kilowatt hour. In addition, the Company receives a monthly fee for
effluent disposal and maintenance. During 1996, such monthly fee was $147,000
per month.
In March 1996, the Company 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 the Company and Union Oil with the intent
that it be at competitive market prices. The Company 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. Under the steam sales
agreement, the Company is required to pay PG&E for the unamortized costs,
including site clean-up, removal and abandonment costs, of power plants that are
installed but are unused as a result of steam supply deficiency. 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, the Company makes offset payments at a reduced rate until total
offsets calculated since July 1, 1991 equal $15.0 million. Accordingly, the
Company's share of offsets in 1996 was $672,000. In approximately 2000 or 2001,
when total offsets may exceed $15.0 million, in accordance with the agreement
the Company'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).
In accordance with the steam sales agreement, PG&E may curtail the power
plants which receive steam in order to produce energy from lower cost sources.
PG&E is contractually 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. During 1996, the Thermal Power Company Steam Fields
experienced curtailment of steam production due to low gas prices and abundant
hydro power. The Company receives a monthly fee for PG&E's right to curtail its
power plants. Such fee was $13,200 per month during 1996.
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, the Company 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, the Company may terminate the agreement with a two-year written
notice to PG&E. If the Company 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, the Company 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. The
Company 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 nameplate
capacity. This percentage reflects a decline in productivity since the
commencement of operations. While it is not possible to accurately predict
long-term
15
18
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
was approximately 9% until 1995, during which year extensive curtailment
interrupted the decline trend. The Company expects steam field productivity to
continue to decline in the future. The Company plans to work with Union Oil and
PG&E to partially offset the expected rate of decline by the development of
water injection projects and power plant improvements.
During 1996, the PG&E power plants produced 3,208,984,000 kilowatt hours of
electrical energy of which the Company's 25% share is 802,246,000 kilowatt hours
for approximately $13.1 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. See Item 2. Properties. Unit 13 and Unit 16
have nameplate capacities of 98 and 113 megawatts, respectively, and currently
operate at outputs of approximately 86 and 82 megawatts, respectively. The PG&E
Unit 13 Steam Field includes 956 acres, 30 production wells, three 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, one
injection well, 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 1996 was 0.955c per kilowatt
hour. The price for 1997 is expected to be approximately 0.985c 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 63,000,000 kilowatt hours under
the steam sales agreement during 1996.
The steam sales agreement with PG&E continues in effect for as long as
either Unit 13 or Unit 16 remains in commercial operation, which depends 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. The Company currently estimates that the productive capacity of the
PG&E Unit 13 and Unit 16 Steam Fields is approximately 22 years. However, no
assurance can be given that the operation of either Unit 13 or Unit 16 will not
become economically impractical at any time during these periods.
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 approximately $10.0 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.
16
19
The PG&E Unit 13 and Unit 16 Steam Fields currently supply steam sufficient
to operate Unit 13 and Unit 16 at approximately 80% 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 8.7% in 1996. 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.
During 1996, the PG&E Unit 13 and Unit 16 Steam Fields produced sufficient
steam to permit Unit 13 and Unit 16 to produce approximately 1,269,400,000
kilowatt hours of electrical energy and approximately $12.8 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"). See Item 2.
Properties. The SMUD power plant has a nameplate capacity of 72 megawatts and
currently operates at an output of 59 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 $1.77 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. Based on current
estimates and analyses performed by the Company, the Company does not expect
SMUD to suspend payments for steam under this provision. 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 82% of its nameplate capacity. This
percentage reflects a decline in the productivity of the SMUDGEO #1 Steam Fields
since commencement of operations. Although the SMUDGEO #1 Steam Fields
productivity increased in 1995 and did not decline in 1996 (due to curtailment
of neighboring plants), the Company expects the SMUDGEO #1 Steam Fields'
productivity to decline in the future.
During 1996, the SMUDGEO #1 Steam Fields produced approximately 6,835,390
thousand pounds of steam and approximately $14.6 million of revenue.
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
17
20
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 (see Note 8 of the
Notes to Consolidated Financial Statements).
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.
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 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. While the
Company believes that Coperlasa is in an advantageous position to renegotiate or
bid for the right to supply steam over a longer term, there can be no assurance
that the steam sales agreement will be extended beyond its current termination
date.
DEVELOPMENT AND FUTURE PROJECTS
The Company is continually engaged in the evaluation of various
opportunities for the development and acquisition of additional power generation
facilities. However, there is no assurance the Company will be successful in the
acquisition or development of power generation projects in the future. See "Risk
Factors."
Pasadena Cogeneration Project
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 Cogeneration Project"). 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 marketing activities. The Company provided a $3.0 million letter of credit
to Phillips to secure the performance under the Energy Project Development
Agreement. On December 20, 1996, the Company entered into a credit agreement
with ING U.S. Capital Corporation to provide $98.6 million of non-recourse
project financing for the Pasadena Cogeneration Project. In accordance with the
terms of the agreement, Calpine Corporation, through its wholly owned
subsidiaries, Calpine Pasadena Cogeneration, Inc. and Calpine Texas
Cogeneration, Inc., contributed $53.1 million in equity to the project. The
Company commenced construction in February 1997, with commercial operation
scheduled to begin in October 1998. However, there can be no assurances that the
Company will be successful in completing any additional power sales agreements
or that the anticipated schedule for construction will be met.
18
21
Glass Mountain Geothermal Project
Calpine is pursuing the development of a geothermal power project at Glass
Mountain, which is located in northern California about 25 miles south of the
Oregon border (the "Glass Mountain Project"). Glass Mountain is believed to be
the largest undeveloped geothermal resource in the United States. In area, the
resource is larger than The Geysers, where approximately 1,200 megawatts of
capacity is operating. The Company believes that Glass Mountain has an estimated
potential in excess of 1,000 megawatts and is seeking potential customers for
the power to be produced by this project.
In August 1994, the Company entered into a partnership with Trans-Pacific
Geothermal Corporation ("TGC") to construct and operate a 30 megawatt project at
Glass Mountain (the "Partnership"). TGC had previously signed a memorandum of
understanding ("MOU") with Bonneville Power Administration ("BPA") and the
Springfield, Oregon Utility Board ("SUB") to develop the project at Vale,
Oregon. BPA and SUB consented on August 25, 1994 to the assignment of the MOU to
the Partnership and the relocation of the project to Glass Mountain. The MOU
contemplated execution of a 45-year power purchase agreement subject to
satisfaction of certain conditions precedent and included an option for an
additional 100 megawatts.
In December 1996, the Partnership and BPA entered into a settlement
agreement which restructured the rights and obligations of the parties. In
return for a $12.0 million payment by BPA to the Partnership and the grant by
the Partnership to BPA of future options to purchase power at Glass Mountain,
the Partnership and BPA terminated the MOU and certain ancillary agreements. In
addition, BPA will pay the Partnership additional consideration should certain
future events occur related to ongoing environmental review of the Glass
Mountain project. Following the settlement with BPA, TGC withdrew from the
Partnership (see Note 7 of the Notes to Consolidated Financial Statements).
In March 1996, the Company completed the acquisition of certain Glass
Mountain geothermal leases. As a result, the Company currently holds an interest
in approximately 29,000 acres of federal geothermal leases at Glass Mountain.
See Item 2. Properties.
Indonesian Geothermal Project
Calpine plans to develop geothermal facilities in the Lampung Province of
Indonesia, located in southern Sumatra. The geothermal resource at Ulubelu is
estimated to have potential capacity in excess of 500 megawatts. The Company
anticipates that the facility would sell electricity to Perusahaan Umum Listrik
Negara ("PLN"), the state-owned electric company. The first phase of the project
is expected to be 110 megawatts.
The Company's joint venture partner will be PT. Dharmasatrya Arthasentosa
("DATRA"), a company with interests in coal mining and other ventures. The
Company expects that it will be the project's managing partner, with
responsibility for the design, construction and operation of the power plant.
The ownership structure, as planned, will be a joint venture with DATRA in which
the Company would be the managing partner and hold at least a 50% equity
interest, and as much as 85% of the project. DATRA would hold up to 50% of the
project.
In March 1996, the Company and DATRA entered into a joint venture agreement
to develop Ulubelu. The Company and DATRA are negotiating with the National
Resource Agency Pertamina ("Pertamina") regarding resource development. Deep
test well drilling and flow tests by Pertamina are planned during 1997 at
Ulubelu. Commercial operation is anticipated in 2001 for the initial phase of
the project. There can be no assurances, however, that this transaction will be
consummated on these terms, if at all, that the proposed timetable will be met
or that commercial operation of these resources will be feasible.
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
19
22
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 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
20
23
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 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. See "Public Utility Holding Company Regulation."
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
21
24
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 seven natural
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 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 contract becomes a part of a utility's cost structure
(generally reflected in its retail rates), power sales contracts 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 contracts. 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,
22
25
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 by January 1, 1988. 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 January 1, 1998 restructure implementation goal.
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 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, eligibility and phase-in schedule for customer choice (direct
access), the continuation of public purpose programs and issues related to
issuance of rate reduction bonds.
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 restructur-
23
26
ing 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.
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 material 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
24
27
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 material 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
material 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 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.
COMPETITION
The Company competes with independent power producers, including affiliates
of utilities, in obtaining long-term agreements to sell electric power to
utilities. In addition, utilities may elect to expand or create generating
capacity through their own direct investments in new plants. Over the past
decade, obtaining a power sales agreement with a utility has become an
increasingly more difficult, expensive and competitive process. In the past few
years, more contracts have been awarded through some form of competitive
bidding. Increased competition also has lowered profit margins of successful
projects. The Company believes that the power marketing business represents an
opportunity to take advantage of growing competition in the electric power
industry. The Company also believes that the power marketing business will be
highly competitive.
The demand for power in the United States traditionally has been met by
utilities constructing large-scale electric generating plants under rate-based
regulation. The enactment of PURPA in 1978 spawned the growth of the independent
power industry, which expanded rapidly in the 1980s. The initial independent
power producers were an entrepreneurial group of cogenerators and small power
producers who recognized the potential business opportunities offered by PURPA.
This initial group of independents was later joined by larger, better
capitalized companies, such as subsidiaries of fuel supply companies,
engineering companies, equipment manufacturers and affiliates of other
industrial companies. In addition, a number of regulated utilities have created
subsidiaries (known as utility affiliates) that compete with independent power
producers. Some independent power producers specialize in market "niches," such
as a specific technology or fuel (e.g., gas-fired cogeneration, geothermal,
hydroelectric, refuse-to-energy, wind, solar, coal and wood), or a specific
region of the country where they believe they have a market advantage. The
Company presently conducts its operations primarily in the United States and
concentrates on gas-fired and geothermal cogeneration plants.
The Company is the second largest producer of geothermal energy in the
United States. Although the Company is an established leader in the geothermal
power industry and has been rapidly growing, most of the Company's competitors
have significantly greater capital, financial and operational resources.
25
28
Recent amendments to PUHCA made by the Energy Policy Act of 1992 are likely
to increase the number of competitors in the independent power industry by
reducing certain restrictions currently applicable to certain projects that are
not QFs under PURPA. However, the recent amendments also should make it simpler
for the Company to develop new projects itself, for example, by enabling the
Company to develop large, gas-fired generation projects without the necessity of
locating its projects in the vicinity of a steam host or otherwise finding a
steam host to accept the useful thermal output required of a cogeneration
facility under PURPA.
EMPLOYEES
As of December 31, 1996, the Company employed 254 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.
RISK FACTORS
High Leverage
The Company is highly 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, 1996, the Company's total consolidated
indebtedness was $601.1 million, its total consolidated assets were $1.0 billion
and its stockholders' equity was $203.1 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.
The Indenture dated as of May 16, 1996 (the "10 1/2% Indenture") relating
to the 10 1/2% Senior Notes Due 2006 and the Indenture dated as of February 17,
1994 (the "9 1/4% Indenture") relating to the Company's 9 1/4% Senior Notes Due
2004 (the "9 1/4% Senior Notes") (collectively, the "Indentures" and the "Senior
Notes") contain certain restrictive covenants. Such restrictions affect, and in
many respects significantly limit or prohibit, among other things, the ability
of the Company or its subsidiaries or such other entities, as the case may be,
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 Indentures also contain
provisions that require the Company, in the event of a Change of Control
Triggering Event (as such term is defined in the Indentures), to make an offer
to purchase the Senior Notes. There can be no assurance that the Company will
have the financial resources necessary to purchase the Senior Notes upon a
Change of Control (as such term is defined in the Indentures). Such Change of
Control provisions contained in the Indentures may not be waived by the Board of
Directors of the Company.
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 Senior Notes, and to enable the
Company to comply with the terms of its 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 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 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.
26
29
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 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. In addition, there can be no assurance that all required
governmental permits and approvals for the Company's new or acquired facilities
will be obtained, that the Company will be able to obtain favorable power sales
agreements and adequate financing, or that the Company will be successful in the
development of power generation facilities in the future. Historically, the
Company has been successful in obtaining debt financing for its facilities and
had relied on Electrowatt Ltd. ("Electrowatt"), formerly the Company's sole
stockholder, to provide funding for a substantial portion of its facility equity
commitments. Over the past few years, the Company has maintained a $50.0 million
credit facility with Credit Suisse (the "Credit Suisse Credit Facility"), which
was arranged for the Company by Electrowatt. In connection with the Company's
initial public offering of Common Stock in September 1996 (the "Common Stock
Offering"), Electrowatt sold all of its shares of Common Stock of the Company
and, as a result, the Company will no longer be able to rely on Electrowatt for
financing. Upon the completion of the Common Stock Offering, the Credit Suisse
Credit Facility was terminated.
On September 25, 1996, the Company entered into a $50.0 million three-year
revolving credit facility with The Bank of Nova Scotia (the "Bank of Nova Scotia
Credit Facility"). The Bank of Nova Scotia 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's power generation facilities have been financed using a
variety of leveraged financing structures, primarily consisting of non-recourse
debt and lease obligations. As of December 31, 1996, the Company had
approximately $601.1 million of total consolidated indebtedness, of which
approximately 51% represented non-recourse subsidiary debt. Each non-recourse
debt and lease 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 significant 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
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
27
30
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. If the lenders or lessors were
to require such guarantees, and the Company were unable to incur indebtedness in
respect of such guarantees under the restrictions on indebtedness (including
guarantees) contained in the Indentures, the Company's ability to fund new
facilities could be adversely affected. The Indentures do not limit the ability
of the Company's subsidiaries to incur non-recourse or lease financing for
investment in new facilities.
Calpine Geysers Company, L.P. ("CGC"), a wholly owned subsidiary of
Calpine, owns the West Ford Flat Power Plant, the Bear Canyon Power Plant, the
PG&E Unit 13 and Unit 16 Steam Fields and the SMUDGEO #1 Steam Fields. Calpine
Greenleaf Corporation ("Calpine Greenleaf"), a wholly owned subsidiary of
Calpine, owns the Greenleaf 1 and 2 Power Plants. The non-recourse facility
financing of each of CGC and Calpine Greenleaf is collateralized by all of the
assets and properties of each of the facilities and steam fields owned by such
subsidiary. In the event of a reduction in revenue derived from one or more of
these facilities or steam fields which results in a failure to make any payments
on, or if such subsidiary otherwise defaults in its obligations under the terms
of, its non-recourse project financing, the lenders would be entitled to
foreclose on all of the assets of such subsidiary, including the assets
pertaining to each such facility and 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.
Impact of Avoided Cost Pricing; Energy Price Fluctuations
Nine of the existing power plants in which the Company has an interest sell
electricity to PG&E under separate long-term power sales agreements. Each of
these agreements provides for both capacity payments and energy payments for the
term of the agreement. During the initial ten-year period of certain of the
agreements, PG&E pays a fixed price for each unit of electrical energy according
to schedules set forth in such agreements. The fixed price periods under these
power sales agreements expire at various times in 1998 through 2000. 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 PG&E's then prevailing avoided cost of energy, which is
determined and published from time to time by the CPUC. The term "avoided cost"
refers to the incremental costs that an electric utility would incur to produce
or purchase an amount of power equivalent to that purchased from qualifying
facilities (as defined under PURPA). The
28
31
currently prevailing avoided cost of energy is substantially lower than the
fixed energy prices under these power sales agreements and is generally expected
to remain so. While avoided cost does not affect capacity payments under the
power sales agreements, in the event that the avoided cost of energy does not
increase significantly, the Company's energy revenue under these power sales
agreements would be materially reduced at the expiration of the fixed price
period. Such reduction could have a material adverse effect on the Company's
results of operations. The Company cannot accurately predict the likely level of
avoided cost energy prices at the expiration of the fixed price periods. 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.
Impact of Curtailment
Each of the Company's power and steam sales agreements contains curtailment
provisions pursuant to which the purchasers of energy or steam are entitled to
reduce the number of hours of energy or amount of steam purchased thereunder.
Curtailment provisions are customary in power and steam sales agreements. During
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 higher levels of energy
generation by hydroelectric power facilities that supply electricity. In limited
circumstances, energy production from third party geothermal power plants may be
curtailed, which would reduce deliveries of steam by the Company under the steam
sales agreements. The Company expects maximum curtailment during 1997 under its
power sales agreements for certain of its facilities, and there can be no
assurance that the Company will not experience curtailment in the future. In the
event of such curtailment, the Company's results of operations may be materially
adversely affected.
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 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.
The Company has grown substantially in recent years as a result of
acquisitions of interests in power generation facilities and steam fields such
as the Transactions. 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.
29
32
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 all of the power generation facilities and
steam fields in which it has an interest, except for two steam fields. 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 in excess of 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 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.
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 1996, approximately 86% and 7% of
the Company's total revenue was attributable to revenue received pursuant to
power and steam sales agreements with PG&E and Sacramento Municipal Utility
District ("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. During 1996, an additional 4% of the Company's revenue was
attributable to operating and maintenance services performed by the Company for
power generation facilities that sell electricity to PG&E.
30
33
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.
International Investments
The Company has made an investment in the Cerro Prieto geothermal steam
fields located in Mexico and intends to pursue investments primarily in Latin
America and Southeast Asia. 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.
Power Marketing Business
It is part of the Company's strategy to continue to develop an integrated
nationwide power marketing business to market power generated both by the
Company's generation facilities and power generated by third parties. However,
the power marketing industry is only in its early stages of development, and
there are no assurances that the industry will develop in such a way as to
permit the Company to achieve these goals. Furthermore, the Company has only
recently commenced its power marketing business, and there can be no assurance
that its power marketing strategy will be successful or that the Company's goals
will be achieved.
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
31
34
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.
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. 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 net revenues.
32
35
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 new power sales agreements, and this competition has
contributed to a reduction in electricity prices. In this regard, many utilities
often engage in "competitive bid" solicitations to satisfy new capacity demands.
This competition adversely affects the ability of the Company to obtain power
sales agreements and the price paid for electricity. There also is increasing
competition between electric utilities, particularly in California where the
CPUC and the California legislature have launched an initiative designed to give
all electric consumers the ability to choose between competing suppliers of
electricity. 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.
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, 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.
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 also maintains a regional
office in Santa Rosa, California under a lease that expires in 1999.
The Company, through its ownership of CGC and Thermal Power Company, 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 and Thermal Power
Company's 25% undivided interest in the Thermal Power Company Steam Fields which
are operated by Union Oil. The Company has subleasehold interests in three
leases comprising 6,825 acres of federal geothermal resource lands in the Coso
area in central California. 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
33
36
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.
See "Item 1. Business -- Description of Facilities" for a description of
the other material properties leased or owned by the projects in which the
Company has ownership interests. The Company believes that its properties are
adequate for its current operations.
ITEM 3. LEGAL PROCEEDINGS
The Company, together with over 100 other parties, was named as a defendant
in an action brought in August 1993 by the bankruptcy trustee for Bonneville
Pacific Corporation ("Bonneville"), captioned Roger G. Segal, as the Chapter 11
Trustee for Bonneville Pacific Corporation v. Portland General Corporation, et
al., in the United States District Court for the District of Utah (the "Court").
In December 1996, the trustee and the Company entered into a settlement
agreement relating to this matter. The trustee has agreed to waive all claims
against the Company and to dismiss the trustee's litigation against the Company
in exchange for a payment of $767,500 by the Company.
The Company is involved in various other claims and legal actions arising
out of the normal course of business. Management does not expect that the
outcome of these cases will have a material adverse effect on the Company's
financial position or results of operations.
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. Calpine Corporation 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.
34
37
ITEM 10. EXECUTIVE OFFICERS, DIRECTORS AND KEY EMPLOYEES
Incorporated by reference from Proxy Statement relating to the 1997 Annual
Meeting of Shareholders.
ITEM 11. EXECUTIVE COMPENSATION
Incorporated by reference from Proxy Statement relating to the 1997 Annual
Meeting of Shareholders.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Incorporated by reference from Proxy Statement relating to the 1997 Annual
Meeting of Shareholders.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
CS Holding, a Swiss corporation, holds approximately 44.9% of the
outstanding shares of Electrowatt, which, prior to the Common Stock Offering,
held all of the outstanding capital stock of the Company. CS Holding also holds
(i) approximately 100% of the outstanding shares of Credit Suisse and (ii)
approximately 69.3% of the outstanding common stock of CS First Boston, Inc.,
which holds all of the outstanding common stock of CS First Boston Corporation.
CS First Boston Corporation was one of the underwriters of the Company's 9 1/4%
Senior Notes issued in February 1994 and was one of the placement agents in the
sale of the 10 1/2% Senior Notes Due 2006. CS First Boston was also an
underwriter in the Common Stock Offering.
In January 1990, O.L.S. Energy-Agnews entered into a credit agreement with
Credit Suisse providing for a $28 million loan to finance the construction of
the Agnews Power Plant. The Company holds a 20% interest in O.L.S.
Energy-Agnews. The loan is collateralized by all of the assets of the Agnews
Power Plant and bears interest on the unpaid principal balance based on LIBOR
plus a margin rate varying between .50% and 1.50%. After commencement of
commercial operation, the Agnews Power Plant was sold to Nynex Credit
Corporation under a sale leaseback arrangement with O.L.S. Energy-Agnews and
Credit Suisse. Under the sale leaseback, O.L.S. Energy-Agnews entered into a
22-year lease, commencing February 1991, providing for the payment of a fixed
base rental, as well as renewal options and a purchase option at the termination
of the lease. As of December 31, 1995, O.L.S. Energy-Agnews's outstanding
obligation of its sale leaseback arrangement was $37.6 million.
In September 1990, the Company obtained a $25.3 million Credit Facility
from Credit Suisse. In April 1993, the Credit Suisse Credit Facility was amended
to increase the amount of credit available to the Company to $54.0 million. The
Credit Suisse Credit Facility was unsecured and bore interest on the amounts
outstanding from time to time, if any, at LIBOR plus .50% per annum. During
1994, the Company completed a $105.0 million public debt offering of the 9 1/4%
Senior Notes. A portion of the net proceeds were used to repay $52.6 million
indebtedness outstanding under the Credit Suisse Credit Facility. On April 21,
1995, the Company entered into the Credit Suisse Credit Facility providing for
advances of $50.0 million. On April 29, 1996, the amount of advances available
under the Credit Suisse Credit Facility was increased to $58.0 million. A
portion of the proceeds of the sale of the 9 1/4% Senior Notes Due 2004 was used
to repay outstanding borrowings under the Credit Suisse Credit Facility of
approximately $53.7 million on May 16, 1996. The amount of advances available
under the Credit Suisse Credit Facility was subsequently restored to $50.0
million. Upon completion of the Common Stock Offering, the Credit Suisse Credit
Facility was terminated.
In January 1992, Sumas and its wholly owned subsidiary, ENCO, entered into
loan agreements with Prudential and Credit Suisse providing for a $120.0 million
loan to finance the construction of the Sumas Power Plant and acquisition of
associated gas reserves. See "Item 1. Business -- Description of Facilities --
Power Generation Facilities -- Sumas Cogeneration Power Plant." As of December
31, 1996, the outstanding indebtedness of Sumas and ENCO under the term loan was
$117.0 million.
In December 1994, the Company entered into a Consulting Agreement with Mr.
George Stathakis, a Director, which was amended and restated effective June 3,
1996. See the Proxy Statement relating to the 1997 Annual Meeting of
Shareholders.
35
38
In January 1995, the Company and Electrowatt entered into a management
services agreement, which replaced a prior similar agreement, under which
Electrowatt agreed to provide the Company with advisory services in connection
with the construction, financing, acquisition and development of power projects,
as well as any other advisory services as may be required by the company in
connection with the operation of the Company. The Company had agreed to pay
Electrowatt $200,000 per year for all services rendered under the management
services agreement. Pursuant to this agreement, $166,000 and $200,000 were paid
in 1996 and 1995, respectively. Upon completion of the Common Stock Offering,
the management services agreement was terminated.
In 1995, the Company paid $106,000 to Electrowatt pursuant to a guarantee
fee agreement whereby Electrowatt agreed to guarantee the payment when due of
any and all indebtedness of the Company to Credit Suisse in accordance with the
terms and conditions of the Credit Suisse Credit Facility. Under the guarantee
fee agreement, the Company had agreed to pay to Electrowatt an annual fee equal
to 1% of the average outstanding balance of the Company's indebtedness to Credit
Suisse during each quarter as compensation for all services rendered under the
guarantee fee agreement. Upon completion of the Common Stock Offering, the
guarantee fee agreement was terminated.
In June 1995, Calpine repaid $57.5 million of non-recourse financing to
Credit Suisse which was outstanding indebtedness related to the Greenleaf 1 and
2 Power Plants at the time of the acquisition of such facilities.
In March 1996, Electrowatt invested $50.0 million in the Company in the
form of shares of Preferred Stock, all of which were converted into shares of
Common Stock in connection with the Common Stock Offering.
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, 1996 and 1995
Consolidated Statements of Operations for the Years Ended December 31, 1996,
1995 and 1994
Consolidated Statements of Shareholders' Equity for the Years Ended December
31, 1996, 1995 and 1994
Consolidated Statements of Cash Flows for the Years Ended December 31, 1996,
1995 and 1994
Notes to Consolidated Financial Statements for December 31, 1996
36
39
(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, 1996 and 1995
Statements of Operations for the Years Ended December 31, 1996, 1995, and
1994
Statements of Cash Flows for the Years Ended December 31, 1996, 1995, and
1994
Notes to Condensed Financial Statements for December 31, 1996
II Valuation and Qualifying Accounts
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
Independent Auditor's Report
Consolidated Balance Sheets, December 31, 1996 and 1995
Consolidated Statements of Operations for the Years Ended December 31, 1996,
1995 and 1994
Consolidated Statements of Changes in Partners' Equity for the Years Ended
December 31, 1996, 1995 and 1994
Consolidated Statements of Cash Flows for the Years Ended December 31, 1996,
1995 and 1994
Notes to Consolidated Financial Statements for the Years Ended December 31,
1996, 1995 and 1994
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.
(A)-3. EXHIBITS
The following exhibits are filed herewith unless otherwise indicated:
EXHIBIT
NUMBER DESCRIPTION
- -------- ------------------------------------------------------------------------------------
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)
37
40
EXHIBIT
NUMBER DESCRIPTION
- -------- ------------------------------------------------------------------------------------
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)
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. *
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)
38
41
EXHIBIT
NUMBER DESCRIPTION
- -------- ------------------------------------------------------------------------------------
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)
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. *
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)
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)
39
42
EXHIBIT
NUMBER DESCRIPTION
- -------- ------------------------------------------------------------------------------------
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)
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)
40
43
EXHIBIT
NUMBER DESCRIPTION
- -------- ------------------------------------------------------------------------------------
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)
10.11 Form of Indemnification Agreement for directors and officers. (l)
21.1 Subsidiaries of the Company. (m)
- ---------------
(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.
41
44
(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.
* Filed herewith.
(B) REPORTS ON FORM 8-K
No reports on Form 8-K were filed during the period from October 1, 1996 to
December 31, 1996.
42
45
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 21, 1997 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.
SIGNATURE TITLE DATE
- ------------------------------------------ --------------------------------- ---------------
/s/ PETER CARTWRIGHT President, Chief Executive March 21, 1997
- ------------------------------------------ Officer and Chairman of the
Peter Cartwright Board (Principal Executive
Officer)
/s/ ANN B. CURTIS Senior Vice President and March 21, 1997
- ------------------------------------------ Director (Principal Financial
Ann B. Curtis Officer)
/s/ JEFFREY E. GARTEN Director March 21, 1997
- ------------------------------------------
Jeffrey E. Garten
43
46
SIGNATURE TITLE DATE
- ------------------------------------------ --------------------------------- ---------------
/s/ SUSAN C. SCHWAB Director March 21, 1997
- ------------------------------------------
Susan C. Schwab
/s/ GEORGE J. STATHAKIS Director March 21, 1997
- ------------------------------------------
George J. Stathakis
/s/ JOHN O. WILSON Director March 21, 1997
- ------------------------------------------
John O. Wilson
/s/ ORVILLE WRIGHT Director March 21, 1997
- ------------------------------------------
V. Orville Wright
/s/ GLORIA S. GEE Controller (Principal Accounting March 21, 1997
- ------------------------------------------ Officer)
Gloria S. Gee
44
47
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
AND OTHER INFORMATION
DECEMBER 31, 1996
PAGE
-----
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-11
Consolidated Balance Sheets, December 31, 1996 and 1995............................... F-12
Consolidated Statements of Operations for the Years Ended December 31, 1996, 1995 and
1994................................................................................ F-13
Consolidated Statements of Shareholder's Equity for the Years Ended December 31, 1996,
1995 and 1994....................................................................... F-14
Consolidated Statements of Cash Flows for the Years Ended December 31, 1996, 1995 and
1994................................................................................ F-15
Notes to Consolidated Financial Statements for the Years Ended December 31, 1996, 1995
and 1994............................................................................ F-16
CALPINE CORPORATION
Schedule I: Condensed Financial Information of Registrant
Report of Independent Public Accountants............................................ F-41
Condensed Balance Sheets, December 31, 1996 and 1995................................ F-42
Condensed Statements of Operations for the Years Ended December 31, 1996, 1995 and
1994............................................................................. F-43
Condensed Statements of Cash Flows for the Years Ended December 31, 1996, 1995 and
1994............................................................................. F-44
Notes to Condensed Financial Statements for December 31, 1996....................... F-45
Schedule II: Valuation and Qualifying Accounts........................................ F-48
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
Report of Independent Public Accountants.............................................. F-49
Consolidated Balance Sheets, December 31, 1996 and 1995............................... F-50
Consolidated Statement of Income for the Years Ended December 31, 1996, 1995 and
1994................................................................................ F-51
Consolidated Statement of Changes in Partners' Equity for the Years Ended December 31,
1996, 1995 and 1994................................................................. F-52
Consolidated Statement of Cash Flows for the Years Ended December 31, 1996, 1995 and
1994................................................................................ F-53
Notes to Consolidated Financial Statements for the Years Ended December 31, 1996, 1995
and 1994............................................................................ F-54
F-1
48
SELECTED CONSOLIDATED FINANCIAL DATA
The consolidated financial data set forth below for and as of the five
years ended December 31, 1996 have been derived from the audited consolidated
financial statements of the Company. The following selected consolidated
financial data should be read in conjunction with the consolidated financial
statements and the related notes thereto appearing elsewhere in this report, and
"Management's Discussion and Analysis of Financial Condition and Results of
Operations."
YEAR ENDED DECEMBER 31,
-------------------------------------------------
1992 1993 1994 1995 1996
------- ------- ------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
STATEMENT OF OPERATIONS DATA:
Revenue:
Electricity and steam sales............................ $ -- $53,000 $90,295 $127,799 $199,464
Service contract revenue............................... 29,817 16,896 7,221 7,153 6,455
Income (loss) from unconsolidated investments in power
projects............................................. 9,760 19 (2,754) (2,854) 6,537
Interest income on loans to power projects............. -- -- -- -- 2,098
------- ------- ------- -------- --------
Total revenue........................................ 39,577 69,915 94,762 132,098 214,554
Cost of revenue.......................................... 25,921 42,501 52,845 77,388 129,200
------- ------- ------- -------- --------
Gross profit............................................. 13,656 27,414 41,917 54,710 85,354
Project development expenses............................. 806 1,280 1,784 3,087 3,867
General and administrative expenses...................... 3,924 5,080 7,323 8,937 14,696
Compensation expense related to stock options (1)........ 1,224 -- -- -- --
Provision for write-off of project development costs
(2).................................................... 800 -- 1,038 -- --
------- ------- ------- -------- --------
Income from operations............................... 6,902 21,054 31,772 42,686 66,791
Interest expense......................................... 1,225 13,825 23,886 32,154 45,294
Other income, net........................................ (310) (1,133) (1,988) (1,895) (6,259)
------- ------- ------- -------- --------
Income before provision for income taxes and
cumulative effect of change in accounting
principle.......................................... 5,987 8,362 9,874 12,427 27,756
Provision for income taxes............................... 2,527 4,195 3,853 5,049 9,064
------- ------- ------- -------- --------
Income before cumulative effect of change in
accounting principle............................... 3,460 4,167 6,021 7,378 18,692
Cumulative effect of adoption of SFAS No. 109............ -- (413) -- -- --
------- ------- ------- -------- --------
Net income........................................... $ 3,460 $ 3,754 $ 6,021 $ 7,378 $ 18,692
======= ======= ======= ======== ========
Primary earnings per share (3) Weighted average shares
outstanding............................................ -- 14,680
======== ========
Primary earnings per share............................. -- $ 1.27
======== ========
Fully diluted earnings per share (3)
Weighted average shares outstanding.................... -- 15,130
======== ========
Fully diluted earnings per share....................... -- $ 1.24
======== ========
As adjusted primary earnings per share assuming
conversion of preferred stock (3)
Weighted average shares outstanding.................... 14,151 --
======== ========
Primary earnings per share............................. $ 0.52 --
======== ========
OTHER FINANCIAL DATA AND RATIOS:
(in thousands, except ratio data)
Depreciation and amortization............................ $ 232 $12,540 $21,580 $ 26,896 $ 40,551
EBITDA (4)............................................... $ 9,898 $42,370 $53,707 $ 69,515 $117,379
EBITDA to Consolidated Interest Expense (5).............. 4.73x 2.98x 2.23x 2.11x 2.41x
Total debt to EBITDA................................... 3.70x 6.24x 6.23x 5.87x 5.12x
Ratio of earnings to fixed charges (6)................... 3.41x 2.09x 1.52x 1.46x 1.45x
See footnotes on next page)
F-2
49
AS OF DECEMBER 31,
-------------------------------------------------------------
1992 1993 1994 1995 1996
------- -------- -------- -------- ----------
(IN THOUSANDS)
BALANCE SHEET DATA:
Cash and cash equivalents........... $ 2,160 $ 6,166 $ 22,527 $ 21,810 $ 100,010
Property, plant and equipment,
net............................... 424 251,070 335,453 447,751 650,053
Total assets........................ 55,370 302,256 421,372 554,531 1,030,215
Total liabilities................... 44,865 288,827 402,723 529,304 827,088
Stockholders' equity................ 10,505 13,429 18,649 25,227 203,127
- ---------------
(1) Represents a non-cash charge for compensation expense associated with the
grant of certain options under the Company's stock option program.
(2) Represents a write-off of certain capitalized project costs.
(3) The weighted average shares outstanding and earnings per share for the year
ended December 31, 1996 gave effect to the issuance of common stock upon the
conversion of the Company's preferred stock in connection with the Company's
initial public offering (see Note 1 of Notes to Consolidated Financial
Statements). The presentation of fully diluted earnings per share for the
year ended 1996 is not required by Accounting Principles Board Opinion No.
15, because it results in dilution of less than 3%. As adjusted primary
earnings per share assuming conversion of preferred stock for the year ended
December 31, 1995 is calculated using average shares outstanding, which
includes common share equivalents using the treasury stock method and the
assumed conversion of preferred stock to common stock as of January 1, 1995
in accordance with Securities and Exchange Commission staff policy. Earnings
per share prior to 1995 have not been presented since such amounts are not
deemed meaningful due to the significant change in the Company's capital
structure that occurred in connection with its initial public offering.
(4) 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 either (i) to income from
operations (determined in accordance with generally accepted accounting
principles) or (ii) to cash flows from operating activities (determined in
accordance with generally accepted accounting principles).
(5) 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.
(6) 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
50
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. 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 risks
and uncertainties 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, and (iii) other risks identified
from time to time in the Company's reports and registration statements filed
with the Securities and Exchange Commission.
GENERAL
Calpine is engaged in the acquisition, development, 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 interests in
15 power generation facilities and steam fields having an aggregate capacity of
1,047 megawatts. Since its inception in 1984, Calpine has developed substantial
expertise in all aspects of electric power generation. The Company's vertical
integration has resulted in significant growth over the last five years as
Calpine has applied its extensive engineering, construction management,
operations, fuel management and financing capabilities to successfully implement
its acquisition and development program. During the last five years, Calpine has
expanded substantially, from $55.4 million of total assets as of December 31,
1992 to $1.0 billion assets as of December 31, 1996. Calpine's revenue for 1996
increased to $214.6 million, representing a compound annual growth rate of 52.6%
since 1992. The Company's EBITDA (see Selected Consolidated Financial Data) for
1996 increased to $117.4 million.
On September 9, 1994, the Company acquired Thermal Power Company, which
owns a 25% undivided interest in certain steam fields at The Geysers steam
fields in northern California ("The Geysers") with a total capacity of 604
megawatts for a purchase price of $66.5 million. In January 1995, the Company
purchased the working interest in certain of the geothermal properties at the
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 natural 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 natural
gas-fired cogeneration facility, for a 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 120 megawatt King City Power Plant, 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.
Each of the power generation facilities produces electricity for sale to a
utility. Thermal energy produced by the gasfired 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. Nine of these agreements with Pacific Gas and
Electric Company ("PG&E") provides for both capacity payments and energy
payments for the term of the agreement. During the initial ten-year period of
certain agreements, PG&E pays a fixed price for each unit of electrical energy
according to schedules set forth in such agreements. The fixed price periods
under these power sales agreements expire at various times in 1998 through 2000.
After the fixed price periods expire,
F-4
51
while the basis for the capacity and capacity bonus payments under these power
sales agreements remains the same, the energy payments adjust to PG&E's then
avoided cost of energy, which is determined by the California Public Utilities
Commission ("CPUC"). The currently prevailing avoided cost of energy is
substantially lower than the fixed energy prices under these power sales
agreements and is generally expected to remain so. While avoided cost does not
affect capacity payments under the power sales agreements, in the event that the
avoided cost of energy does not increase significantly, the Company's energy
revenues under these power sales agreements would 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 cannot predict the
likely level of avoided cost energy prices at the expiration of the fixed price
periods. 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.
Each of the Company's power and steam sales agreements contains 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. During
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 facilities that supply electricity. The
Company expects maximum curtailment during 1997 under its power and steam sales
agreements for certain of its facilities.
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
envisions commencement of deregulation and implementation of customer choice of
electricity supplier by January 1, 1998 (see Note 28 of the Notes to
Consolidated Financial Statements). As part of its policy decision, the CPUC
indicated that power sales agreements of existing qualifying facilities ("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. 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.
SELECTED OPERATING INFORMATION
Set forth below is certain selected operating information for the power
generation facilities and steam fields, for which results are consolidated in
the Company's 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 and the Watsonville Power
Plant since their acquisitions on April 21, 1995 and June 29, 1995,
respectively, the Gilroy Power Plant since its acquisition on August 29,1996,
and the King City Power Plant since the effective date of the lease on May 2,
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 1996, the Thermal Power Company Steam Fields since the acquisition
of Thermal Power Company 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 West Ford Flat Power Plant, Bear Canyon Power Plant, the PG&E Unit 13 and
Unit 16 Steam Fields and the SMUDGEO #1 Steam Fields in April 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.
F-5
52
YEAR ENDED DECEMBER 31,
--------------------------------------------------------------
1992 1993 1994 1995 1996
---------- ---------- ---------- ---------- ----------
(DOLLARS IN THOUSANDS)
POWER PLANTS:
Electricity revenue (1):
Energy............................. $ 38,325 $ 37,088 $ 45,912 $ 54,886 $ 93,851
Capacity........................... $ 7,707 $ 7,834 $ 7,967 $ 30,485 $ 65,064
Megawatt hours produced............ 403,274 378,035 447,177 1,033,566 1,985,404
Average energy price per kilowatt
hour (2)........................ 9.503c 9.811c 10.267c 5.310c 4.727c
STEAM FIELDS:
Steam revenue:
Calpine......................... $ 33,385 $ 31,066 $ 32,631 $ 39,669 $ 40,549
Other interest.................. $ 2,501 $ 2,143 $ 2,051 -- --
Megawatt hours produced............ 2,105,345 2,014,758 2,156,492 2,415,059 2,528,874
Average price per kilowatt hour.... 1.705c 1.648c 1.608c 1.643c 1.603c
- ---------------
(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 hours since 1994 reflects the increase in
the Company's megawatt hour production as a result of acquisitions of
gas-fired cogeneration facilities by the Company.
RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31, 1996 COMPARED TO YEAR ENDED DECEMBER 31, 1995
Revenue. Revenue increased 62% to $214.6 million in 1996 compared to
$132.1 million in 1995, primarily due to a 56% increase in electricity and steam
sales of $199.5 million in 1996 compared to $127.8 million in 1995. The King
City Power Plant and the Gilroy Power Plant contributed revenues of $41.5
million and $14.7 million, respectively, to electric and steam sales revenue
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
increases in electric and steam revenue 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 West Ford Flat and Bear Canyon Power Plants. Without such curtailment, the
West Ford Flat and Bear Canyon Power Plants would have generated an additional
$5.7 million and $5.2 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 Cogeneration Company, L.P.
("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 which
F-6
53
was acquired 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 financings.
Other income, net. Other income, net increased 232% to $6.3 million for
1996 compared with $1.9 million for 1995. The increase was primarily due to $4.5
million of interest income on collateral securities purchased in connection with
the King City transaction, $1.4 million of net proceeds for the settlement of
the Coso project, and higher interest income for the period due to the
investment of the net proceeds of the preferred stock, the 10 1/2% Senior Notes
Due 2006, and from the Company's initial public offering of common shares.
Offsetting these income items was a $3.7 million loss for uncollectible amounts
related to the O'Brien acquisition project (see Note 13 of Notes to Consolidated
Financial Statements).
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 8.84% 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.
YEAR ENDED DECEMBER 31, 1995 COMPARED TO YEAR ENDED DECEMBER 31, 1994
Revenue increased 39% to $132.1 million in 1995 compared to $94.8 million
in 1994, primarily due to a 42% increase in electricity and steam sales to
$127.8 million in 1995 compared to $90.3 million in 1994. Such an increase was
primarily attributable to the $28.3 million of revenue from the Greenleaf 1 and
2 Power Plants, $5.9 million of revenue from the Watsonville Power Plant, the
$5.2 million of additional revenue from the Thermal Power Company Steam Fields
as a result of a full year of operation in 1995, and an increase of $3.0 million
of revenue from the SMUDGEO #1 Steam Fields attributable to increased production
as a result of an extended outage during 1994. Such an increase also reflects a
substantial increase in capacity payments for electricity sales from $8.0
million in 1994 to $30.5 million in 1995 as a result of the transactions stated
above. This revenue increase was partially offset by a $2.7 million decrease in
revenue from the West Ford Flat and Bear Canyon Power Plants as a result of
curtailments by PG&E due to low gas prices and high levels of precipitation
during 1995 as compared to 1994, offset in part by contractual price increases
for 1995. Without such curtailment, the West Ford Flat and Bear Canyon Power
Plants would have generated an additional $5.2 million of revenue in 1995.
Revenue for 1995 also reflects curtailment of steam production at the Thermal
Power Company Steam Fields as a result of higher precipitation and lower gas
prices in 1995, and at the PG&E Unit 13 and Unit 16 Steam Fields as a result of
hydro-spill conditions. Without curtailment, the Thermal Power Company Steam
Fields and the PG&E Unit 13 and Unit 16 Steam Fields would have generated an
additional $5.7 million and $800,000 of revenue during 1995, respectively.
F-7
54
Revenue for 1995 and 1994 reflects reversals of $2.7 million and $3.2
million, respectively, of previously deferred revenue. Company revenue from
sales of steam was previously calculated considering a future period when steam
would be delivered without receiving corresponding revenue. In May 1994, the
Company ceased deferring revenue and recognized $4.0 million of its previously
deferred revenue. Based on estimates and analyses performed by the Company, the
Company no longer expects that it will be required to make these deliveries to
SMUD. Concurrently, $800,000 of the revenue increase was reserved for future
construction of gathering systems required for future production of the steam
fields, with the offset recorded in property, plant and equipment. In October
1995, PG&E agreed to the termination of the free steam provision with respect to
the PG&E Unit 13 Steam Fields. During 1995, the Company took additional measures
regarding future capital commitments and other actions which will increase steam
production and, based on additional analyses and estimates performed, the
Company recognized the remaining $2.7 million of previously deferred revenue.
Cost of revenue. Cost of revenue increased 47% to $77.4 million in 1995
compared to $52.8 million in 1994. The increase was due to plant operating,
production royalty and depreciation and amortization expenses attributable to
(i) a full year of operations at Thermal Power Company, which was purchased on
September 9, 1994, (ii) operations at the Greenleaf 1 and 2 Power Plants
subsequent to April 21, 1995, and (iii) operations at the Watsonville Power
Plant subsequent to June 29, 1995. The increases were partially offset by lower
depreciation and production royalty expenses at the West Ford Flat and Bear
Canyon Power Plants and the PG&E Unit 13 and Unit 16 Steam Fields due to
curtailment by PG&E during 1995.
Project development expenses. Project development expenses increased to
$3.1 million in 1995 compared to $1.8 million in 1994, due to new project
development activities.
General and administrative expenses. General and administrative expenses
were $8.9 million in 1995 compared to $7.3 million in 1994. The increase in 1995
was primarily due to additional personnel and related expenses necessary to
support the Company's expanded operations.
Interest expense. Interest expense increased to $32.2 million in 1995 from
$23.9 million in 1994. Approximately $3.6 million of the increase was
attributable to a full year of interest expense incurred on the debt related to
the Thermal Power Company acquisition in September 1994 and $4.1 million of
interest expense incurred on the debt related to the Greenleaf transaction in
April 1995. In addition, 1995 included a full year of interest expense on the
9 1/4% Senior Notes Due 2004 issued on February 17, 1994.
Provision for income taxes. The effective rate for the income tax
provision was approximately 41% for 1995 and 39% for 1994. The effective rates
were based on statutory tax rates, with minor reductions for depletion in excess
of tax basis benefits. Due to curtailment of production during 1995, the
allowance for statutory depletion decreased in 1995 from 1994.
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 financings. 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:
YEAR ENDED DECEMBER 31,
-----------------------------------
1994 1995 1996
-------- -------- ---------
(IN THOUSANDS)
Cash flows from:
Operating activities.................... $ 34,196 $ 26,653 $ 59,881
Investing activities.................... (84,444) (38,497) (326,834)
Financing activities.................... 66,609 11,127 345,153
-------- -------- ---------
Total........................... $ 16,361 $ (717) $ 78,200
======== ======== =========
F-8
55
Operating activities for 1996 consisted of approximately $18.7 million of
net income from operations, $36.6 million of depreciation and amortization, $2.0
million in deferred income taxes, and $7.8 million net increase in operating
assets and liabilities, offset by $5.3 million of undistributed income from
unconsolidated investments in power projects.
Investing activities used $326.8 million during 1996, primarily due to
$29.9 million of capital expenditures and capitalized project costs, $98.4
million for the purchase of collateral securities, a $12.9 million loan to
Coperlasa in connection with the Cerro Prieto project, $138.1 million for the
acquisition of the Gilroy Power Plant, and a $41.6 million increase in
restricted cash requirements related to the construction of the Pasadena Power
Plant.
Financing activities provided $345.2 million of cash during 1996. The
Company issued $50.0 million of preferred stock to Electrowatt, borrowed $161.8
million of bank debt and an additional $46.9 million under the credit
facilities, received net proceeds of $174.9 million from the 10 1/2% Senior
Notes Due 2006, and received $109.2 million upon the issuance of common stock.
The Company subsequently repaid $46.2 million of bank debt, all borrowings
outstanding under the credit facilities of $66.7 million, and $84.7 million of
non-recourse project financing.
As of December 31, 1996, cash and cash equivalents were $100.0 million and
working capital was $96.2 million. For the twelve months ended December 31,
1996, working capital increased by $145.2 million and cash and cash equivalents
increased by $78.2 million as compared to the comparable period in 1995. The
increase in working capital is primarily due to remaining net proceeds from the
issuance of common stock in September 1996, and reflects the inclusion of $57.0
million of non-recourse project financing in current liabilities as of December
31, 1995. On May 16, 1996, the Company issued the 10 1/2% Senior Notes Due 2006.
A portion of the funds from the issuance of the 10 1/2% Senior Notes Due 2006
was used to refinance current bank debt and borrowings under the Credit Suisse
credit facility, and to repay the $57.0 million non-recourse indebtedness to The
Bank of Nova Scotia.
As a developer, owner and operator of power generation projects, 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.
The Company currently has outstanding $105.0 million of 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
has $180.0 million of 10 1/2% Senior Notes Due 2006 which mature on May 15, 2006
and bear interest semi-annually on May 15 and November 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 include dividends and certain purchases and investments, incur
additional indebtedness and engage in certain transactions.
At December 31, 1996, the Company had $309.3 million of non-recourse
project financing associated with power generating facilities and steam fields
at the West Ford Flat Power Plant, the Bear Canyon Power Plant, the PG&E Unit 13
and Unit 16 Steam Fields, the SMUDGEO #1 Steam Fields, the Greenleaf 1 and 2
Power Plants and the Gilroy Power Plant. As of December 31, 1996, the annual
maturities for all non-recourse project financing were $30.6 million for 1997,
$32.7 million for 1998, $24.2 million for 1999, $24.8 million for 2000, $24.6
million for 2001 and $170.5 million thereafter.
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 LIBOR or at The Bank of Nova Scotia
base rate plus a mutually agreed margin. At December 31, 1996, the Company had
no borrowings outstanding and $5.9 million of letters of credit outstanding
under the revolving credit facility (see Note 16 of Notes to Consolidated
Financial Statements). The Bank of Nova Scotia 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 payments
of certain indebtedness, pay dividends, make
F-9
56
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, 1996, the Company had no borrowings under
this working capital line and $900,000 of letters of credit outstanding.
Borrowings are at prime plus 1%.
The Company also has outstanding a non-interest bearing promissory note to
Natomas Energy Company in the amount of $6.5 million representing a portion of
the September 1994 purchase price of Thermal Power Company. This note has been
discounted to yield 8% per annum and is due September 9, 1997.
The Company intends to continue to seek the use of non-recourse project
financing for new projects, where appropriate. 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, 1996, the Company had commitments for capital expenditures
in 1997 totaling $4.0 million related to various projects at its geothermal
facilities. 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. Capital expenditures for
1996 were $30.2 million compared to $17.4 million for 1995, primarily due to the
purchase of new equipment. For 1996, capital expenditures included $12.5 million
related to the Pasadena Power Plant, $4.0 million for the purchase of geothermal
leases for the Glass Mountain project, $3.1 million for the new rotor at the
PG&E Unit 13 facility, $3.2 million for geothermal well drilling, $2.1 million
for a reinjection pipeline at the Company's geothermal steam fields, and $5.4
million of capital expenditures at various cogeneration facilities.
The Company continues to pursue the acquisition and development of new
power generation projects. The Company expects to commit significant capital in
future years for the acquisition and development of these projects. 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 and 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.
IMPACT OF RECENT ACCOUNTING PRONOUNCEMENT
In February 1997, the Financial Accounting Standards Board ("FASB") issued
SFAS No. 128, Earnings Per Share, which simplifies the standards for computing
earnings per share previously found in Accounting Principles Board Opinion
("APBO") No. 15. SFAS No. 128 replaces the presentation of primary earnings per
share with a presentation of basic earnings per share, which excludes dilution.
SFAS No. 128 also requires dual presentation of basic and diluted earnings per
share on the face of the income statement for all entities with complex capital
structures and requires a reconciliation. Diluted earnings per share is computed
similarly to fully diluted earnings per share pursuant to APBO No. 15. SFAS No.
128 must be adopted for financial statements issued for periods ending after
December 15, 1997, including interim periods; earlier application is not
permitted. SFAS No. 128 requires restatement of all prior-period earnings per
share data presented. The Company has not yet quantified the effect of adopting
SFAS No. 128.
F-10
57
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, 1996
and 1995, and the related consolidated statements of operations, stockholders'
equity and cash flows for each of the three years in the period ended December
31, 1996. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits. We 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 and 1995. The Company has recorded income of $6.4
million and losses of $3.0 million and $2.9 million representing its share of
the net income or loss of Sumas for the years ended December 31, 1996, 1995 and
1994, 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
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 other auditors provide a reasonable
basis for our opinion.
In our opinion, based on our audits and the report of other auditors, the
financial statements referred to above present fairly, in all material respects,
the financial position of Calpine Corporation and subsidiaries as of December
31, 1996 and 1995, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 1996 in conformity with
generally accepted accounting principles.
ARTHUR ANDERSEN LLP
San Jose, California
March 7, 1997
F-11
58
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 1996 AND 1995
(IN THOUSANDS)
1996 1995
---------- --------
ASSETS
Current assets:
Cash and cash equivalents.......................................... $ 100,010 $ 21,810
Accounts receivable
from related parties............................................ 2,826 2,177
from others..................................................... 39,962 17,947
Acquisition project receivables.................................... 791 8,805
Collateral securities, current portion............................. 5,470 --
Interest receivable on collateral securities....................... 1,065 --
Prepaid operating lease............................................ 12,668 --
Other current assets............................................... 8,395 5,491
---------- --------
Total current assets....................................... 171,187 56,230
Property, plant and equipment, net................................... 650,053 447,751
Investments in power projects........................................ 13,937 8,218
Collateral securities, net of current portion........................ 89,806 --
Notes receivable from related parties................................ 18,182 19,391
Notes receivable from Coperlasa...................................... 17,961 6,394
Restricted cash...................................................... 55,219 9,627
Other assets......................................................... 13,870 6,920
---------- --------
Total assets............................................... $1,030,215 $554,531
========== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current portion of non-recourse project financing.................. $ 30,627 $ 84,708
Notes payable and short-term borrowings............................ 6,865 1,177
Accounts payable................................................... 18,363 6,876
Accrued payroll and related expenses............................... 3,912 2,789
Accrued interest payable........................................... 7,332 7,050
Other accrued expenses............................................. 7,870 2,657
---------- --------
Total current liabilities.................................. 74,969 105,257
Long-term line of credit............................................. -- 19,851
Non-recourse project financing, net of current portion............... 278,640 190,642
Notes payable........................................................ -- 6,348
Senior Notes......................................................... 285,000 105,000
Deferred income taxes, net........................................... 100,385 97,621
Deferred lease incentive............................................. 78,521 --
Other liabilities.................................................... 9,573 4,585
---------- --------
Total liabilities.......................................... 827,088 529,304
---------- --------
Commitments and contingencies (Note 28)
Stockholders' equity
Common stock, $0.01 par value per share; authorized 100,000,000
shares in 1996 and 33,760,000 shares in 1995; issued and
outstanding 19,843,400 shares in 1996 and 10,387,693 shares in
1995............................................................ 20 10
Additional paid-in capital......................................... 165,412 6,214
Retained earnings.................................................. 37,726 19,034
Cumulative translation adjustment.................................. (31) (31)
---------- --------
Total stockholders' equity................................. 203,127 25,227
---------- --------
Total liabilities and stockholders' equity................. $1,030,215 $554,531
========== ========
The accompanying notes are an integral part of these consolidated financial
statements.
F-12
59
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
1996 1995 1994
-------- -------- -------
Revenue:
Electricity and steam sales........................... $199,464 $127,799 $90,295
Service contract revenue.............................. 6,455 7,153 7,221
Income (loss) from unconsolidated investments in power
projects........................................... 6,537 (2,854) (2,754)
Interest income on loans to power projects............ 2,098 -- --
-------- -------- -------
Total revenue................................. 214,554 132,098 94,762
-------- -------- -------
Cost of revenue:
Plant operating expenses.............................. 61,894 33,162 14,944
Depreciation.......................................... 39,818 26,264 21,202
Production royalties.................................. 10,793 10,574 11,153
Operating lease expense............................... 9,295 1,542 --
Service contract expenses............................. 7,400 5,846 5,546
-------- -------- -------
Total cost of revenue......................... 129,200 77,388 52,845
-------- -------- -------
Gross profit............................................ 85,354 54,710 41,917
Project development expenses............................ 3,867 3,087 1,784
General and administrative expenses..................... 14,696 8,937 7,323
Provision for write-off of project development costs.... -- -- 1,038
-------- -------- -------
Income from operations........................ 66,791 42,686 31,772
Other (income) expense:
Interest expense
Related party...................................... 894 1,663 375
Other.............................................. 44,400 30,491 23,511
Other income, net..................................... (6,259) (1,895) (1,988)
-------- -------- -------
Income before provision for income taxes........... 27,756 12,427 9,874
Provision for income taxes............................ 9,064 5,049 3,853
-------- -------- -------
Net income.................................... $ 18,692 $ 7,378 $ 6,021
======== ======== =======
Earnings per share:
Weighted average shares outstanding................... 14,680 -- --
======== ======== =======
Earnings per share.................................... $ 1.27 -- --
======== ======== =======
As adjusted earnings per share assuming conversion of
preferred stock:
Weighted average shares outstanding................... -- 14,151 --
======== ======== =======
Earnings per share.................................... -- $ 0.52 --
======== ======== =======
The accompanying notes are an integral part of these consolidated financial
statements.
F-13
60
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
(IN THOUSANDS)
PREFERRED STOCK COMMON STOCK ADDITIONAL CUMULATIVE
--------------- --------------- PAID-IN RETAINED TRANSLATION
SHARES AMOUNT SHARES AMOUNT CAPITAL EARNINGS ADJUSTMENT TOTAL
------ ------ ------ ------ ---------- -------- ---------- --------
Balance, December 31, 1993.............. -- $ -- 10,388 $ 10 $ 6,214 $ 7,235 $(31) $ 13,428
Dividend ($0.40 per share)............ -- -- -- -- -- (800) -- (800)
Net income............................ -- -- -- -- -- 6,021 -- 6,021
------ ---- ------ --- -------- ------- ---- --------
Balance, December 31, 1994.............. -- -- 10,388 10 6,214 12,456 (31) 18,649
Dividend ($0.40 per share)............ -- -- -- -- -- (800) -- (800)
Net income............................ -- -- -- -- -- 7,378 -- 7,378
------ ---- ------ --- -------- ------- ---- --------
Balance, December 31, 1995.............. -- -- 10,388 10 6,214 19,034 (31) 25,227
Issuance of preferred stock........... 5,000 50 -- -- 49,950 -- -- 50,000
Conversion of preferred stock to
common stock........................ (5,000) (50) 2,179 3 47 -- -- --
Issuance of common stock, net......... -- -- 7,276 7 109,172 -- -- 109,179
Tax benefit from stock options
exercised........................... -- -- -- -- 29 -- -- 29
Net income............................ -- -- -- -- -- 18,692 -- 18,692
------ ---- ------ --- -------- ------- ---- --------
Balance, December 31, 1996.............. -- $ -- 19,843 $ 20 $165,412 $37,726 $(31) $203,127
====== ==== ====== === ======== ======= ==== ========
The accompanying notes are an integral part of these consolidated financial
statements.
F-14
61
CALPLNE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
(IN THOUSANDS)
1996 1995 1994
--------- -------- --------
Cash flows from operating activities:
Net income................................................... $ 18,692 $ 7,378 $ 6,021
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization, net......................... 36,600 25,931 20,342
Deferred income taxes, net................................. 2,028 (1,027) 3,180
(Income) loss from unconsolidated investments in power
projects................................................ (5,263) 2,854 2,754
Provision for write-off of project development costs and
other................................................... -- -- 1,038
Change in operating assets and liabilities:
Accounts receivable..................................... (12,652) (3,354) (2,578)
Acquisition project receivables......................... 8,014 (8,805) --
Other current assets.................................... (6,521) (737) 79
Accounts payable and accrued expenses................... 15,636 6,847 6,218
Deferred revenue........................................ 3,347 (2,434) (2,858)
--------- -------- --------
Net cash provided by operating activities............. 59,881 26,653 34,196
--------- -------- --------
Cash flows from investing activities:
Acquisition of property, plant and equipment................. (24,057) (17,434) (7,023)
Acquisition of Greenleaf, net of cash on hand................ -- (14,830) --
Watsonville transaction, net of cash on hand................. -- 494 --
Acquisition of TPC, net of cash on hand...................... -- -- (62,770)
Loans to Coperlasa........................................... (12,926) (6,062) --
(Increase) decrease in notes receivable...................... 2,750 (286) (13,556)
Investment in collateral securities.......................... (98,446) -- --
King City transaction, net of cash on hand................... (11,567) -- --
Maturities of collateral securities.......................... 2,900 -- --
Acquisition of Gilroy, net of cash on hand................... (138,073) -- --
Capitalized project costs.................................... (5,887) (1,258) (175)
Decrease (increase) in restricted cash....................... (41,591) 1,186 (900)
Other, net................................................... 63 (307) (20)
--------- -------- --------
Net cash used in investing activities................. (326,834) (38,497) (84,444)
--------- -------- --------
Cash flows from financing activities:
Payment of dividends......................................... -- (800) (800)
Net borrowings from (repayments of) line of credit........... (19,851) 19,851 (52,595)
Borrowings from non-recourse project financing............... 119,760 76,026 60,000
Repayments of non-recourse project financing................. (84,708) (79,388) (12,735)
Proceeds from short-term borrowings.......................... 45,000 2,683 4,500
Repayments of short-term borrowings.......................... (46,177) (6,006) --
Proceeds from issuance of Senior Notes....................... 180,000 -- 105,000
Proceeds from issuance of preferred stock.................... 50,000 -- --
Proceeds from issuance of common stock....................... 109,208 -- --
Financing costs.............................................. (8,079) (1,239) (3,921)
Proceeds from note payable................................... -- -- 5,167
Repayment of notes payable -- FMRP........................... -- -- (36,807)
Other, net................................................... -- -- (1,200)
--------- -------- --------
Net cash provided by financing activities............. 345,153 11,127 66,609
--------- -------- --------
Net increase (decrease) in cash and cash equivalents........... 78,200 (717) 16,361
Cash and cash equivalents, beginning of period................. 21,810 22,527 6,166
--------- -------- --------
Cash and cash equivalents, end of period....................... $ 100,010 $ 21,810 $ 22,527
========= ======== ========
Supplementary information -- cash paid during the year for:
Interest..................................................... $ 43,805 $ 32,162 $ 19,890
Income taxes................................................. 6,947 4,294 683
The accompanying notes are an integral part of these consolidated financial
statements.
F-15
62
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
1. ORGANIZATION AND OPERATIONS OF THE COMPANY
Calpine Corporation ("Calpine"), a Delaware corporation, and subsidiaries
(collectively, the "Company") are engaged in the development, acquisition,
ownership and operation of power generation facilities in the United States and
selected international markets. The Company has ownership interests in and
operates geothermal steam fields, geothermal power generation facilities, and
natural gas-fired cogeneration facilities in northern California and Washington.
Each of the generation facilities produces electricity for sale to utilities.
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. For the year ended December 31,
1996, primarily all electricity and steam sales revenue from consolidated
subsidiaries was derived from sales to two customers in northern California (see
Note 27), of which 48% related to geothermal activities. In 1996, the Company
began marketing power and energy services to utilities and other end users.
In July 1996, the Company's Board of Directors authorized the
reincorporation of the Company into Delaware in connection with the Company's
initial public offering. In addition, the Board of Directors approved a stock
split of approximately 5.194-for-1. On September 13, 1996, the reincorporation
of the Company 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 (see Note 24).
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation -- The consolidated financial statements
include the accounts of Calpine Corporation and its wholly owned and
majority-owned subsidiaries. All significant intercompany accounts and
transactions are eliminated in consolidation. Prior to 1994, the Company
acquired Calpine Geysers Company, L.P. ("CGC"). During 1994, the Company formed
Calpine Thermal Power, Inc. ("Calpine Thermal") and Calpine Siskiyou Geothermal
Partners, L.P. (see Notes 4 and 7, respectively). Calpine Thermal acquired
Thermal Power Company ("TPC") during 1994. During 1995, the Company formed
Calpine Greenleaf Corporation ("Calpine Greenleaf"), Calpine Monterey
Cogeneration, Inc. ("CMCI") and Calpine Vapor, Inc. ("Calpine Vapor"). Calpine
Greenleaf indirectly acquired two operating gas-fired cogeneration plants (see
Note 5) and CMCI acquired an operating lease for a gas-fired cogeneration
facility (see Note 6). Calpine Vapor made loans to fund construction of new
geothermal wells in Mexico (see Note 8). During 1996, the Company formed Calpine
King City Cogen L.L.C. ("CKCC"), Calpine Gilroy Cogen, L.P. ("Gilroy"), and
Pasadena Cogeneration, L.P. CKCC completed an operating lease transaction for a
gas-fired cogeneration plant (see Note 9) and Calpine Gilroy acquired the assets
of a gas-fired cogeneration plant in California (see Note 10). In December 1996,
Pasadena Cogeneration entered into an energy sales agreement and will construct
a 240 megawatt gas-fired power plant (see Note 11).
Accounting for Jointly Owned Geothermal Properties -- The Company uses the
proportionate consolidation method to account for TPC's 25% interest in jointly
owned geothermal properties. TPC has a steam sales agreement with Pacific Gas
and Electric Company ("PG&E") pursuant to which the steam derived from its
interest in the properties is sold (see Note 4).
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
Note 7), the estimated "free steam" liability (see Note 3), receivables which
the Company believes to be collectible (see Note 15) and the realization of
deferred income taxes (see Note 21). Additionally, the Company believes that
certain industry restructuring
F-16
63
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(see Note 28, Regulation and CPUC Restructuring) will not have a material effect
on existing power service agreements ("PSA") 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 CGC were
entered into prior to May 1992. Had the Company applied this principle, the
revenues of the Company recorded for the years ended December 31, 1996, 1995 and
1994, would have been approximately $16.1 million, $12.6 million, and $11.9
million less, respectively.
The Company performs operations and maintenance services for all projects
in which it has an interest, except for TPC and the geothermal investment in
Mexico. Revenue from investees is recognized on these contracts when the
services are performed. Revenue from consolidated subsidiaries is eliminated in
consolidation.
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.
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 statements of
cash flows.
Investment in Collateral Securities -- The Company's investments in
collateral securities are related to the King City transaction (see Note 9) and
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 lease payment. 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, 1996 are as follows (in thousands):
UNREALIZED
AMORTIZED AGGREGATE HOLDING
COST FAIR VALUE GAINS
--------- ---------- ----------
Debt securities issued by the United
States.................................... $54,826 $ 56,737 $1,911
Corporate debt securities................... 40,450 40,499 49
------- ------- ------
$95,276 $ 97,236 $1,960
======= ======= ======
Concentration of Credit Risk -- Financial instruments which potentially
subject the Company to concentrations of credit risk consist primarily of cash
and accounts / notes receivable. The Company's cash accounts are held by eight
major financial institutions. The Company's accounts / notes receivable are
concentrated within entities engaged in the energy industry, mainly within the
United States, some of which are related parties. Certain of the Company's notes
receivable are with a company in Mexico (see Note 15).
Property, Plant and Equipment -- Property, plant and equipment are stated
at cost less accumulated depreciation and amortization.
F-17
64
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 Calpine Thermal. Proceeds
from the sale of geothermal properties are applied against capitalized costs,
with no gain or loss recognized.
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 thirty
years. The value of the above-market pricing provided in PSAs acquired is
recorded in property, plant and equipment and is amortized over the life of the
PSA or operating lease. 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 the results of operations.
As of December 31, 1996 and 1995, the components of property, plant and
equipment are as follows (in thousands):
1996 1995
-------- --------
Geothermal properties.................................. $297,002 $296,495
Buildings, machinery and equipment..................... 277,572 198,358
Power sales agreement.................................. 145,957 --
Miscellaneous assets................................... 11,287 2,425
-------- --------
731,818 497,278
Less accumulated depreciation and amortization......... 100,674 60,511
-------- --------
631,144 436,767
Land................................................... 754 754
Construction in progress............................... 18,155 10,230
-------- --------
Property, plant and equipment, net................... $650,053 $447,751
======== ========
Investments in Power Projects -- The Company accounts for its
unconsolidated investments in power projects under the equity method. The
Company's share of income from these investments is calculated according to the
Company's equity ownership or in accordance with the terms of the appropriate
partnership agreement (see Note 14).
Capitalized Project Costs -- The Company capitalizes project development
costs upon the execution of a memorandum of understanding or a letter of intent
for a power or steam sales agreement. These costs include
F-18
65
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 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.
Earnings Per Share and As Adjusted Earnings Per Share -- For the calendar
year ending after the Company's initial public offering in September 1996, net
income per share was computed using the weighted average number of common and
common equivalent shares using the treasury stock method for outstanding stock
options. Net income per share also gives effect to common equivalent shares from
convertible preferred shares from the original date of issuance that
automatically converted upon completion of the Company's initial public offering
(using the if-converted method).
For the year ended December 31, 1995, as adjusted net income per share was
computed using the weighted average number of common equivalent shares, which
includes the net additional number of shares which would be issuable upon the
exercise of outstanding stock options, assuming the Company used the proceeds
received to purchase additional shares at an assumed public offering price. Net
income per share also gives effect to common equivalent shares from preferred
stock that converted upon the closing of the Company's initial public offering
assuming such shares were outstanding from the beginning of the period in
accordance with Securities and Exchange Commission staff policy. Earnings per
share prior to 1995 have not been presented since such amounts are not deemed
meaningful due to the significant change in the Company's capital structure that
occurred in connection with its initial public offering.
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, 1996, CPSC held forward
sales and purchase contracts with notional quantities of approximately 724,000
megawatt hours and 631,600 megawatt hours, respectively.
Net open positions may exist due to the origination of new transactions and
the Company's evaluation of changing market conditions. The open position
exposes the Company to the risk that fluctuating market prices may adversely
impact its financial position or results of operations. However, the net open
position is actively managed. The impact of such fluctuations 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 currently for net
aggregate losses of the entire portfolio resulting from the effect of market
changes on the net open positions. Net gains are recognized when realized.
With respect to open power contracts, CPSC has established certain reserves
and allowances, principally for adverse changes in market conditions prior to
termination of the commitments. At December 31, 1996, the Company had recorded
allowances of approximately $917,000 which is included in Service contract
revenue in the accompanying consolidated statement of operations.
The Company's credit risk associated with power contracts results from the
risk of loss as a result of non-performance by counterparties. The Company
reviews and assesses counterparty risk to limit any material impact to its
financial position and results of operations. The Company does not anticipate
non-performance by the counterparties. The Company sets credit limits prior to
entering into transactions and has not obtained collateral or other security.
Impact of Recent Accounting Pronouncements -- In March 1995, the Financial
Accounting Standards Board ("FASB") issued Statement of Financial Accounting
Standards ("SFAS") No. 121, Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to be Disposed Of. This pronouncement requires that
long-lived assets and certain identifiable intangible assets be reviewed for
impairment whenever
F-19
66
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
events or changes in circumstances indicate that the carrying amount of an asset
may not be recoverable. An impairment loss is to be recognized when the sum of
undiscounted cash flows is less than the carrying amount of the asset.
Measurement of the loss for assets that the entity expects to hold and use are
to be based on the fair market value of the asset. The Company adopted SFAS No.
121 effective January 1, 1996, and determined that adoption of this
pronouncement had no material impact on the results of operations or financial
condition as of January 1, 1996.
In February 1997, the FASB issued SFAS No. 128, Earnings Per Share, which
simplifies the standards for computing earnings per share previously found in
Accounting Principles Board Opinion ("APBO") No. 15. SFAS No. 128 replaces the
presentation of primary earnings per share with a presentation of basic earnings
per share, which excludes dilution. SFAS No. 128 also requires dual presentation
of basic and diluted earnings per share on the face of the income statement for
all entities with complex capital structures and requires a reconciliation.
Diluted earnings per share is computed similarly to fully diluted earnings per
share pursuant to APBO No. 15. SFAS No. 128 must be adopted for financial
statements issued for periods ending after December 15, 1997, including interim
periods; earlier application is not permitted. SFAS No. 128 requires restatement
of all prior-period earnings per share data presented. The Company has not yet
quantified the effect of adopting SFAS No. 128.
Reclassifications -- Prior years' amounts in the consolidated financial
statements have been reclassified where necessary to conform to the 1996
presentation.
3. CALPINE GEYSERS COMPANY, L.P.
CGC, a wholly owned subsidiary of the Company, is the owner of two
operating geothermal power plants and their respective steam fields, Bear Canyon
and West Ford Flat, and three geothermal steam fields, which provide steam to
PG&E's Unit 13 and Unit 16 power plants and to Sacramento Municipal Utility
District's ("SMUD") geothermal power plant. The power plants and steam fields
are located in The Geysers area of northern California. Electricity from CGC's
two operating geothermal power plants is sold to PG&E under 20-year agreements.
Under the PG&E Unit 16 and the SMUD agreements, if the quantity of steam
delivered is less than 50% of the units' capacities, then neither PG&E nor SMUD
is required to make payment for steam delivered during such month until the cost
of the affected power plant has been completely amortized. Further, both PG&E
and SMUD can terminate their agreements with written notice under conditions
specified in the agreement if further operation of the plants becomes
uneconomical. In the event that CGC terminates the agreements, PG&E or SMUD may
require CGC to assign them all rights, title and interest to the wells, lands
and related facilities. In consideration for such an assignment to SMUD, SMUD
shall reimburse CGC for its original costs net of depreciation for any
associated materials or facilities.
CGC revenues from sales of steam were calculated considering a future
period when steam would be delivered without receiving corresponding revenue.
The estimated "free steam" obligation was recorded at an average rate over
future steam production as deferred revenue in 1993. As of December 31, 1993,
the Company had deferred revenue of $8.6 million. During 1994, based on
estimates and analyses performed, the Company determined that these deliveries
would no longer be required for a customer and reversed approximately $5.9
million of its deferred revenue liability. This reversal was recorded as a $1.9
million purchase price reduction to property, plant and equipment, with the
remaining $4.0 million as an increase in revenue. Concurrently, $800,000 of the
revenue increase was reserved for future construction of gathering systems
required for future production of the steam fields, with the offset recorded in
property, plant and equipment.
In October 1994, PG&E agreed to the termination of the free steam provision
for one of the geothermal steam fields. During 1995, CGC took additional
measures regarding future capital commitments and other
F-20
67
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
actions which will increase steam production and, based on additional analyses
and estimates performed, the Company recognized the remaining $2.7 million of
previously deferred revenue.
On April 19, 1993, the Company acquired Freeport-McMoRan Resource Partners,
L.P.'s ("FMRP") interest in CGC for $23.0 million in cash and non-recourse notes
payable to FMRP totaling $40.5 million. On February 17, 1994, the Company
exercised its option to prepay the notes utilizing a discount rate of 10% by
paying $36.9 million including interest in full satisfaction of its obligations
under the FMRP notes. The difference between the original carrying amount of the
notes and the prepayment was recorded as an adjustment to the purchase price.
4. CALPINE THERMAL POWER, INC.
On September 9, 1994, Calpine Thermal acquired the outstanding capital
stock of TPC for a total purchase price of $66.5 million, consisting of a $60.0
million cash payment and the issuance by Calpine of a non-interest bearing
promissory note to Natomas in the amount of $6.5 million (discounted to $5.2
million), which is due September 9, 1997. Calpine received payments of $3.0
million from the seller, which represented cash from TPC's operations for the
period from July 1, 1994 to September 8, 1994. These payments were treated as
purchase price adjustments.
Calpine Thermal owns a 25% undivided interest in certain producing
geothermal steam fields located at The Geysers area of northern California.
Union Oil Company of California owns the remaining 75% interest in the steam
fields, which deliver geothermal steam to twelve operating plants owned by PG&E.
The steam fields currently provide the twelve operating plants with sufficient
steam to generate approximately 604 megawatts of electricity.
Steam from Calpine Thermal's steam field is sold to PG&E under a steam
sales agreement. In addition, Calpine Thermal receives a monthly capacity
maintenance fee, which provides for effluent disposal costs and facilities
support costs, and a monthly fee for PG&E's right to curtail its power plants.
The steam price, capacity maintenance and curtailment fees are adjusted
annually. Calpine Thermal is required to compensate PG&E for the unused capacity
of its geothermal power plants due to insufficient field capacities of its steam
supply (offset payment).
In accordance with the steam sales agreement, PG&E may curtail the power
plants which receive steam from the Union Oil/Calpine Thermal Steam Fields in
order to produce energy from lower cost sources. However, PG&E is constrained by
its contractual obligation to operate all the power plants at a minimum of 40%
of the field capacity during any given year. During 1995 and 1996, Calpine
Thermal experienced extensive curtailments of steam production due to low gas
prices and abundant hydro power.
In March 1996, the Company 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 PG&E would
likely curtail under the existing steam sales agreement. The price for this
portion of steam will be set by the Company and Union Oil with the intent that
it be at competitive prices.
The steam sales agreement between Calpine Thermal and PG&E terminates two
years after the closing of the last PG&E operating unit. PG&E may terminate the
agreement upon a one-year written notice to Calpine Thermal. In the event the
agreement is terminated by PG&E, Calpine Thermal has the right to purchase
PG&E's facilities at PG&E's unamortized cost. Calpine Thermal will provide
capacity maintenance services for five years after termination by PG&E or
closure of the last PG&E operating unit. Alternatively, Calpine Thermal may
terminate the agreement upon a two-year written notice to PG&E. PG&E has the
right to take assignment of Calpine Thermal's facilities on the date of
termination. In such a case, Calpine Thermal would generally continue to pay
offset payments for 36 months following the date of termination.
F-21
68
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
5. CALPINE GREENLEAF CORPORATION
On April 21, 1995, Calpine Greenleaf 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.
The acquisition was accounted for as a purchase, and the purchase price has
been allocated to the acquired assets and liabilities based on their estimated
fair values. The adjusted allocation of the purchase price is as follows (in
thousands):
Current assets.................................................... $ 6,572
Property, plant and equipment..................................... 122,545
---------
Total assets................................................. 129,117
---------
Current liabilities............................................... (1,079)
Deferred income taxes, net........................................ (46,580)
---------
Total liabilities............................................... (47,659)
---------
Net purchase price................................................ $ 81,458
=========
The Acquired Companies own 100% of the assets of two 49.5 megawatt natural
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 PG&E
pursuant to two long-term PSAs (expiring in 2019) at prices equal to PG&E's full
short-run avoided operating costs, adjusted annually. The PSA 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. The thermal energy
generated is used by thermal hosts adjacent to the Greenleaf Power Plants.
Gas for the Greenleaf Power Plants is supplied by Montis Niger, Inc.
("MNI"). On January 31, 1997, the Company purchased MNI for $7.5 million.
6. CALPINE MONTEREY COGENERATION, INC.
On June 29, 1995, CMCI acquired a 14.5-year operating lease (through
December 2009) for a 28.5 megawatt natural gas-fired cogeneration power plant
located in Watsonville, California. The Company acquired the operating lease
from Ford Motor Credit Company for $900,000. The Watsonville Power Plant sells
electricity to PG&E under a 20-year PSA, generally at prices equal to PG&E's
full short-run avoided operating costs. Basic and contingent lease rental
payments are described in Note 26. The power plant also provides steam to two
local food processing plants. The Company also provides project and fuels
management services.
7. CALPINE SISKIYOU GEOTHERMAL PARTNERS, L.P.
In 1994, the Company formed a partnership with Trans-Pacific Geothermal
Corporation ("TGC") to build a geothermal power generation facility located at
Glass Mountain in northern California. TGC had previously signed a memorandum of
understanding ("MOU") with Bonneville Power Administration ("BPA") and the
Springfield, Oregon Utility Board ("SUB") to develop the project at Vale,
Oregon. BPA and SUB consented in August 1994 to the assignment of the MOU to the
partnership and the relocation of the project to Glass Mountain. The MOU
contemplated execution of a 45-year power purchase agreement subject to
satisfaction of certain conditions precedent and included an option for an
additional 100 megawatts. The partnership is consolidated as the Company owns a
controlling interest.
F-22
69
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In December 1996, the partnership and BPA entered into a settlement
agreement which restructured the rights and obligations of the parties. In
return for the payment of $12.0 million by BPA to the partnership and the grant
by the partnership to BPA of future options to purchase power at Glass Mountain,
the partnership and BPA terminated the MOU and certain ancillary agreements. In
addition, BPA will pay the partnership additional consideration should certain
future events occur related to the ongoing environmental review of the Glass
Mountain project. Following the settlement with BPA, TGC withdrew from the
partnership.
Of the $12.0 million received by the partnership in December 1996, $4.7
million was allocated to TGC, of which $3.0 million was received by the Company
in payment of a loan (see Note 15). Previously capitalized project costs were
charged to expense, and no significant gain or loss was included in net income
for the year 1996.
At December 31, 1996, the Company had $4.0 million of geothermal leases at
Glass Mountain recorded as Property, plant and equipment, net in the
accompanying consolidated balance sheet. 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.
8. CALPINE VAPOR, INC.
In November 1995, Calpine Vapor entered into agreements with Constructora y
Perforadora Latina, S.A. de C.V. ("Coperlasa") and certain Mexican bank lenders
to loan funds to Coperlasa in connection with a geothermal steam production
contract at the Cerro Prieto geothermal resource in Baja California, Mexico. 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. Calpine Vapor loaned
$18.5 million to Coperlasa, and received fees for technical services provided to
the project. At December 31, 1996, notes receivable (see Note 15) totaled $18.0
million. 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.
In December 1995, Calpine Vapor also paid $1.5 million for an option to
purchase an equity interest in Coperlasa. The option is being amortized over the
estimated repayment period of the Coperlasa loan and is included in Other
assets.
9. 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 natural
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 PSA through
2019 and provides steam to a vegetable processing plant.
The Company makes semi-annual lease payments to BAF on each February 15 and
August 15, a portion of which is supported by a $95.0 million collateral fund
owned by the Company. The collateral fund consists of investment grade and U.S.
Treasury Securities that mature serially in amounts equal to a portion of the
lease payment. The collateral fund securities are classified as held-to-maturity
investments (see Note 2). As of December 31, 1996, future rent payments are
$24.4 million for 1997, $23.8 million for 1998, $19.4 million for 1999, $20.1
million for 2000, $20.8 million for 2001, and $183.2 million thereafter.
Included in the accompanying December 31, 1996 balance sheet is approximately
$12.7 million of unamortized prepaid lease costs.
The Company recorded the value of the above-market pricing provided in the
PSA as an asset which is included in property, plant and equipment. The Company
has also recorded a deferred lease incentive of $78.5 million at December 31,
1996 equal to the value of the above-market payments to be received. The asset
and liability are being amortized over the life of the power sales agreement and
lease, respectively.
F-23
70
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
10. GILROY TRANSACTION
On August 29, 1996, the Company acquired a 120 megawatt natural 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. The Company recorded the value of the above-market
pricing provided in the PSA of $82.1 million as an asset which is included in
Property, plant and equipment.
Electricity generated by the Gilroy Power Plant is sold to PG&E pursuant to
a long-term PSA terminating in 2018. The PSA 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 transactions had occurred
on January 1, 1995 (in thousands, except per share amounts):
1996 1995
-------- --------
Revenue................................................ $237,924 $221,447
Net income............................................. $ 18,954 $ 11,288
Earnings per share..................................... $ 1.29 $ 0.80
11. PASADENA COGENERATION PROJECT
The Company 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. In December 1996, 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. The Company provided a $3.0 million letter of credit to
Phillips to secure the performance under the project development agreement. The
Company also entered into a credit agreement with ING U.S. Capital Corporation
to provide $98.6 million of non-recourse project financing. In accordance with
the credit agreement, the Company contributed $53.1 million in cash to the
project, of which the remaining $41.0 million is included in Restricted cash in
the accompanying consolidated balance sheet. The Company commenced construction
in February 1997, with commercial operation scheduled to begin in October 1998.
There can be no assurances that the Company will be successful in completing any
additional PSAs or that the anticipated schedule for construction will be met.
12. ACCOUNTS RECEIVABLE
At December 31, 1996, accounts receivable of $42.8 million included $1.9
million to be received from the Los Angeles Department of Water and Power for
reimbursement of costs related to the Coso development project incurred by the
Company in prior years. Such amount was received in 1997.
F-24
71
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Accounts receivable from related parties at December 31, 1996 and 1995
include the following (in thousands):
1996 1995
------ ------
O.L.S. Energy-Agnews, Inc.................................. $ 687 $ 806
Geothermal Energy Partners, Ltd. .......................... 350 462
Sumas Cogeneration Company, L.P............................ 590 908
Electrowatt Ltd. and subsidiaries.......................... 1,199 1
------ ------
$2,826 $2,177
====== ======
At December 31, 1996, the $1.2 million receivable from Electrowatt Ltd. was
for reimbursement of costs for the sale of Electrowatt's ownership of Calpine
common stock during the Company's initial public offering.
13. ACQUISITION PROJECT RECEIVABLES
In connection with an unsuccessful bid to acquire O'Brien Environmental
Energy, Inc. ("OEE") in 1995 through the U.S. Bankruptcy Court, the Company
incurred and capitalized project acquisition costs. On November 8, 1996, the
court denied Calpine's application for approval of such costs and fees and the
Company recorded a $3.7 million loss for unrecoverable amounts (included in
Other income, net in the accompanying consolidated statement of operations). The
Company is appealing the court's decision.
The Company also purchased $1.9 million of accounts receivable from two
subsidiaries of OEE. Payments were made to the Company based on cash
availability for each subsidiary. In February 1996, the Company received
approximately $1.1 million against these receivables.
The Company purchased for $900,000 from Stewart & Stevenson, Inc. ("S&S") a
participation interest in a $1.0 million note issued by OEE. The Company
received principal plus accrued interest in 1996.
The Company purchased all of S&S's rights and obligations in a Subordinated
Loan Agreement and Note between S&S and O'Brien (Newark) Cogeneration, Inc. The
purchase price was $2.8 million and the notes bore interest at prime plus 2.0%.
The Company received principal plus accrued interest in 1996.
14. INVESTMENTS IN POWER PROJECTS
The Company has unconsolidated investments in power projects which are
accounted for under the equity method. Financial information related to these
investments is as follows (in thousands):
SUMAS O.L.S. GEOTHERMAL
COGENERATION ENERGY- ENERGY
COMPANY, AGNEWS, PARTNERS,
L.P. INC. LTD.
------------ ------------ ------------
1996
Operating revenue.............................. $ 44,092 $ 11,023 $ 22,302
Net income (loss).............................. 8,494 (840) 6,367
Assets......................................... 129,273 37,160 69,249
Liabilities.................................... 125,652 36,711 38,304
Company's percentage ownership................. (a) 20% 5%
Equity investments in power projects........... 11,382 124 1,556
Project development costs...................... 875 -- --
-------- ------- -------
Total investments in power projects............ 12,257 124 1,556
======== ======= =======
Company's share of net income (loss)........... $ 6,396 $ (190) $ 331
======== ======= =======
F-25
72
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
SUMAS O.L.S. GEOTHERMAL
COGENERATION ENERGY- ENERGY
COMPANY, AGNEWS, PARTNERS,
L.P. INC. LTD.
------------ ------------ ------------
1995
Operating revenue.............................. $ 31,526 $ 10,779 $ 21,676
Net income (loss).............................. (6,098) (483) 5,538
Assets......................................... 122,802 40,330 76,017
Liabilities.................................... 123,377 39,034 51,439
Company's percentage ownership................. (a) 20% 5%
Equity investments in power projects........... 5,763 314 1,229
Project development costs...................... 912 -- --
-------- ------- -------
Total investments in power projects............ 6,675 314 1,229
======== ======= =======
Company's share of net income (loss)........... $ (3,049) $ (82) $ 227
======== ======= =======
SUMAS O.L.S. GEOTHERMAL
COGENERATION ENERGY- ENERGY
COMPANY, AGNEWS, PARTNERS,
L.P. INC. LTD.
------------ ------------ ------------
1994
Operating revenue.............................. $ 32,060 $ 11,985 $ 21,721
Net income (loss).............................. (5,777) (415) 5,548
Assets......................................... 130,148 42,596 77,081
Liabilities.................................... 124,625 40,864 58,041
Company's percentage ownership................. (a) 20% 5%
Equity investments in power projects........... 8,812 396 952
Project development costs...................... 946 8 --
-------- ------- -------
Total investments in power projects............ 9,758 404 952
======== ======= =======
Company's share of net income (loss)........... $ (2,888) $ (143) $ 277
======== ======= =======
- ---------------
(a) Distributions will be made out of operating income after certain required
deposits are made and certain minimum balances are met. After receiving
certain preferential distributions, the Company will have a 50% interest in
the profits and losses of Sumas until earning a 24.5% pre-tax cumulative
return on its investment, at which time the Company's interest in Sumas will
be reduced to 11.33%.
Sumas Cogeneration Company, L.P. -- Sumas Cogeneration Company, L P.
("Sumas") is a Delaware limited partnership formed between Sumas Energy, Inc.
("SEI"), a Washington State Subchapter S corporation, and Whatcom Cogeneration
Partners, L.P. ("Whatcom"), a wholly owned partnership of the Company. SEI is
the general partner and Whatcom is the limited partner. Sumas has a wholly owned
Canadian subsidiary, ENCO Gas, Ltd. ("ENCO"), which is incorporated in New
Brunswick, Canada.
Sumas owns and operates a 125 megawatt natural gas-fired cogeneration power
plant. In connection with the Sumas power plant is a lumber dry kiln facility
and a 3.5 mile private natural gas pipeline. ENCO acquired, developed and is
operating a portfolio of proven natural gas reserves in British Columbia and
Alberta, Canada to provide a dedicated fuel supply for the Sumas Power Plant.
Sumas produces and sells electrical energy to Puget Sound Power & Light
Company ("Puget") under a 20-year agreement for an average 123 megawatts. Sumas
leases the dry kiln facility and sells steam to Socco, Inc. ("Socco"), a custom
lumber drying operation owned by an affiliated individual.
F-26
73
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Construction financing was provided through a $95.2 million construction
and term loan agreement with The Prudential Insurance Company of America
("Prudential") and Credit Suisse, an affiliate of the Company. In addition, ENCO
has a $24.8 million loan agreement with Prudential and Credit Suisse. On May 25,
1993, the entire $120.0 million was converted to a term loan.
In addition, the Company provides operations and maintenance services to
Sumas and receives a fixed fee of $1.1 million per year adjusted annually for
inflation, an annual base fee of $150,000 per year also adjusted annually for
inflation and certain other reimbursable expenses. The Company is entitled to an
annual performance bonus of up to $400,000 based upon the achievement of certain
performance levels. This arrangement will expire upon the date Whatcom receives
its 24.5% pre-tax return or 10 years, subject to renewal terms, whichever is
later. The Company recorded revenue of approximately $2.0 million, $2.0 million,
and $1.9 million associated with this arrangement during the years ended
December 31, 1996, 1995 and 1994, respectively.
O.L.S. Energy-Agnews, Inc. -- The Company has a 20% interest in O.L.S.
Energy-Agnews, Inc., a joint venture with GATX Capital Corporation, which owns
and operates a 29 megawatt gas-fired combined-cycle cogeneration facility at the
State-owned Agnews Developmental Center ("Center") in San Jose, California. The
cogeneration plant provides the Center with all of its thermal and electric
requirements. Excess electricity is sold to PG&E under a Standard Offer No. 4
contract. The Company's original investment was $1.8 million.
In addition to its interest as stated above, the Company has been
contracted by the joint venture to provide operations and maintenance services
at cost plus overhead and fees, as specified. The Company recorded revenue of
$2.0 million, $1.5 million, and $1.4 million associated with this service
agreement and for other services provided to the joint venture for the years
ended December 31, 1996, 1995 and 1994, respectively.
In January 1990, O.L.S Energy-Agnews, Inc. entered into a credit agreement
with Credit Suisse providing for a $28.0 million loan. The loan is secured by
all of the assets of the Agnews Power Plant and bears interest on the unpaid
principal balance based on the London Interbank Offered Rate ("LIBOR") plus a
margin rate varying between 0.05% and 1.5%.
Geothermal Energy Partners, Ltd. -- During 1989, the Company acquired a 5%
interest in Geothermal Energy Partners Ltd. ("GEP"). GEP was established in 1988
to develop, finance and construct a 20 megawatt geothermal power production
facility located in The Geysers area of northern California. The facility began
operations on June 6, 1989.
In addition to its interest as stated above, the Company has been
contracted by GEP to provide operations and maintenance services at cost plus
overhead and fees, as specified. The Company recorded revenue of $4.0 million,
$3.5 million and $3.7 million associated with this service agreement to GEP for
the years ended December 31, 1996, 1995 and 1994, respectively.
The Company accounts for its investment in GEP under the equity method
because control of the project is deemed to be shared under the terms of the
partnership agreement, and the Company has significant influence over the
operation of the venture.
15. NOTES RECEIVABLE
In May 1993, in accordance with the Sumas partnership agreement, the
Company was entitled to receive a distribution of $1.5 million and 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 loan
bears interest at 20% and is secured by a security interest in the loan between
SEI and its sole shareholder. The Company will receive payments of 50% of SEI's
cash
F-27
74
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
distributions from Sumas. The payments will first reduce any accrued and unpaid
interest and then reduce the principal balance. On May 25, 2003, all unpaid
principal and interest is due.
In March 1994, the Company loaned $10.0 million to the sole shareholder of
SEI. The loan matures in 10 years and bears interest at 16.25%. The loan is
secured by a pledge to Calpine of SEI's interest in Sumas. In order to provide
for the payment of principal and interest on the loan, an additional 12 1/2% of
the cash flow generated by Sumas was assigned to Calpine. The Company deferred
the recognition of interest income from these notes until Sumas generated net
income. In 1996, the Company recognized a total of $2.1 million of interest
income related to the above two loans, which represents the portion of Sumas'
earnings not recognized by Calpine related to its equity investment in Sumas.
In August 1994, the Company entered into a loan agreement providing for
loans up to $4.8 million to Trans-Pacific Geothermal Glass Mountain Ltd.
("TGGM"), a subsidiary of TGC (see Note 7). The loan bore interest at 10% and
had a maturity date which was based on certain future events. The loan was
secured by a pledge to Calpine of the partner's interest in the Glass Mountain
project. The Company was deferring the recognition of income from this note
until the Glass Mountain project generated sufficient income to support the
collectibility of interest earned. At December 1, 1996, $4.1 million was
outstanding. In December 1996, the Company received $3.0 million from TGGM in
payment of the loan and recorded a $1.1 million loss for uncollectible amounts,
which was included in Other income, net (see Note 7).
As of December 31, 1996, Calpine Vapor had notes receivable of $18.0
million from Coperlasa and associated unamortized loan acquisition fees of $1.1
million (see Note 8). Interest accrues on the outstanding notes receivable at
approximately 18.9%. The Company is deferring the recognition of income from
this note until the Cerro Prieto project generates sufficient cash flows
available for distribution to support the collectibility of interest earned.
16. REVOLVING CREDIT FACILITY AND LINES OF CREDIT
At December 31, 1996, the Company had a $50.0 million three-year credit
facility available with a consortium of commercial lending institutions which
include The Bank of Nova Scotia, International Nederlanden U.S. Capital
Corporation, Sumitomo Bank of California and Canadian Imperial Bank of Commerce.
As of December 31, 1996, the Company had no borrowings and $5.9 million of
letters of credit outstanding, which reflect $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 or at
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, 1995, the Company had a $50.0 million credit facility with
Credit Suisse (whose parent company owns approximately 44.9% of Electrowatt Ltd.
("Electrowatt"), the former indirect sole owner of the Company prior to the
initial public offering on September 25, 1996). At December 31, 1995, the
Company had $19.9 million of borrowings outstanding, bearing interest at LIBOR
plus 0.5% (6.4% at December 31, 1995). Interest could be paid at either LIBOR or
the Credit Suisse base rate, plus applicable margins in both cases. The credit
agreement specified that the Company maintain certain covenants with which the
Company was in compliance. The Company terminated its Credit Suisse credit
facility on September 25, 1996.
At December 31, 1996, the Company had a loan facility with available
borrowings totaling $1.2 million. There were no borrowings and $900,000 of
letters of credit outstanding as of December 31, 1996. At December 31, 1995, the
Company had three loan facilities with available borrowings totaling $10.2
million.
F-28
75
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Borrowings and letters of credit outstanding were $1.2 million and $3.8 million
as of December 31, 1995, respectively. Interest is payable at variable interest
rates based on bank base rates, LIBOR or prime plus applicable margins in all
cases (approximately 7.6% at December 31, 1995 on borrowings). The credit
agreements specified that the Company maintain certain covenants with which the
Company was in compliance.
17. WORKING CAPITAL LOAN
The Company has a $5.0 million working capital loan agreement with a bank
providing for advances and letters of credit. The aggregate unpaid principal of
the working capital loan is payable in full at least once a year, with the final
payment of principal, interest and fees due June 30, 1998. Interest on
borrowings accrues at the option of the Company at either a base rate, LIBOR, or
a certificate of deposit rate (plus applicable margins in all cases) over the
term of the loan. No borrowings were outstanding at December 31, 1996 and 1995.
The Company had letters of credit outstanding of $459,000 at December 31, 1996
and 1995. Outstanding letters of credit bear interest at 0.625% payable
quarterly.
18. NON-RECOURSE PROJECT FINANCING
The components of non-recourse project financing as of December 31, 1996
and 1995 are (in thousands):
1996 1995
-------- --------
Senior-term loans:
Fixed rate portion................................... $ 73,000 $ 99,400
Variable rate portion................................ 20,000 20,000
Premium on debt...................................... 1,824 2,959
-------- --------
Total senior-term loans...................... 94,824 122,359
Junior-term loans...................................... 19,965 19,965
Notes payable to banks................................. 194,478 133,026
-------- --------
Total long-term debt......................... 309,267 275,350
Less current portion......................... 30,627 84,708
-------- --------
Long-term debt, less current portion......... $278,640 $190,642
======== ========
The Company entered into the Senior-Term Loans and Junior-Term Loans in
connection with the Company's acquisition of CGC in 1993.
Senior-Term Loans -- Principal and interest are payable in quarterly
installments at variable amounts with the final payment of principal, interest
and fees due June 30, 2002. A portion of the senior-term loans bears interest
fixed at 9.93% (see discussion on swap agreement below) with the remainder
accruing interest at LIBOR plus an applicable margin (6.75% and 6.69% at
December 31, 1996 and 1995, respectively) over the term of the loan,
collateralized by all of CGC's assets and the Company's interest in CGC. The
premium is amortized over the life of the fixed rate portion of the loan using
the interest method.
Junior-Term Loans -- Principal and interest are payable in quarterly
installments at variable amounts beginning September 30, 2002 with the final
payment of principal, interest and fees due June 30, 2005; interest accrues at
LIBOR plus an applicable margin (7.75% and 7.69% at December 31, 1996 and 1995,
respectively) over the term of the loan, collateralized by all of CGC's assets
and the Company's interest in CGC.
The Company entered into two interest rate swap agreements to minimize the
impact of changes in interest rates on a portion of its senior-term loans. These
agreements fix the interest on this portion at 9.93%. At December 31, 1996, the
swap agreements applied to debt with a principal balance total of $73.0 million.
The interest rate swap agreements mature through December 31, 2000. The premium
on debt was recorded in
F-29
76
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
conjunction with the acquisition as discussed above. The amortization of the
premium adjusts the effective interest rate on the fixed-rate debt to 7.05% per
annum. The floating interest rate associated with this portion of the
senior-term loans was LIBOR plus an applicable margin (6.63% at December 31,
1996 and 6.99% at December 31, 1995). The Company is exposed to credit risk in
the event of non-performance by the other parties to the swap agreements.
Notes Payable to Banks -- In September 1994, the Company entered into a
two-year agreement with The Bank of Nova Scotia to finance the acquisition of
TPC. In May 1996, a portion of the net proceeds from the Company's issuance of
the 10 1/2% Senior Notes Due 2006 was utilized to repay the total $57.0 million
of borrowings under this agreement.
In June 1995, the Company entered into an agreement with Sumitomo Bank to
finance the acquisition of the Greenleaf Power Plants. Of the $74.7 million debt
outstanding at December 31, 1996, $59.0 million bears interest fixed at 7.4%,
with the remaining floating rate portion accruing interest at LIBOR plus an
applicable margin (6.24% as of December 31, 1996). At December 31, 1995, $76.0
million of debt was outstanding, of which $60.0 million was at the fixed
interest rate of 7.4%, with the remaining floating rate portion accruing
interest at approximately 6.5%. This debt is secured by all of the assets of
Greenleaf 1 and 2. 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 $74.7 million debt will be
repaid quarterly, with a final maturity date of December 31, 2010.
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, 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. In addition, BNP provided two additional tranches for
the payment of certain contingent consideration, which at December 31, 1996
totaled $19.6 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% (see discussion below), with the remainder accruing interest at
LIBOR plus an applicable margin (6.6% at December 31, 1996). Interest on the
floating rate portion may be at BNP's base rate plus an applicable margin or at
LIBOR plus an applicable margin. Interest on base rate 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 $119.8 million debt will be repaid semi-annually beginning
August 31, 1997, 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 $87.5
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.
F-30
77
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The annual principal maturities of the non-recourse debt outstanding at
December 31, 1996 are as follows (in thousands):
1997.............................................. $ 30,627
1998.............................................. 32,658
1999.............................................. 24,183
2000.............................................. 24,851
2001.............................................. 24,631
Thereafter........................................ 170,493
--------
307,443
Unamortized premium on fixed portion of senior
loans........................................... 1,824
--------
Total................................... $309,267
========
The carrying value of $73.0 million and $99.4 million of the senior-term
loan as of December 31, 1996 and 1995, respectively, has an effective rate of
9.93% under the Company's interest rate swap agreements (7.05% after
consideration of the debt premium). Based on the borrowing rates currently
available to the Company for bank loans with similar terms and maturities, the
fair value of the debt as of December 31, 1996 and 1995 is approximately $83.2
million and $107.3 million, respectively. The carrying value of the remaining
$20.0 million of the senior-term and the $20.0 million junior-term loans and the
notes payable to banks approximate the debts' fair market value as the rates are
variable and based on the current LIBOR rate.
The non-recourse debt is held by subsidiaries of Calpine. 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.
On December 20, 1996, the Company entered into a credit agreement with ING
U.S. Capital Corporation to provide $98.6 million of non-recourse project
financing for the Pasadena Cogeneration Project (see Note 11). No borrowings
were outstanding at December 31, 1996. 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 no less 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.
19. 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 has been discounted to yield 8.0%
per annum, due September 9, 1997. The carrying amount of $6.2 million at
December 31, 1996 approximates fair market value.
In January 1995, the Company purchased the working interest covering
certain properties in its geothermal properties at CGC from Santa Fe Geothermal,
Inc. The purchase price included $6.0 million cash, and a $750,000 non-interest
bearing note discounted to yield 9% per annum and due on December 26, 1997. The
Company may repay all or any part of the note at any time without penalty. The
carrying value of $686,000 of the discounted non-interest bearing note at
December 31, 1996 approximates fair market value.
F-31
78
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
20. SENIOR NOTES
On May 16, 1996, the Company issued $180.0 million aggregate principal
amount of 10 1/2% Senior Notes Due 2006. The net proceeds of $174.9 million were
used to repay $53.7 million of borrowings under the Credit Suisse Credit
Facility, $57.0 million of non-recourse project financing and $45.0 million of
borrowings from The Bank of Nova Scotia. The remaining $19.2 million was
available for general corporate purposes. Transaction costs of $5.1 million
incurred in connection with the public debt offering were recorded as a deferred
charge and are amortized over the ten-year life of the 10 1/2% Senior Notes Due
2006.
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 $191.7 million as of December 31,
1996.
On February 17, 1994, the Company completed a $105.0 million public debt
offering of 9 1/4% Senior Notes Due 2004. Transaction costs of $4.1 million
incurred in connection with the public debt offering were recorded as a deferred
charge and are amortized over the ten-year life of the 9 1/4% Senior Notes Due
2004.
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 $105.7 million as of
December 31, 1996.
The Senior Note indentures specify that the Company maintain 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.
21. 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, 1996 and
1995 are (in thousands):
1996 1995
--------- ---------
Expenses deductible in a future period............... $ 3,329 $ 1,674
Net operating loss and credit carryforwards.......... 19,856 19,480
Other differences.................................... 1,186 2,034
--------- ---------
Deferred tax asset, before valuation allowance..... 24,371 23,188
Valuation allowance.................................. (692) (749)
--------- ---------
Deferred tax asset................................. 23,679 22,439
--------- ---------
Property differences................................. (119,842) (116,314)
Difference in taxable income and income from
investments recorded on the equity method.......... (2,753) (2,311)
Other differences.................................... (1,469) (1,435)
--------- ---------
Deferred tax liabilities........................... (124,064) (120,060)
--------- ---------
Net deferred tax liability...................... $(100,385) $ (97,621)
========= =========
F-32
79
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The net operating loss and credit carryforwards consist of Federal and
State net operating loss carryforwards which expire 2005 through 2010 and 2000,
respectively, and Federal and State alternative minimum tax credit carryforwards
which can be carried forward indefinitely. At December 31, 1996, the Federal and
State net operating loss carryforwards were approximately $23.8 million and
$12.0 million, respectively. At December 31, 1996, the State net operating
losses have been fully reserved for in the valuation allowance due to the
limited carryforward period allowed by the State of California. At December 31,
1996, Federal and State alternative minimum tax credit carryforwards were
approximately $6.7 million and $1.7 million, respectively.
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.
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 8.84% effective January 1, 1997.
The provision for income taxes for the years ended December 31, 1996, 1995
and 1994 consists of the following (in thousands):
1996 1995 1994
------ ------ ------
Current:
Federal........................................ $5,671 $3,085 $ 96
State.......................................... 1,805 1,163 365
Deferred:
Federal........................................ 3,890 816 2,546
State.......................................... (801) (15) 547
Adjustment in state tax rate................ (769) -- --
Revision in prior years' tax estimates...... (732) -- --
Increase in valuation allowance............. -- -- 299
------ ------ ------
Total provision........................ $9,064 $5,049 $3,853
====== ====== ======
The Company's effective rate for income taxes for the years ended December
31, 1996, 1995 and 1994 differs from the U.S. statutory rate, as reflected in
the following reconciliation.
1996 1995 1994
----- ----- -----
U.S. statutory tax rate............................. 35.0% 35.0% 35.0%
State income tax, net of Federal benefit............ 6.0 6.0 6.0
Depletion allowance................................. (2.3) (0.3) (8.6)
Effect of change in tax rates....................... (3.0) -- --
Revision in prior years' tax estimates.............. (2.6) -- --
Increase in valuation allowance..................... -- -- 7.8
Other, net.......................................... (0.4) (0.1) (1.2)
---- ---- ----
Effective income tax rate......................... 32.7% 40.6% 39.0%
==== ==== ====
F-33
80
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
22. 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 1996, 1995, and 1994 totaled $485,000, $350,000 and $311,000,
respectively.
23. PREFERRED STOCK
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
Company's initial public offering, all of the Series A Preferred Stock was
converted into approximately 2.2 million shares of common stock and sold to the
public in the offering by Electrowatt (see Note 24).
24. COMMON STOCK
In September 1996, Calpine completed the initial public offering of
18,045,000 shares of its common stock with $0.01 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 sold 12,567,180 shares of
common stock, representing its entire ownership interest in Calpine. As a result
of the Common Stock Offering, Electrowatt no longer owns any interest in
Calpine. 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. Approximately $13.0 million of total net proceeds was
used to repay short-term bank borrowings. The remaining net proceeds are for
working capital and general corporate purposes, and for the development and
acquisition of power generation facilities. 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 preferred stock into shares
of common stock.
25. STOCK-BASED COMPENSATION PROGRAMS
1996 Employee Stock Purchase Plan
The Company adopted 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. Shares are purchased
on February 28 and August 31 of each year. On the first purchase date of
February 28, 1997, employees purchased 25,819 shares of common stock at a
weighted average fair value of $13.60 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; such plan succeeded the Company's previously adopted stock option program.
The Company accounts for this plan under APB Opinion No. 25, under which no
compensation cost has been recognized in 1996. Had compensation cost for
F-34
81
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
this plan been determined consistent with SFAS No. 123, Accounting for
Stock-Based Compensation, the Company's net income and earning per share would
have been reduced to the following pro forma amounts (in thousands, except per
share amounts):
1996 1995
------- ------
Net income.................................. As reported $18,692 $7,378
Pro forma $18,145 $7,232
Primary earnings per share.................. As reported $ 1.27 --
Pro forma $ 1.24 --
As adjusted primary earnings per share
assuming conversion of preferred stock.... As reported -- $ 0.52
Pro forma -- $ 0.51
Because the SFAS No. 123 method 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 future years.
The Company may grant options for up to 4,041,858 shares under the SIP. As
of December 31, 1996, the Company had granted options to purchase 2,340,294
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.
A summary of the status of the Company's SIP at December 31, 1996 and
changes during the year then ended is presented in the table and narrative
below:
SHARES OF COMMON STOCK
--------------------------- WEIGHTED
AVAILABLE SIP AVERAGE
FOR OPTION OPTION EXERCISE
OR AWARD SHARES PRICE
------------- --------- --------
Balance, January 1, 1995.................. 1,160,782 1,436,141 $ 1.53
Granted................................. (444,333) 444,333 $ 4.91
Forfeited............................... 25,963 (25,963) $ 2.13
--------- -----
Balance, 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
Forfeited............................... 56,796 (56,796) $ 7.90
--------- -----
Balance, December 31, 1996................ 1,696,564 2,340,294 $ 3.69
========= =====
F-35
82
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table summarizes information concerning outstanding and
exercisable options at December 31, 1996:
OPTIONS OUTSTANDING
--------------------------- OPTIONS EXERCISABLE
WEIGHTED ------------------------
AVERAGE WEIGHTED
REMAINING AVERAGE
EXERCISE NUMBER CONTRACTUAL NUMBER EXERCISE
PRICES OUTSTANDING LIFE EXERCISABLE PRICE
--------------------------------------- ----------- ----------- ----------- --------
$ 0.50................................. 934,920 6.00 934,920 $ 0.50
$ 1.85................................. 174,193 6.25 174,193 $ 1.85
$ 4.57................................. 296,058 7.75 222,043 $ 4.57
$ 4.91................................. 434,290 8.97 104,590 $ 4.91
$ 8.57................................. 490,833 10.00 -- $ 8.57
$16.00................................. 10,000 9.99 10,000 $16.00
--------- --------- -----
2,340,294 1,445,746 $ 1.71
========= ========= =====
The estimated average fair value of options granted in 1995 and 1996 is
$1.23 and $3.29 on the date of grant using the Black-Scholes option pricing
model with the following weighted-average assumptions: risk-free interest rates
of 5.4% to 6.2%; expected dividend yields of zero percent; expected lives of 3
years; expected volatility of 0% to 27%.
26. RELATED PARTY TRANSACTIONS
In January 1995, the Company and Electrowatt entered into a management
services agreement whereby Electrowatt agreed to provide the Company with
advisory services in connection with the construction, financing, acquisition
and development of power projects, as well as any other advisory services as may
be required by the Company in connection with the operation of the Company.
Pursuant to this agreement, the Company paid $166,000 and $200,000 of such
management expenses in 1996 and 1995, respectively. The management services
agreement terminated September 25, 1996, with completion of the initial public
offering.
During 1996, 1995, and 1994, the Company paid $123,000, $106,000, and
$69,000, respectively, to Electrowatt pursuant to a guarantee fee agreement
whereby Electrowatt agreed to guarantee the payment, when due, of any and all
indebtedness of the Company to Credit Suisse in accordance with the terms and
conditions of the line of credit. Under the guarantee fee agreement, the Company
had agreed to pay to Electrowatt an annual fee equal to 1% of the average
outstanding balance of the Company's indebtedness to Credit Suisse during each
quarter as compensation for all services rendered under the guarantee fee
agreement. The guarantee fee agreement terminated in September 1996.
At December 31, 1996, the Company had approximately $1.2 million in
accounts receivable from Electrowatt (see Note 12) related to reimbursement of
costs for the sale of Electrowatt's common stock in Calpine. As a result of
Electrowatt's sale of Calpine common shares, Electrowatt no longer owns any
interest in Calpine.
F-36
83
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
27. SIGNIFICANT CUSTOMERS
The Company's electricity and steam sales revenue is primarily from two
sources -- PG&E and SMUD. Revenues earned from these sources for the years ended
December 31, 1996, 1995 and 1994 were as follows (in thousands):
1996 1995 1994
-------- -------- -------
PG&E........................................ $183,531 $112,522 $77,010
SMUD........................................ 14,609 12,345 9,296
Other....................................... 1,324 173 804
-------- -------- --------
199,464 125,040 87,110
Deferred revenues recognized (see Note 3)... -- 2,759 3,185
-------- -------- --------
Total electricity and steam sales........... $199,464 $127,799 $90,295
======== ======== ========
PG&E, the Company's primary customer, is also affected by industry
restructuring and deregulation (see Note 28 regarding Regulation and CPUC
Restructuring).
28. COMMITMENTS AND CONTINGENCIES
Capital Projects -- The Company has 1997 commitments for capital
expenditures totaling $4.0 million related to various projects at its geothermal
facilities. In March 1996, the Company entered into an energy development
agreement with Phillips Petroleum Company to develop, construct, own and operate
a 240 megawatt gas-fired cogeneration facility at Phillips Houston Chemical
Complex in Pasadena, Texas. The Company commenced construction in February 1997,
with commercial operation scheduled to begin in October 1998. The Company has
1997 commitments of $97.2 million related to this 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.
The Company also has working interest agreements with third parties
providing for the sharing of approximately 25% to 30% of drilling and other well
costs, various percentages of other operating costs and 25% to 30% of revenues
on specified wells.
Expenses under these agreements for the years ended December 31, 1996, 1995
and 1994 are (in thousands):
1996 1995 1994
------- ------- -------
Production royalties.......................... $10,793 $10,574 $11,153
Lease payments................................ $ 246 $ 225 $ 252
Natural Gas Purchases -- The Company enters into long-term gas purchase
contracts with third parties to supply gas to its gas-fired cogeneration
projects. Such contracts generally have terms of 1 to 24 months, and existing
contracts expire though July 31, 1997, continuing month to month thereafter
unless either party terminates the agreement upon sixty days written notice. On
January 31, 1997, the Company purchased MNI which supplies gas to the Greenleaf
Power Plants (see Note 5).
F-37
84
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Watsonville Operating Lease -- The Company is committed under an operating
lease (through December 2009) for a 28.5 megawatt natural gas-fired cogeneration
power plant located in Watsonville, California (see Note 6). 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, 1996, future basic rent payments
are $2.9 million for each year from 1997 to 2001, and $24.4 million thereafter
through December 2009. Contingent rent payments are 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.
Office and Equipment Leases -- The Company leases its corporate office,
Houston office, Portland office, Santa Rosa office facilities and certain office
equipment under noncancellable operating leases expiring through 2001. Future
minimum lease payments under these leases are (in thousands):
1997................................................ $1,138
1998................................................ 1,125
1999................................................ 977
2000................................................ 936
2001................................................ 367
Thereafter.......................................... --
------
Total future minimum lease commitments.............. $4,543
======
Lease payments are subject to adjustment for the Company's pro rata portion
of annual increases or decreases in building operating costs. In 1996, 1995 and
1994, rent expense for noncancellable operating leases amounted to $1,036,000,
$733,000 and $663,000, respectively.
Regulation and CPUC Restructuring -- Electricity and steam sales agreements
with PG&E are regulated by the CPUC. In December 1995, the CPUC proposed the
transition of the electric generation market to a competitive market beginning
January 1, 1998, with all consumers participating by 2003. Since the proposed
restructure results in widespread impact on the market structure and requires
participation and oversight of the Federal Energy Regulatory Commission
("FERC"), the CPUC has sought to build a California consensus involving the
legislature, the Governor, public and municipal utilities and customers. The
consensus has resulted in filings with FERC which should permit both the CPUC
and FERC to collectively proceed with implementation of the new competitive
market structure. On September 23, 1996 state legislation was passed, AB 1890
(the "Bill"), which codified much of the CPUC decision and directed the CPUC to
proceed with implementation of restructure no later than January 1, 1998. The
Bill accelerated the transition period to a fully competitive market from five
years to four years with all consumers participating by the year 2002. The Bill
provided for an electricity rate freeze for the period of transition and
mandated through issuance of rate reduction bonds a 10% rate reduction for small
commercial and residential customers effective January 1, 1998. The proposed
restructuring provides for phased-in customer choice (direct access),
development of a non-discriminatory market structure, full recovery of utility
stranded costs, sanctity of existing contracts, and continuation of existing
public policy programs including funds for enhancement of in-state renewable
energy technologies during the transition period. 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.
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 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
F-38
85
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
"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 PSA, 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 -- The Company, together with over 100 other parties, was named
as a defendant in an action brought in August 1993 by the bankruptcy trustee for
Bonneville Pacific Corporation ("Bonneville"), captioned Roger G. Segal, as the
Chapter 11 Trustee for Bonneville Pacific Corporation v. Portland General
Corporation, et al., in the United States District Court for the District of
Utah (the "Court"). In December 1996, the trustee and the Company entered into a
settlement agreement relating to this matter. The trustee has agreed to waive
all claims against the Company and to dismiss the trustee's litigation against
the Company in exchange for a payment of $767,500 by the Company.
The Company is involved in various other claims and legal actions arising
out of the normal course of business. Management does not expect that the
outcome of these cases will have a material adverse effect on the Company's
financial position or results of operations.
29. 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.
In the first quarter of 1996, the Company issued $50.0 million of preferred
stock to Electrowatt (see Note 23).
In the second quarter of 1996, the Company entered into an operating lease
for the King City Power Plant (see Note 9) and issued $180.0 million of 10 1/2%
Senior Notes Due 2006 (see Note 20).
In the third quarter of 1996, the Company acquired the Gilroy Power Plant
(see Note 10) and charged to earnings a $3.7 million uncollectible amount
associated with the attempt to acquire the O'Brien companies (see Note 13). The
Company also incurred an employee bonus expense of $1.4 million related to the
initial public offering of common stock in September 1996, and recorded a $1.8
million loss related to its electricity trading operations. In addition, the
Company decreased its deferred income taxes by $769,000 to reflect the change in
California's state income tax rate from 9.3% to 8.84% effective January 1, 1997.
In the fourth quarter of 1996, the Company recorded a $1.4 million net gain
related to the settlement of the Coso project, offset by a $767,500 expense
related to the settlement of certain litigation (see Note 28). In addition, the
Company revised its prior years' tax estimates by $700,000.
The Company's common stock has been traded on the New York stock exchange
beginning September 19, 1996. There were approximately 39 common stockholders of
record at December 31, 1996. No dividends have been paid to-date.
F-39
86
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
QUARTER ENDED
-----------------------------------------------
DECEMBER 31 SEPTEMBER 30 JUNE 30 MARCH 31
----------- ------------ ------- --------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
1996
Total revenue....................................... $61,663 $ 70,897 $50,321 $31,673
Income from operations.............................. $14,303 $ 29,097 $16,203 $ 7,188
Net income.......................................... $ 3,537 $ 10,732 $ 4,717 $ (294)
Earnings per common share........................... $ 0.17 $ 0.76 $ 0.35 $ (0.03)
Common stock price per share
High.............................................. $ 20.00 $ 16.38 -- --
Low............................................... $ 16.00 $ 16.00 -- --
1995
Total revenue....................................... $39,570 $ 42,176 $28,342 $22,010
Income from operations.............................. $11,473 $ 16,446 $ 8,195 $ 6,572
Net income.......................................... $ 2,115 $ 4,965 $ 239 $ 59
As adjusted earnings per common share assuming
conversion of preferred stock (see Note 2)........ $ 0.15 $ 0.35 $ 0.02 --
F-40
87
REPORT OF INDEPENDENT PUBLIC AUDITORS
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 March 7,
1997. 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
March 7 , 1997
F-41
88
CALPINE CORPORATION
SCHEDULE I
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
BALANCE SHEETS
DECEMBER 31, 1996 AND 1995
1996 1995
------------ ------------
ASSETS
Current assets:
Cash and cash equivalents..................................... $ 33,150,134 $ (1,970,526)
Accounts receivable........................................... 5,023,945 1,348,969
Accounts receivable from affiliates........................... 4,534,048 4,955,625
Acquisition project receivables............................... 791,206 8,805,186
Other current assets.......................................... 811,816 270,806
------------ ------------
Total current assets.................................. 44,311,149 13,410,060
Property, plant and equipment, net.............................. 5,711,074 724,359
Investments in power projects................................... 141,816,204 82,610,719
Intercompany receivables........................................ 302,230,313 48,323,629
Notes receivable from related parties........................... 18,182,372 19,390,952
Deferred charges................................................ 8,325,857 3,390,677
Other assets.................................................... 121,358 197,144
------------ ------------
Total assets.......................................... $520,698,327 $168,047,540
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable.............................................. $ 503,598 $ 2,667,808
Accrued payroll and related expenses.......................... 3,477,246 2,582,194
Accrued interest payable...................................... 6,461,875 4,051,785
Other accrued expenses........................................ 5,385,747 2,704,257
------------ ------------
Total current liabilities............................. 15,828,466 12,006,044
Long-term line of credit........................................ -- 14,000,000
Senior Notes.................................................... 285,000,000 105,000,000
Deferred income taxes........................................... 11,229,502 7,877,537
Deferred revenue................................................ 5,513,458 3,937,175
------------ ------------
Total liabilities..................................... 317,571,426 142,820,756
------------ ------------
Stockholders' equity:
Common stock, $0.01 par value................................. 19,843 20,000
Additional paid-in capital.................................... 165,412,455 6,204,000
Retained earnings............................................. 37,694,603 19,002,784
------------ ------------
Total stockholders' equity............................ 203,126,901 25,226,784
------------ ------------
Total liabilities and stockholders' equity............ $520,698,327 $168,047,540
============ ============
The accompanying notes are an integral part of these condensed financial
statements.
F-42
89
CALPINE CORPORATION
SCHEDULE I
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
1996 1995 1994
------------ ----------- -----------
Revenue:
Service contract revenue from related parties.... $ 36,581,736 $28,733,399 $22,929,897
Income from unconsolidated investments in power
projects...................................... 66,625,486 32,397,392 23,711,895
------------ ----------- -----------
Total revenue................................. 103,207,222 61,130,791 46,641,792
Cost of revenue:
Service contract expenses........................ 34,953,440 27,433,069 19,161,445
------------ ----------- -----------
Gross profit....................................... 68,253,782 33,697,722 27,480,347
Project development expenses....................... 3,866,828 3,087,316 2,822,459
General and administrative expenses................ 13,650,881 8,081,458 6,867,520
------------ ----------- -----------
Income from operations........................ 50,736,073 22,528,948 17,790,368
Other (income) expense:
Interest expense................................. 23,036,232 10,479,144 9,207,381
Other income, net................................ (56,420) (377,276) (1,290,739)
------------ ----------- -----------
Income before provision for income taxes...... 27,756,261 12,427,080 9,873,726
Provision for income taxes......................... 9,064,445 5,049,568 3,853,115
------------ ----------- -----------
Net income.................................... $ 18,691,816 $ 7,377,512 $ 6,020,611
============ =========== ===========
Primary earnings per share
Weighted average number of shares outstanding.... 14,679,984 -- --
============ =========== ===========
Earnings per share............................... $ 1.27 -- --
============ =========== ===========
As adjusted primary earnings per share, assuming
Weighted average number of shares outstanding.... -- 14,150,837 --
============ =========== ===========
Earnings per share............................... -- $ 0.52 --
============ =========== ===========
The accompanying notes are an integral part of these condensed financial
statements.
F-43
90
CALPINE CORPORATION
SCHEDULE I
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
1996 1995 1994
------------- ----------- ------------
Net cash used in operating activities............ $(281,904,648) $(8,874,945) $(44,753,732)
------------- ------------ ------------
Cash flows from investing activities:
Acquisition of property, plant and equipment... (5,320,508) (367,711) (299,961)
Investments in power projects.................. -- (1,262,000) (175,352)
Decrease (increase) in notes receivable, net... 2,750,000 (10,336,640) 3,294,727
Other, net..................................... 75,786 (122,244) 97,838
------------- ------------ ------------
Net cash provided by (used in) investing
activities..................................... (2,494,722) (12,088,595) 2,917,252
------------- ------------ ------------
Cash flows from financing activities:
Payment of dividends........................... -- (800,000) (800,000)
Borrowings under line of credit................ 46,861,000 14,000,000 --
Repayment of borrowings under line of credit... (60,861,000) -- (52,595,000)
Proceeds from Senior Notes Due 2004............ -- -- 105,000,000
Proceeds from Senior Notes Due 2006............ 180,000,000 -- --
Proceeds from issuance of preferred stock...... 50,000,000 -- --
Proceeds from issuance of common stock......... 109,208,298 -- --
Costs associated with future financing......... (5,688,268) 279,012 (3,419,003)
Repayment of note payable to shareholder....... -- -- (1,200,000)
------------- ------------ ------------
Net cash provided by financing
activities........................... 319,520,030 13,479,012 46,985,997
------------- ------------ ------------
Net increase (decrease) in cash and cash
equivalents.................................... 35,120,660 (7,484,528) 5,149,517
Cash and cash equivalents, beginning of period... (1,970,526) 5,514,002 364,485
------------- ------------ ------------
Cash and cash equivalents, end of period......... $ 33,150,134 $(1,970,526) $ 5,514,002
============= ============ ============
Supplementary information:
Cash paid during the period for:
Interest....................................... $ 19,762,029 $ 9,945,443 $ 4,917,773
Income taxes................................... $ 6,947,000 $ 4,293,725 $ 683,364
The accompanying notes are an integral part of these condensed financial
statements.
F-44
91
CALPINE CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS
DECEMBER 31, 1996
1. ORGANIZATION AND OPERATION OF CALPINE
Calpine Corporation ("Calpine") is a Delaware corporation 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 into 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. On September 13, 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.
2. LINES OF CREDIT AND REVOLVING CREDIT FACILITY
At December 31, 1996, Calpine had a $50.0 million three-year credit
facility available with a consortium of commercial lending institutions which
include The Bank of Nova Scotia, International Nederlanden U.S. Capital
Corporation, Sumitomo Bank of California and Canadian Imperial Bank of Commerce.
As of December 31, 1996, the Company had no borrowings and $5.9 million of
letters of credit outstanding, which reflect $3.0 million to secure performance
with the Pasadena Power Plant and $2.9 million related to operating expenses at
a subsidiary. Borrowings bear interest at The Bank of Nova Scotia's base rate or
at 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 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, 1995, Calpine had a $50.0 million credit facility with
Credit Suisse (whose parent company owns approximately 44.9% of Electrowatt Ltd.
("Electrowatt"), the former indirect sole owner of Calpine prior to the initial
public offering on September 25, 1996. At December 31, 1995, Calpine had $19.9
million of borrowings outstanding, bearing interest at LIBOR plus 0.5% (6.4% at
December 31, 1995). Interest was payable at either LIBOR or the Credit Suisse
base rate, plus applicable margins in both cases. The credit agreement specified
that Calpine maintain certain covenants with which Calpine was in compliance.
Calpine terminated its Credit Suisse credit facility on September 25, 1996.
At December 31, 1996, Calpine had one loan facility with available
borrowings totaling $1.2 million. There were no borrowings and 900,000 of
letters of credit outstanding as of December 31, 1996. At December 31, 1995,
Calpine had three loan facilities with available borrowings totaling $10.2
million. Borrowings and letters of credit outstanding were $1.2 million and $3.8
million as of December 31, 1995, respectively. Interest is payable at variable
interest rates based on bank base rates, LIBOR or prime plus applicable margins
in all cases (approximately 7.6% at December 31, 1995 on borrowings). The credit
agreements specified that Calpine maintain certain covenants with which Calpine
was in compliance.
3. NOTE PAYABLE TO ELECTROWATT
On December 31, 1991, Calpine declared a dividend of $1.2 million to its
parent company, Electrowatt Services, Inc. On the same date, Calpine issued a
note payable to Electrowatt Services, Inc. for $1.2 million.
F-45
92
CALPINE CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS -- (CONTINUED)
Interest was paid quarterly at a rate of 4.25%, which approximated market. The
note was paid on June 30, 1994, the maturity date.
4. SENIOR NOTES
On May 16, 1996, the Company issued $180.0 million aggregate principal
amount of 10 1/2% Senior Notes Due 2006. The net proceeds of $174.9 million were
used to repay $53.7 million of borrowings under the Credit Suisse Credit
Facility, $57.0 million of non-recourse project financing and $45.0 million of
borrowings from The Bank of Nova Scotia. The remaining $19.2 million was
available for general corporate purposes. Transaction costs of $5.1 million
incurred in connection with the public debt offering were recorded as a deferred
charge and are amortized over the ten-year life of the 10 1/2% Senior Notes Due
2006.
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 $191.7 million as of December 31,
1996.
On February 17, 1994, Calpine completed a $105.0 million public debt
offering of 9 1/4% Senior Notes Due 2004. Transaction costs of $4.1 million
incurred in connection with the public debt offering were recorded as a deferred
charge and are amortized over the ten-year life of the 9 1/4% Senior Notes Due
2004.
The 9 1/4% Senior Notes Due 2004 will mature on February 1, 2004. Calpine
has no sinking fund or mandatory redemption obligations with respect to the
9 1/4% Senior Notes Due 2006. 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 $105.7 million as of December 31,
1996.
The Senior Note indentures specify that Calpine maintain certain covenants
with which Calpine was in compliance. Calpine 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.
5. COMMITMENTS AND CONTINGENCIES
Capital Projects -- Calpine has 1997 commitments for capital expenditures
totaling $4.0 million related to various projects at its geothermal facilities.
In March 1996, Calpine entered into an energy development agreement with
Phillips Petroleum Company to develop, construct, own and operate a 240 megawatt
gas-fired cogeneration facility at Phillips Houston Chemical Complex in
Pasadena, Texas. The initial permitting process is underway, with construction
of the facility planned to begin in late 1996 and to be completed in 1998.
Calpine has 1997 commitments of $97.2 million related to this project.
Office and Equipment Leases -- Calpine leases its corporate office, Houston
office, Portland office, Santa Rosa office facilities and certain office
equipment under noncancellable operating leases expiring through 2001. Future
minimum lease payments under these leases are (in thousands):
1997.............................................. $1,138
1998.............................................. 1,125
1999.............................................. 977
2000.............................................. 936
2001.............................................. 367
Thereafter........................................ --
------
Total future minimum lease commitments............ $4,543
======
F-46
93
CALPINE CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS -- (CONTINUED)
Lease payments are subject to adjustment for Calpine's pro rata portion of
annual increases or decreases in building operating costs. In 1996, 1995 and
1994, rent expense for noncancellable operating leases amounted to $1,036,000,
$733,000 and $663,000, 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 proposed the transition of the electric generation
market to a competitive market beginning January 1, 1998, with all consumers
participating by 2003. Since the proposed restructure results in widespread
impact on the market structure and requires participation and oversight of the
Federal Energy Regulatory Commission ("FERC"), the CPUC has sought to build a
California consensus involving the legislature, the Governor, public and
municipal utilities and customers. The consensus has resulted in filings with
FERC which should permit both the CPUC and FERC to collectively proceed with
implementation of the new competitive market structure. On September 23, 1996
state legislation was passed, AB 1890 ("the Bill"), which codified much of the
CPUC decision and directed the CPUC to proceed with implementation of
restructure no later than January 1, 1998. The Bill accelerated the transition
period to a fully competitive market from five years to four years with all
consumers participating by year 2002. The Bill provided for an electricity rate
freeze for the period of transition and mandated through issuance of rate
reduction bonds a 10% rate reduction for small commercial and residential
customers effective January 1, 1998. The proposed restructuring provides for
phased-in customer choice (direct access), development of a non-discriminatory
market structure, full recovery of utility stranded costs, sanctity of existing
contracts, and continuation of existing public policy programs including funds
for enhancement of in-state renewable energy technologies during the transition
period. Calpine cannot predict the final form or timing of the proposed
restructuring and the impact, if any, that such restructuring would have on
Calpine's existing business or results of operations. Calpine 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.
A domestic electricity generating project must be a qualified 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 ("PUHPA"), 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
PSA, 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 -- Calpine, together with over 100 other parties, was named as a
defendant in an action brought in August 1993 by the bankruptcy trustee for
Bonneville Pacific Corporation ("Bonneville"), captioned Roger G. Segal, as the
Chapter 11 Trustee for Bonneville Pacific Corporation v. Portland General
Corporation, et al., in the United States District Court for the District of
Utah (the "Court"). In December 1996, the trustee and Calpine entered into a
settlement agreement relating to this matter. The trustee has agreed to waive
all claims against Calpine and to dismiss the trustee's litigation against
Calpine in exchange for a payment of $767,500 by Calpine.
Calpine is involved in various other claims and legal actions arising out
of the normal course of business. Management does not expect that the outcome of
these cases will have a material adverse effect on Calpine's financial position
or results of operations.
F-47
94
CALPINE CORPORATION
VALUATION AND QUALIFYING ACCOUNTS
SCHEDULE II
(IN THOUSANDS)
FOR THE YEAR ENDED DECEMBER 31, 1996
ADDITIONS
-------------------------------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD
- -------------------------------------------- ---------- ---------- ---------- ---------- ----------
Reserve for capitalized costs............... $1,838 $ -- $ -- $ -- $1,838(1)
Allowance for uncollectible accounts........ $ 238 -- -- -- $ 238
====== ====== ====== ====== ======
FOR THE YEAR ENDED DECEMBER 31, 1995
ADDITIONS
-------------------------------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD
- -------------------------------------------- ---------- ---------- ---------- ---------- ----------
Reserve for capitalized costs............... $1,838 $ -- $ -- $ -- $1,838(1)
Allowance for uncollectible accounts........ $ 238 -- -- -- $ 238
====== ====== ====== ====== ======
FOR THE YEAR ENDED DECEMBER 31, 1994
ADDITIONS
-------------------------------------------------
BALANCE AT CHARGED TO CHARGED TO BALANCE AT
BEGINNING COSTS AND OTHER END OF
DESCRIPTION OF PERIOD EXPENSES ACCOUNTS DEDUCTIONS PERIOD
- -------------------------------------------- ---------- ---------- ---------- ---------- ----------
Reserve for capitalized costs............... $ 800 $1,038 $ -- $ -- $1,838(1)
Allowance for uncollectible accounts........ $ -- 238 -- -- $ 238
====== ====== ====== ====== ======
- ---------------
(1) Provision for write-off of project development expenses.
F-48
95
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, 1996 and 1995, and
the related consolidated statements of income, changes in partners' equity, and
cash flows for each of the three years ended December 31, 1996. 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, 1996 and 1995, and
the results of their operations and cash flows for each of the three years ended
December 31, 1996, in conformity with generally accepted accounting principles.
MOSS ADAMS LLP
Everett, Washington
January 24, 1997
F-49
96
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
CONSOLIDATED BALANCE SHEET
DECEMBER 31,
-------------------------------
1996 1995
------------ ------------
ASSETS
Current assets
Cash and cash equivalents................................... $ 317,196 $ 199,169
Current portion of restricted cash and cash equivalents..... 5,787,121 2,937,884
Accounts receivable......................................... 4,605,135 3,090,213
Prepaid expenses............................................ 220,130 222,828
------------ ------------
Total current assets................................ 10,929,582 6,450,094
Restricted cash and cash equivalents, net of current
portion..................................................... 15,666,647 8,017,758
Property, plant and equipment, at cost, net................... 91,737,933 95,589,737
Other assets.................................................. 10,938,732 12,744,480
------------ ------------
Total assets........................................ $129,272,894 $122,802,069
============ ============
LIABILITIES AND PARTNERS' EQUITY
Current liabilities
Accounts payable and accrued liabilities.................... $ 2,988,207 $ 2,051,178
Related party distributions and payables
Calpine Corporation payable.............................. 476,390 4,864
National Energy Systems Company payable.................. 1,490 1,861
Whatcom Cogeneration Partners, L.P. distribution......... 3,517,491 --
Current portion of long-term debt........................... 3,600,000 2,000,000
------------ ------------
Total current liabilities........................... 10,583,578 4,057,903
Related party payable -- Calpine Corporation, net of current
portion..................................................... -- 908,679
Long-term debt, net of current portion........................ 113,400,003 117,000,003
Future removal and site restoration costs..................... 679,600 502,600
Deferred income taxes......................................... 988,400 907,800
Commitments................................................... -- --
Partners' equity (deficit).................................... 3,621,313 (574,916)
------------ ------------
Total liabilities and partners' equity.............. $129,272,894 $122,802,069
============ ============
The accompanying notes are an integral part of these consolidated financial
statements.
F-50
97
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
CONSOLIDATED STATEMENT OF INCOME
YEAR ENDED DECEMBER 31,
----------------------------------------------
1996 1995 1994
------------ ------------ ------------
Revenues
Power sales.................................... $ 43,488,465 $ 30,603,018 $ 29,206,469
Natural gas sales, net......................... 434,611 893,690 2,832,668
Other.......................................... 169,146 29,146 20,490
------------ ------------ ------------
Total revenues......................... 44,092,222 31,525,854 32,059,627
------------ ------------ ------------
Costs and expenses
Operating and production costs................. 16,852,253 18,493,245 19,032,754
Depletion, depreciation and amortization....... 5,702,310 6,965,496 6,715,156
General and administrative..................... 2,481,470 1,400,129 1,412,326
------------ ------------ ------------
Total costs and expenses............... 25,036,033 26,858,870 27,160,236
------------ ------------ ------------
Income from operations........................... 19,056,189 4,666,984 4,899,391
------------ ------------ ------------
Other income (expense)
Interest income................................ 406,537 490,071 436,741
Interest expense............................... (10,678,618) (11,006,056) (10,172,959)
Other expense.................................. (133,958) (60,664) (359,000)
------------ ------------ ------------
Total other expense.................... (10,406,039) (10,576,649) (10,095,218)
------------ ------------ ------------
Income (loss) before provision for income
taxes.......................................... 8,650,150 (5,909,665) (5,195,827)
Provision for income taxes....................... (155,951) (188,387) (581,190)
------------ ------------ ------------
Net income (loss)...................... $ 8,494,199 $ (6,098,052) $ (5,777,017)
============ ============ ============
The accompanying notes are an integral part of these consolidated financial
statements.
F-51
98
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
Partners' Equity, December 31, 1993........................................... $11,300,153
Net loss...................................................................... (5,777,017)
-----------
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
===========
The accompanying notes are an integral part of these consolidated financial
statements.
F-52
99
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
CONSOLIDATED STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31,
--------------------------------------------
1996 1995 1994
------------ ----------- -----------
Cash flows from operating activities
Net income (loss)................................ $ 8,494,199 $(6,098,052) $(5,777,017)
Adjustments to reconcile net income (loss) to net
cash from operating activities
Depletion, depreciation and amortization...... 6,571,522 6,965,496 6,715,156
Deferred income taxes......................... 80,600 134,000 532,400
Change in operating assets and liabilities
Accounts receivable......................... (1,514,922) 1,017,993 (1,254,639)
Prepaid expenses............................ 2,698 9,497 (30,342)
Accounts payable and accrued liabilities.... 1,114,029 (1,407,621) 1,081,431
Related party distributions and payables.... (437,524) 425,479 132,296
------------ ----------- -----------
Net cash from operating activities....... 14,310,602 1,046,792 1,399,285
------------ ----------- -----------
Cash flows from investing activities
Decrease (increase) in restricted cash and cash
equivalents................................... (10,498,126) 2,908,466 2,922,819
Acquisition of property, plant and equipment..... (913,970) (3,710,025) (3,690,399)
Other assets..................................... -- -- (167,483)
------------ ----------- -----------
Net cash from investing activities....... (11,412,096) (801,559) (935,063)
------------ ----------- -----------
Cash flows from financing activities
Repayment of long-term debt...................... (2,000,000) (400,000) (400,025)
Distributions to partners........................ (780,479) -- --
------------ ----------- -----------
Net cash from financing activities....... (2,780,479) (400,000) (400,025)
------------ ----------- -----------
Net increase (decrease) in cash and cash
equivalents...................................... 118,027 (154,767) 64,197
Cash and cash equivalents, beginning of year....... 199,169 353,936 289,739
------------ ----------- -----------
Cash and cash equivalents, end of year............. $ 317,196 $ 199,169 $ 353,936
============ =========== ===========
Supplementary disclosure of cash flow information
Cash paid for interest during the year........... $ 10,678,618 $11,006,056 $10,172,959
============ =========== ===========
The accompanying notes are an integral part of these consolidated financial
statements.
F-53
100
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1996, 1995 AND 1994
NOTE 1 -- ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(a) GENERAL -- Sumas Cogeneration Company, L.P. (the Partnership) is a
Delaware limited partnership formed on August 28, 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. The Partnership agreement specifies that certain preferential
distributions are paid to SEI and Whatcom. 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 has acquired and is operating and developing a portfolio of proven
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
incidental 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 Power & Light Company (Puget) under a 20-year electricity sales contract.
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 megawatt hours of electricity to
Puget as follows:
MEGAWATT
YEAR ENDED DECEMBER 31, HOURS REVENUE
---------------------------------------------------- --------- -----------
1996................................................ 1,031,900 $43,488,000
1995................................................ 1,026,000 $30,603,000
1994................................................ 1,000,400 $29,206,000
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 (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.
(b) 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. SEI and Whatcom are both currently entitled to a 50%
interest in the profits and losses of the Partnership, after the payment of
certain preferential distributions to Whatcom of approximately $2,756,000 and
$6,239,000 at December 31, 1996 and 1995, respectively, and to SEI of
approximately $536,000 and $441,000 at December 31, 1996 and 1995, respectively.
A portion of these preferential distributions compound at 20% per annum. After
Whatcom has received cumulative distributions representing a fixed
rate-of-return of 24.5% on its equity investment, exclusive of the preferential
distributions referred to above, SEI's share of operating distributions will
increase to 88.67% and Whatcom's share of operating distributions will decrease
to 11.33%.
F-54
101
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(c) 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,
1996, distributions totaling $4,297,970 were paid or accrued. As of January 31,
1997, the accrued balance of $3,517,491 of distributions were paid. No
distributions were paid or accrued for the years ended December 31, 1995 and
1994.
(d) REVENUE RECOGNITION -- Revenue from the sale of electricity is
recognized based on kilowatt hours generated and delivered to Puget at
contractual rates. 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.
(e) 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 method include estimated
future costs of dismantlement and abandonments of $3,718,000 in 1996, $3,748,000
in 1995 and $3,630,000 in 1994. 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
$177,000 in 1996, $193,000 in 1995 and $169,000 in 1994 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%.
(f) JOINT VENTURE ACCOUNTING -- Substantially all 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.
(g) 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.
(h) 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,
excluding restricted cash and cash equivalents.
(i) 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
F-55
102
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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.
(j) 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.
(k) AMORTIZATION OF OTHER ASSETS -- The Company provides for amortization
of other assets using the straight-line method as follows:
Organization, start-up and development costs..... 5-30 years
Financing costs.................................. 15 years
Gas contract costs............................... 20 years
(l) INCOME TAXES -- Profits or losses of the Partnership are passed
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.
(m) 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.
NOTE 2 -- PROPERTY, PLANT AND EQUIPMENT
DECEMBER 31,
-----------------------------
1996 1995
------------ ------------
Land and land improvements...................... $ 381,071 $ 381,071
Plant and equipment............................. 84,152,257 84,061,359
Acquisition of gas properties, including
development thereon........................... 25,838,035 25,030,165
Furniture and fixtures.......................... 211,116 195,914
------------ ------------
110,582,479 109,668,509
Less accumulated depreciation and depletion..... 18,844,546 14,078,772
------------ ------------
$ 91,737,933 $ 95,589,737
============ ============
Depreciation expense was $3,159,774 in 1996, $3,316,748 in 1995 and
$3,069,446 in 1994. Depletion expense was $1,606,000 in 1996, $1,843,000 in 1995
and $1,671,000 in 1994.
F-56
103
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 3 -- OTHER ASSETS
DECEMBER 31,
---------------------------
1996 1995
----------- -----------
Organization, start-up and development costs...... $ 4,844,015 $ 6,165,574
Financing costs................................... 3,909,886 4,254,719
Gas contract costs................................ 2,184,831 2,324,187
----------- -----------
$10,938,732 $12,744,480
=========== ===========
NOTE 4 -- LONG-TERM DEBT
The Partnership and ENCO have loan agreements with The Prudential Insurance
Company of America (Prudential) and Credit Suisse (collectively, the Lenders).
Through September 1996, Credit Suisse was an affiliate of Whatcom. At December
31, 1996 and 1995, amounts outstanding under the term loan agreements, by
entity, were as follows:
DECEMBER 31,
-----------------------------
1996 1995
------------ ------------
Sumas Cogeneration Company, L.P................. $ 92,781,003 $ 94,367,003
ENCO Gas, Ltd................................... 24,219,000 24,633,000
------------ ------------
117,000,003 119,000,003
Less current portion............................ 3,600,000 2,000,000
------------ ------------
$113,400,003 $117,000,003
============ ============
Scheduled annual principal payments under the loan agreements as of
December 31, 1996 are as follows:
YEAR ENDING DECEMBER 31, AMOUNT
--------------------------------------------------------------- ------------
1997........................................................... $ 3,600,000
1998........................................................... 4,200,000
1999........................................................... 5,400,000
2000........................................................... 7,200,000
2001........................................................... 10,800,000
Thereafter..................................................... 85,800,003
------------
$117,000,003
============
The Partnership's loan is 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 quarterly 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 2.25% to .875%
as stated in the loan agreement. During the year ended December 31, 1996,
interest rates on the variable rate loan ranged from 6.94% to 7.38%. The loans
mature in May 2008.
ENCO's loan is 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 quarterly at either the LIBOR,
certificate of deposit rate or Credit Suisse's base rate, plus an applicable
margin as stated in the loan agreement. During the year ended December 31, 1996,
interest rates on the variable rate loan ranged from 6.94% to 7.38%. The loans
mature in May 2008.
F-57
104
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Partnership pays Prudential an agency fee of $50,000 per year, adjusted
annually by an inflation index, 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.
NOTE 5 -- INCOME TAXES
The provision for income taxes represents Canadian taxes which consist of
the following:
YEAR ENDED DECEMBER 31,
----------------------------------
1996 1995 1994
-------- -------- --------
Current
Federal large corporation tax.................... $ 41,340 $ 34,625 $ 31,314
British Columbia capital taxes................... 34,011 19,762 17,476
-------- -------- --------
75,351 54,387 48,790
Deferred........................................... 79,744 135,400 178,400
-------- -------- --------
155,095 189,787 227,190
Utilization of loss carryforwards for Canadian
income tax purposes.............................. -- 47,700 259,000
Reduction of (increase in) Canadian loss
carryforwards due to foreign exchange and other
adjustments...................................... 856 (49,100) 95,000
-------- -------- --------
$155,951 $188,387 $581,190
======== ======== ========
The principal sources of temporary differences resulting in deferred tax
assets and liabilities are as follows:
DECEMBER 31,
-------------------------
1996 1995
---------- ----------
Deferred tax asset
Canadian net operating loss carryforwards......... $ (919,400) $ (840,900)
Deferred tax liabilities
Acquisition and development costs of gas deducted
for tax purposes in excess of amounts deducted
for financial reporting purposes............... 1,907,800 1,748,700
---------- ----------
Net deferred tax liability..................... $ 988,400 $ 907,800
========== ==========
F-58
105
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The provision for income taxes differs from the Canadian statutory rate
principally due to the following:
YEAR ENDED DECEMBER 31,
----------------------------------
1996 1995 1994
-------- -------- --------
Canadian statutory rate............................ 44.62% 44.62% 44.34%
Income taxes based on statutory rate............... $(45,824) $(33,852) $ 82,909
Capital taxes, net of deductible portion........... 60,175 47,028 36,678
Non-deductible provincial royalties, net of
resource allowance............................... 123,464 95,671 39,836
Depletion on gas properties with no tax basis...... 36,488 44,641 38,420
Foreign exchange adjustments....................... 16,362 14,860 29,347
Other.............................................. (35,570) 21,439 --
-------- -------- --------
$155,095 $189,787 $227,190
======== ======== ========
As of December 31, 1996, ENCO has non-capital loss carryforwards of
approximately $2,061,000, which may be applied against taxable income of future
periods which expire as follows:
1999............................................. $1,619,000
2000............................................. $ 260,000
2003............................................. $ 182,000
NOTE 6 -- RELATED PARTY TRANSACTIONS AND COMMITMENTS
(a) 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 $311,000 in 1996, $258,000 in 1995 and
$253,000 in 1994 was paid to SEI under this agreement.
(b) 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 anniversary of the Project completion date,
subject to renewal terms. Approximately $2,014,000 in 1996, $2,031,000 in 1995
and $1,946,000 in 1994 was earned under this agreement.
(c) 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, $19,000 in 1995 and $61,000 in 1994.
(d) 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 $107,000 in 1996, $100,000 in 1995 and
$101,000 in 1994 was paid under this agreement.
F-59
106
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(e) 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 gas supply agreements with Westcoast Gas Services, Inc.
(WGSI) to provide the Partnership with quantities of firm gas. Commencing April
1, 1993, WGSI must provide the Partnership with quantities of gas ranging from
10,000 MMBtu's per day up to 12,900 MMBtu's per day at a firm price, as provided
under the agreements. Deliveries under the agreement are expected to terminate
on October 31, 1997.
The Partnership and ENCO have a gas management agreement with WGSI. WGSI is
paid a gas management fee for each MMBtu of gas delivered. 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.
ENCO is committed to the utilization of pipeline capacity on the Westcoast
Energy Inc. System. These firm capacity commitments are predominantly under
one-year renewable contracts. Firm capacity has been accepted at an annual cost
of approximately $3,526,000 in 1996, $2,569,000 in 1995 and $2,776,000 in 1994.
As collateral for the obligations of the Company under the gas supply and
gas management agreements with WGSI, the Partnership secured an irrevocable
standby letter of credit with Credit Suisse in favor of WGSI. In January 1996,
the face amount of the letter of credit was reduced, in accordance with its
terms, from $2,500,000 to $500,000. Accordingly, the required balance in the
cash collateral account supporting the letter of credit was reduced from
$2,500,000 to $500,000. As of December 31, 1996, the letter of credit had a face
amount of $500,000 and the Partnership had a restricted cash deposit of
$500,000. As of December 31, 1995, the letter of credit had a face amount of
$2,500,000 and the Partnership had a restricted cash deposit of $2,500,000.
(f) UTILITY SERVICES -- The Partnership entered into an agreement for
utility services with the City of Sumas, Washington. The City of Sumas has
agreed to provide a guaranteed annual 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.
The Partnership entered into 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 received a permit for waste water disposal from the
Washington State Department of Ecology which expires June 30, 2000.
(g) 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 $56,600 in 1996 and $48,400 in 1995
and 1994.
In April 1992, ENCO signed an operating lease for office space which
expires in March 1997. Monthly rental expense is approximately $1,700. Rental
expense was approximately $20,400 in 1996, $17,700 in 1995 and $17,000 in 1994.
F-60
107
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Future minimum land and office lease commitments as of December 31, 1996
are as follows:
YEAR ENDING DECEMBER 31, AMOUNT
----------------------------------------------------------------- ----------
1997............................................................. $ 51,000
1998............................................................. 49,300
1999............................................................. 49,300
2000............................................................. 52,500
2001............................................................. 55,700
Thereafter....................................................... 812,600
----------
$1,070,400
==========
(h) PARTNER LOAN -- In March 1994, the sole shareholder of SEI borrowed
$10,000,000 from Calpine. The loan bears interest at 16.25%, compounded
quarterly, and is collateralized by a subordinated assignment in SEI's interest
in the Partnership and a subordinated pledge of SEI's stock. The loan requires
payments of interest and principal to be made from 50% of SEI's cash
distributions from the Partnership, less amounts due to Whatcom under a previous
note. On March 15, 2004, all unpaid principal and interest on the loan is due.
NOTE 7 -- FAIR VALUES OF FINANCIAL INSTRUMENTS
The carrying amount of all cash and cash equivalents 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 long-term debt
with a carrying amount of $117,000,003 and $119,000,003 at December 31, 1996 and
1995, 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-61
108
EXHIBIT 11
CALPINE CORPORATION AND SUBSIDIARIES
CALCULATION OF EARNINGS PER SHARE
(AMOUNTS IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
FOR YEAR ENDING
DECEMBER 31,
-------------------
1996 1995
------- -------
Net income............................................................... $18,692 $ 7,378
======= =======
Primary earnings per share
Average number of common shares outstanding............................ 12,293
Conversion of preferred stock.......................................... 1,700
Common shares issuable upon exercise of stock options using the
treasury method..................................................... 687
-------
14,680
-------
Primary earnings per share.......................................... $ 1.27
=======
Fully diluted earnings per share
Average number of common shares outstanding............................ 12,293
Conversion of preferred stock.......................................... 1,700
Common shares issuable upon exercise of stock options using the
treasury method..................................................... 1,137
-------
15,130
-------
Fully diluted earnings per share.................................... $ 1.24
=======
As adjusted primary earnings per share assuming conversion of preferred
stock
Average number of common shares outstanding............................ 10,388
Assumed conversion of preferred stock.................................. 2,179
Common shares issuable upon exercise of stock options using the
treasury method..................................................... 1,584
-------
14,151
-------
As adjusted primary earnings per share.............................. $ 0.52
=======
109
EXHIBIT INDEX
EXHIBIT NO. DESCRIPTION
- ----------- --------------------------------------------------------------------------------
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.
10.3.11 Amended and Restated Energy Sales Agreement, dated December 16, 1996, between
Phillips Petroleum Company and Pasadena Cogeneration, L.P.
27 Financial Data Schedule