<PAGE> 1
Filed Pursuant to Rule 424(b)(4)
Registration Statement No. 333-07497
LOGO
18,045,000 Shares
Calpine Corporation
Common Stock
($.001 par value)
------------------
Of the shares of Common Stock, $.001 par value ("Common Stock"), of Calpine
Corporation (the "Company" or "Calpine") offered hereby, 5,477,820 shares are
being sold by the Company and 12,567,180 shares are being sold by the
Selling Stockholder named herein under "Principal and Selling
Stockholders." Of the 18,045,000 shares of Common Stock being offered,
14,436,000 shares are initially being offered in the United States
and Canada (the "U.S. Shares") by the U.S. Underwriters (the "U.S.
Offering") and 3,609,000 shares are initially being concurrently
offered outside the United States and Canada (the "International
Shares") by the Managers (the "International Offering" and,
together with the U.S. Offering, the "Common Stock Offering").
The offering price and underwriting discounts and commissions
of the U.S. Offering and the International Offering are
identical.
Prior to the Common Stock Offering, there has been no public market for the
Common Stock. For information
relating to the factors considered in determining the initial
public offering price
to the public, see "Underwriting."
The Common Stock has been approved for listing on the New York Stock Exchange
under the symbol "CPN,"
subject to notice of issuance.
------------------
FOR A DISCUSSION OF CERTAIN FACTORS THAT SHOULD BE CONSIDERED IN CONNECTION WITH
AN INVESTMENT
IN THE COMMON STOCK, SEE "RISK FACTORS" BEGINNING ON PAGE 8 HEREIN.
------------------
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR
HAS THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE
SECURITIES COMMISSION PASSED UPON THE ACCURACY OR AD-
EQUACY OF THIS PROSPECTUS. ANY REPRESENTATION
TO THE CONTRARY IS A CRIMINAL
OFFENSE.
<TABLE>
<S> <C> <C> <C> <C>
Underwriting Proceeds to
Price to Discounts and Proceeds to Selling
Public Commissions Calpine(1) Stockholder(1)
---------------- ---------------- ---------------- ----------------
Per Share...................... $16.00 $.90 $15.10 $15.10
Total(2)....................... $288,720,000 $16,240,500 $82,715,082 $189,764,418
</TABLE>
(1) Before deduction of expenses payable by Calpine and the Selling Stockholder,
estimated at $1.5 million.
(2) The Company has granted the U.S. Underwriters and the Managers an option,
exercisable by CS First Boston Corporation for 30 days from the date of this
Prospectus, to purchase a maximum of 2,706,750 additional shares to cover
over-allotments of shares. If the option is exercised in full, the total
Price to Public will be $332,028,000, Underwriting Discounts and Commissions
will be $18,676,575, Proceeds to Calpine will be $123,587,007 and Proceeds
to Selling Stockholder will be $189,764,418.
------------------
The U.S. Shares are offered by the several U.S. Underwriters when, as and if
delivered to and accepted by the U.S. Underwriters and subject to their right to
reject orders in whole or in part. It is expected that the U.S. Shares will be
ready for delivery on or about September 25, 1996, against payment in
immediately available funds.
CS First Boston
Morgan Stanley & Co.
Incorporated
PaineWebber Incorporated
Salomon Brothers Inc
The date of this Prospectus is September 19, 1996.
<PAGE> 2
IN CONNECTION WITH THE COMMON STOCK OFFERING, CS FIRST BOSTON CORPORATION
ON BEHALF OF THE U.S. UNDERWRITERS AND MANAGERS MAY OVER-ALLOT OR EFFECT
TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICE OF THE COMMON STOCK AT
A LEVEL ABOVE THAT WHICH MIGHT OTHERWISE PREVAIL IN THE OPEN MARKET. SUCH
TRANSACTIONS MAY BE EFFECTED ON THE NEW YORK STOCK EXCHANGE OR OTHERWISE. SUCH
STABILIZING, IF COMMENCED, MAY BE DISCONTINUED AT ANY TIME.
DURING THE COMMON STOCK OFFERING, CERTAIN PERSONS AFFILIATED WITH PERSONS
PARTICIPATING IN THE DISTRIBUTION MAY ENGAGE IN TRANSACTIONS FOR THEIR OWN
ACCOUNTS OR FOR THE ACCOUNTS OF OTHERS IN THE COMMON STOCK PURSUANT TO
EXEMPTIONS FROM RULES 10B-6, 10B-7, AND 10B-8 UNDER THE SECURITIES EXCHANGE ACT
OF 1934.
<PAGE> 3
PROSPECTUS SUMMARY
The following summary is qualified in its entirety by the more detailed
information and financial statements appearing elsewhere in this Prospectus.
This Prospectus contains forward-looking statements that involve risks and
uncertainties. The Company's actual results could differ materially from those
projected in such forward-looking statements as a result of certain factors,
including those set forth under "Risk Factors" and elsewhere in this Prospectus.
Unless the context indicates otherwise, (i) all references in this Prospectus to
the "Company" or "Calpine" include Calpine Corporation and its consolidated
subsidiaries, (ii) all references to "Common Stock" refer to the Company's
Common Stock, $.001 par value, (iii) all information in this Prospectus relating
to the Company's Common Stock assumes no exercise of the Underwriters'
over-allotment option, and (iv) all information in this Prospectus assumes the
following transactions are completed prior to or concurrent with the
consummation of the Common Stock Offering: (1) the reincorporation of the
Company in Delaware, (2) the conversion of the Company's outstanding Class B
Common Stock into Common Stock and the elimination of the Class A Common Stock
and Class B Common Stock, (3) a 5.194-for-1 stock split of the Company's Common
Stock, and (4) the conversion of the Company's outstanding Preferred Stock into
2,179,487 shares of Common Stock.
THE COMPANY
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
1,057 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 $41.2 million of total assets as of December 31,
1991 to $911.0 million of total assets on a pro forma basis as of June 30, 1996.
Calpine's revenue on a pro forma basis for 1995 increased to $224.3 million,
representing a compound annual growth rate of 55% since 1991. The Company's
EBITDA (as defined herein) on a pro forma basis for 1995 increased to $123.8
million. See "Pro Forma Consolidated 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 power generation facilities, as well
as marketing power and energy services to utilities and other end users.
THE MARKET
The power generation industry represents the third largest industry in the
United States, with an estimated end user market of approximately $207.5 billion
of electricity sales and 3 million gigawatt hours of production in 1995. In
response to increasing customer demand for access to low cost electricity and
enhanced services, new regulatory initiatives are currently being adopted or
considered at both state and federal levels to increase competition in the
domestic power generation industry. To date, such initiatives are under
consideration at the federal level and in approximately thirty states. For
example, in April 1996, the Federal Energy Regulatory Commission ("FERC")
adopted Order No. 888, opening wholesale power sales to competition and
providing for open and fair electric transmission services by public utilities.
In addition, the California Public Utilities Commission ("CPUC") has issued an
electric industry restructuring decision which envisions commencement of
deregulation and implementation of customer choice of electricity supplier by
January 1, 1998. Calpine believes that industry trends and such regulatory
initiatives will lead to the transformation of the existing market, which is
largely characterized by electric utility monopolies selling to a captive
customer base, to a more competitive market where end users may purchase
electricity from a variety of suppliers, including non-utility generators, power
marketers, public utilities and others. The Company believes that these market
trends will create substantial opportunities for companies such as Calpine that
are low cost power producers and have an integrated power services capability
which enables them to produce and sell energy to customers at competitive rates.
The Company also believes that these market trends will result in the
disposition of power generation facilities by utilities, independent power
producers and industrial companies. Utilities such as Pacific Gas & Electric
Company ("PG&E") and Southern California Edison Company have announced their
intentions to sell power generation facilities totalling approximately 3,150
megawatts and 5,000 megawatts, respectively. The independent power industry,
which represents approximately 8% of the installed capacity in the United
States, or approximately 59,000 megawatts, and has accounted for approximately
50% of all additional capacity in the United States since 1990, is currently
undergoing significant consolidation. Many independent producers operating a
limited number of power plants are seeking to dispose of such plants in response
to
3
<PAGE> 4
competitive pressures, and industrial companies are selling their power plants
to redeploy capital in their core businesses. Over 200 independent power plant
and portfolio sale transactions have occurred in the past two years. The Company
believes that this consolidation will continue in the highly fragmented
independent power industry.
The power generation industry outside the United States is approximately
three times larger than the domestic market, and the demand for electricity is
growing rapidly. In 1996, it has been estimated that in excess of 590 gigawatts
of new capacity will be required outside the United States over the ensuing
ten-year period. In order to satisfy this anticipated increase in demand, many
countries have adopted active government programs designed to encourage private
investment in power generation facilities. The Company believes that these
market trends will create significant opportunities to acquire and develop power
generation facilities in such countries.
STRATEGY
Calpine's objective is to become a leading power company by capitalizing on
these emerging opportunities in the domestic and international power markets.
The key elements of the Company's strategy are as follows:
Expand and diversify 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
since 1993.
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 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 completion of financing and
obtaining required approvals. See "Business -- 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 in excess 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
has established an integrated power marketing capability, conducted through its
wholly owned subsidiary, Calpine Power Services Company ("CPSC"). In 1995, CPSC
received approval from the 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
an investment in 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
4
<PAGE> 5
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.
BACKGROUND
Calpine was founded in 1984 by Peter Cartwright, the Company's President
and Chief Executive Officer. Through 1988, the Company provided engineering,
management, finance and operating and maintenance services to the emerging
independent power production industry. Since 1989, the Company has focused on
the acquisition, development, ownership, operation and maintenance of gas-fired
and geothermal power generation facilities. Prior to the Common Stock Offering,
the Company has been a wholly owned subsidiary of Electrowatt Ltd.
("Electrowatt"), a major utility, industrial products and engineering services
company based in Zurich, Switzerland. Electrowatt has advised the Company that
its current strategy is to focus its resources on its industrial business. As a
result of the Common Stock Offering, Electrowatt will no longer own any interest
in the Company and Calpine management will hold stock options representing
approximately 11.7% of the Company's Common Stock.
Calpine was incorporated under the laws of the State of California in 1984
and was reincorporated in the State of Delaware in September 1996. The principal
executive offices of the Company are located at 50 West San Fernando Street, San
Jose, California 95113, and its telephone number is (408) 995-5115.
RISK FACTORS
Prospective investors should carefully consider the information presented
in this Prospectus, particularly the matters set forth under the caption "Risk
Factors."
THE COMMON STOCK OFFERING
Of the Common Stock offered hereby, 14,436,000 shares are initially being
offered in the United States and Canada by the U.S. Underwriters in the U.S.
Offering and 3,609,000 shares are initially being concurrently offered outside
the United States and Canada by the Managers in the International Offering.
<TABLE>
<S> <C>
Total Common Stock offered................... 18,045,000 shares
By the Company
U.S. Offering........................... 4,382,256 shares
International Offering.................. 1,095,564 shares
Total.............................. 5,477,820 shares
By the Selling Stockholder
U.S. Offering........................... 10,053,744 shares
International Offering.................. 2,513,436 shares
Total.............................. 12,567,180 shares
Common Stock to be outstanding after
the Common Stock Offering.................. 18,045,000 shares(1)
Use of proceeds.............................. The net proceeds of the sale of shares of
Common Stock by the Company will be used for
repayment of approximately $13.0 million of
outstanding indebtedness and for working
capital and general corporate purposes,
including the development and acquisition
of power generation facilities. See "Use of
Proceeds."
NYSE trading symbol.......................... CPN
</TABLE>
- ---------------
(1) Excludes 2,392,026 shares of Common Stock reserved for issuance upon
exercise of options previously granted and outstanding as of June 30, 1996
under the Company's Stock Option Program. Of such amount, options to
purchase 1,366,696 shares were exercisable as of June 30, 1996. See
"Management -- Stock Option Program" and "-- 1996 Stock Incentive Plan."
5
<PAGE> 6
SUMMARY CONSOLIDATED FINANCIAL DATA
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, SIX MONTHS ENDED JUNE 30,
------------------------------------------------------------------------ --------------------------------------
1991 1992 1993 1994 1995 1995 1996
--------- --------- --------- --------- ------------------------ --------- -------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
PRO FORMA(1)
ACTUAL ------------ ACTUAL PRO FORMA(2)
--------- --------- -------------
(DOLLARS AND SHARES IN THOUSANDS, EXCEPT PER SHARE DATA)
STATEMENT OF
OPERATIONS
DATA:
Total
revenue.... $39,052 $39,577 $69,915 $94,762 $132,098 $224,261 $50,352 $81,994 $93,068
Cost of
revenue.... 25,064 25,921 42,501 52,845 77,388 142,298 30,618 51,319 65,940
Gross
profit..... 13,988 13,656 27,414 41,917 54,710 81,963 19,734 30,675 27,128
Project
development
expenses... 1,067 806 1,280 1,784 3,087 3,087 1,308 1,410 1,410
General and
administrative
expenses... 3,443 3,924 5,080 7,323 8,937 8,937 3,659 5,874 5,874
Income from
operations... 9,478 6,902 21,054 31,772 42,686 69,939 14,767 23,391 19,844
Interest
expense.... 1,925 1,225 13,825 23,886 32,154 57,523 15,116 18,665 27,900
Other income,
net........ (416) (310) (1,133) (1,988) (1,895) (9,158) (855) (2,777) (5,303)
Net income
(loss)..... 5,958 3,460 3,754 6,021 7,378 12,810 298 4,423 (1,623)
Weighted
average
shares
outstanding(3)... 14,151 14,151 14,400 14,400
Net income
(loss) per
share(3)... $0.52 $0.91 $0.31 $(0.11)
OTHER
FINANCIAL
DATA:
Depreciation
and
amortization... $ 219 $ 232 $12,540 $21,580 $ 26,896 $42,734 $ 9,882 $15,757 $21,302
EBITDA(4).... $ 4,909 $ 9,898 $42,370 $53,707 $ 69,515 $123,770 $25,440 $41,345 $46,993
SELECTED
OPERATING
INFORMATION:(5)
Power plants:
Electricity
revenue:(6)
Energy... $33,426 $38,325 $37,088 $45,912 $54,886 $89,292 $22,323 $34,362 $36,839
Capacity... $ 7,562 $ 7,707 $ 7,834 $ 7,967 $30,485 $83,591 $ 9,051 $19,774 $28,364
Megawatt
hours
produced... 392,471 403,274 378,035 447,177 1,033,566 2,387,730 324,059 736,739 860,969
Average
energy
price per
kilowatt
hour(7)... 8.517c 9.503c 9.811c 10.267c 5.310c 3.740c 6.889c 4.664c 4.279c
Steam fields:
Steam
revenue:
Calpine... $36,173 $33,385 $31,066 $32,631 $39,669 $39,669 $17,639 $15,866 $15,866
Other
interest... $ 2,820 $ 2,501 $ 2,143 $ 2,051 -- -- -- -- --
Megawatt
hours
produced... 2,095,576 2,105,345 2,014,758 2,156,492 2,415,059 2,415,059 1,027,317 1,040,271 1,040,271
Average
price per
kilowatt
hour..... 1.861c 1.705c 1.648c 1.608c 1.643c 1.643c 1.717c 1.525c 1.525c
</TABLE>
<TABLE>
<CAPTION>
AS OF JUNE 30, 1996
AS OF DECEMBER 31, -----------------------------------------
---------------------------------------------------------- PRO PRO FORMA AS
1991 1992 1993 1994 1995 ACTUAL FORMA(2) ADJUSTED(2)(8)
------- ------- -------- -------- -------- -------- --------- --------------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Cash and cash
equivalents........ $ 958 $ 2,160 $ 6,166 $ 22,527 $ 21,810 $ 38,403 $ 16,047 $ 98,307
Property, plant and
equipment, net..... 351 424 251,070 335,453 447,751 530,203 657,724 657,724
Total assets......... 41,245 55,370 302,256 421,372 554,531 792,812 910,977 993,237
Total liabilities.... 34,624 44,865 288,827 402,723 529,304 713,156 831,321 831,321
Stockholder's
equity............. 6,621 10,505 13,429 18,649 25,227 79,656 79,656 161,916
(see footnotes on next page)
</TABLE>
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- ------------
(1) The pro forma information presented under statement of operations data and
other financial data for the year ended December 31, 1995 gives effect to
the following transactions as if such transactions had occurred on January
1, 1995: (i) the acquisition by the Company of the Greenleaf 1 and 2
Facilities (the "Greenleaf Transaction"); (ii) the acquisition by the
Company of the lease for the Watsonville Facility (the "Watsonville
Transaction"); (iii) the entry by the Company into the agreements in
respect of the Cerro Prieto Steam Fields (the "Cerro Prieto Transaction");
(iv) the entry by the Company into a transaction involving a lease for the
King City Facility (the "King City Transaction"); (v) the acquisition by
the Company of the Gilroy Facility (the "Gilroy Transaction"); (the
Greenleaf Transaction, the Watsonville Transaction, the Cerro Prieto
Transaction, the King City Transaction and the Gilroy Transaction being
collectively referred to as the "Transactions"); (vi) the $50.0 million
Preferred Stock investment in Calpine by Electrowatt (the "Preferred Stock
Investment") and the application of the proceeds therefrom; and (vii) the
sale of the Company's 10 1/2% Senior Notes Due 2006 (the "10 1/2% Senior
Notes") and the application of the net proceeds therefrom. The pro forma
information presented under selected operating information for the year
ended December 31, 1995 gives effect to the Greenleaf Transaction, the
Watsonville Transaction, the King City Transaction and the Gilroy
Transaction as if such transactions had occurred on January 1, 1995. See
"Pro Forma Consolidated Financial Data," "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and
"Business -- Description of Facilities."
(2) The pro forma information presented under statement of operations data,
other financial data and selected operating information for the six months
ended June 30, 1996 gives effect to (i) the King City Transaction, (ii) the
Gilroy Transaction and (iii) the sale of the 10 1/2% Senior Notes and the
application of the net proceeds therefrom as if such transactions had
occurred on January 1, 1996. The pro forma information presented under
balance sheet data as of June 30, 1996 gives effect to the Gilroy
Transaction as if such transaction had occurred on June 30, 1996. See "Pro
Forma Consolidated Financial Data," "Management's Discussion and Analysis
of Financial Condition and Results of Operations" and
"Business -- Description of Facilities."
(3) The actual and pro forma weighted average shares outstanding and net income
(loss) per share for the year ended December 31, 1995 and the six months
ended June 30, 1996 give effect to the issuance of Common Stock upon the
conversion of the Company's outstanding Preferred Stock.
(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) For an explanation of such selected operating information, see
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Selected Operating Information."
(6) The significant increase in capacity revenue and the accompanying decline
in average energy price per kilowatt hour since 1994 reflects the increase
in the Company's megawatt hour production as a result of acquisitions of
gas-fired cogeneration facilities by the Company.
(7) Average energy price per kilowatt hour represents energy revenue divided by
the kilowatt hours produced.
(8) Adjusted to reflect the sale of the 5,477,820 shares of Common Stock
offered by the Company hereby.
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<PAGE> 8
RISK FACTORS
Prospective purchasers of the Common Stock should carefully consider the
factors set forth below, as well as the other information contained in this
Prospectus, in evaluating an investment in the Common Stock.
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 June 30, 1996, the Company's total consolidated
indebtedness was $499.8 million, its total consolidated assets were $792.8
million and its stockholder's equity was $79.7 million. At such date, on a pro
forma basis after giving effect to the Gilroy Transaction, the Company's total
consolidated indebtedness would have been $615.8 million, its total consolidated
assets would have been $911.0 million and its stockholder's equity would have
been $79.7 million. See "Capitalization," "Pro Forma Consolidated Financial
Data" and "Management's Discussion and Analysis of Financial Condition and
Results of Operations." 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 May 16, 1996 (the "10 1/2% Indenture") relating to the
Company's 10 1/2% Senior Notes and the Indenture dated 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") contain certain
restrictive covenants. Such restrictions will affect, and in many respects will
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 certain change of control
transactions, to make an offer to purchase the 10 1/2% Senior Notes and the
9 1/4% Senior Notes. The Common Stock Offering will not constitute a change of
control transaction under the Indentures. There can be no assurance that the
Company will have the financial resources necessary to purchase the 10 1/2%
Senior Notes and the 9 1/4% Senior Notes upon a change of control. 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 10 1/2% Senior Notes and the
9 1/4% 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. See "-- Possible Unavailability of Financing,"
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and "Certain Transactions."
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
8
<PAGE> 9
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 has relied on Electrowatt, currently the
Company's sole stockholder, to provide funding for a substantial portion of its
facility equity commitments. The Company currently has an existing $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 Common Stock
Offering, Electrowatt will sell 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 will terminate.
On July 20, 1996, the Company entered into a Commitment Letter with The
Bank of Nova Scotia for a $50.0 million three-year revolving credit facility
(the "Bank of Nova Scotia Facility"). The Bank of Nova Scotia Facility will
become effective upon the completion of the Common Stock Offering, and will
contain certain restrictions that will 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. See "Management's Discussion and
Analysis of Result of Operations and Financial Condition -- Liquidity and
Capital Resources."
The Company's power generation facilities have been financed using a
variety of leveraged financing structures, consisting of corporate debt,
non-recourse debt and lease obligations. As of June 30, 1996, on a pro forma
basis after giving effect to the Gilroy Transaction, the Company would have had
approximately $615.8 million of total consolidated indebtedness, of which
approximately 53% would have represented non-recourse subsidiary debt. See "Pro
Forma Consolidated Financial Data." 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. See "Business -- Description of
Facilities."
The Company has from time to time guaranteed certain obligations of its
subsidiaries and other affiliates. There can be no assurance that, in respect of
any financings of facilities in the future, lenders or lessors will not require
the Company to guarantee the indebtedness of such future facilities, rendering
the Company's general corporate funds vulnerable in the event of a default by
such facility or related subsidiary. If the lenders or lessors were to require
such guarantees, and the Company were unable to incur indebtedness in respect of
such
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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 Facility, the Bear Canyon Facility, 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 Facilities. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- General" and
"Business -- Description of Facilities." 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 the Public Utility Regulatory Policies Act of 1978,
as amended ("PURPA")). The currently prevailing avoided cost of energy is
substantially lower than the fixed energy prices under these power sales
agreements and is generally expected
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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. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- General" and "Business -- Description of Facilities." 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. See
"Business -- Description of Facilities -- 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
1995, certain of the Company's power generation facilities experienced maximum
curtailment primarily as a result of a high degree of precipitation during the
period, which resulted in higher levels of energy generation by hydroelectric
power facilities that supply electricity. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations." 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 1996 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. See "Business -- Description of Facilities."
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
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favorable prices or, to the extent that any opportunities are identified, that
the Company will be able to consummate such acquisitions.
START-UP RISKS
The commencement of operation of a newly constructed power plant or steam
field involves many risks, including start-up problems, the breakdown or failure
of equipment or processes and performance below expected levels of output or
efficiency. New plants have no operating history and may employ recently
developed and technologically complex equipment. Insurance is maintained to
protect against certain of these risks, warranties are generally obtained for
limited periods relating to the construction of each project and its equipment
in varying degrees, and contractors and equipment suppliers are obligated to
meet certain performance levels. Such insurance, warranties or performance
guarantees may not be adequate to cover lost revenues or increased expenses and,
as a result, a project may be unable to fund principal and interest payments
under its financing obligations and may operate at a loss. A default under such
a financing obligation could result in the Company losing its interest in such
power generation facility or steam field. See "-- Possible Unavailability of
Financing."
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 in
which it has an interest, except for two steam fields. See
"Business -- Description of Facilities." 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 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. See "-- Possible Unavailability of
Financing."
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 1995, approximately 87% and 9% of
the Company's 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
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1995, 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.
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. The
Company believes that this strategy will enhance the earning potential of its
operating assets, generate additional revenue and expand its customer base.
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. See
"Business -- Government Regulation."
The Company's operations are subject to the provisions of various energy
laws and regulations, including PURPA, the Public Utility Holding Company Act of
1935, as amended ("PUHCA"), and state and local regulations. See
"Business -- Government Regulation." PUHCA provides for the extensive regulation
of public utility holding companies and their subsidiaries. PURPA provides to
qualifying facilities ("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
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another exemption. In order to be a QF, a facility must be not more than 50%
owned by an electric utility or electric utility holding company. A QF that is a
cogeneration facility must produce not only electricity, but also useful thermal
energy for use in an industrial or commercial process or heating or cooling
applications in certain proportions to the facility's total energy output, and
it must meet certain energy efficiency standards. Therefore, loss of a thermal
energy customer could jeopardize a cogeneration facility's QF status. All
geothermal power plants up to 80 megawatts that meet PURPA's ownership
requirements and certain other standards are considered QFs. If one of the power
plants in which the Company has an interest were to lose its QF status and not
otherwise receive a PUHCA exemption, the project subsidiary or partnership in
which the Company has an interest owning or leasing that plant could become a
public utility company, which could subject the Company to significant federal,
state and local laws, including rate regulation and regulation as a public
utility holding company under PUHCA. This loss of QF status, which may be
prospective or retroactive, in turn, could cause all of the Company's other
power plants to lose QF status because, under FERC regulations, a QF cannot be
owned by an electric utility or electric utility holding company. In addition, a
loss of QF status could, depending on the power sales agreement, allow the power
purchaser to cease taking and paying for electricity or to seek refunds of past
amounts paid and thus could cause the loss of some or all contract revenues or
otherwise impair the value of a project and could trigger defaults under
provisions of the applicable project contracts and financing agreements
(rendering such debt immediately due and payable). If a power purchaser ceased
taking and paying for electricity or sought to obtain refunds of past amounts
paid, there can be no assurance that the costs incurred in connection with the
project could be recovered through sales to other purchasers. See
"Business -- Government Regulation -- Federal Energy 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.
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
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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.
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 has launched an initiative designed to give all electric consumers the
ability to choose between competing suppliers of electricity. See
"Business -- Government Regulation -- State Regulation." 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. See "Business -- Competition."
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. See
"Management."
ANTI-TAKEOVER PROVISIONS
Certain provisions of Delaware law applicable to the Company could have the
effect of delaying, deterring or preventing a change in control of the Company,
including Section 203 of the Delaware General Corporation Law, which prohibits a
Delaware corporation from engaging in any business combination with any
interested stockholder for a period of three years from the date the person
became an interested stockholder unless certain conditions are met. In addition,
the Company's Certificate of Incorporation and By-laws contain certain
provisions that could discourage potential takeover attempts and make more
difficult attempts by stockholders to change management. The Company's Board of
Directors is classified into three classes of directors serving staggered,
three-year terms and has the authority without action by the Company's
stockholders to fix the rights and preferences and issue shares of Preferred
Stock, and to impose various procedural and other requirements that could make
it more difficult for stockholders to effect certain corporate actions. The
Company's Certificate of Incorporation provides that Directors may be removed
only by the affirmative vote of the holders of two-thirds of the shares of
capital stock of the Company entitled to vote. Any vacancy on the Board of
Directors may be filled only by vote of the majority of Directors then in
office. Further, the Company's Certificate of Incorporation provides that any
"Business Combination" (as therein defined) requires the affirmative vote of the
holders of two-thirds of the shares of capital stock of the Company entitled to
vote, voting together as a single class. These provisions, and certain other
provisions of the Certificate of Incorporation which may have the effect of
delaying proposed stockholder actions until the next annual meeting of
stockholders, could have the effect of delaying or preventing a tender offer for
the Company's Common Stock or other changes of control or management of the
Company, which could adversely affect the market price of the Company's Common
Stock. See "Description of Capital Stock."
NO PRIOR MARKET; STOCK PRICE VOLATILITY; DILUTION
Prior to the Common Stock Offering, there has been no public market for the
Company's Common Stock. Consequently, the initial public offering price was
determined by negotiations among the Company, the Selling Stockholder and the
Representatives of the Underwriters and may not be indicative of the prices that
prevail in the public market. There can be no assurance that an active public
market for the Common Stock will develop or be sustained after the Common Stock
Offering. The trading price of the Company's
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Common Stock could be subject to wide fluctuations in response to
quarter-to-quarter variations in operating results, announcements of new
acquisitions or power projects by the Company or its competitors, general
conditions in the independent power production industry, and other events or
factors. In addition, stock markets have experienced extreme price and trading
volume volatility in recent years. This volatility has had a substantial effect
on the market prices of securities of many companies for reasons frequently
unrelated to the operating performance of the specific companies. These broad
market fluctuations may adversely affect the market price of the Company's
Common Stock. Moreover, investors in the Common Stock Offering will incur
immediate, substantial book value dilution. See "Dilution" and "Underwriting."
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. The market price of the Common Stock could be subject to
significant fluctuations in response to those variations in quarterly operating
results and other factors. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Quarterly Results of Operations
and Seasonality."
SHARES ELIGIBLE FOR FUTURE SALE
Sales of substantial amounts of Common Stock in the public market after the
Common Stock Offering could adversely affect the prevailing market price of the
Common Stock. Other than the 18,045,000 shares of Common Stock offered hereby,
there will be no shares of Common Stock outstanding immediately following the
completion of the Common Stock Offering. All of the shares of Common Stock sold
in the Common Stock Offering will be freely transferable without registration or
further registration under the Securities Act of 1933, as amended (the
"Securities Act"), unless held by an "affiliate" of the Company (as defined in
the Securities Act). As of the date of this Prospectus, options to purchase
2,392,026 shares of Common Stock were outstanding under the Company's Stock
Option Program. Of such amount, options to purchase 1,366,696 shares were
exercisable, all of which will become eligible for sale 180 days after the date
of this Prospectus, upon expiration of certain lock-up agreements with the
Underwriters and pursuant to Rule 701, subject in some cases to certain volume
and other resale restrictions. See "Shares Eligible for Future Sale."
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USE OF PROCEEDS
The aggregate net proceeds to the Company from the sale of the 5,477,820
shares of Common Stock offered by the Company in the Common Stock Offering
(after deducting underwriting discounts and commissions and estimated offering
expenses) will be approximately $82.3 million ($123.1 million if the
Underwriters' over-allotment option is exercised in full). The Company expects
to use a portion of the net proceeds from the Common Stock Offering to repay the
outstanding balance on the Credit Suisse Credit Facility. The outstanding
balance is approximately $13.0 million as of the date of this Prospectus and
bears interest at 6.0% per annum. The remaining net proceeds are expected to be
used for working capital and general corporate purposes, and for the development
and acquisition of power generation facilities, including investments in the
Pasadena Cogeneration Project and the Indonesian Geothermal Project. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources" and "Business -- Development and
Future Projects." Pending such uses, the Company expects to invest the net
proceeds in short-term, interest-bearing securities.
DIVIDEND POLICY
The Company does not anticipate paying any cash dividends on its Common
Stock in the foreseeable future because it intends to retain its earnings to
finance the expansion of its business and for general corporate purposes. In
addition, the Company's ability to pay cash dividends is restricted under the
Indentures and will be restricted under the Bank of Nova Scotia Facility. Future
cash dividends, if any, will be at the discretion of the Company's Board of
Directors and will depend upon, among other things, the Company's future
operations and earnings, capital requirements, general financial condition,
contractual restrictions and such other factors as the Board of Directors may
deem relevant.
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CAPITALIZATION
The following table sets forth, as of June 30, 1996: (i) the actual
consolidated capitalization of the Company; (ii) the pro forma consolidated
capitalization of the Company after giving effect to the Gilroy Transaction and
the conversion of the Company's outstanding Preferred Stock into Common Stock in
connection with the Common Stock Offering; and (iii) the pro forma as adjusted
consolidated capitalization of the Company after giving effect to the sale of
the shares of Common Stock offered by the Company hereby and the application of
the estimated net proceeds therefrom (after deducting underwriting discounts and
commissions and estimated offering expenses). This table should be read in
conjunction with "Pro Forma Consolidated Financial Data" and the consolidated
financial statements and related notes thereto appearing elsewhere in this
Prospectus.
<TABLE>
<CAPTION>
AS OF JUNE 30, 1996
--------------------------------------------
PRO FORMA
ACTUAL PRO FORMA AS ADJUSTED
-------- ----------- -----------
(IN THOUSANDS)
<S> <C> <C> <C>
Short-term debt:
Current portion of non-recourse project
financing....................................... $ 27,178 $ 27,178 $ 27,178
======== ========= =========
Long-term debt:
Long-term line of credit........................... -- -- --
Non-recourse long-term project financing, less
current portion................................. $180,974 $ 296,974 $ 296,974
Notes payable...................................... 6,598 6,598 6,598
Senior notes....................................... 285,000 285,000 285,000
-------- ----------- -----------
Total long-term debt............................ 472,572 588,572 588,572
-------- ----------- -----------
Stockholder's equity:
Preferred Stock, $.001 par value: 5,000,000 shares
authorized and outstanding; pro forma and pro
forma as adjusted, 10,000,000 shares authorized,
no shares outstanding........................... 5 -- --
Common Stock, $.001 par value: 33,760,000 shares
authorized, 10,387,693 shares outstanding; pro
forma, 33,760,000 shares authorized, 12,567,180
shares outstanding; pro forma as adjusted,
100,000,000 shares authorized, 18,045,000 shares
outstanding(1).................................. 10 13 18
Additional paid-in capital......................... 56,209 56,211 138,466
Retained earnings.................................. 23,463 23,463 23,463
Cumulative translation adjustment.................. (31) (31) (31)
-------- ----------- -----------
Total stockholder's equity...................... 79,656 79,656 161,916
-------- ----------- -----------
Total capitalization.......................... $552,228 $ 668,228 $ 750,488
======== ========= =========
</TABLE>
- ------------
(1) Does not include 2,392,026 shares of Common Stock reserved for issuance upon
exercise of options previously granted and outstanding as of June 30, 1996
under the Company's Stock Option Program. See "Management -- Stock Option
Program" and "-- 1996 Stock Incentive Plan."
18
<PAGE> 19
DILUTION
The net tangible book value of the Company as of June 30, 1996 was $69.7
million, or $5.55 per share of Common Stock. Net tangible book value per share
is equal to the Company's total assets (excluding deferred financing and
offering expenses) less its total liabilities, divided by the total number of
outstanding shares of Common Stock. After giving effect to the sale of 5,477,820
shares of Common Stock offered by the Company hereby and the receipt and
application of the net proceeds therefrom, the pro forma net tangible book value
of the Company as of June 30, 1996 would have been approximately $152.0 million
or $8.42 per share. This represents an immediate dilution of $7.58 per share to
new stockholders purchasing shares in the Common Stock Offering. The following
table illustrates this per share dilution:
<TABLE>
<S> <C> <C>
Initial public offering price............................. $16.00
Net tangible book value before the Common Stock
Offering............................................. $5.55
Increase attributable to new stockholders............... 2.87
-----
Pro forma net tangible book value after the Common Stock
Offering................................................ 8.42
------
Total dilution to new stockholders........................ $ 7.58
======
</TABLE>
The calculations in the table set forth above assume no exercise of the
Underwriters' over-allotment option and do not reflect 2,392,026 shares of
Common Stock reserved for issuance pursuant to options granted and outstanding
as of June 30, 1996 under the Company's Stock Option Program. See
"Management -- Stock Option Program" and "-- 1996 Stock Incentive Plan."
19
<PAGE> 20
SELECTED CONSOLIDATED FINANCIAL DATA
The consolidated financial data set forth below for and as of the five
years ended December 31, 1995 have been derived from the audited consolidated
financial statements of the Company. The consolidated financial data for the six
months ended June 30, 1995 and June 30, 1996 and as of June 30, 1996 are
unaudited, but have been prepared on the same basis as the audited consolidated
financial statements and, in the opinion of management, contain all adjustments,
consisting only of normal recurring adjustments necessary for the fair
presentation of the financial position and results of operations for these
periods. Consolidated operating results for the six months ended June 30, 1996
are not necessarily indicative of the results that may be expected for the
entire year. 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 Prospectus, and "Management's Discussion and
Analysis of Financial Condition and Results of Operations."
<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
-------------------------------------------------------- -------------------
1991 1992 1993 1994 1995 1995 1996
------- ------- ------- ------- -------- ------- -------
<S> <C> <C> <C> <C> <C> <C> <C>
(DOLLARS AND SHARES IN THOUSANDS, EXCEPT PER SHARE DATA)
STATEMENT OF OPERATIONS DATA:
Revenue:
Electricity and steam sales............. -- -- $53,000 $90,295 $127,799 $49,014 $72,030
Service contract revenue................ $29,067 $29,817 16,896 7,221 7,153 3,129 5,434
Income (loss) from unconsolidated
investments in power projects......... 9,985 9,760 19 (2,754) (2,854) (1,791) 1,713
Interest income on loans to power
projects.............................. -- -- -- -- -- -- 2,817
-------- -------- -------- -------- -------- -------- --------
Total revenue......................... 39,052 39,577 69,915 94,762 132,098 50,352 81,994
Cost of revenue........................... 25,064 25,921 42,501 52,845 77,388 30,618 51,319
-------- -------- -------- -------- -------- -------- --------
Gross profit.............................. 13,988 13,656 27,414 41,917 54,710 19,734 30,675
Project development expenses.............. 1,067 806 1,280 1,784 3,087 1,308 1,410
General and administrative expenses....... 3,443 3,924 5,080 7,323 8,937 3,659 5,874
Compensation expense related to stock
options(1).............................. -- 1,224 -- -- -- -- --
Provision for write-off of project
development costs(2).................... -- 800 -- 1,038 -- -- --
-------- -------- -------- -------- -------- -------- --------
Income from operations.................... 9,478 6,902 21,054 31,772 42,686 14,767 23,391
Interest expense.......................... 1,925 1,225 13,825 23,886 32,154 15,116 18,665
Other income, net......................... (416) (310) (1,133) (1,988) (1,895) (855) (2,777)
-------- -------- -------- -------- -------- -------- --------
Income before provision for income
taxes, extraordinary item and
cumulative effect of change in
accounting
principle........................... 7,969 5,987 8,362 9,874 12,427 506 7,503
Provision for income taxes................ 3,149 2,527 4,195 3,853 5,049 208 3,080
-------- -------- -------- -------- -------- -------- --------
Income before extraordinary item and
cumulative effect of change in
accounting principle................ 4,820 3,460 4,167 6,021 7,378 298 4,423
Extraordinary item:
Utilization of net operating loss
carryforward.......................... 1,138 -- -- -- -- -- --
-------- -------- -------- -------- -------- -------- --------
Income before cumulative effect of
change in accounting principle...... 5,958 3,460 4,167 6,021 7,378 298 4,423
Cumulative effect of adoption of SFAS No.
109..................................... -- -- (413) -- -- -- --
-------- -------- -------- -------- -------- -------- --------
Net income........................ $ 5,958 $ 3,460 $ 3,754 $ 6,021 $ 7,378 $ 298 $ 4,423
======== ======== ======== ======== ======== ======== ========
Weighted average shares outstanding(3).... 14,151 14,400
======== ========
Net income per share(3)................... $ 0.52 $ 0.31
======== ========
OTHER FINANCIAL DATA:
Depreciation and amortization........... $ 219 $ 232 $12,540 $21,580 $ 26,896 $ 9,882 $15,757
EBITDA(4)............................... $ 4,909 $ 9,898 $42,370 $53,707 $ 69,515 $25,440 $41,345
</TABLE>
(See footnotes on next page)
20
<PAGE> 21
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
---------------------------------------------------------- AS OF JUNE 30,
1991 1992 1993 1994 1995 1996
------- ------- -------- -------- -------- --------------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Cash and cash equivalents.................. $ 958 $ 2,160 $ 6,166 $ 22,527 $ 21,810 $ 38,403
Property, plant and equipment, net......... 351 424 251,070 335,453 447,751 530,203
Total assets............................... 41,245 55,370 302,256 421,372 554,531 792,812
Total liabilities.......................... 34,624 44,865 288,827 402,723 529,304 713,156
Stockholder's equity....................... 6,621 10,505 13,429 18,649 25,227 79,656
</TABLE>
- ------------
(1) Represents a non-cash charge for compensation expense associated with the
grant of certain options under the Company's Stock Option Program. See
"Management -- 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, 1995 and the six months ended June 30, 1996 give effect
to the issuance of Common Stock upon the conversion of the Company's
outstanding Preferred Stock.
(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).
21
<PAGE> 22
PRO FORMA CONSOLIDATED FINANCIAL DATA
The following unaudited pro forma consolidated statement of operations for
the year ended December 31, 1995 gives effect to: (i) the Transactions; (ii) the
Preferred Stock Investment and the application of the proceeds therefrom; and
(iii) the sale of the 10 1/2% Senior Notes and the application of the net
proceeds therefrom as if such transactions had occurred on January 1, 1995. The
following unaudited pro forma consolidated statement of operations for the six
months ended June 30, 1996 gives effect to: (i) the King City Transaction; (ii)
the Gilroy Transaction; and (iii) the sale of the 10 1/2% Senior Notes and the
application of the net proceeds therefrom, as if such transactions had occurred
on January 1, 1996. For further discussion regarding the Transactions, see
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and "Business -- Description of Facilities." The following unaudited
pro forma consolidated balance sheet as of June 30, 1996 gives effect to the
Gilroy Transaction as if such transaction had occurred on June 30, 1996. The
following unaudited pro forma consolidated financial data does not give effect
to the Common Stock Offering or the application of the net proceeds therefrom.
The pro forma consolidated financial data and accompanying notes should be
read in conjunction with the consolidated financial statements and related notes
thereto appearing elsewhere in this Prospectus. The pro forma adjustments are
based upon available information and certain assumptions that management
believes are reasonable and are described in the notes accompanying the pro
forma consolidated financial data. The pro forma consolidated financial data are
presented for informational purposes only and do not purport to represent what
the Company's results of operations or financial position would actually have
been had such transactions in fact occurred at such dates, or to project the
Company's results of operations or financial position at any future date or for
any future period. In the opinion of management, all adjustments necessary to
present fairly such pro forma consolidated financial data have been made.
22
<PAGE> 23
PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1995
----------------------------------------------------------------------
PRO FORMA FOR THE
TRANSACTIONS, THE
PREFERRED STOCK
ADJUSTMENTS FOR THE ADJUSTMENTS INVESTMENT AND THE
TRANSACTIONS AND THE FOR THE SALE SALE OF THE
PREFERRED STOCK OF THE 10 1/2% 10 1/2% SENIOR
ACTUAL INVESTMENT(1) SENIOR NOTES NOTES
-------- -------------------- --------------- ------------------
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenue:
Electricity and steam sales............. $127,799 $ 89,349 -- $217,148
Service contract revenue................ 7,153 250 -- 7,403
Income (loss) from unconsolidated
investments in power projects......... (2,854) -- -- (2,854)
Interest income on loans to power
projects.............................. -- 2,564 -- 2,564
-------- -------- --------------- ----------
Total revenue......................... 132,098 92,163 -- 224,261
-------- -------- --------------- ----------
Cost of revenue:
Plant operating expenses................ 33,162 37,369 -- 70,531
Depreciation and amortization........... 26,264 15,838 -- 42,102
Operating lease expense................. 1,542 11,703 -- 13,245
Service contract expense................ 5,846 -- -- 5,846
Production royalties.................... 10,574 -- -- 10,574
-------- -------- --------------- ----------
Total cost of revenue................. 77,388 64,910 -- 142,298
-------- -------- --------------- ----------
Gross profit.............................. 54,710 27,253 -- 81,963
Project development expenses.............. 3,087 -- -- 3,087
General and administrative expenses....... 8,937 -- -- 8,937
-------- -------- --------------- ----------
Income from operations................ 42,686 27,253 -- 69,939
Interest expense.......................... 32,154 16,193 $ 9,176(2) 57,523
Other income, net......................... (1,895) (7,263) -- (9,158)
-------- -------- --------------- ----------
Income before provision for income
taxes................................. 12,427 18,323 (9,176) 21,574
Provision for income taxes................ 5,049 7,443 (3,728) 8,764
-------- -------- --------------- ----------
Net income.......................... $ 7,378 $ 10,880 $(5,448) $ 12,810
========= ================== ============== ==================
Net income per share................ $ 0.52 $ 0.91
========= ==================
OTHER FINANCIAL DATA:
Depreciation and amortization............. $ 26,896 $ 42,734
EBITDA.................................... $ 69,515 $123,770
</TABLE>
See Notes to Pro Forma Consolidated Statements of Operations
23
<PAGE> 24
PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30, 1996
-----------------------------------------------------------------------------------------
PRO FORMA FOR THE
KING CITY
ADJUSTMENTS TRANSACTION,
ADJUSTMENTS ADJUSTMENTS FOR THE THE GILROY
FOR THE FOR THE SALE OF THE TRANSACTION AND
KING CITY GILROY 10 1/2% THE SALE OF THE
ACTUAL TRANSACTION(3)(5) TRANSACTION(4)(5) SENIOR NOTES 10 1/2% SENIOR NOTES
------- ------------------- ----------------- ------------- ---------------------
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenue:
Electricity and steam
sales..................... $72,030 $ 1,583 $ 9,491 -- $83,104
Service contract revenue.... 5,434 -- -- -- 5,434
Income (loss) from
unconsolidated investments
in power projects......... 1,713 -- -- -- 1,713
Interest income on loans to
power
projects.................. 2,817 -- -- -- 2,817
------- ------- ------- -------- ------
Total revenue............. 81,994 1,583 9,491 -- 93,068
------- ------- ------- -------- ------
Cost of revenue:
Plant operating expenses.... 22,901 1,669 4,035 -- 28,605
Depreciation and
amortization.............. 15,413 2,800 2,745 -- 20,958
Operating lease expense..... 3,239 3,372 -- -- 6,611
Service contract expense.... 4,484 -- -- -- 4,484
Production royalties........ 5,282 -- -- -- 5,282
------- ------- ------- -------- ------
Total cost of revenue..... 51,319 7,841 6,780 -- 65,940
------- ------- ------- -------- ------
Gross profit.................. 30,675 (6,258) 2,711 -- 27,128
Project development
expenses.................... 1,410 -- -- -- 1,410
General and administrative
expenses.................... 5,874 -- -- -- 5,874
------- ------- ------- -------- ------
Income from operations.... 23,391 (6,258) 2,711 -- 19,844
Interest expense.............. 18,665 1,391 4,585 $ 3,259(6) 27,900
Other income, net............. (2,777) (2,526) -- -- (5,303)
------- ------- ------- -------- ------
Income (loss) before
provision for income
taxes................... 7,503 (5,123) (1,874) (3,259) (2,753)
Provision for (benefit from)
income taxes................ 3,080 (2,103) (769) (1,338) (1,130)
------- ------- ------- -------- ------
Net income (loss).... $ 4,423 $(3,020) $(1,105) $(1,921) $(1,623)
======= ======= ======= ======== ======
Net income (loss) per
share.............. $ 0.31 $ (0.11)
======= ======
OTHER FINANCIAL DATA:
Depreciation and
amortization................ $15,757 $21,302
EBITDA........................ $41,345 $46,993
</TABLE>
See Notes to Pro Forma Consolidated Statements of Operations
24
<PAGE> 25
NOTES TO PRO FORMA CONSOLIDATED STATEMENTS OF OPERATIONS
(1) Represents the pro forma results of operations for the facilities involved
in the Transactions for the periods during 1995 prior to the completion of
the Transactions, as if the Transactions had been completed on January 1,
1995, including: (i) the Greenleaf 1 and 2 Facilities for the period
through April 21, 1995; (ii) the Watsonville Facility for the period
through June 28, 1995; (iii) the Cerro Prieto Steam Fields for the period
through December 14, 1995; (iv) the King City Facility for the period
through December 31, 1995; and (v) the Gilroy Facility for the period
through December 31, 1995. The information provided for the Cerro Prieto
Steam Fields does not include the portion of service contract revenue which
is contingent on future results. The pro forma adjustments reflect the
historical results of operations of the facilities, as adjusted to give
effect to the changes resulting from purchase price allocations and other
transaction effects, as applicable. Such adjustments include depreciation
and amortization applicable to new asset bases, interest expense amounts
applicable to debt instruments outstanding, income tax amounts at the
estimated effective rate of approximately 41%, and other adjustments. The
following table sets forth adjustments to results of operations for such
periods:
<TABLE>
<CAPTION>
GREENLEAF
1 AND 2 WATSONVILLE CERRO PRIETO KING CITY GILROY
FACILITIES FACILITY STEAM FIELDS FACILITY FACILITY TOTAL
--------- ----------- ------------ --------- -------- -------
<S> <C> <C> <C> <C> <C> <C>
(IN THOUSANDS)
STATEMENT OF OPERATIONS DATA:
Revenue:
Electricity and steam sales.................. $ 5,314 $ 3,978 -- $43,836 $ 36,221 $89,349
Service contract revenue..................... -- -- $ 250 -- -- 250
Income (loss) from unconsolidated investments
in power projects.......................... -- -- -- -- -- --
Interest income on loans to power projects... -- -- 2,564 -- -- 2,564
------- ------ ------ ------- -------
Total revenue.............................. 5,314 3,978 2,814 43,836 36,221 92,163
------- ------ ------ ------- -------
Cost of revenue:
Plant operating expenses..................... 5,954 2,857 -- 14,743 13,815 37,369
Depreciation and amortization................ 1,802 147 -- 8,399 5,490 15,838
Operating lease expense...................... -- 1,586 -- 10,117 -- 11,703
Service contract expense..................... -- -- -- -- -- --
Production royalties......................... -- -- -- -- -- --
------- ------ ------ ------- -------
Total cost of revenue...................... 7,756 4,590 -- 33,259 19,305 64,910
------- ------ ------ ------- -------
Gross profit................................... (2,442) (612) 2,814 10,577 16,916 27,253
Project development expenses................... -- -- -- -- -- --
General and administrative expenses............ -- -- -- -- -- --
------- ------ ------ ------- -------
Income from operations..................... (2,442) (612) 2,814 10,577 16,916 27,253
Interest expense............................... 1,921 -- 932 4,172 9,168 16,193
Other income, net.............................. (105) -- -- (7,158) -- (7,263)
------- ------ ------ ------- -------
Income before provision for income taxes... (4,258) (612) 1,882 13,563 7,748 18,323
Provision (benefit) for income taxes........... (1,730) (249) 765 5,509 3,148 7,443
------- ------ ------ ------- -------
Net income............................. $(2,528) $ (363) $1,117 $ 8,054 $ 4,600 $10,880
======= ====== ====== ======= =======
</TABLE>
The adjustments reflected in the table set forth above for the Greenleaf 1
and 2 Facilities and the Watsonville Facility are not necessarily
indicative of a full year's results. See "Risk Factors -- Quarterly
Fluctuations; Seasonality." Other income, net for the King City Facility
reflects interest income from amounts contractually invested pursuant to
collateral fund requirements. See "Business -- Description of
Facilities -- Power Generation Facilities -- King City Facility."
(2) Reflects $18.9 million of interest expense related to the 10 1/2% Senior
Notes and $540,000 of amortization expense for the costs associated with the
sale of the 10 1/2% Senior Notes, reduced by $4.4 million of actual
25
<PAGE> 26
interest expense in 1995 as a result of the repayment of the $57 million
loan from The Bank of Nova Scotia to Calpine Thermal Company, a wholly-owned
subsidiary of the Company (the "$57 Million Bank of Nova Scotia Loan"), $3.4
million of interest expense as a result of the repayment of the $45 million
loan from The Bank of Nova Scotia to the Company (the "$45 Million Bank of
Nova Scotia Loan") (assuming an interest rate of 7.5%) and $2.4 million of
interest expense as a result of the repayment of all amounts outstanding
under the Credit Suisse Credit Facility. The $2.4 million represents
$704,000 of actual interest expense in 1995 and $1.7 million of assumed
interest expense to fund the King City and Cerro Prieto Transactions
(assuming an interest rate of 6.0%).
(3) Represents the pro forma results of operations for the King City Facility
for the period of January 1 through April 30, 1996. Other income, net for
the King City Facility reflects interest income from amounts contractually
invested pursuant to collateral fund requirements. See
"Business -- Description of Facilities -- Power Generation
Facilities -- King City Facility."
(4) Represents the pro forma results of operations for the Gilroy Facility for
the period of January 1 through June 30, 1996.
(5) Results for the six months ended June 30, 1996 reflected in the Pro Forma
Consolidated Statement of Operations are not necessarily indicative of a
full year's results. See "Risk Factors -- Quarterly Fluctuations;
Seasonality."
(6) Reflects $7.0 million of interest expense related to the 10 1/2% Senior
Notes and $201,000 of amortization expense for the costs associated with the
sale of the 10 1/2% Senior Notes, reduced by $1.9 million of actual interest
expense as a result of the repayment of the $57 Million Bank of Nova Scotia
Loan, $1.1 million of interest expense as a result of the repayment of the
$45 Million Bank of Nova Scotia Loan (assuming an interest rate of 7.5%) and
$973,000 of interest expense as a result of the repayment of all amounts
outstanding under the Credit Suisse Credit Facility. The $973,000 represents
$707,000 of actual interest expense and $266,000 of assumed interest expense
to fund a portion of the King City Transaction (assuming an interest rate of
6.0%).
26
<PAGE> 27
PRO FORMA CONSOLIDATED BALANCE SHEET
<TABLE>
<CAPTION>
AS OF JUNE 30, 1996
-------------------------------------------
ADJUSTMENTS PRO FORMA
FOR THE FOR THE
GILROY GILROY
ACTUAL TRANSACTION TRANSACTION
-------- ------------ -----------------
(IN THOUSANDS)
<S> <C> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents.................................. $ 38,403 $(22,356)(1) $ 16,047
Accounts receivable........................................ 43,227 9,000(2) 52,227
Collateral securities, current portion..................... 9,745 -- 9,745
Other current assets....................................... 13,369 -- 13,369
-------- ------------ -----------------
Total current assets..................................... 104,744 (13,356) 91,388
Property, plant and equipment, net........................... 530,203 127,521(3) 657,724
Investments in power projects................................ 12,693 -- 12,693
Notes receivable............................................. 37,386 -- 37,386
Collateral securities, net of current portion................ 88,669 -- 88,669
Other assets................................................. 19,117 4,000(4) 23,117
-------- ------------ -----------------
Total assets............................................. $792,812 $118,165 $ 910,977
========= ============= ==================
LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities:
Current portion of non-recourse project financing.......... $ 27,178 $ -- $ 27,178
Other current liabilities.................................. 25,680 2,165(5) 27,845
-------- ------------ -----------------
Total current liabilities................................ 52,858 2,165 55,023
Long-term credit facility.................................... -- -- --
Non-recourse long-term project financing, less current
portion.................................................... 180,974 116,000(6) 296,974
Notes payable................................................ 6,598 -- 6,598
Senior Notes Due 2004........................................ 105,000 -- 105,000
Senior Notes Due 2006........................................ 180,000 -- 180,000
Deferred lease incentive..................................... 81,495 -- 81,495
Deferred income taxes, net................................... 100,068 -- 100,068
Other liabilities............................................ 6,163 -- 6,163
-------- ------------ -----------------
Total liabilities........................................ 713,156 118,165 831,321
-------- ------------ -----------------
Stockholder's equity:
Preferred stock............................................ 50,000 -- 50,000
Common stock............................................... 6,224 -- 6,224
Retained earnings.......................................... 23,463 -- 23,463
Cumulative translation adjustment.......................... (31) -- (31)
-------- ------------ -----------------
Total stockholder's equity............................... 79,656 -- 79,656
-------- ------------ -----------------
Total liabilities and stockholder's equity............... $792,812 $118,165 $ 910,977
========= ============= ==================
</TABLE>
See Notes to Pro Forma Consolidated Balance Sheet
27
<PAGE> 28
NOTES TO PRO FORMA CONSOLIDATED BALANCE SHEET
(1) Represents the cash required to finance, in part, the Gilroy Transaction.
(2) Represents the accounts receivable in the Gilroy Transaction.
(3) Represents the property, plant and equipment acquired in the Gilroy
Transaction.
(4) Represents debt reserve amount.
(5) Represents the accounts payable and accrued liabilities in the Gilroy
Transaction.
(6) Project financing required to finance, in part, the Gilroy Transaction.
28
<PAGE> 29
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion should be read in conjunction with, and is
qualified in its entirety by reference to, the consolidated financial statements
of the Company, including the notes thereto, appearing elsewhere in this
Prospectus.
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
1,057 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 $41.2 million of total assets as of December 31,
1991 to $911.0 million of total assets on a pro forma basis as of June 30, 1996.
Calpine's revenue on a pro forma basis for 1995 increased to $224.3 million,
representing a compound annual growth rate of 55% since 1991. The Company's
EBITDA on a pro forma basis for 1995 increased to $123.8 million. See "Pro Forma
Consolidated Financial Data."
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 Facilities, 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 Facility, 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
transaction involving a lease for the 120 megawatt King City Facility, which
required an investment of $108.3 million, primarily related to the collateral
fund requirements. On August 29, 1996, the Company acquired the 120 megawatt
Gilroy 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. See "Business -- Description of Facilities."
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 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.
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
1995, 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 1996 under its power sales agreements
for certain of its facilities. See "Business -- Description of 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. As part of its policy decision, the
CPUC indicated that power sales
29
<PAGE> 30
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. 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
affected, although there can be no assurance in this regard.
Electricity and steam sales represents the sale of electricity and
geothermal steam from the Company's majority-owned facilities to utilities under
the terms and conditions of long-term power and steam sales agreements. Revenue
attributable to the West Ford Flat Facility, the Bear Canyon Facility, the
Greenleaf 1 and 2 Facilities, the Watsonville Facility, the King City Facility,
the Gilroy Facility, the PG&E Unit 13 and Unit 16 Steam Fields, the Thermal
Power Company Steam Fields and the SMUDGEO #1 Steam Fields is included in
electricity and steam sales. See "Business -- Description of Facilities."
Service contract revenue consists of revenue earned on services performed
under operating and maintenance agreements for projects that are not
consolidated in the Company's consolidated financial statements. The Company
recognizes revenue on these agreements at the time services are performed.
Income from unconsolidated investments in power projects represents the
Company's share of income from projects that are not consolidated in the
Company's consolidated financial statements and, accordingly, are accounted for
under the equity method of accounting. The Company's share of income from such
projects is calculated according to the Company's equity ownership or in
accordance with the terms of the appropriate partnership agreement. The
Company's current investments which are accounted for under the equity method
consist of the Aidlin Facility, the Agnews Facility and the Sumas Facility.
Depreciation and amortization expense for natural gas-fired cogeneration
facilities is computed using a straight-line method over the estimated remaining
useful life. Depreciation and amortization expense also reflects the
amortization of the Company's geothermal power generation facilities and steam
fields using the units of production method of depreciation. The Company
capitalizes all capital costs related to the operating power plants and steam
fields, as well as the cost of drilling wells and estimated future development
and de-commissioning costs. These capital costs are then amortized using the
units of production method based on current production over the estimated useful
life of the geothermal resource. 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 and amortization
expense.
Capitalized project costs are costs related to the development or
acquisition of new projects which are capitalized upon the execution of a
memorandum of understanding or a power sales agreement. Upon the start-up of
plant operations or the completion of an acquisition, such costs are generally
transferred to property, plant and equipment and amortized over the estimated
useful life of the project. As of June 30, 1996, the Company had deferred $2.8
million of development costs associated with projects currently in the
development stage.
General and administrative expenses include administrative, accounting,
finance, legal, human resources, insurance and other expenses incurred in
connection with the Company's operations. In addition, general and
administrative expenses also include the expenses associated with management of
the Company's operating and maintenance agreements and the expenses incurred in
the management of the Company's project investments.
Provision for income taxes includes income taxes calculated at the
effective rate for each applicable period reflecting statutory rates and as
adjusted for percentage depletion in excess of basis and other items.
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 Facility, the Bear Canyon
Facility, the
30
<PAGE> 31
Greenleaf 1 and 2 Facilities and the Watsonville Facility since their
acquisitions on April 21, 1995 and June 29, 1995, respectively, and the King
City Facility subsequent to 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 and 1995, 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 Facility,
Bear Canyon Facility, 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. See "-- General."
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, SIX MONTHS ENDED JUNE 30,
------------------------------------------------------------------- ----------------------------------
1991 1992 1993 1994 1995
------- ------- ------- ------- -------
1995 1996
----------------------- -----------------------
PRO FORMA(1) PRO FORMA(2)
ACTUAL ------------ ACTUAL ------------
------- -------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
POWER PLANTS:
Electricity
revenue:
Energy........... $33,426 $38,325 $37,088 $45,912 $54,886 $ 89,292 $22,323 $34,362 $36,839
Capacity(3)...... $ 7,562 $ 7,707 $ 7,834 $ 7,967 $30,485 $ 83,591 $ 9,051 $19,774 $28,364
Megawatt hours
produced......... 392,471 403,274 378,035 447,177 1,033,566 2,387,730 324,059 736,759 860,969
Average energy
price per
kilowatt
hour(3).......... 8.517c 9.503c 9.811c 10.267c 5.310c 3.740c 6.889c 4.664c 4.279c
STEAM FIELDS:
Steam revenue:
Calpine.......... $36,173 $33,385 $31,066 $32,631 $39,669 $ 39,669 $17,639 $15,866 $15,866
Other interest... $ 2,820 $ 2,501 $ 2,143 $ 2,051 -- -- -- -- --
Megawatt hours
produced......... 2,095,576 2,105,345 2,014,758 2,156,492 2,415,059 2,415,059 1,027,317 1,040,271 1,040,271
Average price per
kilowatt hour.... 1.861c 1.705c 1.648c 1.608c 1.643c 1.643c 1.717c 1.525c 1.525c
</TABLE>
- ------------
(1) Pro forma results for the year ended December 31, 1995 give effect to the
Greenleaf Transaction, the Watsonville Transaction, the King City
Transaction and the Gilroy Transaction as if such transactions had occurred
on January 1, 1995.
(2) Pro forma results for the six months ended June 30, 1996 give effect to the
King City Transaction and the Gilroy Transaction as if such transactions had
occurred on January 1, 1996.
(3) Represents 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
SIX MONTHS ENDED JUNE 30, 1996 COMPARED TO SIX MONTHS ENDED JUNE 30, 1995
Revenue. Revenue increased 63% to $82.0 million for the six months ended
June 30, 1996 compared to $50.4 million for the comparable period in 1995.
Electricity and steam sales revenue increased 47% to $72.0 million for the six
months ended June 30, 1996, compared to $49.0 million for the comparable period
in 1995. The increase in electricity and steam sales revenue was primarily
attributable to $11.0 million of revenue from the King City Facility, an
increase in revenue of $6.0 million from the Greenleaf 1 and 2 Facilities, and
$3.9 million of revenue from the Watsonville Facility. The remaining increase in
electricity and steam sales revenue of $2.1 million is primarily a result of
higher generation and higher prices at other Company power generation facilities
and steam fields. Service contract revenue from related parties increased 48% to
$4.6 million for the six months ended June 30, 1996 compared to $3.1 million for
the same period in 1995, primarily as a result of service revenue earned in
connection with overhauls at the Aidlin Facility and the Agnews Facility. Income
from unconsolidated investments in power projects increased to $1.7 million for
the six months ended June 30, 1996 compared to a loss of $1.8 million for the
comparable period in 1995, primarily as a result of $1.9 million of equity
income from the Company's investment in the Sumas Facility. This increase is
primarily
31
<PAGE> 32
attributable to a contractual increase in the energy price under the power sales
agreement. Interest income on loans to power projects increased to $2.8 million
for the six months ended June 30, 1996 as a result of $1.9 million attributable
to the recognition of interest income on loans to the sole shareholder of the
general partner in the Sumas Facility, and interest income of $962,000 on loans
to Coperlasa related to the Cerro Prieto Steam Fields.
Cost of revenue. Cost of revenue increased 68% to $51.3 million for the
six months ended June 30, 1996 compared to $30.6 million for the comparable
period in 1995. The increase was primarily due to plant operating, depreciation
and operating lease expenses attributable to (i) a full six months of operations
during 1996 at the Greenleaf 1 and 2 Facilities, which were purchased on April
21, 1995, (ii) a full six months of operations during 1996 at the Watsonville
Facility which was acquired on June 29, 1995, and (iii) operations at the King
City Facility subsequent to May 2, 1996. The increase in cost of revenue was
also due to the increase in service contract expenses as a result of expenses
related to the Cerro Prieto Steam Fields, partially offset by lower operating
and depreciation expenses at the Company's other existing power generation
facilities and steam fields.
General and administrative expenses. General and administrative expenses
increased 60% to $5.9 million for the six months ended June 30, 1996 compared to
$3.7 million for the comparable period in 1995. The increase was primarily due
to additional personnel and related expenses necessary to support the Company's
expanding operations.
Interest expense. Interest expense increased 24% to $18.7 million for the
six months ended June 30, 1996 compared to $15.1 million for the comparable
period in 1995. The increase was primarily attributable to $2.4 million of
interest on the Company's 10 1/2% Senior Notes issued in May 1996 and $1.7
million of interest expense related to the Greenleaf 1 and 2 Facilities acquired
in April 1995, offset in part by a $1.5 million decrease in interest expense as
a result of repayments of principal on certain indebtedness.
Other income, net. Other income, net increased to $2.8 million for the six
months ended June 30, 1996 compared to $855,000 for the comparable period in
1995. The increase was primarily due to $1.5 million of interest income on
collateral securities purchased in connection with the King City Transaction and
to an increase in interest income from the investment of the proceeds of the
Preferred Stock Investment and a portion of the proceeds from the sale of the
10 1/2% Senior Notes.
Provision for income taxes. The effective rate for the income tax
provision was approximately 41% for the six months ended June 30, 1996. The
effective rate was based on statutory tax rates.
YEAR ENDED DECEMBER 31, 1995 COMPARED TO YEAR ENDED DECEMBER 31, 1994
Revenue. 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 Facilities, $5.9 million of revenue from the Watsonville Facility, 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 Facilities 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
Facilities 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.
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 were previously calculated considering a future period
32
<PAGE> 33
when steam would be delivered without receiving corresponding revenue. See Note
2 of the notes to consolidated financial statements appearing elsewhere in this
Prospectus. 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 Facilities
subsequent to April 21, 1995, and (iii) operations at the Watsonville Facility
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 Facilities 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 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.
YEAR ENDED DECEMBER 31, 1994 COMPARED TO YEAR ENDED DECEMBER 31, 1993
Revenue. Revenue increased 36% to $94.8 million in 1994 from $69.9 million
in 1993, primarily due to a 70% increase in electricity and steam sales to $90.3
million in 1994 compared to $53.0 million in 1993. Such increases were primarily
attributable to the $5.8 million of revenue from the Thermal Power Company Steam
Fields, the $5.1 million and $3.0 million of additional revenue from the West
Ford Flat and the Bear Canyon Facilities, respectively, as a result of the
acquisition of the additional interests in such facilities in 1994, the effects
of curtailment at such facilities in 1993 as a result of higher precipitation in
1993 and the sale of $804,000 of electricity to the Northern California Power
Agency. These revenue increases were partially offset by a decrease of $3.5
million in electricity and steam sales from the SMUDGEO #1 Steam Fields as a
result of a four-month shut-down for major maintenance.
In May 1994, the Company recognized approximately $5.9 million of its
previously deferred revenue. The revenue was previously deferred when it was
expected that steam would have been delivered without receiving corresponding
revenue. Based on current estimates and analyses performed by the Company, the
Company no longer expects that it will be required to make these deliveries to
SMUD. This resulted in a $4.0 million increase in revenue during 1994, while the
remaining $1.9 million was treated as a purchase price reduction to property,
plant and equipment. Concurrently, $800,000 of the revenue increase was reserved
for future
33
<PAGE> 34
construction of gathering systems required for future production of the steam
fields, with the offset recorded in property, plant and equipment.
Service contract revenue decreased 57% to $7.2 million in 1994 compared to
$16.9 million in 1993, primarily reflecting the elimination of intercompany
revenue for services provided to the power generation facilities and steam
fields owned by CGC after the acquisition of the remaining interest in CGC in
April 1993. In addition, the decline reflected the higher revenue recognized in
1993 on services associated with the Aidlin Facility overhaul, maintenance at
the Agnews Facility, the start-up of the Sumas Facility and the completion of
the Sumas construction management project.
Unconsolidated investments in power projects contributed a loss of $2.8
million in 1994 compared to income of $19,000 in 1993. The decrease is partially
attributable to a full year of operating loss at the Sumas Facility of $2.9
million in 1994, as compared to approximately eight months of operating loss of
$1.9 million in 1993. The 1994 Sumas Facility operating loss is attributable to
higher interest, depreciation and general and administrative expenses. The
decrease from 1993 income from unconsolidated investments in power projects is
also attributable to $2.0 million of equity income from CGC recognized prior to
the April 1993 acquisition under the equity method of accounting.
Cost of revenue. Cost of revenue increased 24% to $52.8 million in 1994
from $42.5 million in 1993. The increase was attributable to higher plant
operating, production royalty and depreciation expenses due to a full year of
operations at CGC during 1994, and to additional expenses of Thermal Power
Company as a result of its acquisition by the Company on September 9, 1994.
Service contract expenses decreased by $8.8 million primarily due to the
elimination of $6.2 million of operation expenses incurred at CGC after the
acquisition of the remaining interest in April 1993, as well as higher 1993
costs incurred in connection with the Aidlin Facility overhaul and higher
maintenance expenses at the Agnews Facility.
Project development expenses. Project development expenses increased to
$1.8 million in 1994 from $1.3 million in 1993 due to increased expenses
attributable to new project development activities.
General and administrative expenses. General and administrative expenses
increased 43% to $7.3 million in 1994 from $5.1 million in 1993 due to
additional personnel and related expenses necessary to support the Company's
expanded operations.
Provision for write-off of project development expenses. The Company
established in 1994 a $1.0 million reserve for capitalized project costs
associated with the development of projects which the Company has determined may
not be consummated.
Interest expense. Interest expense increased to $23.9 million in 1994 from
$13.8 million in 1993. The Company incurred $8.5 million of interest expense
related to the 9 1/4% Senior Notes issued in February 1994. A portion of the
proceeds of the 9 1/4% Senior Notes was used to repay all of the $52.6 million
then outstanding under the Credit Suisse Credit Facility, and to repay the
non-recourse notes payable to Freeport-McMoran Resource Partners, L.P. ("FMRP")
plus accrued interest. Interest expense also increased approximately $1.0
million due to a full year of interest expense at higher interest rates related
to CGC debt. Additionally, interest expense of $1.3 million was incurred on the
new debt related to the Company's acquisition of Thermal Power Company in
September 1994.
Provision for income taxes. The effective rate for the income tax
provision was 39% in 1994 compared to 50% for 1993. The 1994 effective rate
reflects a reduction for a depletion in excess of tax basis benefit at Thermal
Power Company and CGC. The effective rate for 1993 reflects a provision of
$700,000 due to a change in the California state income tax regulations to
disallow 50% of net operating loss carryforwards.
QUARTERLY RESULTS OF OPERATIONS AND 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. The market price of the Common Stock
34
<PAGE> 35
could be subject to significant fluctuations in response to those variations in
quarterly operating results and other factors.
LIQUIDITY AND CAPITAL RESOURCES
To date, the Company has obtained cash from its operations, borrowings
under the Credit Suisse Credit Facility and other working capital lines, equity
contributions from Electrowatt and proceeds from non-recourse project financings
and other long-term debt. The Company utilized this cash to fund its operations,
service debt obligations, fund the acquisition, development and construction of
power generation facilities, finance capital expenditures and meet its other
cash and liquidity needs.
The following table summarizes the Company's cash flow activities for the
periods indicated:
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE
YEAR ENDED DECEMBER 31, 30,
---------------------------------- ----------------------
1993 1994 1995 1995 1996
-------- -------- -------- -------- ---------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Cash flows from:
Operating activities........... $ 24,310 $ 34,196 $ 26,653 $ 5,126 $ 5,035
Investing activities........... (27,082) (84,444) (38,497) (23,874) (126,051)
Financing activities........... 6,778 66,609 11,127 3,742 137,609
-------- -------- -------- -------- ---------
Total....................... $ 4,006 $ 16,361 $ (717) $(15,006) $ 16,593
======== ======== ======== ======== =========
</TABLE>
Operating activities for 1995 consisted of approximately $7.4 million of
net income from operations, $25.9 million of depreciation and amortization and a
$2.9 million loss from unconsolidated investments in power projects, offset by
an $8.5 million net increase in operating assets and liabilities. Operating
activities for the six months ended June 30, 1996 consisted of approximately
$4.4 million of net income from operations, $15.0 million of depreciation and
amortization and $1.7 million in deferred income taxes, offset by $1.7 million
of income from unconsolidated investments in power projects and a $14.4 million
net increase in operating assets and liabilities.
Investing activities used $38.5 million during 1995, primarily due to $17.4
million of capital expenditures, $14.8 million for the acquisition of the
Greenleaf 1 and 2 Facilities and a $6.3 million investment in notes receivable.
Investing activities used $126.1 million during the six months ended June 30,
1996, primarily due to $11.0 million of capital expenditures and capitalized
project costs, $98.4 million for the purchase of collateral securities, a $12.1
million investment in Coperlasa and $4.9 million for deferred transaction costs
in connection with the King City Transaction, offset by a $1.1 million decrease
in restricted cash requirements.
Financing activities provided $11.1 million of cash during 1995. Borrowings
in 1995 included $76.0 million of non-recourse project financing and $37.5
million from the Company's lines of credit. Proceeds were primarily used to
repay $60.4 million of project debt assumed in the acquisition of the Greenleaf
1 and 2 Facilities, and $15.0 million borrowed from the lines of credit for the
acquisition of the Greenleaf 1 and 2 Facilities. In addition, $19.0 million was
used to reduce the balance outstanding under non-recourse project financing, and
$6.0 million was used to repay short-term borrowings. Financing activities
provided $137.6 million of cash during the six months ended June 30, 1996. The
Company issued $50.0 million of Preferred Stock to Electrowatt, incurred the $45
Million Bank of Nova Scotia Loan and borrowed an additional $33.8 million under
the Credit Suisse Credit Facility and received net proceeds of $175.2 million
from the 10 1/2% Senior Notes during the six months ended June 30, 1996. In
addition, the Company repaid $46.2 million of bank debt and all of the $53.7
million of borrowings outstanding under the Credit Suisse Credit Facility and
$66.6 million of non-recourse project financing.
In 1995, working capital decreased $50.5 million and cash and cash
equivalents decreased $717,000. The decrease in working capital is primarily due
to the reclassification of the $57 Million Bank of Nova Scotia Loan from
long-term to current. On May 16, 1996, the Company issued the 10 1/2% Senior
Notes, a portion of the net proceeds of which was used to refinance current
indebtedness and to repay the $57 Million Bank of
35
<PAGE> 36
Nova Scotia Loan. As of June 30, 1996, cash and cash equivalents were $38.4
million and working capital was $51.9 million. For the six months ended June 30,
1996, working capital increased $100.9 million and cash and cash equivalents
increased $16.6 million as compared to the twelve months ended December 31,
1995. Working capital at December 31, 1995 included the $57 Million Bank of Nova
Scotia Loan. A portion of the net proceeds from the issuance of the 10 1/2%
Senior Notes was used to refinance current bank debt and borrowings under the
Credit Suisse Credit Facility and to repay the $57 Million Bank of Nova Scotia
Loan. Working capital also increased as a result of the investment of the
balance of the proceeds from the issuance of the 10 1/2% Senior Notes in
short-term marketable securities. The increase in working capital was also due
to the proceeds from the issuance of $50.0 million of preferred stock which were
invested until May 1, 1996 for the King City Transaction.
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.
At June 30, 1996, the Company had $208.2 million of non-recourse project
financing associated with power generating facilities and steam fields at the
West Ford Flat Facility, the Bear Canyon Facility, the PG&E Unit 13 and Unit 16
Steam Fields, the SMUDGEO #1 Steam Fields and the Greenleaf 1 and 2 Facilities.
As of June 30, 1996, the annual maturities for all non-recourse project debt
were $18.1 million for the remainder of 1996, $24.8 million for 1997, $26.0
million for 1998, $18.7 million for 1999, $18.0 million for 2000 and $100.2
million thereafter.
The Company currently has the Credit Suisse Credit Facility, which was
arranged by Electrowatt and provides for total borrowings of up to $50.0
million, with borrowings bearing interest at either LIBOR or at the Credit
Suisse base rate plus a mutually-agreed margin. As of June 30, 1996, the Company
had no borrowings outstanding under the Credit Suisse Credit Facility. Upon the
completion of the Common Stock Offering, the Credit Suisse Credit Facility will
terminate and is expected to be replaced by a comparable facility. On July 20,
1996, the Company entered into a Commitment Letter with The Bank of Nova Scotia
for a $50.0 million three-year revolving credit facility. The Bank of Nova
Scotia Facility will become effective upon the completion of the Common Stock
Offering.
The Company currently has outstanding $105.0 million of its 9 1/4% Senior
Notes which mature on February 1, 2004 and bear interest at 9 1/4% payable
semi-annually on February 1 and August 1 of each year and $180.0 million of its
10 1/2% Senior Notes which mature on May 15, 2006 and bear interest at 10 1/2%
payable semi-annually on May 15 and November 15 of each year. Under the
provisions of the 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. In addition, the Bank of Nova Scotia
Facility will contain certain restrictions that will 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 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 June 30, 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 had 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, which has
been discounted to yield 8% per annum, is due September 9, 1997.
On August 29, 1996, in connection with the acquisition of the Gilroy
Facility, the Company entered into a non-recourse project loan in the aggregate
amount of $116.0 million. Such loan, which was provided by Banque Nationale de
Paris, 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.
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<PAGE> 37
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 June 30, 1996, the Company had commitments for capital expenditures in
1996 totaling $6.5 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
1995 were $17.4 million compared to $7.0 million for 1994, primarily due to the
purchase of new equipment and the additional working interest. For the six
months ended June 30, 1996, capital expenditures included $4.0 million for the
purchase of geothermal leases for the Glass Mountain Project and $2.7 million
for the new rotor at the PG&E Unit 13 facility.
The Company continues to pursue the acquisition and development of
geothermal resources and new power generation projects. The Company expects to
commit significant capital during the remainder of 1996 and in future years for
the acquisition and development of these projects. The Company's actual capital
expenditures may vary significantly during any year.
In April 1996, the Company entered into a transaction involving a lease of
the King City Facility. The Company financed this transaction with the $45
Million Bank of Nova Scotia Loan, $13.3 million of borrowings under the Credit
Suisse Credit Facility (both of which were repaid with a portion of the net
proceeds from the sale of the 10 1/2% Senior Notes) and $50.0 million of
proceeds from the Preferred Stock Investment by Electrowatt. See
"Business -- Description of Facilities -- King City Facility."
The Company believes that it will have sufficient liquidity from cash flow
from operations, borrowings available from lines of credit and working capital
lines to satisfy all obligations under outstanding indebtedness, to finance
anticipated capital expenditures and to fund working capital requirements.
IMPACT OF RECENT ACCOUNTING PRONOUNCEMENTS
In March 1995, the Financial Accounting Standards Board 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 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. SFAS No. 121 must be adopted for fiscal years
beginning in 1996. The Company has 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 of the Company as of January
1, 1996.
In October 1995, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards ("SFAS") No. 123, Accounting for Stock-Based
Compensation. The disclosure requirements of SFAS No. 123 are effective for the
Company's 1996 fiscal year. The Company does not expect the new pronouncement to
have an impact on its results of operations since the intrinsic value-based
method prescribed by APB Opinion No. 25 and also allowed by SFAS No. 123 will
continue to be used by the Company to account for its stock-based compensation
plans.
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<PAGE> 38
BUSINESS
OVERVIEW
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
1,057 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 $41.2 million of total assets as of December 31,
1991 to $911.0 million of total assets on a pro forma basis as of June 30, 1996.
Calpine's revenue on a pro forma basis for 1995 increased to $224.3 million,
representing a compound annual growth rate of 55% since 1991. The Company's
EBITDA on a pro forma basis for 1995 increased to $123.8 million. See "Pro Forma
Consolidated 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 power generation facilities, as well as
marketing power and energy services to utilities and other end users.
THE MARKET
The power generation industry represents the third largest industry in the
United States, with an estimated end user market of approximately $207.5 billion
of electricity sales and 3.0 million gigawatt hours of production in 1995. In
response to increasing customer demand for access to low cost electricity and
enhanced services, new regulatory initiatives are currently being adopted or
considered at both state and federal levels to increase competition in the
domestic power generation industry. To date, such initiatives are under
consideration at the federal level and in approximately thirty states. For
example, in April 1996, FERC adopted Order No. 888, opening wholesale power
sales to competition and providing for open and fair electric transmission
services by public utilities. In addition, the CPUC has issued an electric
industry restructuring decision which envisions commencement of deregulation and
implementation of customer choice of electricity supplier by January 1, 1998.
Calpine believes that industry trends and such regulatory initiatives will lead
to the transformation of the existing market, which is largely characterized by
electric utility monopolies selling to a captive customer base, to a more
competitive market where end users may purchase electricity from a variety of
suppliers, including non-utility generators, power marketers, public utilities
and others. The Company believes that those market trends will create
substantial opportunities for companies such as Calpine that are low cost power
producers and have an integrated power services capability which enables them to
produce and sell energy to customers at competitive rates.
The Company also believes that these market trends will result in the
disposition of power generation facilities by utilities, independent power
producers and industrial companies. Utilities such as PG&E and Southern
California Edison Company have announced their intentions to sell power
generation facilities totalling approximately 3,150 megawatts and 5,000
megawatts, respectively. The independent power industry, which represents
approximately 8% of the installed capacity in the United States, or
approximately 59,000 megawatts, and has accounted for approximately 50% of all
additional capacity in the United States since 1990, is currently undergoing
significant consolidation. Many independent producers operating a limited number
of power plants are seeking to dispose of such plants in response to competitive
pressures, and industrial companies are selling their power plants to redeploy
capital in their core businesses. Over 200 independent power plant and portfolio
sale transactions have occurred in the past two years. The Company believes that
this consolidation will continue in the highly fragmented independent power
industry.
The power generation industry outside the United States is approximately
three times larger than the domestic market, and the demand for electricity is
growing rapidly. In 1996, it has been estimated that in excess of 590 gigawatts
of new capacity will be required outside the United States over the ensuing
ten-year
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<PAGE> 39
period. In order to satisfy this anticipated increase in demand, many countries
have adopted active government programs designed to encourage private investment
in power generation facilities. The Company believes that these programs will
create significant opportunities to acquire and develop power generation
facilities in such countries.
STRATEGY
Calpine's objective is to become a leading power company by capitalizing on
these 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 since 1993.
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 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 completion of financing and
obtaining 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 in excess 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
has established an integrated power marketing capability, conducted through its
wholly owned subsidiary, CPSC. In 1995, CPSC received approval from the 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
an investment in 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
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<PAGE> 40
investments in these projects will effectively position it for future expansion
in Southeast Asia and Latin America.
POWER GENERATION TECHNOLOGIES
NATURAL GAS-FIRED
Natural gas-fired power plants offer significant advantages over power
plants utilizing other fuel sources, such as coal, oil and nuclear energy,
including readily available supplies of natural gas, currently favorable prices,
highly efficient technology, higher availabilities, shorter construction periods
and lower capital and operating costs. In addition, natural gas-fired power
plants have fewer environmental impacts, including significantly lower emission
levels of certain pollutants than power plants utilizing other fossil fuels such
as coal and oil. During recent years, natural gas-fired power plants have
accounted for a substantial portion of the annual increase in independent power
capacity in the United States, and natural gas-fired power generation has become
the predominant power generation technology utilized for the production of
electricity by new power plants in the United States. Industry analysts have
predicted that natural gas will continue to be the dominant fuel for new power
generation facilities in the United States for the foreseeable future.
LOGO
GEOTHERMAL
Geothermal energy is a clean, alternative source of power that is produced
by utilizing hot water or steam that has been naturally heated by the earth.
Geothermal energy is found in areas of the world where heat within the earth's
crust is close to the surface. These areas generally coincide with the
boundaries of the earth's tectonic plates. Exploitable geothermal reservoirs
have three primary defining characteristics: (i) a high heat flow near the
surface, (ii) a porous geologic medium where water can circulate to become
heated
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<PAGE> 41
and (iii) an impermeable cap rock to prevent dispersion of the heated fluids.
Factors that affect the ability to exploit geothermal energy include the ability
to drill wells and produce fluids from the porous medium, the temperature and
quantity of the fluids and the chemical characteristics of the fluids. In
addition, the productive capacity of geothermal wells decreases over time,
requiring the drilling of new wells in an effort to maintain production.
LOGO
Geothermal energy facilities, such as those currently owned and operated by
the Company, provide significant advantages over other alternative power
generation technologies, such as wind, solar or solid waste/biomass, including
lower operating and maintenance costs per kilowatt hour, shorter construction
periods and higher plant availability. Geothermal energy also provides a
reliable and environmentally preferred source of electricity, emitting
significantly lower levels of pollutants than are released from power plants
utilizing fossil fuels. As a result of these and other advantages, as well as
federal and state tax incentives that have been adopted to encourage the
development of geothermal power generation projects, the Company believes that
there will continue to be demand for the production of electricity using
geothermal energy.
The geothermal energy capacity of the United States is located
predominantly in the western states in tectonically active regions. Total
installed geothermal capacity in the United States was approximately 2,925
megawatts as of the end of 1995, with approximately 2,650 megawatts located in
California and 275 megawatts located in Nevada, Utah and Hawaii. The Geysers
constitute the world's largest developed geothermal reservoir. The Geysers steam
fields have been in commercial production since 1960, and currently are capable
of producing an amount of steam sufficient to generate 1,200 megawatts of
electricity.
DESCRIPTION OF FACILITIES
The Company has interests in 15 power generation facilities and steam
fields with a current aggregate capacity of approximately 1,057 megawatts,
consisting of seven natural gas-fired cogeneration facilities 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 468 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.
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<PAGE> 42
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 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 Thermal Power
Company Steam Fields that produce steam for sale under steam sales agreements
and for use in producing electricity from its wholly owned geothermal power
generation facilities. See "-- 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
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
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<PAGE> 43
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.
LOGO
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
"-- Government Regulation."
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The table below sets forth certain information regarding the Company's
power generation facilities and steam fields currently in operation.
POWER GENERATION FACILITIES
<TABLE>
<CAPTION>
COMMENCEMENT TERM OF
POWER NAMEPLATE CALPINE CALPINE NET OF POWER
GENERATION CAPACITY INTEREST INTEREST COMMERCIAL UTILITY SALES
FACILITY TECHNOLOGY (MEGAWATTS)(1) (PERCENTAGE) (MEGAWATTS) OPERATION PURCHASER AGREEMENT
- --------------------- ------------ -------------- ---------- ----------- ------------ ------------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
Sumas................ Gas-Fired 125 75%(2) 93.8 1993 Puget Sound 2013
Cogeneration Power &
Light
King City............ Gas-Fired 120 100% 120 1989 Pacific Gas & 2019
Cogeneration Electric
Gilroy............... Gas-Fired 120 100% 120 1988 Pacific Gas & 2018
Cogeneration Electric
Greenleaf 1.......... Gas-Fired 49.5 100% 49.5 1989 Pacific Gas & 2019
Cogeneration Electric
Greenleaf 2.......... Gas-Fired 49.5 100% 49.5 1989 Pacific Gas & 2019
Cogeneration Electric
Agnews............... Gas-Fired 29 20% 5.8 1990 Pacific Gas & 2021
Cogeneration Electric
Watsonville.......... Gas-Fired 28.5 100% 28.5 1990 Pacific Gas & 2009
Cogeneration Electric
West Ford Flat....... Geothermal 27 100% 27 1988 Pacific Gas & 2008
Electric
Bear Canyon.......... Geothermal 20 100% 20 1988 Pacific Gas & 2008
Electric
Aidlin............... Geothermal 20 5% 1 1989 Pacific Gas & 2009
Electric
</TABLE>
STEAM FIELDS
<TABLE>
<CAPTION>
APPROXIMATE CALPINE CALPINE NET COMMENCEMENT
CAPACITY INTEREST INTEREST OF COMMERCIAL UTILITY ESTIMATED
STEAM FIELD (MEGAWATTS)(3) (PERCENTAGE) (MEGAWATTS) OPERATION PURCHASER LIFE(4)
- ------------------------------ ------------- ---------- ---------- ------------- ---------------- ---------
<S> <C> <C> <C> <C> <C> <C>
Thermal Power Company......... 151 100% 151 1960 Pacific Gas 2018
& Electric
PG&E Unit 13.................. 100 100% 100 1980 Pacific Gas 2018
& Electric
PG&E Unit 16.................. 78 100% 78 1985 Pacific Gas 2018
& Electric
SMUDGEO #1.................... 59 100% 59 1983 Sacramento 2018
Municipal
Utility District
Cerro Prieto.................. 80 100%(5) 80 1973 Comision 2000(6)
Federal de
Electricidad
</TABLE>
- ------------
(1) Nameplate capacity may not represent the actual output for a facility at any
particular time.
(2) See "-- Power Generation Facilities -- Sumas Facility" for a description of
the Company's interest in the Sumas partnership and current sales of power
by the Sumas Facility.
(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."
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<PAGE> 45
POWER GENERATION FACILITIES
Sumas Facility
The Sumas cogeneration facility (the "Sumas Facility") 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 Facility. 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 Facility 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
bearing interest at 16.25% and matures in 2004. The Sumas Facility commenced
commercial operation in April 1993.
The Company managed the engineering, procurement and construction of the
power plant and related facilities of the Sumas Facility, including the gas
pipeline. The Sumas Facility was constructed by a Washington joint venture
formed by Industrial Power Corporation and Haskell Corporation. The Sumas
Facility 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 Facility has operated at an average
availability of approximately 96.5%.
The Sumas Facility'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 LIBOR, which are
amortized over a 15-year period.
Electrical energy generated by the Sumas Facility is sold to Puget Sound
Power & Light Company ("Puget") under the terms of a 20-year power sales
agreement terminating in 2013. Under the power sales agreement, Puget has agreed
to purchase an annual average of 123 megawatts of electrical energy.
The power sales agreement provides for the sale of electrical energy at a
total price equal to the sum of (i) a fixed price component and (ii) a variable
price component multiplied by an escalation factor for the year in which the
energy is delivered. The schedule of annual fixed average energy prices
(expressed in cents per kilowatt hour) in effect through 2013 under the Sumas
power sales agreement is as follows:
<TABLE>
<CAPTION>
FIXED FIXED FIXED
ENERGY ENERGY ENERGY
YEAR PRICE YEAR PRICE YEAR PRICE
- -------------------- ------ -------------------- ------ -------------------- ------
<S> <C> <C> <C> <C> <C>
1996................ 3.19c
1997................ 3.38c
1998................ 3.64c
1999................ 3.98c
2000................ 4.23c
2001................ 6.23c
2002................ 6.11c
2003................ 6.22c
2004................ 6.33c
2005................ 6.45c
2006................ 6.57c
2007................ 5.23c
2008................ 5.31c
2009................ 5.40c
2010................ 5.49c
2011................ 5.58c
2012................ 5.58c
2013................ 5.58c
</TABLE>
The variable price component is set according to a scheduled rate set forth in
the agreement, which in 1995 was .97c per kilowatt hour, and escalates annually
by a factor equal to the U.S. Gross National Product Implicit Price Deflator.
For 1995, the average price paid by Puget under the power sales agreement was
2.954c per kilowatt hour. Pursuant to the power sales agreement, Puget may
displace the production of the Sumas Facility when the cost of Puget's
replacement power is less than the Sumas Facility's incremental power generation
costs. Thirty-five percent of the savings to Puget under this displacement
provision are shared with
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<PAGE> 46
the Sumas Facility. In 1995, the Sumas Facility's net profit was increased by
$278,000 as a result of the displacement provision. The Company currently
estimates a similar level of displacement in 1996 as that experienced in 1995.
In addition to the sale of electricity to Puget, pursuant to a long-term
steam supply and dry kiln lease agreement, the Sumas Facility 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 Facility's QF
status. See "-- Government Regulation."
In connection with the development of the Sumas Facility, 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 totalled 138 billion cubic feet as of January 1, 1996. 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 12,000 million British thermal units per day ("mmbtu/day") to the
Sumas Facility. The remaining 13,000 mmbtu/day requirement is being supplied
under a one-year contract with West Coast Gas Services, Inc. The Company
believes that the gas reserves owned by ENCO and the availability of
supplemental gas supplies are sufficient to fuel the Sumas Facility through the
year 2013.
The Company operates and maintains the Sumas Facility 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 Facility 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 1995, the Sumas Facility generated approximately 1,026,000,000
kilowatt hours of electrical energy and approximately $31.5 million of total
revenue. In 1995, the Company recognized a loss of approximately $3.0 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 Facility
The King City cogeneration facility (the "King City Facility") 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, A California Limited Partnership ("BAF").
Under the terms of the operating lease, Calpine makes semi-annual lease payments
to BAF, a portion of which is supported by a $100.7 million collateral fund,
owned by the Company. The collateral consists of a portfolio of investment grade
and U.S. Treasury Securities that will mature serially in amounts equal to a
portion of the lease payments.
The Company financed the collateral fund and other transaction costs with
the $45 Million Bank of Nova Scotia Loan and $13.3 million of borrowings under
the Credit Suisse Credit Facility (both of which were repaid with a portion of
the net proceeds from the sale of the 10 1/2% Senior Notes), as well as $50.0
million of proceeds from the Preferred Stock Investment by Electrowatt.
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 Facility commenced commercial operation in 1989 and has
operated at an average availability of approximately 97%.
46
<PAGE> 47
Electricity generated by the King City Facility is sold to PG&E under a
30-year power sales agreement terminating in 2019. The power sales agreement
contains payment provisions for capacity and energy. The power sales agreement
provides for a firm capacity payment of $184 per kilowatt year for 111 megawatts
for the term of the agreement so long as the King City Facility delivers 80% of
the firm capacity during designated periods of the year. Additional capacity
payments are received for as-delivered capacity in excess of 111 megawatts
delivered during peak and partial peak hours. The following schedule sets forth
the as-delivered capacity prices per kilowatt year:
<TABLE>
<CAPTION>
AS-DELIVERED
YEAR CAPACITY PRICE
---------------------------------------------------- --------------
<S> <C>
1996................................................ $176
1997................................................ $188
1998................................................ $188
</TABLE>
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 schedule of fixed average energy prices (expressed in cents per kilowatt
hour) in effect through 1998 under the King City Facility power sales agreement
is as follows:
<TABLE>
<CAPTION>
ENERGY
YEAR PRICE
-------------------------------------------------------- ------
<S> <C>
1996.................................................... 12.24c
1997.................................................... 13.14c
1998.................................................... 13.14c
</TABLE>
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 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 1995,
PG&E's avoided cost of energy averaged approximately 1.84c 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 Facility 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 .7c per
kilowatt hour for all energy delivered from the King City Facility.
In addition to the sale of electricity to PG&E, the King City Facility
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 Facility'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 Facility 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. The Company believes that
upon expiration of these agreements that it will be able to obtain sufficient
quantities and firm transportation of natural gas to operate the King City
Facility for the remaining term of the power sales agreement.
Fee title to the premises is owned by Basic American, Inc., who 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 Facility. The Company is subleasing the
premises, together with certain easements, from such affiliate of BAF pursuant
to a ground sublease for approximately 15 acres.
47
<PAGE> 48
Gilroy Facility
On August 29, 1996, the Company acquired the Gilroy cogeneration facility
(the "Gilroy Facility"), a 120 megawatt gas-fired cogeneration power plant
located in Gilroy, California, from McCormick & Company, Inc. The Company
purchased the Gilroy 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.
The acquisition of the Gilroy Facility was financed utilizing a
non-recourse project loan in the aggregate amount of $116.0 million. Such loan,
which was provided by Banque Nationale de Paris, consists of a 15-year tranche
in the amount of $81.0 million and an 18-year tranche in the amount of $35.0
million and bears interest at fixed and floating rates.
The 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 Facility commenced commercial operation in March 1988
and has operated at an average availability of approximately 98.5%.
Electricity generated by the Gilroy Facility 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 Facility 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. The following schedule sets forth the as-delivered capacity
prices per kilowatt year:
<TABLE>
<CAPTION>
AS-DELIVERED
YEAR CAPACITY PRICE
-------------------------------------------------------- --------------
<S> <C>
1996.................................................... $176
1997.................................................... $188
</TABLE>
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 period of dispatchable operation at a price equal
to PG&E's avoided cost of energy excluding adders (as determined by the CPUC).
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 varies from month to month and has
ranged from an annual average of 1.84c to 2.96c per kilowatt hour since 1992.
During 1995, PG&E's avoided cost of energy averaged approximately 1.84c 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 Facility operates.
In addition to the sale of electricity to PG&E, the Gilroy Facility
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 Facility, 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
Facility's QF status. See "-- Government Regulation."
Natural gas for the Gilroy Facility is supplied pursuant to a contract with
Amoco Energy Trading Corporation ("Amoco") expiring July 31, 1997. The Company
believes that upon expiration of this fuel supply agreement, it will be able to
obtain a sufficient quantity of natural gas to operate the Gilroy Facility for
the remaining term of the power sales agreement. Natural gas is transported
under a firm transportation agreement, expiring July 1, 1997, via a dedicated
300-yard pipeline owned and maintained by PG&E.
The Gilroy Facility is located on approximately five acres of land which is
leased to the Company by Gilroy Foods. The lease term runs concurrent with the
term of the power sales agreement.
48
<PAGE> 49
Greenleaf 1 and 2 Facilities
On April 21, 1995, Calpine completed the acquisition of the Greenleaf 1 and
2 cogeneration facilities (the "Greenleaf 1 and 2 Facilities") from Radnor Power
Corporation, an affiliate of LFC Financial Corporation ("LFC"), for an adjusted
purchase price of $81.5 million.
On June 30, 1995, Calpine refinanced the existing debt on the Greenleaf 1
and 2 Facilities 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 (6.5% as of
December 31, 1995) with the amortization of principal based on a fixed schedule
through December 31, 2010.
The Greenleaf 1 and 2 Facilities 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 that is connected to the facilities. Calpine Fuels is committed
to purchasing all gas produced by MNI under this agreement which terminates in
December 2019. The quantity of gas produced by MNI varies and is currently less
than the facilities' full requirements. As a result, Calpine Fuels has
supplemented the MNI gas supply with a short-term contract with Coastal Gas
Marketing Company, which expires on September 30, 1996. This gas is delivered
over PG&E's intrastate pipeline which is directly connected to each facility.
The Greenleaf 1 and 2 Facilities have interruptible transportation agreements
with PG&E, expiring in June 1997. The Company believes that it will be able to
obtain a sufficient quantity of natural gas to operate the Greenleaf 1 and 2
Facilities for the remaining term of the power sales agreement.
Greenleaf 1 Facility. The Greenleaf 1 cogeneration facility (the
"Greenleaf 1 Facility") is a 49.5 megawatt natural gas-fired cogeneration
facility located near Yuba City, California. The Greenleaf 1 Facility 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
Facility 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 94.4%.
Electricity generated by the Greenleaf 1 Facility is sold to PG&E under a
30-year power sales agreement terminating in 2019 which contains payment
provisions for capacity and energy. The power sales agreement provides for a
firm capacity payment of $184 per kilowatt year for 49.2 megawatts for the term
of the agreement, so long as the Greenleaf 1 Facility delivers 80% of its firm
capacity during certain designated periods of the year, and an as-delivered
capacity payment for an additional .3 megawatts of capacity. The following
schedule sets forth the as-delivered capacity prices per kilowatt year through
1997 under the Greenleaf 1 Facility power sales agreement:
<TABLE>
<CAPTION>
AS-DELIVERED
YEAR CAPACITY PRICE
---------------------------------------------------- --------------
<S> <C>
1996................................................ $176
1997................................................ $188
</TABLE>
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 1995, PG&E's avoided cost of
energy averaged approximately 1.84c per kilowatt hour.
49
<PAGE> 50
In accordance with the power sales agreement, PG&E is entitled to curtail
the Greenleaf 1 Facility during hydro-spill periods, or during periods of
negative avoided costs. During 1995, the Greenleaf 1 Facility did not experience
curtailment, and the Company does not expect to experience curtailment at such
facility during 1996. 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 Facility
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 Facility's QF
status. See "-- Government Regulation."
The Greenleaf 1 Facility is located on 77 acres owned by the Company near
the rural area of Yuba City, California.
From April 21, 1995 through December 31, 1995, the Greenleaf 1 Facility
generated approximately 258,921,000 kilowatt hours of electric energy for sale
to PG&E and approximately $13.9 million in revenue.
Greenleaf 2 Facility. The Greenleaf 2 cogeneration facility (the
"Greenleaf 2 Facility") is a 49.5 megawatt natural gas-fired cogeneration
facility located near Yuba City, California. The Greenleaf 2 Facility includes a
STIG LM5000 gas turbine manufactured by General Electric and a Deltak heat
recovery steam generator. The Greenleaf 2 Facility 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 95%.
Electricity generated by the Greenleaf 2 Facility 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 Facility delivers 80% of its firm
capacity during certain designated periods of the year, and an as-delivered
capacity payment for an additional .3 megawatts of capacity. The following
schedule sets forth the as-delivered capacity prices per kilowatt year through
1997 under the Greenleaf 2 Facility power sales agreement:
<TABLE>
<CAPTION>
AS-DELIVERED
YEAR CAPACITY PRICE
---------------------------------------------------- --------------
<S> <C>
1996................................................ $176
1997................................................ $188
</TABLE>
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 1995, PG&E's avoided cost of
energy averaged approximately 1.84c per kilowatt hour.
In accordance with the power sales agreement, PG&E is entitled to curtail
the Greenleaf 2 Facility during hydro-spill periods or during any period of
negative avoided costs. During 1995, the Greenleaf 2 Facility did not experience
curtailment, and the Company does not expect to experience curtailment at such
facility during 1996. 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 Facility
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 Facility as a QF. See "-- Government
Regulation."
The Greenleaf 2 Facility is located on 2.5 acres of land under a lease from
Sunsweet, which runs concurrent with the power sales agreement.
50
<PAGE> 51
From April 21, 1995 through December 31, 1995, the Greenleaf 2 Facility
generated approximately 276,038,000 kilowatt hours of electric energy for sale
to PG&E and approximately $14.5 million of revenue.
Agnews Facility
The Agnews cogeneration facility (the "Agnews Facility") 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 Facility 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 Facility. The Company and GATX managed the development and financing
of the Agnews Facility, which commenced commercial operations in December 1990.
The Company managed the engineering, construction and start-up of the
Agnews Facility. 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 Facility has operated at an average availability of
approximately 96.5%.
The total cost of the Agnews Facility was approximately $39 million. The
construction financing was provided by Credit Suisse in the amount of $28.0
million. After the commencement of commercial operation, the facility 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 Facility 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 Facility 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. The
following schedule sets forth the as-delivered capacity prices per kilowatt year
through 1998 under the Agnews Facility power sales agreement:
<TABLE>
<CAPTION>
AS-DELIVERED
YEAR CAPACITY PRICE
---------------------------------------------------- --------------
<S> <C>
1996................................................ $176
1997................................................ $188
1998................................................ $188
</TABLE>
Thereafter, the payment for as-delivered capacity will be at 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 1995, PG&E's avoided cost of energy averaged approximately
1.84c per kilowatt hour.
Under certain circumstances, PG&E may curtail energy deliveries for up to
1,000 off-peak hours per year. During 1995, PG&E curtailed the energy purchased
under the power sales agreement by 1,000 hours. The Company currently expects
the maximum amount of curtailment allowed under the agreement during 1996.
51
<PAGE> 52
In addition to the sale of electricity to PG&E, the Agnews Facility
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 Facility 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 Facility's QF status. See "-- Government Regulation."
The supply of natural gas for the Agnews Facility 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. The
Company believes that, upon expiration of this fuel supply agreement, it will be
able to obtain a sufficient quantity of natural gas to operate the Agnews
Facility for the remaining term of the power sales agreement. Intrastate
transportation is provided under a firm gas transportation agreement with PG&E
expiring in June 1997.
The Agnews Facility 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 has an initial term of six years expiring on
December 31, 1996 and may be automatically renewed for an additional six-year
term, provided certain performance standards are met, and thereafter upon
mutually agreeable terms. The Company expects the contract will be renewed on
December 31, 1996.
The Agnews Facility 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 Facility, as well as a purchase option
at fair market value.
During 1995, the Agnews Facility generated approximately 225,683,000
kilowatt hours of electrical energy and total revenue of $10.8 million. In 1995,
the Company recognized a loss of approximately $82,000 as a result of the
Company's 20% ownership interest and recorded revenue of $1.5 million for
services performed under the operating and maintenance agreement.
Watsonville Facility
The Watsonville cogeneration facility (the "Watsonville Facility") 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 Facility 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 96.5%.
Electricity generated by the Watsonville Facility 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 Facility 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 an additional 7.6 megawatts of
capacity. In addition, the power sales agreement provides for payments for up to
28.5 megawatts of electrical energy actually delivered. Through April of 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
52
<PAGE> 53
hour) and the as-delivered capacity prices per kilowatt year through 2000 for
energy deliveries under the Watsonville Facility power sales agreement:
<TABLE>
<CAPTION>
ENERGY AS-DELIVERED
YEAR PRICE CAPACITY PRICE
-------------------------------------------- ------- --------------
<S> <C> <C>
1996........................................ 12.24c $176
1997........................................ 13.14c $188
1998........................................ 13.90c $188
1999........................................ 13.90c $188
2000........................................ 13.90c $188
</TABLE>
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 1995, PG&E's avoided cost of energy averaged approximately
1.84c per kilowatt hour.
Under certain circumstances, PG&E may curtail energy deliveries for a block
of up to 400 hours between January 1 and April 15 and an additional 900 off-peak
hours from October 1 though April 30. From June 29, 1995 through December 31,
1995, PG&E curtailed energy purchases of 212 hours under the power sales
agreement.
In addition to the sale of electricity to PG&E, during 1995 the Watsonville
Facility 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 Facility has
constructed a water distillation facility on the site of the Watsonville
Facility 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 Facility's QF status. See "-- Government Regulation."
Amoco is the supplier of natural gas to the Watsonville Facility. The
Company has negotiated a contract with Amoco, which it expects to execute by
September 1, 1996 and which will be effective through June 30, 1997. In the
interim, the Company has executed a series of monthly contracts with Amoco. PG&E
provides firm gas transportation to the Watsonville Facility under a contract
expiring June 30, 1997. The Company believes that upon expiration of this fuel
supply agreement, it will be able to obtain a sufficient quantity of natural gas
to operate the Watsonville Facility for the remaining term of the power sales
agreement.
The Watsonville Facility is located on 1.8 acres of land leased from Dean
Foods under the terms of a 30-year lease expiring in 2010.
For the period from June 29, 1995 to December 31, 1995, the Watsonville
Facility generated approximately 117,147,000 kilowatt hours of electrical energy
for sale to PG&E and approximately $5.9 million in revenue.
West Ford Flat Facility
The West Ford Flat geothermal facility (the "West Ford Flat Facility")
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 Facility 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 Facility
commenced commercial operation in December 1988. Since start-up, the West Ford
Flat Facility has operated at an average availability of approximately 98%.
53
<PAGE> 54
Electricity generated by the West Ford Flat Facility 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 Facility
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 schedule of fixed average energy prices (expressed in cents
per kilowatt hour) in effect through 1998 under the West Ford Flat Facility
power sales agreement is as follows:
<TABLE>
<CAPTION>
ENERGY
YEAR PRICE
-------------------------------------------------------- ------
<S> <C>
1996.................................................... 12.89c
1997.................................................... 13.83c
1998.................................................... 13.83c
</TABLE>
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 1995,
PG&E's avoided cost of energy averaged approximately 1.84c 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 1995, 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 1996.
The Company believes that the geothermal reserves that supply energy for
use by the West Ford Flat Facility will be sufficient to operate at full
capacity for the entire term of the power sales agreement due 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 Facility.
The West Ford Flat Facility 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 "-- Properties."
During 1995, the West Ford Flat Facility generated approximately
216,614,000 kilowatt hours of electrical energy for sale to PG&E and
approximately $29.4 million of revenue.
Bear Canyon Facility
The Bear Canyon facility (the "Bear Canyon Facility") 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 Facility. The Bear Canyon Facility 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
eight production wells, an injection well and steam reserves. The Bear Canyon
Facility commenced commercial operation in October 1988. Since start-up, the
Bear Canyon Facility has operated at an average availability of approximately
98.4%.
Electricity generated by the Bear Canyon Facility 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 Facility 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
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through the initial ten-year term of the agreement ending September 1998. 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 1998 for energy deliveries under the Bear Canyon Facility power sales
agreements:
<TABLE>
<CAPTION>
ENERGY AS-DELIVERED
YEAR PRICE CAPACITY PRICE
-------------------------------------------- ------- --------------
<S> <C> <C>
1996........................................ 12.89c $176
1997........................................ 13.83c $188
1998........................................ 13.83c $188
</TABLE>
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 1995, PG&E's avoided cost of energy averaged approximately
1.84c 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 1995, 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 1996.
The Company believes that the geothermal reserves for the Bear Canyon
Facility 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 Facility.
The Bear Canyon Facility 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 "-- Properties."
During 1995, the Bear Canyon Facility generated approximately 164,847,000
kilowatt hours of electrical energy and approximately $21.8 million of revenue.
Aidlin Facility
The Aidlin geothermal facility (the "Aidlin Facility") 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 Facility. The Company's ownership
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 Facility.
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
Facility commenced commercial operation in May 1989.
The Aidlin Facility includes a power plant consisting of two turbine
generators manufactured by Fuji Electric and ABB Industries, Inc., as well as
seven production wells and two injection wells. Since start-up, the Aidlin
Facility has operated at an average availability of approximately 99%.
The construction of the Aidlin Facility 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 Facility 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
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<PAGE> 56
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
Facility delivers 80% of its capacity during certain designated periods of the
year. In addition, the Aidlin Facility power sales agreements provide for energy
payments for 20 megawatts based on a schedule of fixed energy prices (expressed
in cents per kilowatt hour) in effect through 1999 as follows:
<TABLE>
<CAPTION>
ENERGY
YEAR PRICE
-------------------------------------------------------- ------
<S> <C>
1996.................................................... 12.89c
1997.................................................... 13.83c
1998.................................................... 13.83c
1999.................................................... 13.83c
</TABLE>
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 1995,
PG&E's avoided cost of energy averaged approximately 1.84c 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 1995, PG&E curtailed the energy purchased
under this agreement by 1,000 hours. The Company currently expects the maximum
amount of curtailment under the agreement in 1996.
The output of the Aidlin Facility is expected to decline over the remaining
life of the facility unless additional reserves are developed on existing or
adjacent leases and enhanced water injection projects are successful in reducing
field declines. See "Risk Factors -- Risks Related to the Development and
Operation of Geothermal Energy Resources."
The Aidlin Facility 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 Facility 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 1995, the Aidlin Facility generated approximately 174,087,000
kilowatt hours of electrical energy and revenue of $21.7 million. In 1995, the
Company recognized revenue of approximately $277,000 as a result of the
Company's 5% ownership interest and $3.5 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 247 production wells,
19 injection wells and 52 miles of steam-transporting pipeline. See
"-- Properties." The 12 plants have a nameplate capacity of 978 megawatts and
currently have the capability to operate at 604 megawatts providing the Company
with an effective interest in 151 megawatts. The steam fields commenced
commercial operation in 1960.
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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 1995
was 1.647c per kilowatt hour. In addition, the Company receives a monthly fee
for effluent disposal and maintenance. During 1995, such monthly fee was
$144,000 per month.
In March 1996, the Company and Union Oil Company of California ("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 strategy 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 million. Accordingly, the
Company's share of offsets in 1995 was $757,000. In approximately 1999, when
total offsets may exceed $15 million in accordance with the agreement, the
Company's share of offset payments to PG&E would be approximately 2 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 1995, the Thermal Power Company Steam Fields
experienced extensive 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 $12,800 per month during 1995. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations."
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
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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 1995, the PG&E power plants produced 2,688,176,000 kilowatt hours of
electrical energy of which the Company's 25% share is 672,044,000 kilowatt hours
for approximately $11.0 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 "-- Properties." Unit 13 and Unit 16
have nameplate capacities of 134 and 113 megawatts, respectively, and currently
operate at outputs of approximately 100 and 78 megawatts, respectively. The PG&E
Unit 13 Steam Field includes 956 acres, 30 production wells, two injection wells
and five miles of pipeline, and commenced commercial operations in May 1980. The
PG&E Unit 16 Steam Field includes 675 acres, 19 producing wells, two injection
wells, and three miles of pipeline, and commenced commercial operation in
October 1985.
The PG&E Unit 13 and Unit 16 Steam Fields produce steam for sale to PG&E
under long-term steam sales agreements. Under the steam sales agreements with
PG&E, the Company is paid for steam on the basis of the amount of electricity
produced by Unit 13 and Unit 16. The price paid for steam under the PG&E Unit 13
and Unit 16 Steam Fields agreements is determined according to a formula that is
essentially a weighted average of PG&E's fossil (oil and gas) fuel price and
PG&E's nuclear fuel price. The price of steam for 1995 was 1.207c per kilowatt
hour. The price for 1996 is expected to be approximately .995c. The Company
receives an additional .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 64,000,000 kilowatt hours under
the steam sales agreement during 1995. The Company currently expects
approximately the same amount of curtailment under the agreement during 1996
that was experienced in 1995.
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 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
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PG&E to operate at variable pressure operations which will optimize production
at the PG&E Unit 13 and Unit 16 Steam Fields.
The PG&E Unit 13 and Unit 16 Steam Fields currently supply steam sufficient
to operate Unit 13 and Unit 16 at approximately 72% 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 10% until curtailment of neighboring plants and Unit 13 and Unit
16 in 1995 reduced the decline to zero. The Company expects steam field
productivity to continue to decline in the future, but at decreasing 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 1995, the PG&E Unit 13 and Unit 16 Steam Fields produced sufficient
steam to permit Unit 13 and Unit 16 to produce approximately 1,296,900,000
kilowatt hours of electrical energy and approximately $16.3 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 SMUD SMUDGEO #1 steam fields (the "SMUDGEO
#1 Steam Fields"). See "-- 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 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 $1.746 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 .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 increased
in productivity in 1995 due to curtailment of neighboring plants, the Company
expects the SMUDGEO #1 Steam Fields' productivity to decline in the future.
During 1995, the SMUDGEO #1 Steam Fields produced approximately 6,600,835
thousand pounds of steam and approximately $12.3 million of revenue.
Cerro Prieto Steam Fields
On November 17, 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
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Company has agreed to invest up to $20 million in the Cerro Prieto steam fields
(the "Cerro Prieto Steam Fields") located in Baja California, Mexico. The Cerro
Prieto Steam Fields provide geothermal steam to three geothermal power plants
owned and operated by Comision Federal de Electricidad, the Mexican national
utility ("CFE").
The Company's investment consists of a loan of up to $18.5 million and a
$1.5 million payment for an option to purchase a 29% equity interest in
Coperlasa for $5.8 million, which payment was made in December 14, 1995. This
option expires in May 1997.
The $18.5 million loan was made in installments throughout 1996, which
provided capital to Coperlasa to fund the drilling of new wells and the repair
of existing wells to meet its performance under its agreement with CFE. The loan
matures in November 1999 and bears interest at an effective rate of 18.8% per
annum. Repayment of this loan will be interest only for the first 18 months.
Thereafter, 100% of the cash flow generated from the sale of steam less
operating expenses and capital expenditures will be used to pay principal and
interest on the loan. The Company's loan is senior to the existing debt at
Coperlasa.
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 -- Project Development Risks."
PASADENA COGENERATION PROJECT
Calpine was selected by Phillips Petroleum Company ("Phillips") to
negotiate for the development of a 240 megawatt gas-fired cogeneration project
at the Phillips Houston Chemical Complex ("HCC") located in Pasadena, Texas (the
"Pasadena Cogeneration Project"). In July 1995 and March 1996, the Company
entered into Energy Project Development Agreements with Phillips pursuant to
which the Company and Phillips propose to enter into 20-year agreements for the
purchase and sale of 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. Pursuant to the Energy Project Development
Agreements, the Company has agreed to make $3.5 million of capital expenditures
on the Pasadena Cogeneration Project during 1996. In addition, the Company has
provided a $3.0 million letter of credit to Phillips to secure the performance
under the Energy Project Development Agreement. On August 2, 1996, the Company
entered into a commitment letter with ING Capital Corporation to provide $100.0
million of non-recourse project financing for the Pasadena Cogeneration Project.
The Company expects to complete financing and commence construction in September
1996, with commercial operation scheduled to begin in August 1998. However,
there can be no assurances that the Company will be successful in completing
either the agreements with Phillips or any additional power sales agreements or
that the anticipated schedule for financing and construction will be met.
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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.
In August 1994, the Company entered into a partnership with Trans-Pacific
Geothermal Glass Mountain, Ltd. ("TGC") to construct and operate a 30 megawatt
project at Glass Mountain. 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 Calpine partnership and the relocation of the project to Glass Mountain. The
memorandum of understanding contemplates execution of a 45-year power purchase
agreement subject to satisfaction of certain conditions precedent and includes
an option for an additional 100 megawatts.
Subject to the execution of the power purchase agreement with BPA, the
Company plans to begin construction of an initial 45 megawatt phase of the Glass
Mountain Project in 1998. The Company is in the process of preparing an
Environmental Impact Statement and commercial operation is planned for 2000.
There can be no assurances, however, that the Company and BPA will enter into a
definitive agreement, that this project will be completed on this schedule, if
at all, or that commercial operation of this project will be successful.
In March 1996, the Company completed the acquisition of certain Glass
Mountain geothermal leases previously held by FMRP. As a result, the Company
currently holds an interest in approximately 29,000 acres of federal geothermal
leases at Glass Mountain. See "-- Properties."
COSO GEOTHERMAL PROJECT
In January 1992, the Company was selected by the Los Angeles Department of
Water and Power (the "Department") to negotiate for the development of up to 150
megawatts of electric generating capacity utilizing geothermal energy from the
Department's Coso geothermal leaseholds. Data from four deep exploration wells
and a number of shallow, temperature gradient wells indicate that a productive
area could exist with a capacity to support 200 megawatts or more. The resource
is on land leased by the Department from the United States Bureau of Land
Management ("BLM"), which is subleased to the Company.
The Company entered into definitive agreements with the Department in 1995
which granted the Company the right to develop the Department's Coso geothermal
leaseholds located in Inyo County, California and to produce steam or
electricity for sale to third parties. In addition, the agreements include an
amended power sales agreement with the Department which grants the Department an
option to purchase up to 150 megawatts of electricity from the geothermal
resource. The ordinance approving the agreements has been passed by the Los
Angeles City Council and approved by the Mayor.
In January 1996, certain litigation was filed against the Department
seeking to compel the Department to submit the agreements entered into with the
Company to a public bidding procedure in accordance with the Charter of the City
of Los Angeles. In August 1996, the court ruled that certain of the rights
granted by the Department in the agreements, including the right to produce
steam or electricity for sale to third parties, were void and were required to
be submitted to such a public bidding procedure. The Company is unable to
predict the impact of such ruling on the agreements and the development of the
Department's Coso geothermal leaseholds.
NAVAJO SOUTH COAL PROJECT
Calpine, BHP Minerals International Inc. and BHP Power Inc. have entered
into a memorandum of understanding to assess the development of the Navajo South
Project, a 1,700 megawatt coal-fired power generation facility in the Four
Corners area of New Mexico. It is anticipated that this new power plant will
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provide electricity to the west and southwest United States markets. BHP
Minerals International Inc. is the owner and operator of three coal mines in the
Four Corners area of New Mexico. One of these, the Navajo Mine, is located on
the Navajo Reservation.
BLACK HILLS COAL PROJECT
Calpine and Black Hills Corporation have entered into a joint venture
agreement to assess the development of the WYGEN Project, an 80 megawatt
coal-fired power generation facility located in northeastern Wyoming. It is
anticipated that this new power plant will provide electricity to the western
United States markets, with a commercial operation date expected in 1999. Black
Hills Corporation, the parent of Black Hills Power & Light Company, is a public
utility located in South Dakota.
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 1996 and 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 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.
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FEDERAL ENERGY REGULATION
PURPA
The enactment in 1978 of 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 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, 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. FERC regulations also permit QFs and utilities to negotiate
agreements for utility purchases of power at rates lower than the utility's
avoided costs. Due to increasing competition for utility contracts, the current
practice is for most power sales agreements to be awarded at a rate below
avoided cost. While public utilities are not explicitly required by PURPA to
enter into long-term power sales agreements, PURPA helped to create a regulatory
environment in which it has been common for long-term agreements to be
negotiated.
In order to be a QF, a cogeneration facility must produce not only
electricity, but also useful thermal energy for use in an industrial or
commercial process for heating or cooling applications in certain proportions to
the facility's total energy output and must meet certain energy efficiency
standards. Finally, a QF (including a geothermal or hydroelectric QF or other
qualifying small power producer) must not be controlled or more than 50% owned
by an electric utility or by most electric utility holding companies, or a
subsidiary of such a utility or holding company or any combination thereof.
The Company endeavors to develop its projects, monitor compliance by the
projects with applicable regulations and choose its customers in a manner which
minimizes the risks of any project losing its QF status. Certain factors
necessary to maintain QF status are, however, subject to the risk of events
outside the Company's control. For example, loss of a thermal energy customer or
failure of a thermal energy customer to take required amounts of thermal energy
from a cogeneration facility that is a QF could cause the facility to fail
requirements regarding the level of useful thermal energy output. Upon the
occurrence of such an event, the Company would seek to replace the thermal
energy customer or find another use for the thermal energy which meets PURPA's
requirements, but no assurance can be given that this would be possible.
If one of the projects in which the Company has an interest should lose its
status as a QF, the project would no longer be entitled to the exemptions from
PUHCA and the FPA. This could trigger certain rights of termination under the
power sales agreement, could subject the project to rate regulation as a public
utility under the FPA and state law and could result in the Company
inadvertently becoming a public utility holding company by owning more than 10%
of the voting securities of, or controlling, a facility that would no longer be
exempt from PUHCA. This could cause all of the Company's remaining projects to
lose their qualifying status, because QFs may not be controlled or more than 50%
owned by such public utility holding companies. Loss of QF status may also
trigger defaults under covenants to maintain QF status in the projects' power
sales agreements, steam sales agreements and financing agreements and result in
termination, penalties or
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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 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.
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Federal Natural Gas Transportation Regulation
The Company has an ownership interest in and operates six 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 broad authority to regulate
both the rates charged by and financial activities of electric utilities, and to
promulgate regulations implementing PURPA. Since a power sales contract will
become a part of a utility's cost structure (and therefore is generally
reflected in its retail rates), power sales contracts with independents are
potentially under the regulatory purview of PUCs, particularly the process by
which the utility has entered into the power sales contracts. If a PUC has
approved of the process by which a utility secures its power supply, a PUC
generally will be inclined to allow a utility to "pass through" the expenses
associated with an independent power contract to the utility's retail customers.
However, a regulatory commission may disallow the full reimbursement to a
utility for the purchase of electricity from QFs. 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 are considered to
be public utilities in many states and are subject to broad regulation by PUCs
ranging from the requirement of certificates of public convenience and necessity
to regulation of organizational, accounting, financial and other corporate
matters. In addition, states may assert jurisdiction over the siting and
construction of facilities not qualifying as QFs (as well as QFs), and over the
issuance of securities and the sale or other transfer of assets by these
facilities (but not QFs).
CPUC and the California Assembly 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 Order
Instituting Rulemaking and Order Instituting Investigation on the Commission
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, is also holding
hearings on policy issues related to a more competitive electric services
industry.
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On December 20, 1995, the CPUC issued an electric industry restructuring
decision which envisions commencement of deregulation and implementation of
customer choice beginning January 1, 1998, with all consumers participating by
2003. Because restructuring the California electric industry requires
participation and oversight by the FERC, the CPUC seeks to build a consensus
involving the California Legislature, the Governor, public and municipal
utilities, and customers. This consensus would be reflected in filings for
approval by the FERC and provides a cooperative spirit whereby both agencies
would move forward to implement the new market structure no later than January
1, 1998.
The decision provides for phased-in customer choice, development of a
non-discriminatory market structure, recovery of utilities stranded costs,
sanctity of existing contracts and continuation of existing public policy
programs including the promotion of fuel diversity through a renewable energy
purchase requirement.
On February 5, 1996, the CPUC issued a proposed procedural plan that
facilitates the transition of the electric generation market to competition by
January 1, 1998. This electric restructuring "roadmap" focuses on the multiple
and interrelated tasks that must be accomplished and sets forth the process to
achieve the necessary procedural milestones that must be completed in order to
meet the implementation goal.
In addition to the significant opportunity provided for power producers
such as Calpine resulting from the implementation of direct access, the decision
recognizes the sanctity of existing QF contracts. The decision recognizes that
horizontal market power concerns will likely require investor owned utilities to
divest themselves of a substantial portion of their generating assets and
requires the utilities to file with the Commission a plan for voluntary
divestiture of up to 50% of their fossil generating assets. The decision to
commit to the establishment of a restructuring policy maintains California's
resource diversity provided by existing renewal resources (including geothermal)
and encourages development of new renewable resources. The continued resource
diversity would be provided by a renewable portfolio standard which establishes
that a renewable purchase requirement be placed on providers of electricity and
creates a system of tradeable credits for meeting the purchase requirement.
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 intraprovincial
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
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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 stormwater 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 stormwater 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
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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 than the
Company.
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 July 31, 1996, the Company employed 235 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.
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 111 leases comprising 27,287 acres of federal, state and
private geothermal resource lands in The Geysers area in northern California.
These leases comprise its West Ford Flat Facility, Bear Canyon Facility, 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 23 leases
comprising approximately 29,000 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
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initial terms varying from 10 to 20 years or for so long as geothermal resources
are produced and sold. Certain of the leases contain drilling or other
exploratory work requirements. In certain cases, if a requirement is not
fulfilled, the lease may be terminated and in other cases additional payments
may be required. The Company believes that its leases are valid and that it has
complied with all the requirements and conditions material to their continued
effectiveness. A number of the Company's leases for undeveloped properties may
expire in any given year. Before leases expire, the Company performs geological
evaluations in an effort to determine the resource potential of the underlying
properties. No assurance can be given that the Company will decide to renew any
expiring leases.
The Company, through its ownership of the Greenleaf 1 Facility, owns 77
acres in Sutter County, California.
See "-- 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.
LEGAL PROCEEDINGS
The Company, together with over 100 other parties, was named as a defendant
in the second amended complaint 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"). This complaint alleges that, in conjunction
with top executives of Bonneville and with the alleged assistance of the other
100 defendants, the Company engaged in a broad conspiracy and fraud. The
complaint has been amended a number of times. The Company has answered each
version of the complaint by denying all claims. In August 1994, the Company
successfully moved for an order severing the trustee's claims against the
Company from the claims against the other defendants. Although the case involves
over 25 separate financial transactions entered into by Bonneville, the severed
case concerns the Company in respect of only one of these transactions. In 1988,
the Company invested $2.0 million in a partnership formed with Bonneville to
develop four hydroelectric projects in the State of Hawaii. The projects were
not successfully developed by the partnership and, subsequent to Bonneville's
Chapter 11 filing, the Company filed a claim as a creditor against Bonneville's
bankruptcy estate. The trustee alleges that the investment was actually a loan
and was designed to inflate Bonneville's earnings. The trustee initially alleged
that Calpine is one of many defendants in this case responsible for Bonneville's
"deepening insolvency" and the amount of damages attributable to the Company
based on the $2.0 million partnership investment was alleged to be $577.2
million. Based upon statements made by the Court and the trustee at a pre-trial
hearing in September 1996, the Company believes that the maximum compensatory
damages which the trustee may seek will not exceed $2.0 million. There can be no
assurance, however, of the actual amount of damages to be sought by the trustee.
The Company believes the claims against it are without merit and will continue
to defend the action vigorously. The Company further believes that the
resolution of this matter will not have a material adverse effect on its
financial position or results of operations.
In connection with the Company's unsuccessful attempt to acquire O'Brien
Environmental Energy, Inc. ("O'Brien") in 1995 through the U.S. Bankruptcy Court
proceedings, the Company incurred approximately $3.6 million of third-party
expenses, all of which have been capitalized by the Company. Pursuant to the
terms of a contract with O'Brien, the Company is seeking the reimbursement of
$2.3 million of such expenses and a $2.0 million break-up fee, each of which is
subject to the approval of the Bankruptcy Court. On June 6, 1996, the Bankruptcy
Court ruled that the Company had the right to seek reimbursement of its fees and
expenses and conducted an evidentiary hearing on August 28, 1996 to determine
the amount to be awarded. The Bankruptcy Court is scheduled to decide this
matter on September 30, 1996. Although the Company believes it will be awarded
all or a substantial part of the fees and expenses which it is seeking, there
can be no assurance as to the ultimate resolution of this claim.
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.
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MANAGEMENT
BOARD OF DIRECTORS AND EXECUTIVE OFFICERS
The following table sets forth certain information as of June 30, 1996 with
respect to each person who is a Director, a nominee for Director or an executive
officer of the Company.
<TABLE>
<CAPTION>
NAME AGE POSITION
------------------------------------------ ---- ---------------------------------------------
<S> <C> <C>
Peter Cartwright.......................... 66 President, Chief Executive Officer, Director
and Chairman of the Board Nominee
Pierre Krafft............................. 66 Chairman of the Board
Hans-Peter Aebi........................... 48 Director
Rudolf Boesch............................. 59 Director
Ann B. Curtis............................. 45 Senior Vice President and Director Nominee
George J. Stathakis....................... 66 Director Nominee
Rodney M. Boucher......................... 53 Senior Vice President
Lynn A. Kerby............................. 58 Senior Vice President
Kenneth J. Kerr........................... 52 Senior Vice President
Peter W. Camp............................. 57 Vice President
Robert D. Kelly........................... 38 Vice President
Larry R. Krumland......................... 56 Vice President
Alicia N. Noyola.......................... 46 Vice President
John P. Rocchio........................... 58 Vice President
Ron A. Walter............................. 47 Vice President
</TABLE>
Set forth below is certain information with respect to each current
Director, nominee for Director and executive officer of the Company. Upon
completion of the Common Stock Offering, Mr. Krafft, Mr. Aebi and Mr. Boesch
will resign from the Board of Directors of the Company and Ms. Curtis and Mr.
Stathakis will be appointed to fill two of the vacancies. Accordingly, following
the Common Stock Offering, the Board of Directors will be comprised of Mr.
Cartwright, Ms. Curtis and Mr. Stathakis and Mr. Cartwright will serve as
Chairman of the Board. The Company is actively seeking to add up to four
additional independent Directors who are not directors, officers or employees of
the Company, Electrowatt or an affiliate of Electrowatt. The Company anticipates
that at least one additional independent Director will be appointed within six
months of the completion of the Common Stock Offering.
Peter Cartwright founded the Company in 1984 and has since served as a
Director and as the Company's President and Chief Executive Officer. Mr.
Cartwright will become Chairman of the Board of Directors of the Company
effective upon completion of the Common Stock Offering. From 1979 to 1984, Mr.
Cartwright was Vice President and General Manager of Gibbs & Hill, Inc.'s
Western Regional Office, an office which he established. Gibbs & Hill, Inc. is
an architect-engineering firm which specializes in power engineering projects.
From 1960 to 1979, Mr. Cartwright worked for General Electric's Nuclear Energy
Division. His responsibilities included plant construction, project management
and new business development. He served on the Board of Directors of nuclear
fuel manufacturing companies in Germany, Italy and Japan. Mr. Cartwright was
responsible for General Electric's technology development and licensing programs
in Europe and Japan. Mr. Cartwright obtained a Master of Science Degree in Civil
Engineering from Columbia University in 1953 and a Bachelor of Science Degree in
Geological Engineering from Princeton University in 1952. Mr. Cartwright is a
Professional Engineer licensed in the states of New York and California.
Pierre Krafft has been the Company's Chairman of the Board since March
1991. Mr. Krafft served as Executive Vice President of Electrowatt from 1971
until his retirement in April 1995. He also serves as a director of several
electric utility companies in Switzerland, Germany and France and as Chairman of
the Swiss National Committee of the World Energy Council. Mr. Krafft obtained a
Master of Science Degree in Electrical Engineering from the Georgia Institute of
Technology in 1956 and an undergraduate degree in Electrical Engineering from
the Federal Institute of Technology in 1953.
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<PAGE> 71
Hans-Peter Aebi has been a Director of the Company since June 1994. Mr.
Aebi has served as the President of Elektrizitats-Gesellschaft Laufenburg AG,
Executive Vice President of the Electric Power Operations Division and a member
of Electrowatt's executive management since October 1994. He was also named
Executive Vice President for Landis & Gyr AG in March 1996. He served as the
Senior Vice President of the Energy Division of Electrowatt from 1993 to 1994.
Mr. Aebi's prior experience includes 14 years with an Electrowatt affiliate,
CKW, in various capacities including Executive Vice President from 1991 to 1992,
and as the First Vice President from 1988 to 1990. Mr. Aebi obtained a Master of
Science Degree in Engineering from the Federal Institute of Technology in 1972.
Rudolf Boesch has been a Director of the Company since its inception in
1984. Dr. Boesch serves as a member of the Executive Committee of Electrowatt,
and as Executive Vice President of Electrowatt's Services Division. His prior
experience with Electrowatt includes over ten years in the areas of marketing
and sales and technical development. Dr. Boesch obtained a Ph.D. in Physics from
the Federal Institute of Technology in 1965.
Ann B. Curtis has served as the Company's Senior Vice President since
September 1992 and has been employed by the Company since its inception in 1984.
Ms. Curtis will become a Director of the Company effective upon the completion
of the Common Stock Offering. She is responsible for the Company's financial and
administrative functions, including the functions of general counsel, corporate
and project finance, accounting, human resources, public relations and investor
relations. Ms. Curtis also serves as Corporate Secretary for the Company, and
serves as an officer of each of the Company's subsidiaries. Ms. Curtis also
represents the Company on partnership management committees. From the Company's
inception in 1984 through 1992, she served as the Company's Vice President for
Management and Financial Services. Prior to joining Calpine, Ms. Curtis was
Manager of Administration for Gibbs & Hill, Inc.
George J. Stathakis has been a Senior Advisor to the Company since 1994 and
will be a Director of the Company effective upon completion of the Common Stock
Offering. Mr. Stathakis has been providing financial, business and management
advisory services to numerous international investment banks since 1985. He also
served as Chairman of the Board and Chief Executive Officer of Ramtron
International Corporation, an advanced technology semiconductor company, from
1990 to 1994. From 1986 to 1989, he served as Chairman of the Board and Chief
Executive Officer of International Capital Corporation, a subsidiary of American
Express. Prior to 1986, Mr. Stathakis served thirty-two years with General
Electric Corporation in various management and executive positions. During his
service with General Electric Corporation, Mr. Stathakis founded the General
Electric Trading Company and was appointed its first President and Chief
Executive Officer. Mr. Stathakis obtained a Bachelor of Science Degree in
Engineering from the University of California at Berkeley in 1952 and a Master
of Science Degree in Engineering from the University of California at Berkeley
in 1953.
Rodney M. Boucher joined the Company in June 1995 as Senior Vice President,
and as President and Chief Executive Officer of the Company's subsidiary,
Calpine Power Services Company. He is responsible for the purchase, sale and
marketing of electric power, as well as the restructuring of contract,
transmission and generation rights. Prior to joining the Company, Mr. Boucher
served as Chief Operating Officer of Citizens Power & Light Company from 1992 to
1995 and as Senior Vice President of Citizens Lehman Power L.P., in Boston,
Massachusetts from 1994 to 1995. Prior to joining Citizens he served as
President for Electrical Interconnections-International from 1991 to 1992. Mr.
Boucher also served as Vice President and Chief Information Officer with
PacifiCorp from 1984 to 1991, and held various other positions with PacifiCorp
since 1975. Mr. Boucher holds a Master of Science Degree in Power Systems from
Rensselaer Polytechnic Institute and a Bachelor of Science Degree in Electrical
Engineering from Oregon State University.
Lynn A. Kerby joined the Company in January 1991 and served as Vice
President of Operations through January 1993, at which time he became a Senior
Vice President for the Company. Prior to joining the Company, Mr. Kerby served
as Senior Vice President-Operations of Guy F. Atkinson Company, an engineering
and construction company, from 1989 to 1990, and served in various other
positions within Guy F. Atkinson since 1961. Mr. Kerby served on Calpine's Board
of Directors from 1984 to 1988 as a Guy F. Atkinson representative. He obtained
a Bachelor of Science Degree in Civil Engineering and Business from the
University of Idaho in 1961. Mr. Kerby holds a Class A Contractors License in
the states of California, Arizona and Hawaii.
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<PAGE> 72
Kenneth J. Kerr joined the Company in March 1996 as Senior Vice
President-International. Prior to joining the Company, he served as Senior Vice
President-Commercial Development for Magma Power Company from 1993 to 1995. From
1989 to 1993 he served as Business Vice President-Plastics, Pacific Area with
The Dow Chemical Company. From 1966 to 1989, he served in various marketing and
management positions also with The Dow Chemical Company. Mr. Kerr obtained a
Bachelor of Science Degree in Chemical Engineering from the University of
Delaware in 1966.
Peter W. Camp joined the Company in November 1993 and served as Director of
Project Development through January 1995, at which time he became a Vice
President of Project Development. From 1992 to 1993 he served as a full-time
consultant with the Company. From 1988 to 1992, he served as President for
Altran Corporation, a nuclear waste technology company. From 1975 to 1987, Mr.
Camp worked for General Electric Company as General Manager, Nuclear Fuel
Marketing and Projects Department, and as Manager, Nuclear Energy Strategic
Planning. He obtained a Master of Business Administration Degree from Stanford
University in 1970 and a Bachelor of Science Degree in Mechanical Engineering
from Yale University in 1962.
Robert D. Kelly has served as the Company's Vice President, Finance since
1994. Mr. Kelly's responsibilities include all project and corporate finance
activities. From 1991 to 1992, Mr. Kelly served as Project Finance Manager, and
from 1992 to 1994, he served as Director-Project Finance for the Company. Prior
to joining the Company, he was the Marketing Manager of Westinghouse Credit
Corporation from 1990 to 1991. From 1989 to 1990, Mr. Kelly was Vice President
of Lloyds Bank PLC. From 1982 to 1989, Mr. Kelly was employed in various
positions with The Bank of Nova Scotia. He obtained a Master of Business
Administration Degree from Dalhousie University, Canada in 1980 and a Bachelor
of Commerce Degree from Memorial University, Canada, in 1979.
Larry R. Krumland has served as the Company's Vice President of Asset
Management since January 1993. From 1990 to 1993, Mr. Krumland served as
Director-Asset Management. From 1984 to 1990, Mr. Krumland served as
Manager-Geothermal Development. Prior to joining the Company, he served as
Director of Sales and Manager of Geothermal Projects for Gibbs & Hill, Inc. Mr.
Krumland obtained a Master of Business Administration Degree in Business
Economics and Finance from the University of California, Los Angeles in 1972; a
Master of Science Degree in Engineering, Energy Systems, from the University of
California, Los Angeles in 1967; and a Bachelor of Science Degree in Mechanical
Engineering from the University of California at Berkeley in 1964.
Alicia N. Noyola joined the Company in March 1991 and served as a full-time
consultant through March 1992, at which time she became employed by the Company
as Special Counsel. Ms. Noyola became a Vice President of Project Development in
January 1993. From 1987 to 1991, Ms. Noyola was a partner in the San Francisco,
California-based law firm Thelen, Marrin, Johnson and Bridges, where she
concentrated on commercial and corporate finance. Ms. Noyola obtained a Juris
Doctor Degree in 1973 from Hastings College of the Law, University of California
and obtained a Bachelor of Arts Degree in Architecture in 1970 from the
University of California, Berkeley.
John P. Rocchio joined the Company at inception in 1984 as Vice President
of Project Development. Prior to joining the Company, he served as Manager of
Business Development for Gibbs & Hill, Inc. from 1979 to 1984. Prior to 1979,
Mr. Rocchio served for 17 years with General Electric in various positions,
including Manager International Sales for the Nuclear Energy Group from 1970 to
1979 and various engineering and marketing positions from 1962 to 1979. He
obtained a Bachelor of Science Degree in Marine Engineering from the U.S.
Merchant Marine Academy in 1959.
Ron A. Walter has served as the Company's Vice President of Project
Development since July 1990. From 1984 to 1990, Mr. Walter served as the
Company's Manager-Geothermal Projects. Prior to joining the Company, he served
as Director of Sales-Geothermal for the San Jose-based architect-engineering
firm, Gibbs & Hill, Inc. from 1983 to 1984 and Senior Engineer from 1982 to
1983. From 1981 to 1982 he served as Project Manager Geothermal Projects with
Rogers Engineering Co. and from 1972 to 1981 he served in engineering and
management positions with Batelle Northwest Laboratories. Mr. Walter obtained a
Master of Science Degree in Mechanical Engineering from Oregon State University
in 1976 and a Bachelor of Science Degree in Mechanical Engineering from the
University of Nebraska in 1971.
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<PAGE> 73
CLASSIFIED BOARD OF DIRECTORS
The Company's Amended and Restated By-laws, which will become effective
upon the completion of the Common Stock Offering, will provide that the number
of directors shall be between three and nine, with the actual number of
directors to be established from time to time by resolution of the Board of
Directors. Following the Common Stock Offering, the Company's Board of Directors
will be divided into three classes, designated Class I, Class II and Class III,
with each class having a three-year term. Initially, Mr. Stathakis will serve in
Class I, Ms. Curtis will serve in Class II and Mr. Cartwright will serve in
Class III. The initial Directors in each class will hold office for terms of one
year, two years and three years, respectively. Thereafter each class will serve
a three-year term. The Company's Directors are elected by the stockholders at
the annual meeting of stockholders and will serve until their successors are
elected and qualified, or until their earlier resignation or removal. Additional
Directors will be designated to serve as Class I, Class II or Class III
Directors upon their appointment to the Board of Directors following the Common
Stock Offering.
COMMITTEES OF THE BOARD OF DIRECTORS
The Board of Directors will establish an Audit Committee and a Compensation
Committee upon completion of the Common Stock Offering. The Audit Committee will
review internal auditing procedures, the adequacy of internal controls and the
results and scope of the audit and other services provided by the Company's
independent auditors. The Compensation Committee will administer salaries,
incentives and other forms of compensation for officers and other employees of
the Company, as well as the incentive compensation and benefit plans of the
Company. Initially, Mr. Stathakis will serve as the sole Director on the Audit
Committee and the Compensation Committee. Thereafter, the Board of Directors
will designate one or more additional non-employee Directors to serve on the
Audit Committee and the Compensation Committee upon appointment to the Board of
Directors.
DIRECTOR COMPENSATION
Directors currently do not receive any compensation or other services as
members of the Board of Directors. The Company has determined that, following
the completion of the Common Stock Offering, non-employee Directors will receive
an annual fee of $25,000 and will be reimbursed for expenses incurred in
attending meetings of the Board of Directors or any committee thereof. The
chairman of the Compensation Committee and the chairman of the Audit Committee
will receive an additional annual fee of $5,000. In addition, Directors will be
eligible to participate in the Company's 1996 Stock Incentive Plan. See "-- 1996
Stock Incentive Plan."
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<PAGE> 74
EXECUTIVE COMPENSATION
The following table provides certain summary information concerning the
compensation earned, paid or awarded for services rendered to the Company in all
capacities during each of the three years ended December 31, 1995 to the
Company's Chief Executive Officer and each of the five other most highly
compensated executive officers of the Company serving in that capacity as of
December 31, 1995.
SUMMARY COMPENSATION TABLE
<TABLE>
<CAPTION>
LONG-TERM
COMPENSATION
------------
ANNUAL COMPENSATION SHARES
---------------------------- UNDERLYING ALL OTHER
NAME AND PRINCIPAL POSITION YEAR SALARY BONUS OPTIONS COMPENSATION(1)
- ------------------------------------- ---- -------- -------- ------------ ---------------
<S> <C> <C> <C> <C> <C>
Peter 1995 $341,000 $255,750 178,668 $21,420
Cartwright........................... 1994 300,000 292,500 155,815 11,934
President and Chief Executive 1993 220,055 176,000 -- 7,722
Officer
Lynn A. 1995 195,000 72,000 53,600 4,815
Kerby................................ 1994 180,000 72,000 38,954 4,275
Senior Vice President 1993 173,250 90,000 41,551 4,228
Ann B. 1995 160,000 60,000 53,600 877
Curtis............................... 1994 130,000 75,000 38,954 694
Senior Vice President 1993 122,500 70,000 -- 648
Alicia N. 1995 140,000 45,000 13,400 1,288
Noyola............................... 1994 133,875 40,162 -- 1,134
Vice President 1993 124,417 40,000 31,163 660
Ron A. 1995 135,000 45,000 13,400 1,235
Walter............................... 1994 120,000 40,000 -- 1,027
Vice President 1993 112,500 30,000 -- 587
Robert D. 1995 126,684 42,000 22,334 436
Kelly................................ 1994 115,208 60,000 31,163 389
Vice President 1993 103,347 50,000 23,372 343
</TABLE>
- ------------
(1) Represents the taxable value of an employer-sponsored life insurance policy.
The amount is calculated based on the age of the employee and the life
insurance coverage in excess of $50,000.
EMPLOYMENT AGREEMENTS, CONSULTING AGREEMENT AND CHANGE OF CONTROL ARRANGEMENTS
The Company has entered into employment agreements with Mr. Peter
Cartwright, Mr. Lynn Kerby, Ms. Ann Curtis, Mr. Ron Walter and Mr. Robert Kelly.
Each of the employment agreements expires during 1999 unless earlier terminated
or subsequently extended. The employment agreements provide for the payment of a
base salary, subject to periodic adjustment by the Board of Directors, and
provide for annual bonuses and participation in all benefit and equity plans.
The employment agreements also provide for other employee benefits such as life
insurance and health care, in addition to certain disability and death benefits.
Severance benefits, including the acceleration of outstanding options, are also
payable upon an involuntary termination or a termination following a change of
control in the Company. Severance benefits would not be payable in the event
that termination was for cause.
On December 1, 1994, the Company entered into a Consulting Agreement with
Mr. George J. Stathakis, a Director nominee. The Consulting Agreement was
amended and restated effective June 3, 1996. Pursuant to the Consulting
Agreement, Mr. Stathakis has been retained to provide, among other things,
advice to the Company with regard to domestic and international business, to
identify project investment opportunities, and to provide advisory support to
the Company's management in identifying potential buyers for, and negotiating
the sale of, Electrowatt's equity interest in the Company. The Consulting
Agreement provides for a monthly retainer of $5,000. In addition, for services
rendered in connection with the Common Stock Offering, the Company will pay Mr.
Stathakis $250,000 plus 0.25% of all payments received by Electrowatt in excess
of $200 million. The Consulting Agreement terminates on January 1, 1997 unless
otherwise earlier terminated or extended by mutual agreement of the parties.
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<PAGE> 75
Should the Company be acquired by merger or asset sale, then all
outstanding options held by the Chief Executive Officer and the other executive
officers under the Company's Stock Option Program or the 1996 Stock Incentive
Plan will automatically accelerate and vest in full, except to the extent those
options are to be assumed by the successor corporation. In addition, the
Compensation Committee as Plan Administrator of the 1996 Stock Incentive Plan
will have the authority to provide for the accelerated vesting of the shares of
Common Stock subject to outstanding options held by the Chief Executive Officer
or any other executive officer or any unvested shares of Common Stock subject to
direct issuances held by such individual, in connection with the termination of
that individual's employment following: (i) a merger or asset sale in which
these options are assumed or are assigned or (ii) certain hostile changes in
control of the Company. However, certain executive officers have existing
employment agreements that provide for the acceleration of their options upon a
termination of their employment following certain changes in control or
ownership of the Company.
STOCK OPTION PROGRAM
The following table sets forth certain information concerning grants of
stock options during the fiscal year ended December 31, 1995 to each of the
executive officers named in the Summary Compensation Table above. The table also
sets forth hypothetical gains or "option spreads" for the options at the end of
their respective ten-year terms. These gains are based on the assumed rates of
annual compound stock price appreciation of 5% and 10% from the date the option
was granted over the full option term.
OPTION GRANTS IN LAST FISCAL YEAR
<TABLE>
<CAPTION>
INDIVIDUAL GRANTS(1) POTENTIAL REALIZABLE
------------------------------------------------------------- VALUE AT ASSUMED
PERCENTAGE OF ANNUAL RATES OF
TOTAL OPTIONS STOCK
GRANTED TO PRICE APPRECIATION
OPTIONS EMPLOYEES EXERCISE FOR OPTION TERM(4)
GRANTED IN FISCAL PRICE PER EXPIRATION --------------------
NAME (NO. OF SHARES)(2) YEAR(3) SHARE DATE 5% 10%
- ------------------------ ------------------ ------------- ----------- ---------- -------- ---------
<S> <C> <C> <C> <C> <C> <C>
Peter Cartwright........ 178,668 40% $4.91 1/1/05 $551,704 $1,398,126
Lynn A. Kerby........... 53,600 12 4.91 1/1/05 165,510 419,435
Ann B. Curtis........... 53,600 12 4.91 1/1/05 165,510 419,435
Alicia N. Noyola........ 13,400 3 4.91 1/1/05 41,377 104,859
Ron A. Walter........... 13,400 3 4.91 1/1/05 41,377 104,859
Robert D. Kelly......... 22,334 5 4.91 1/1/05 68,965 174,770
</TABLE>
- ------------
(1) The exercise price may be paid in cash, in shares of the Company's Common
Stock valued at fair market value on the exercise date or through a cashless
exercise procedure involving a same-day sale of the purchased shares. The
Company may also finance the option exercise by loaning the optionee
sufficient funds to pay the exercise price for the purchased shares,
together with any federal and state income tax liability incurred by the
optionee in connection with such exercise. The Compensation Committee of the
Board of Directors, as the Plan Administrator of the Company's 1996 Stock
Incentive Plan, will have the discretionary authority to reprice the options
through the cancellation of those options and the grant of replacement
options with an exercise price based on the fair market value of the option
shares on the grant date.
(2) Each option set forth in the table above was granted on January 1, 1995 and
has a maximum term of ten years measured from the grant date, subject to
earlier termination upon the executive officer's termination of service with
the Company. Each option is immediately exercisable, but the underlying
shares are subject to repurchase by the Company at the original exercise
price paid per share should the executive officer's service with the Company
cease prior to vesting in such shares. The Company's repurchase right will
lapse with respect to, and the executive officer will vest in, four equal
annual installments over the four-year period of service measured from the
grant date. The Company's right to repurchase with respect to the option
shares will terminate immediately upon an acquisition of the Company by
merger or asset sale if the options are not assumed by the successor
corporation.
(3) The Company granted options to purchase 446,930 shares of Common Stock
during the year ended December 31, 1995.
(4) The 5% and 10% assumed annual rates of compound stock price appreciation are
mandated by the rules of the Securities and Exchange Commission (the
"Commission") and do not represent the Company's estimate or a projection by
the Company of future stock prices.
In addition to the options described above, in March 1996 the Board of
Directors granted options to purchase shares of Common Stock under the Company's
Stock Option Program to the following individuals in the designated amounts; Mr.
Cartwright, an option for 181,785 shares; Mr. Kerby, an option for 41,551
shares; Ms. Curtis, an option for 51,938 shares; Ms. Noyola, an option for
20,775 shares; Mr. Walter, an option for
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<PAGE> 76
20,775 shares; and Mr. Kelly, an option for 36,357 shares. The exercise price
for each option is $8.57 per share. Each option has a maximum term of ten (10)
years measured from the date of grant, subject to earlier termination in the
event of the optionee's cessation of service with the Company. The Company's
right of repurchase will lapse with respect to, and the optionee will vest in,
the option shares in a series of four equal annual installments over the
four-year period of service measured from January 1, 1996. The Company's right
to repurchase with respect to the option shares will terminate immediately upon
an acquisition of the Company by merger or asset sale if the options are not
assumed by the successor corporation.
No executive officer named in the Summary Compensation Table above
exercised stock options during the year ended December 31, 1995. The following
table sets forth certain information concerning the number of shares subject to
exercisable and unexercisable stock options held by the executive officers named
in the Summary Compensation Table above as of December 31, 1995. Also reported
are values for "in-the-money" options that represent the positive spread between
the respective exercise prices of outstanding stock options and the fair market
value of the Company's Common Stock.
AGGREGATE OPTION EXERCISES IN LAST FISCAL YEAR AND YEAR-END OPTION VALUES
<TABLE>
<CAPTION>
NUMBER OF UNEXERCISED OPTIONS VALUE OF UNEXERCISED IN-THE-
AT DECEMBER 31, 1995 (NO. OF MONEY OPTIONS AT
OPTIONS) DECEMBER 31, 1995(1)
----------------------------- -----------------------------
NAME EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
- ---------------------------------------- ----------- ------------- ----------- -------------
<S> <C> <C> <C> <C>
Peter Cartwright........................ 597,292 438,361 $ 8,940,672 $ 4,222,964
Lynn A. Kerby........................... 50,640 125,016 663,495 1,272,877
Ann B. Curtis........................... 144,129 125,016 2,154,639 1,203,077
Alicia N. Noyola........................ 23,372 41,966 330,662 413,207
Ron A. Walter........................... 114,265 34,176 1,771,040 302,998
Robert D. Kelly......................... 33,111 80,115 426,088 778,593
</TABLE>
- ---------------
(1) For purposes of the computation of the value of unexercised in-the-money
options at December 31, 1995, the table above assumes that the value of the
underlying shares is the initial public offering price of the shares offered
hereby.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
For 1995, the members of the Board of Directors, other than Mr. Cartwright,
acted as the Compensation Committee for the purposes of establishing the
compensation for Mr. Cartwright, the Company's President and Chief Executive
Officer. All decisions regarding the compensation of the Company's other
executive officers were made by Mr. Cartwright. Upon the consummation of the
Common Stock Offering, there will be established a Compensation Committee of the
Board of Directors. Following the Common Stock Offering, no member of the
Compensation Committee of the Board of Directors of the Company will serve as a
member of the board of directors or compensation committee of any entity that
has one or more executive officers serving as a member of the Company's Board of
Directors or Compensation Committee.
1996 STOCK INCENTIVE PLAN
The Company's 1996 Stock Incentive Plan (the "1996 Plan") is intended to
serve as the successor equity incentive program to the Company's Stock Option
Program (the "Predecessor Plan"). See "-- Stock Option Program." The 1996 Plan
became effective on July 17, 1996 upon adoption by the Board of Directors and
was approved by the Company's stockholder on July 17, 1996. The Company has
initially authorized 4,041,858 shares of Common Stock for issuance under the
1996 Plan. This initial share reserve is comprised of (i) the 2,596,923 shares
which remained available for issuance under the Predecessor Plan, including the
2,392,026 shares subject to outstanding options thereunder, plus (ii) an
additional increase of 1,444,935 shares. In addition, the share reserve will
automatically be increased on the first trading day of January each calendar
year, beginning in January 1997, by a number of shares equal to one percent (1%)
of the number of shares of Common Stock outstanding on the last trading day of
the immediately preceding calendar year. However, in
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<PAGE> 77
no event may any one participant in the 1996 Plan receive option grants or
direct stock issuances for more than 500,000 shares in the aggregate per
calendar year.
Outstanding options under the Predecessor Plan will be incorporated into
the 1996 Plan upon the consummation of the Common Stock Offering, and no further
option grants will be made under the Predecessor Plan. The incorporated options
will continue to be governed by their existing terms, unless the Plan
Administrator elects to extend one or more features of the 1996 Plan to those
options. However, except as otherwise noted below, the outstanding options under
the Predecessor Plan contain substantially the same terms and conditions
summarized below for the Discretionary Option Grant Program in effect under the
1996 Plan.
The 1996 Plan is divided into five separate components: (i) the
Discretionary Option Grant Program under which eligible individuals in the
Company's employ or service (including officers and other employees,
non-employee Board members and independent consultants) may, at the discretion
of the Plan Administrator, be granted options to purchase shares of Common Stock
at an exercise price not less than 85% of their fair market value on the grant
date, (ii) the Stock Issuance Program under which such individuals may, in the
Plan Administrator's discretion, be issued shares of Common Stock directly,
through the purchase of such shares at a price not less than 100% of their fair
market value at the time of issuance or as a bonus tied to the performance of
services, (iii) the Salary Investment Option Grant Program under which executive
officers and other highly compensated employees may elect to apply a portion of
their base salary to the acquisition of special stock option grants, (iv) the
Automatic Option Grant Program under which option grants will automatically be
made at periodic intervals to eligible non-employee Directors to purchase shares
of Common Stock at an exercise price equal to 100% of their fair market value on
the grant date and (v) the Director Fee Option Grant Program pursuant to which
the non-employee Directors may apply a portion of the annual retainer fee, if
any, otherwise payable to them in cash each year to the acquisition of special
stock option grants.
The Discretionary Option Grant, Stock Issuance and Salary Investment Option
Grant Programs will be administered by the Compensation Committee. The
Compensation Committee as Plan Administrator will have complete discretion to
determine which eligible individuals are to receive option grants or stock
issuances, the time or times when such option grants or stock issuance are to be
made, the number of shares subject to each such grant or issuance, the vesting
schedule to be in effect for the option grant or stock issuance, the maximum
term for which any granted option is to remain outstanding and the status of any
granted option as either an incentive stock option or a non-statutory stock
option under the Federal tax laws, except that all options granted under the
Salary Investment Option Grant Program will be non-statutory stock options. The
administration of the Automatic Option Grant and Director Fee Option Grant
Programs will be self-executing in accordance with the express provisions of
each such program.
The exercise price for the shares of Common Stock subject to option grants
made under the 1996 Plan may be paid in cash or in shares of Common Stock valued
at fair market value on the exercise date. The option may also be exercised
through a same-day sale program without any cash outlay by the optionee. In
addition, the Plan Administrator may provide financing to one or more optionees
in the exercise of their outstanding options by allowing such individuals to
deliver a full-recourse, interest-bearing promissory note in payment of the
exercise price and any associated withholding taxes incurred in connection with
such exercise.
In the event that the Company is acquired by merger or asset sale, each
outstanding option under the Discretionary Option Grant Program which is not to
be assumed by the successor corporation will automatically accelerate in full,
and all unvested shares under the Stock Issuance Program will immediately vest,
except to the extent the Company's repurchase rights with respect to those
shares are to be assigned to the successor corporation. The Plan Administrator
will have the authority under the Discretionary Option Grant and Stock Issuance
Programs to grant options and to structure repurchase rights so that the shares
subject to those options or repurchase rights will automatically vest in the
event the individual's service is terminated, whether involuntarily or through a
resignation for good reason, within a specified period (not to exceed 18 months)
following (i) a merger or asset sale in which those options are assumed or (ii)
a hostile
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change in control of the Company effected by a successful tender offer for more
than 50% of the outstanding voting stock or by proxy contest for the election of
Directors. Options currently outstanding under the Predecessor Plan will
accelerate upon an acquisition of the Company by merger or asset sale, unless
those options are assumed by the acquiring entity. However, such options under
the Predecessor Plan are not subject to acceleration upon the termination of the
optionee's service following an acquisition in which those options are assumed
or following a hostile change in control, except to the extent provided in any
employment contract or severance agreement in effect between the optionee and
the Company.
Stock appreciation rights may be issued in tandem with option grants made
under the Discretionary Option Grant Program. The holders of such rights will
have the opportunity to elect between the exercise of their outstanding stock
options for shares of Common Stock or the surrender of those options for an
appreciation distribution from the Company equal to the excess of (i) the fair
market value of the vested shares of Common Stock subject to the surrendered
option over (ii) the aggregate exercise price payable for such shares. Such
appreciation distribution may be made in cash or in shares of Common Stock.
There are currently no outstanding stock appreciation rights under the
Predecessor Plan.
The Plan Administrator has the authority to effect the cancellation of
outstanding options under the Discretionary Option Grant Program (including
options incorporated from the Predecessor Plan) in return for the grant of new
options for the same or different number of option shares with an exercise price
per share based upon the fair market value of the Common Stock on the new grant
date.
In the event the Plan Administrator elects to activate the Salary
Investment Option Grant Program for one or more calendar years, each executive
officer and other highly compensated employee of the Company selected for
participation may elect, prior to the start of the calendar year, to reduce his
or her base salary for that calendar year by a specified dollar amount not less
than $10,000 nor more than $50,000. If such election is approved by the Plan
Administrator, the officer will be granted, on or before the last trading day in
January in the calendar year for which the salary reduction is to be in effect,
a non-statutory option to purchase that number of shares of Common Stock
determined by dividing the salary reduction amount by two-thirds of the fair
market value per share of Common Stock on the grant date. The option will be
exercisable at a price per share equal to one-third of the fair market value of
the option shares on the grant date. As a result, the total spread on the option
shares at the time of grant will be equal to the amount of salary invested in
that option. The option will vest in a series of 12 equal monthly installments
over the calendar year for which the salary reduction is in effect and will be
subject to full and immediate vesting upon certain changes in the ownership or
control of the Company.
Under the Automatic Option Grant Program, each individual who is serving as
a non-employee Director on the date the Underwriting Agreement for the Common
Stock Offering is executed will receive at that time a stock option for 10,000
shares of Common Stock, provided that individual has not previously received an
option grant from the Company in connection with his or her service on the Board
of Directors. Each individual who becomes a non-employee Director after such
date will receive an option grant for 10,000 shares of Common Stock at the time
of his or her commencement of service on the Board of Directors, provided such
individual has not otherwise been in the prior employment of the Company. In
addition, at each Annual Stockholders Meeting, beginning with the 1997 Annual
Stockholders Meeting, each individual who is to continue to serve as a
non-employee Director will receive an option grant to purchase 1,500 shares of
Common Stock, whether or not such individual has been in the prior employment of
the Company or has previously received a stock option grant from the Company.
Each automatic grant will have an exercise price equal to the fair market
value per share of Common Stock on the grant date and will have a maximum term
of 10 years, subject to earlier termination following the optionee's cessation
of service on the Board of Directors. Each automatic option will be immediately
exercisable; however, any shares purchased upon exercise of the option will be
subject to repurchase, at the option exercise price paid per share, should the
optionee's service as a non-employee Director cease prior to vesting in the
shares. The 10,000-share grant will vest in four successive equal annual
installments over the optionee's period of service on the Board of Directors
measured from the grant date. Each annual 1,500-share grant will vest upon the
optionee's completion of one year of service on the Board of Directors measured
from
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the grant date. However, each outstanding option will immediately vest upon (i)
certain changes in the ownership or control of the Company or (ii) the death or
disability of the optionee while serving as a Director.
Should the Director Fee Option Grant Program be activated in the future,
each non-employee Director would have the opportunity to apply all or a portion
of his or her annual retainer fee otherwise payable in cash to the acquisition
of a below-market option grant. The option grant would automatically be made on
the first trading day in January in the year for which the retainer fee would
otherwise be payable in cash. The option will have an exercise price per share
equal to one-third of the fair market value of the shares of Common Stock on the
grant date, and the number of shares subject to the option will be determined by
dividing the amount of the retainer fee applied to the program by two-thirds of
the fair market value per share of Common Stock on the grant date. As a result,
the total spread on the option (the fair market value of the option shares on
the grant date less the aggregate exercise price payable for those shares) will
be equal to the portion of the retainer fee invested in that option. The option
will become exercisable for the option shares in a series of installments over
the optionee's period of service on the Board of Directors as follows: one half
of the option shares will become exercisable upon the optionee's completion of
six months of service on the Board of Directors during the calendar year of the
option grant and the balance will become exercisable in six successive equal
monthly installments upon his or her completion of each additional month of
service on the Board of Directors in such calendar year. However, the option
will become immediately exercisable for all the option shares upon (i) certain
changes in the ownership or control of the Company or (ii) the death or
disability of the optionee while serving as a Director.
The Board of Directors may amend or modify the 1996 Plan at any time. The
1996 Plan will terminate on July 16, 2006, unless sooner terminated by the Board
of Directors.
EMPLOYEE STOCK PURCHASE PLAN
The Company's Employee Stock Purchase Plan (the "Purchase Plan") was
adopted by the Board of Directors on July 17, 1996. The Purchase Plan is
designed to allow eligible employees of the Company and participating
subsidiaries to purchase shares of Common Stock, at semi-annual intervals,
through their periodic payroll deductions under the Purchase Plan, and a reserve
of 275,000 shares of Common Stock has been established for this purpose.
The Purchase Plan will be implemented in a series of successive offering
periods, each with a maximum duration of 24 months. However, the initial
offering period will begin on the day the Underwriting Agreement is executed in
connection with the Common Stock Offering and will end on the last business day
in August 1998.
Individuals who are eligible employees on the start date of any offering
period may enter the Purchase Plan on that start date or on any subsequent
semi-annual entry date (March 1 or September 1 each year). Individuals who
become eligible employees after the start date of the offering period may join
the Purchase Plan on any subsequent semi-annual entry date within that period.
Payroll deductions may not exceed 15% of the participant's cash
compensation for each semi-annual period of participation, and the accumulated
payroll deductions will be applied to the purchase of shares on the
participant's behalf on each semi-annual purchase date (February 28 and August
31 each year, with the first such purchase date to occur on February 28, 1997)
at a purchase price per share not less than eighty-five percent (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. In no event, however, may any participant purchase
more than 300 shares on any one semi-annual purchase date. Should the fair
market value of the Common Stock on any semi-annual purchase date be less than
the fair market value of the Common Stock on the first day of the offering
period, then the current offering period will automatically end and a new
24-month offering period will begin, based on the lower fair market value.
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LIMITATION OF LIABILITY AND INDEMNIFICATION MATTERS
The Company's Certificate of Incorporation limits the liability of
directors to the maximum extent permitted by Delaware law. Delaware law provides
that a director of a corporation will not be personally liable for monetary
damages for breach of such individual's fiduciary duties as a director except
for liability (i) for any breach of such director's duty of loyalty to the
corporation, (ii) for acts or omissions not in good faith or that involve
intentional misconduct or a knowing violation of law, (iii) for unlawful
payments of dividends or unlawful stock repurchases or redemptions as provided
in Section 174 of the Delaware General Corporation Law, or (iv) for any
transaction from which a director derives an improper personal benefit.
The Company's Bylaws provide that the Company will indemnify its directors
and may indemnify its officers, employees and other agents to the full extent
permitted by law. The Company believes that indemnification under its Bylaws
covers at least negligence and gross negligence on the part of an indemnified
party and permits the Company to advance expenses incurred by an indemnified
party in connection with the defense of any action or proceeding arising out of
such party's status or service as a director, officer, employee or other agent
of the Company upon an undertaking by such party to repay such advances if it is
ultimately determined that such party is not entitled to indemnification.
The Company has entered into separate indemnification agreements with each
of its directors and officers. These agreements require the Company, among other
things, to indemnify such director or officer against expenses (including
attorneys' fees), judgments, fines and settlements (collectively, "Liabilities")
paid by such individual in connection with any action, suit or proceeding
arising out of such individual's status or service as a director or officer of
the Company (other than Liabilities arising from willful misconduct or conduct
that is knowingly fraudulent or deliberately dishonest) and to advance expenses
incurred by such individual in connection with any proceeding against such
individual with respect to which such individual may be entitled to
indemnification by the Company. The Company believes that its Certificate of
Incorporation and Bylaw provisions and indemnification agreements are necessary
to attract and retain qualified persons as directors and officers.
At present the Company is not aware of any pending litigation or proceeding
involving any director, officer, employee or agent of the Company where
indemnification will be required or permitted. The Company is not aware of any
threatened litigation or proceeding that might result in a claim for such
indemnification.
CERTAIN TRANSACTIONS
CS Holding, a Swiss corporation, holds approximately 44.9% of the
outstanding shares of Electrowatt, which indirectly holds 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 in May 1996. CS First Boston Corporation is acting as 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 Facility. The Company holds a 20% interest in O.L.S. Energy-Agnews.
The loan is collateralized by all of the assets of the Agnews Facility 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 of
the Agnews Facility, the Facility 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
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Company to $54.0 million. The Credit Suisse Credit Facility is unsecured and
bears 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 10 1/2%
Senior Notes 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
reduced to $50.0 million. Borrowings of approximately $13.0 million are
outstanding under the Credit Suisse Credit Facility as of the date of this
Prospectus. All of such borrowings will be repaid with a portion of the net
proceeds to the Company from the Common Stock Offering. Upon the completion of
the Common Stock Offering, the Credit Suisse Credit Facility will terminate.
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 Facility and acquisition of
associated gas reserves. See "Business -- Description of Facilities -- Power
Generation Facilities -- Sumas Facility." As of December 31, 1995, the
outstanding indebtedness of Sumas and ENCO under the term loan was $119.0
million.
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 has agreed to pay
Electrowatt $200,000 per year for all services rendered under the management
services agreement. Pursuant to this agreement, $200,000 was paid in 1995. Upon
the completion of the Common Stock Offering, the management services agreement
will terminate.
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 has 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 the completion of the Common Stock Offering, the
guarantee fee agreement will terminate.
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 Facilities at the time of the acquisition of such facilities.
In December 1994, the Company entered into a Consulting Agreement with Mr.
Stathakis, a Director nominee, which was amended and restated effective June 3,
1996. See "Management--Employment Agreements, Consulting Agreement and Change of
Control Agreements."
In March 1996, Electrowatt invested $50.0 million in the Company in the
form of shares of Preferred Stock, all of which have been converted into shares
of Common Stock in connection with the Common Stock Offering.
The Company believes that all transactions between the Company and its
officers, Directors, principal shareholders and affiliates have been and will be
on terms no less favorable to the Company than could be obtained from
unaffiliated parties.
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PRINCIPAL AND SELLING STOCKHOLDERS
The following table sets forth certain information regarding beneficial
ownership of the Company's Common Stock as of June 30, 1996 and as adjusted to
reflect the Common Stock Offering by: (i) each person known by the Company to be
the beneficial owner of more than five percent of the outstanding shares of the
Company's Common Stock, (ii) each Director and nominee for Director of the
Company, (iii) each executive officer of the Company listed in the Summary
Compensation Table, (iv) Electrowatt (the "Selling Stockholder"), and (v) all
executive officers and Directors and nominees for Director of the Company as a
group.
<TABLE>
<CAPTION>
SHARES BENEFICIALLY SHARES BENEFICIALLY
OWNED OWNED
PRIOR TO THE AFTER THE
COMMON STOCK COMMON STOCK
OFFERING(1) OFFERING(1)
NAME AND ADDRESS ----------------------- NUMBER OF SHARES ----------------------
OF BENEFICIAL OWNER NUMBER PERCENT BEING OFFERED(2) NUMBER PERCENT
- -------------------------------- ---------- ------- ---------------- --------- -------
<S> <C> <C> <C> <C> <C>
Electrowatt Ltd.(2)............. 12,567,180 100%(2) 12,567,180 -- --
Pierre Krafft................... -- -- -- -- --
Hans-Peter Aebi................. -- -- -- -- --
Rudolf Boesch................... -- -- -- -- --
Peter Cartwright(3)............. 641,959 4.9% -- 641,959 3.4%
Ann B. Curtis(3)................ 157,529 1.2% -- 157,529 *
George J. Stathakis............. -- -- -- -- --
Lynn A. Kerby(3)................ 74,428 * -- 74,428 *
Ron A. Walter(3)................ 117,615 * -- 117,615 *
Alicia N. Noyola(3)............. 34,513 * -- 34,513 *
Robert D. Kelly(3).............. 44,537 * -- 44,537 *
All executive officers and
Directors and nominees for
Director as a group (15
persons)(3)................... 1,366,696 9.8% -- 1,366,696 7.0%
</TABLE>
- ------------
* Less than one percent
(1) Beneficial ownership is determined in accordance with the rules of the
Commission and generally includes voting or investment power with respect to
securities. Shares of Common Stock subject to options, warrants and
convertible notes currently exercisable or convertible, or exercisable or
convertible within 60 days, are deemed outstanding for computing the
percentage of the person holding such options but are not deemed outstanding
for computing the percentage of any other person. Subject to community
property laws where applicable, the persons named in the table have sole
voting and investment power with respect to all shares of Common Stock shown
as beneficially owned by them.
(2) Electrowatt's address is: Bellerivestrasse 36, P.O. Box CH-8022, Zurich,
Switzerland.
(3) Represents shares of the Company's Common Stock issuable upon exercise of
options that are currently exercisable or will become exercisable within 60
days after June 30, 1996.
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DESCRIPTION OF CAPITAL STOCK
The authorized capital stock of the Company consists of 100,000,000 shares
of Common Stock, $.001 par value, and 10,000,000 shares of Preferred Stock,
$.001 par value. The following summary is qualified in its entirety by the
provisions of the Certificate of Incorporation and Bylaws of the Company, which
have been filed as exhibits to the Registration Statement of which this
Prospectus constitutes a part.
COMMON STOCK
There will be 18,045,000 shares of Common Stock outstanding upon the
completion of the Common Stock Offering. The holders of Common Stock are
entitled to one vote per share on all matters to be voted upon by the
stockholders. Subject to preferences that may be applicable to any outstanding
Preferred Stock, the holders of Common Stock are entitled to receive ratably
such dividends, if any, as may be declared from time to time by the Board of
Directors out of funds legally available therefor. See "Dividend Policy." In the
event of the liquidation, dissolution or winding up of the Company, the holders
of Common Stock are entitled to share ratably in all assets remaining after
payment of liabilities, subject to prior liquidation rights of Preferred Stock,
if any, then outstanding. The Common Stock has no preemptive or conversion
rights or other subscription rights. There are no redemption or sinking fund
provisions applicable to the Common Stock. All outstanding shares of Common
Stock to be outstanding upon the completion of the Common Stock Offering will be
fully paid and non-assessable.
PREFERRED STOCK
The Board of Directors has the authority to issue the Preferred Stock in
one or more series and to fix the rights, preferences, privileges and
restrictions granted to or imposed upon any wholly unissued shares of
undesignated preferred stock and to fix the number of shares constituting any
series and the designations of such series, without any further vote or action
by the stockholders. The Board of Directors, without stockholder approval, can
issue Preferred Stock with voting and conversion rights which could adversely
affect the voting power of the holders of Common Stock. The issuance of
Preferred Stock may have the effect of delaying, deferring or preventing a
change in control of the Company, or could delay or prevent a transaction that
might otherwise give stockholders of the Company an opportunity to realize a
premium over the then prevailing market price of the Common Stock. There will be
no shares of Preferred Stock outstanding upon the completion of the Common Stock
Offering.
ANTI-TAKEOVER EFFECTS OF PROVISIONS OF THE CERTIFICATE OF INCORPORATION, BYLAWS
AND DELAWARE LAW
Certificate of Incorporation and Bylaws
The Company's Certificate of Incorporation and Bylaws provide that the
Company's Board of Directors is classified into three classes of Directors
serving staggered, three-year terms. The Certificate of Incorporation also
provides that Directors may be removed only by the affirmative vote of the
holders of two-thirds of the shares of capital stock of the Company entitled to
vote. Any vacancy on the Board of Directors may be filled only by vote of the
majority of Directors then in office. Further, the Certificate of Incorporation
provides that any "Business Combination" (as therein defined) requires the
affirmative vote of the holders of two-thirds of the shares of capital stock of
the Company entitled to vote, voting together as a single class. The Certificate
of Incorporation also provides that all stockholder actions must be effected at
a duly called meeting and not by a consent in writing. The Bylaws provide that
the Company's stockholders may call a special meeting of stockholders only upon
a request of stockholders owning at least 50% of the Company's capital stock.
These provisions of the Certificate of Incorporation and Bylaws could discourage
potential acquisition proposals and could delay or prevent a change in control
of the Company. These provisions are intended to enhance the likelihood of
continuity and stability in the composition of the Board of Directors and in the
policies formulated by the Board of Directors and to discourage certain types of
transactions that may involve an actual or threatened change of control of the
Company. These provisions are designed to reduce the vulnerability of the
Company to an unsolicited acquisition proposal. The provisions also are intended
to discourage certain tactics that may be used in proxy fights. However, such
provisions could have the effect of
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discouraging others from making tender offers for the Company's shares and, as a
consequence, they also may inhibit fluctuations in the market price of the
Company's shares that could result from actual or rumored takeover attempts.
Such provisions also may have the effect of preventing changes in the management
of the Company. See "Risk Factors -- Anti-Takeover Provisions" and
"Management -- Classified Board of Directors."
Delaware Anti-Takeover Statute
The Company is subject to Section 203 of the Delaware General Corporation
Law ("Section 203"), which, subject to certain exceptions, prohibits a Delaware
corporation from engaging in any business combination with any interested
stockholder for a period of three years following the date that such stockholder
became an interested stockholder, unless: (i) prior to such date, the board of
directors of the corporation approved either the business combination or the
transaction that resulted in the stockholder becoming an interested stockholder;
(ii) upon consummation of the transaction that resulted in the stockholder
becoming an interested stockholder, the interested stockholder owned at least
85% of the voting stock of the corporation outstanding at the time the
transaction commenced, excluding for purposes of determining the number of
shares outstanding those shares owned (x) by persons who are directors and also
officers and (y) by employee stock plans in which employee participants do not
have the right to determine confidentially whether shares held subject to the
plan will be tendered in a tender or exchange offer; or (iii) on or subsequent
to such date, the business combination is approved by the board of directors and
authorized at an annual or special meeting of stockholders, and not by written
consent, by the affirmative vote of at least 66 2/3% of the outstanding voting
stock that is not owned by the interested stockholder.
Section 203 defines business combination to include: (i) any merger or
consolidation involving the corporation and the interested stockholder; (ii) any
sale, transfer, pledge or other disposition of 10% or more of the assets of the
corporation involving the interested stockholder; (iii) subject to certain
exceptions, any transaction that results in the issuance or transfer by the
corporation of any stock of the corporation to the interested stockholder; (iv)
any transaction involving the corporation that has the effect of increasing the
proportionate share of the stock of any class or series of the corporation
beneficially owned by the interested stockholder; or (v) the receipt by the
interested stockholder of the benefit of any loans, advances, guarantees,
pledges or other financial benefits provided by or through the corporation. In
general, Section 203 defines an interested stockholder as any entity or person
beneficially owning 15% or more of the outstanding voting stock of the
corporation and any entity or person affiliated with or controlling or
controlled by such entity or person.
TRANSFER AGENT AND REGISTRAR
The Transfer Agent and Registrar for the Company's Common Stock is First
Chicago Trust Company of New York. Its address is 525 Washington Boulevard,
Jersey City, New Jersey 07310 and its telephone number is (201) 222-4114.
LISTING
The Common Stock has been approved for listing on the New York Stock
Exchange under the trading symbol "CPN," subject to notice of issuance.
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SHARES ELIGIBLE FOR FUTURE SALE
Upon the completion of the Common Stock Offering, the Company will have
18,045,000 shares of Common Stock outstanding (assuming no exercise of the
Underwriters' over-allotment option and assuming no exercise of outstanding
options). All of the shares sold in the Common Stock Offering will be freely
tradeable without restriction or further registration under the Securities Act,
except that any shares purchased by "affiliates" of the Company, as that term is
defined under the Securities Act ("Affiliates"), may generally only be sold in
compliance with the limitations of Rule 144 described below.
SALES OF RESTRICTED SHARES
Shares of Common Stock not freely tradeable without restriction or further
registration under the Securities Act are deemed "restricted" under Rule 144 of
the Securities Act. The number of shares of Common Stock available for sale in
the public market is limited by restrictions under the Securities Act and
lock-up agreements under which the holders of such shares have agreed with the
Underwriters not to sell or otherwise dispose of any of their shares for a
period of 180 days after the date of this Prospectus without the prior written
consent of CS First Boston. The Company intends to register with the Commission
on a registration statement on Form S-8 a total of 4,041,858 shares of Common
Stock issuable pursuant to the Company's 1996 Plan, including the 2,392,026
shares of Common Stock subject to outstanding options previously granted under
the Predecessor Plan. Upon the effectiveness of such registration statement, the
shares issuable upon the exercise of outstanding options or otherwise under the
1996 Plan will become freely tradeable upon issuance thereof, subject to the
restrictions on Affiliates under the Securities Act.
In general, under Rule 144 of the Securities Act as currently in effect,
beginning 90 days after the Common Stock Offering, a person (or persons whose
shares are aggregated) who has beneficially owned "restricted" shares for at
least two years, including a person who may be deemed an Affiliate of the
Company, is entitled to sell within any three-month period a number of shares of
Common Stock that does not exceed the greater of 1% of the then-outstanding
shares of Common Stock of the Company (approximately 180,450 shares after giving
effect to the Common Stock Offering) or the average weekly trading volume of the
Common Stock on the New York Stock Exchange during the four calendar weeks
preceding such sale. Sales under Rule 144 are subject to certain restrictions
relating to manner of sale, notice and the availability of current public
information about the Company. A person (or persons whose shares are aggregated)
who is not an Affiliate of the Company at any time during the ninety days
preceding a sale, and who has beneficially owned shares for at least three
years, would be entitled to sell such shares immediately following the Common
Stock Offering without regard to the volume limitations, manner of sale
provisions or notice or other requirements of Rule 144 of the Securities Act
pursuant to Rule 144(k). However, the transfer agent may require an opinion of
counsel that a proposed sale of shares comes within the terms of Rule 144(k)
prior to effecting a transfer of such shares.
Prior to the Common Stock Offering, there has been no public market for the
Common Stock of the Company and no predictions can be made of the effect, if
any, that the sale or availability for sale of shares of additional Common Stock
will have on the market price of the Common Stock. Nevertheless, sales of
substantial amounts of such shares in the public market, or the perception that
such sales could occur, could adversely affect the market price of the Common
Stock and could impair the Company's future ability to raise capital through an
offering of its equity securities.
OPTIONS
As of the date of this Prospectus, options to purchase a total of 2,392,026
shares of Common Stock were outstanding under the Company's 1996 Plan. Of such
amount, options to purchase 1,366,696 shares were exercisable, all of which will
become eligible for sale 180 days after the date of this Prospectus upon
expiration of certain lock-up agreements with the Underwriters and pursuant to
Rule 701, subject in some cases to certain volume and other resale restrictions.
Rule 701 under the Securities Act provides that shares of Common Stock acquired
on the exercise of outstanding options may be resold (i) by persons other than
Affiliates, beginning 90 days after the date of this Prospectus, subject only to
the manner of sale provisions of
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Rule 144 and (ii) by Affiliates, beginning 90 days after the date of this
Prospectus, subject to all provisions of Rule 144 except its two-year minimum
holding period.
LOCK-UP AGREEMENTS
All holders of options to purchase shares of Common Stock have agreed with
the Underwriters that they will not, without the prior written consent of CS
First Boston, offer, sell, contract to sell or otherwise dispose of any shares
of Common Stock beneficially owned by them or any shares issuable upon exercise
of stock options for a period of 180 days from the date of this Prospectus. See
"Underwriting."
CERTAIN UNITED STATES FEDERAL TAX CONSEQUENCES
TO NON-U.S. HOLDERS
The following is a general discussion of certain United States federal
income and estate tax consequences of an investment in Common Stock by a holder
that, for United States federal income tax purposes, is not a "United States
person" (a "Non-U.S. Holder"). For purposes of this discussion, a "United States
person" means a citizen or resident (as defined for United States federal income
and estate tax purposes, as the case may be) of the United States, a corporation
or partnership created or organized in the United States or under the laws of
the United States or of any State thereof or an estate or trust whose income is
includible in gross income for United States federal income tax purposes
regardless of its source. The discussion is based on the United States Internal
Revenue Code of 1986, as amended (the "Code"). Treasury regulations promulgated
thereunder, and judicial and administrative interpretations thereof, all as in
effect on the date hereof and all of which are subject to change, possibly
retroactively, and is for general information only. The discussion does not
address aspects of United States federal taxation other than income and estate
taxation and does not address all aspects of United States federal income and
estate taxation. The discussion does not consider any specific facts or
circumstances that may apply to a particular Non-U.S. Holder. PROSPECTIVE
INVESTORS ARE URGED TO CONSULT THEIR TAX ADVISORS WITH RESPECT TO THE UNITED
STATES FEDERAL, STATE, LOCAL AND NON-U.S. INCOME AND OTHER TAX CONSEQUENCES TO
THEM OF AN INVESTMENT IN COMMON STOCK.
DIVIDENDS
Dividends paid to a Non-U.S. Holder will generally be subject to
withholding of United States federal income tax at a rate equal to 30% of the
gross amount of the distribution (or at a lower rate prescribed by an applicable
tax treaty) unless the dividends are effectively connected with the conduct of a
trade or business within the United States by the Non-U.S. Holder, in which case
the dividends generally will not be subject to withholding (if the Non-U.S.
Holder files certain forms with the payor of the dividend) and generally will be
subject to the United States federal income tax on net income that applies to
United States persons generally (and, in the case of corporate holders,
effectively connected dividends may also, under certain circumstances, be
subject to the branch profits tax at a 30% rate or such lower rate as may be
specified by an applicable income tax treaty). An applicable income tax treaty
may, however, change these rules. To determine the applicability of a tax treaty
providing for a lower rate of withholding, dividends paid to an address in a
foreign country are presumed under current interpretation of existing Treasury
regulations to be paid to a resident of that country. Treasury regulations
proposed to be effective for payments made after December 31, 1997, which have
not been finally adopted, however, would require Non-U.S. Holders to file
certain new forms to obtain the benefit of any applicable tax treaty providing
for a lower rate of withholding tax on dividends. Such forms would contain the
holder's name and address and certain other information.
The gross amount of a distribution with respect to Common stock will be
treated as a dividend to the extent of the Company's current and accumulated
earnings and profits as determined for U.S. federal income tax purposes. In the
event that such a distribution exceeds the amount of the Company's earnings and
profits, it will be treated first as a non-taxable return of capital to the
extent of the Non-U.S. Holder's basis in Common Stock (but not below zero), and
thereafter as capital gain. A Non-U.S. Holder will have to file a refund claim
to obtain a refund of tax withheld on distributions in excess of the dividend
portion of any distribution.
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GAIN ON DISPOSITION
A Non-U.S. Holder generally will not be subject to United States federal
income tax on gain recognized upon a sale or other disposition of shares of
Common Stock unless (i) the gain is effectively connected with the conduct of a
trade or business within the United States by the Non-U.S. Holder, (ii) the
Non-U.S. Holder is an individual who has a tax home (as specifically defined
under the United States federal income tax laws) in the United States (or
maintains an office or other fixed place of business in the United States to
which the gain from the sale of the stock is attributable), holds the shares of
Common Stock as a capital asset, and is present in the United States for 183
days or more in the taxable year of the disposition or (iii) except as discussed
below, the Company is or has been a "United States real property holding
corporation" ("USRPHC") within the meaning of section 897(c)(2) of the Code at
any time within the shorter of the five year period preceding such disposition
or such holder's holding period.
Gain that is (or is treated as being) effectively connected with the
conduct of a trade or business within the United States by the Non-U.S. Holder
will be subject to the United States federal income tax on net income that
applies to United States persons generally (and, with respect to corporate
holders and under certain circumstances, the branch profits tax) but will not be
subject to withholding. If the Company is a USRPHC, a Non-U.S. Holder may be
subject to taxation under certain provisions of the Codes enacted pursuant to
the Foreign Investors Real Property Tax Act ("FIRPTA"). The determination of
whether the Company is a USRPHC depends in part upon unresolved issues of what
constitutes real property for purposes of the FIRPTA provisions and upon
difficult and uncertain questions of valuation. If the Company were or were to
become a USRPHC, gains realized upon a disposition of Common Stock by a Non-U.S.
Holder that is not deemed to own more than 5% of the Common Stock would not be
subject to tax under the FIRPTA provisions provided that the Common Stock is
"regularly traded" on an established securities market. Since the Common Stock
will trade on the New York Stock Exchange, the Company believes the Common Stock
will be "regularly traded" on an established securities market.
Non-U.S. Holders should consult applicable treaties, which may provide for
different rules (including possibly the exemption of certain capital gains from
tax).
FEDERAL ESTATE TAXES
Common stock owned or treated as owned by an individual who is not a
citizen or resident (as specially defined for United States federal estate tax
purposes) of the United States at the time of death will be includible in the
individual's gross estate for United States federal estate tax purposes, unless
an applicable estate tax treaty provides otherwise. Such individual's estate may
be subject to the United States federal estate tax on the property includible in
the estate for United States federal estate tax purposes.
BACKUP WITHHOLDING AND INFORMATION REPORTING
The Company or its designated paying agent (the "payor") must report
annually to the Internal Revenue Service (the "Service") and to each Non-U.S.
Holder the amount of dividends paid to, and the tax, if any, withheld with
respect to, such holder. That information may also be made available to the tax
authorities of the country in which the Non-U.S. Holder resides.
United States federal backup withholding (imposed at a 31% rate on certain
payments to nonexempt persons) and information reporting with respect to such
withholding will generally not apply to dividends paid to a Non-U.S. Holder that
are otherwise subject to withholding or taxed as effectively connected income as
described above under "Dividends."
The backup withholding and information reporting requirements also apply to
the payment of gross proceeds to a Non-U.S. Holder upon the disposition of
Common Stock by or through a United States office of a United States or foreign
broker, unless the holder certifies to the broker under penalties of perjury as
to its name, address, and status as a Non-U.S. Holder or the holder otherwise
establishes an exemption. Information reporting requirements (but not backup
withholding if the payor does not have actual knowledge that the payee is a
United States person) will apply to a payment of the proceeds of a disposition
of Common
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Stock by or through a foreign office of (i) a United States broker, (ii) a
foreign broker 50% or more of whose gross income for certain periods is
effectively connected with the conduct of a trade or business in the United
States or (iii) a foreign broker that is a "controlled foreign corporation" for
United States federal income tax purposes, unless the broker has documentary
evidence in its records that the holder is a Non-U.S. Holder and certain other
conditions are met, or the holder otherwise establishes an exemption. Neither
backup withholding nor information reporting will generally apply to a payment
of the proceeds of a disposition of Common Stock by or through a foreign office
of a foreign broker not subject to the preceding sentence.
Backup withholding is not an additional tax. Any amounts withheld under the
backup withholding rules will be refunded (or credited against the Non-U.S.
Holder's United States federal income tax liability, if any), provided that the
required information is furnished to the Service.
These information reporting and backup withholding rules are under review
by the United States Treasury and their application to the Common Stock could be
changed by future regulations. The Service recently issued proposed Treasury
regulations concerning the withholding of tax and reporting for certain amounts
paid to non-resident individuals and foreign corporations. The proposed Treasury
regulations, if adopted in their present form, would be effective for payments
made after December 31, 1997. Prospective investors should consult their tax
advisors concerning the potential adoption of such proposed Treasury regulations
and the potential effect on their ownership of the Common Stock.
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UNDERWRITING
Under the terms and subject to the conditions contained in an Underwriting
Agreement dated September 19, 1996 (the "U.S. Underwriting Agreement"), the
underwriters named below (the "U.S. Underwriters"), for whom CS First Boston
Corporation, Morgan Stanley & Co. Incorporated, PaineWebber Incorporated and
Salomon Brothers Inc are acting as representatives (the "Representatives"), have
severally but not jointly agreed to purchase from Calpine and the Selling
Stockholder the following respective number of U.S. Shares:
<TABLE>
<CAPTION>
NUMBER OF
UNDERWRITER U.S. SHARES
----------------------------------------------------------------- -----------
<S> <C>
CS First Boston Corporation...................................... 2,521,500
Morgan Stanley & Co. Incorporated................................ 2,521,500
PaineWebber Incorporated......................................... 2,521,500
Salomon Brothers Inc ............................................ 2,521,500
Bear, Stearns & Co. Inc. ........................................ 300,000
The Buckingham Research Group Incorporated....................... 150,000
First Analysis Securities Corporation............................ 150,000
Goldman, Sachs & Co. ............................................ 300,000
Howard, Weil, Labouisse, Friedrichs Incorporated................. 300,000
Invemed Associates, Inc. ........................................ 300,000
Jefferies & Company, Inc. ....................................... 150,000
Lehman Brothers Inc. ............................................ 300,000
Merrill Lynch, Pierce, Fenner & Smith Incorporated............... 300,000
J.P. Morgan Securities Inc. ..................................... 300,000
Petrie Parkman & Co., Inc. ...................................... 150,000
Prudential Securities Incorporated............................... 300,000
Scotia Capital Markets (USA) Inc. ............................... 300,000
Scott & Stringfellow, Inc. ...................................... 150,000
Smith Barney Inc. ............................................... 300,000
UBS Securities LLC............................................... 300,000
Unterberg Harris................................................. 150,000
Van Kasper & Company............................................. 150,000
-----------
Total.................................................. 14,436,000
=========
</TABLE>
The U.S. Underwriting Agreement provides that the obligations of the U.S.
Underwriters are subject to certain conditions precedent and that the U.S.
Underwriters will be obligated to purchase all of the U.S. Shares offered hereby
(other than those shares covered by the over-allotment option described below)
if any are purchased. The U.S. Underwriting Agreement provides that, in the
event of a default by a U.S. Underwriter, in certain circumstances the purchase
commitments of non-defaulting U.S. Underwriters may be increased or the U.S.
Underwriting Agreement may be terminated.
Calpine has entered into a Subscription Agreement (the "Subscription
Agreement") with the Managers of the International Offering (the "Managers" and,
together with the U.S. Underwriters, the "Underwriters") providing for the
concurrent offer and sale of the International Shares outside the United States
and Canada. The closing of the U.S. Offering is a condition to the closing of
the International Offering and vice versa.
Calpine has granted to the U.S. Underwriters and the Managers an option,
exercisable by CS First Boston Corporation, expiring at the close of business on
the 30th day after the date of this Prospectus, to purchase up to 2,706,750
additional shares at the initial public offering price, less the underwriting
discounts and commissions, all as set forth on the cover page of this
Prospectus. Such option may be exercised only to cover over-allotments in the
sale of the shares of Common Stock offered hereby. To the extent that this
option to purchase is exercised, each U.S. Underwriter and each Manager will
become obligated, subject to certain
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<PAGE> 90
conditions, to purchase approximately the same percentage of additional shares
being sold to the U.S. Underwriters and the Managers as the number of U.S.
Shares set forth next to such U.S. Underwriter's name in the preceding table and
as the number set forth next to such Manager's name in the corresponding table
in the Prospectus relating to the International Offering bears to the sum of the
total number of shares of Common Stock in such tables.
Calpine has been advised by the Representatives that the U.S. Underwriters
propose to offer the U.S. Shares in the United States and Canada to the public
initially at the public offering price set forth on the cover page of this
Prospectus and, through the Representatives, to certain dealers at such price
less a concession of $.54 per share, and the U.S. Underwriters and such dealers
may allow a discount of $.10 per share on sales to certain other dealers. After
the initial public offering, the public offering price and concession and
discount to dealers may be changed by the Representatives.
The public offering price, the aggregate underwriting discounts and
commissions per share and per share concession and discount to dealers for the
U.S. Offering and the concurrent International Offering are identical. Pursuant
to an Agreement between the U.S. Underwriters and Managers (the "Intersyndicate
Agreement") relating to the Common Stock Offering, changes in the public
offering price, concession and discount to dealers will be made only upon the
mutual agreement of CS First Boston Corporation, as representative of the U.S.
Underwriters, and CS First Boston Limited ("CSFBL"), on behalf of the Managers.
Pursuant to the Intersyndicate Agreement, each of the U.S. Underwriters has
agreed that, as part of the distribution of the U.S. Shares and subject to
certain exceptions, it has not offered or sold, and will not offer or sell,
directly or indirectly, any shares of Common Stock or distribute any prospectus
relating to the Common Stock to any person outside the United States or Canada
or to any other dealer who does not so agree. Each of the Managers has agreed or
will agree that, as part of the distribution of the International Shares and
subject to certain exceptions, it has not offered or sold, and will not offer or
sell, directly or indirectly, any shares of Common Stock or distribute any
prospectus relating to the Common Stock in the United States or Canada or to any
other dealer who does not so agree. The foregoing limitations do not apply to
stabilization transactions or to transactions between the U.S. Underwriters and
the Managers pursuant to the Intersyndicate Agreement. As used herein, "United
States" means the United States of America (including the States and District of
Columbia), its territories, possessions and other areas subject to its
jurisdiction, "Canada" means Canada, its provinces, territories, possessions and
other areas subject to its jurisdiction, and an offer or sale shall be in the
United States or Canada if it is made to (i) any individual resident in the
United States or Canada or (ii) any corporation, partnership, pension,
profit-sharing or other trust or other entity (including any such entity acting
as an investment adviser with discretionary authority) whose office most
directly involved with the purchase is located in the United States or Canada.
Pursuant to the Intersyndicate Agreement, sales may be made between the
U.S. Underwriters and the Managers of such number of shares of Common Stock as
may be mutually agreed upon. The price of any shares so sold will be the public
offering price, less such amount as may be mutually agreed upon by CS First
Boston Corporation, as representative of the U.S. Underwriters, and CSFBL, on
behalf of the Managers, but not exceeding the selling concession applicable to
such shares. To the extent there are sales between the U.S. Underwriters and the
Managers pursuant to the Intersyndicate Agreement, the number of shares of
Common Stock initially available for sale by the U.S. Underwriters or by the
Managers may be more or less than the amount appearing on the cover page of the
Prospectus. Neither the U.S. Underwriters nor the Managers are obligated to
purchase from the other any unsold shares of Common Stock.
Calpine has agreed that it will not offer, sell, contract to sell, announce
its intention to sell, pledge or otherwise dispose of, directly or indirectly,
or file with the Securities and Exchange Commission a registration statement
under the Securities Act (other than a registration statement on Form S-8)
relating to, any additional shares of its Common Stock or securities convertible
into or exchangeable or exercisable for any shares of its Common Stock without
the prior written consent of CS First Boston Corporation for a period of 180
days after the date of this Prospectus, except issuances pursuant to the
exercise of employee stock options outstanding on the date hereof. In addition,
all holders of options to purchase shares of Common Stock have
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<PAGE> 91
agreed that they will not, without the prior written consent of CS First Boston
Corporation, offer, sell, contract to sell or otherwise dispose of any shares of
Common Stock beneficially owned by them or any shares issuable upon exercise of
stock options for a period of 180 days after the date of this Prospectus.
Calpine has agreed to indemnify the U.S. Underwriters and the Managers
against certain liabilities, including civil liabilities under the Securities
Act, or to contribute to payments that the U.S. Underwriters and the Managers
may be required to make in respect thereof.
CS First Boston Corporation, one of the Underwriters, is an affiliate of
the Company. The Common Stock Offering therefore is being conducted in
accordance with the applicable provisions of Rule 2720 to the Conduct Rules of
the National Association of Securities Dealers, Inc. Rule 2720 requires that the
initial public offering price of the Common Stock not be higher than that
recommended by a "qualified independent underwriter" meeting certain standards.
Accordingly, PaineWebber Incorporated is assuming the responsibilities of acting
as the qualified independent underwriter in pricing the Common Stock Offering
and conducting due diligence. In connection with the Common Stock Offering,
PaineWebber Incorporated in its role as qualified independent underwriter has
performed due diligence investigations and reviewed and participated in the
preparation of this Prospectus and the Registration Statement of which this
Prospectus forms a part. The initial public offering price of the Common Stock
set forth on the cover page of this Prospectus is no higher than the price
recommended by PaineWebber Incorporated.
The Underwriters may not confirm sales to any discretionary account without
the prior specific written approval of the customer.
The decision made by CS First Boston Corporation and CSFBL to underwrite
the Common Stock Offering was made independently of the Company, CS Holding and
Electrowatt. The net proceeds from the Common Stock Offering will not be applied
for the benefit of CS First Boston Corporation or CSFBL. CS First Boston
Corporation and CSFBL will not receive any benefit from the Common Stock
Offering other than their respective portion of the underwriting discounts and
commissions.
The Common Stock has been approved for listing on the New York Stock
Exchange, subject to notice of issuance, under the symbol "CPN." In connection
with the listing of the Common Stock on the New York Stock Exchange, the
Underwriters have undertaken to sell round lots of 100 shares or more to a
minimum of 2,000 beneficial holders.
Prior to the Common Stock Offering, there has been no public market for the
shares of Common Stock offered hereby. The initial public offering price for the
shares was determined by negotiations among the Company, the Selling Stockholder
and CS First Boston Corporation, as one of the Representatives of the U.S.
Underwriters, and by CSFBL, on behalf of the Managers, and does not necessarily
reflect the secondary market prices for the Common Stock following the initial
offering hereby. Among the principal factors considered in determining the
initial public offering price were prevailing economic prospects, the sales,
earnings and financial and operating performance of the Company in recent
periods, the future prospects of the Company, market valuations of companies in
related businesses and the history and prospects for the industries in which the
Company competes. Additionally, consideration has been given to the general
condition of the securities markets, the market for new issues of securities and
the demand for securities of comparable companies.
In the ordinary course of their business, CS First Boston Corporation and
certain of the other Underwriters and their affiliates have engaged and may in
the future engage in investment banking transactions with Calpine, including the
provision of certain advisory services to Calpine. CS Holding, a Swiss
corporation, holds approximately 44.9% of the outstanding shares of Electrowatt,
which indirectly holds 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 and of CSFBL. CS First Boston Corporation was one of the
Underwriters in connection with the public offering of the Company's 9 1/4%
Senior Notes in February 1994, one of the placement agents in connection with
the sale of the 10 1/2% Senior Notes in May 1996 and is one of the
Representatives of the U.S. Underwriters in the U.S. Offering, and CSFBL is one
of the Managers in the International Offering. See "Certain Transactions."
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NOTICE TO CANADIAN RESIDENTS
RESALE RESTRICTIONS
The distribution of the Common Stock in Canada is being made only on a
private placement basis exempt from the requirement that the Company prepare and
file a prospectus with the securities regulatory authorities in each province
where trades of Common Stock are effected. Accordingly, any resale of the Common
Stock in Canada must be made in accordance with applicable securities laws which
will vary depending on the relevant jurisdiction, and which may require resales
to be made in accordance with available statutory exemptions or pursuant to a
discretionary exemption granted by the applicable Canadian securities regulatory
authority. Purchasers are advised to seek legal advice prior to any resale of
the Common Stock.
REPRESENTATIONS OF PURCHASERS
Each purchaser of Common Stock in Canada who receives a purchase
confirmation will be deemed to represent to the Company and the dealer from whom
such purchase confirmation is received that (i) such purchaser is entitled under
applicable provincial securities laws to purchase such Common Stock without the
benefit of a prospectus qualified under such securities laws, (ii) where
required by law, that such purchaser is purchasing as principal and not as
agent, and (iii) such purchaser has reviewed the text above under "Resale
Restrictions."
RIGHTS OF ACTION AND ENFORCEMENT
The securities being offered are those of a foreign issuer and Ontario
purchasers will not receive the contractual right of action prescribed by
section 32 of the Regulation under the Securities Act (Ontario). As a result,
Ontario purchasers must rely on other remedies that may be available, including
common law rights of action for damages or rescission or rights of action under
the civil liability provisions of the U.S. federal securities laws.
All of the issuer's directors and officers as well as the experts named
herein may be located outside of Canada and, as a result, it may not be possible
for Ontario purchasers to effect service of process within Canada upon the
issuer or such persons. All or a substantial portion of the assets of the issuer
and such persons may be located outside of Canada and, as a result, it may not
be possible to satisfy a judgment against the issuer or such persons in Canada
or to enforce a judgment obtained in Canadian courts against such issuer or
persons outside of Canada.
NOTICE TO BRITISH COLUMBIA RESIDENTS
A purchaser of Common Stock to whom the Securities Act (British Columbia)
applies is advised that such purchaser is required to file with the British
Columbia Securities Commission a report within ten days of the sale of any
Common Stock acquired by such purchaser pursuant to this offering. Such report
must be in the form attached to British Columbia Securities Commission Blanket
Order BOR #95/17, a copy of which may be obtained from the Company. Only one
such report must be filed in respect of Common Stock acquired on the same date
and under the same prospectus exemption.
LEGAL MATTERS
The validity of the Common Stock will be passed upon for the Company by
Brobeck, Phleger & Harrison LLP, San Francisco, California and for the
Underwriters by Skadden, Arps, Slate, Meagher & Flom, New York, New York.
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EXPERTS
The consolidated financial statements and schedules of the Company as of
December 31, 1995 and 1994 and for the three years ended December 31, 1995, 1994
and 1993, the financial statements of Calpine Geysers Company, L.P. for the
period ended April 18, 1993 and the financial statements of BAF Energy, A
California Limited Partnership as of October 31, 1995 and 1994 and for the three
years ended October 31, 1995, 1994 and 1993 included in this Prospectus and
elsewhere in the Registration Statement have been audited by Arthur Andersen
LLP, independent public accountants, as indicated in their reports with respect
thereto, and are included herein in reliance upon authority of said firm as
experts in giving said reports. In the reports for the Company, that firm states
that with respect to Sumas Cogeneration Company, L.P., its opinion is based on
the reports of other independent public accountants, namely Moss Adams LLP.
The consolidated financial statements of Sumas Cogeneration Company, L.P.
and Subsidiary as of December 31, 1995 and 1994 and for the three years ended
December 31, 1995, 1994 and 1993 appearing in this Prospectus have been audited
by Moss Adams LLP, independent public accountants, as indicated in their reports
with respect thereto, and are included herein in reliance upon authority of said
firm as experts in giving said reports.
The combined financial statements of LFC No. 38 Corp. and Portsmouth
Leasing Corporation and Subsidiaries and the consolidated financial statements
of LFC No. 60 Corp. and Subsidiary as of December 31, 1994 and 1993 and for the
years then ended appearing in this Prospectus have been audited by Coopers &
Lybrand L.L.P., independent accountants, as indicated in their reports with
respect thereto, and are included herein in reliance upon authority of said firm
as experts in giving said reports.
The financial statements of Gilroy Energy Company, a wholly owned
subsidiary of Gilroy Foods, Inc. which in turn is a wholly owned subsidiary of
McCormick & Company, Inc., at November 30, 1995 and 1994, and for each of the
two years in the period ended November 30, 1995, appearing in this Prospectus
and Registration Statement have been audited by Ernst & Young LLP, independent
auditors, as set forth in their report thereon appearing elsewhere herein, and
are included in reliance upon such report given upon the authority of such firm
as experts in accounting and auditing.
AVAILABLE INFORMATION
The Company has filed with the Commission a Registration Statement on Form
S-1 under the Securities Act with respect to the Common Stock offered hereby. As
permitted by the rules and regulations of the Commission, this Prospectus omits
certain information, exhibits and undertakings contained in the Registration
Statement. The Company is subject to the informational requirements of the
Securities Exchange Act of 1934, as amended (the "Exchange Act"), and, in
accordance therewith, files periodic reports and other information with the
Commission. For further information with respect to the Company and the Common
Stock offered hereby, reference is made to the Registration Statement, including
the exhibits thereto and the financial statements, notes and schedules filed as
a part thereof, as well as the periodic reports and other information filed by
the Company with the Commission, which may be inspected and copied at the Public
Reference Section of the Commission at Room 1024, Judiciary Plaza, 450 Fifth
Street, N.W., Washington, D.C. 20549 and at the regional offices of the
Commission located at 7 World Trade Center, 13th Floor, New York, New York 10048
and Suite 1400, Northwestern Atrium Center, 500 West Madison Street, Chicago,
Illinois 60661-2511. Copies of such materials may be obtained from the Public
Reference Section of the Commission, Room 1024, Judiciary Plaza, 450 Fifth
Street, N.W., Washington, D.C. 20549, and its public reference facilities in New
York, New York and Chicago, Illinois, at the prescribed rates. The Commission
maintains a Web site that contains reports, proxy and information statements and
other information regarding registrants, such as the Company, that file
electronically with the Commission and the address of such site is
http://www.sec.gov. Statements contained in this Prospectus as to the contents
of any contract or other document are not necessarily complete, and in each
instance reference is made to the copy of such contract or document filed as an
exhibit to the Registration Statement, each such statement being qualified in
all respects by such reference.
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<PAGE> 95
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
CALPINE CORPORATION
Report of Independent Public Accountants.............................................. F-3
Consolidated Balance Sheets, December 31, 1995 and 1994............................... F-4
Consolidated Statements of Operations for the Years Ended December 31, 1995, 1994 and
1993................................................................................ F-5
Consolidated Statements of Stockholder's Equity for the Years Ended December 31, 1995,
1994 and 1993....................................................................... F-6
Consolidated Statements of Cash Flows for the Years Ended December 31, 1995, 1994 and
1993................................................................................ F-7
Notes to Consolidated Financial Statements for the Years Ended December 31, 1995, 1994
and 1993............................................................................ F-8
Condensed Consolidated Balance Sheets, June 30, 1996 (unaudited) and December 31,
1995................................................................................ F-30
Condensed Consolidated Statements of Operations for the Six Months Ended June 30, 1996
and 1995 (unaudited)................................................................ F-31
Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 1996
and 1995 (unaudited)................................................................ F-32
Notes to Condensed Consolidated Financial Statements for the Six Months Ended June 30,
1996 and 1995 (unaudited)........................................................... F-33
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
Report of Independent Public Accountants.............................................. F-38
Consolidated Balance Sheets, December 31, 1995 and 1994............................... F-39
Consolidated Statement of Operations for the Years Ended December 31, 1995, 1994 and
1993................................................................................ F-40
Consolidated Statement of Changes in Partners' Deficit for the Years Ended December
31, 1995, 1994 and 1993............................................................. F-41
Consolidated Statement of Cash Flows for the Years Ended December 31, 1995, 1994 and
1993................................................................................ F-42
Notes to Consolidated Financial Statements for the Years Ended December 31, 1995, 1994
and 1993............................................................................ F-43
CALPINE GEYSERS COMPANY, L.P.
Report of Independent Public Accountants.............................................. F-52
Statement of Operations for the Period from January 1, 1993 to April 18, 1993......... F-53
Statement of Cash Flows for the Period from January 1, 1993 to April 18, 1993......... F-54
Notes to Financial Statements for the Period from January 1, 1993 to April 18, 1993... F-55
LFC NO. 38 CORP. AND PORTSMOUTH LEASING CORPORATION AND SUBSIDIARIES
Report of Independent Accountants..................................................... F-60
Combined Balance Sheets, December 31, 1994 and 1993................................... F-61
Combined Statement of Operations for the Years Ended December 31, 1994 and 1993....... F-62
Combined Statements of Changes in Shareholder's Deficiency for the Years Ended
December 31, 1994 and 1993.......................................................... F-63
Combined Statements of Cash Flows for the Years Ended December 31, 1994 and 1993...... F-64
Notes to Combined Financial Statements for the Years Ended December 31, 1994 and
1993................................................................................ F-65
LFC NO. 60 CORP. AND SUBSIDIARY
Report of Independent Accountants..................................................... F-69
Consolidated Balance Sheets, December 31, 1994 and 1993............................... F-70
Consolidated Statements of Operations for the Years Ended December 31, 1994 and
1993................................................................................ F-71
Consolidated Statements of Changes in Shareholder's Deficiency for the Years Ended
December 31, 1994 and 1993.......................................................... F-72
Consolidated Statements of Cash Flows for the Years Ended December 31, 1994 and
1993................................................................................ F-73
Notes to Consolidated Financial Statements for the Years Ended December 31, 1994 and
1993................................................................................ F-74
</TABLE>
F-1
<PAGE> 96
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
BAF ENERGY, A CALIFORNIA LIMITED PARTNERSHIP
Report of Independent Public Accountants.............................................. F-77
Balance Sheets, October 31, 1995 and 1994............................................. F-78
Statements of Income for the Years Ended October 31, 1995, 1994 and 1993.............. F-79
Statements of Partners' Equity for the Years Ended October 31, 1995, 1994 and 1993.... F-80
Statements of Cash Flows for the Years Ended October 31, 1995, 1994 and 1993.......... F-81
Notes to Financial Statements for the Years Ended October 31, 1995, 1994 and 1993..... F-82
Condensed Balance Sheets as of January 31, 1996 (unaudited) and October 31, 1995...... F-86
Condensed Statements of Income for the Three Months Ended January 31, 1996 and 1995
(unaudited)......................................................................... F-87
Condensed Statements of Cash Flows for the Three Months Ended January 31, 1996 and
1995 (unaudited).................................................................... F-88
Notes to Condensed Financial Statements as of January 31, 1996........................ F-89
GILROY ENERGY COMPANY
Report of Independent Auditors........................................................ F-91
Balance Sheets, November 30, 1995 and 1994 and May 31, 1996 (unaudited)............... F-92
Statements of Income for the Years Ended November 30, 1995 and 1994 and for the Six
Months Ended May 31, 1996 and 1995 (unaudited)...................................... F-93
Statement of Shareholder's Equity for the Years Ended November 30, 1995 and 1994 and
for the Six Months Ended May 31, 1996 (unaudited)................................... F-94
Statements of Cash Flows for the Years Ended November 30, 1995 and 1994 and for the
Six Months Ended May 31, 1996 and 1995 (unaudited).................................. F-95
Notes to Financial Statements for the Years Ended November 30, 1995 and 1994 and for
the Six Months Ended May 31, 1996 and 1995 (unaudited).............................. F-96
</TABLE>
F-2
<PAGE> 97
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, 1995
and 1994, and the related consolidated statements of operations, stockholder's
equity and cash flows for each of the three years in the period ended December
31, 1995. 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% and 2% of the Company's
total assets at December 31, 1995 and 1994, respectively. The Company has
recorded a loss of $3.0 million, $2.9 million and $1.9 million representing its
share of the net loss of Sumas for the years ended December 31, 1995, 1994 and
1993, 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, 1995 and 1994, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 1995 in conformity with
generally accepted accounting principles.
ARTHUR ANDERSEN LLP
San Jose, California
March 15, 1996 (except with respect to
the matter discussed in Note 26, as to
which the date is September 13, 1996)
F-3
<PAGE> 98
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 1995 AND 1994
(IN THOUSANDS)
<TABLE>
<CAPTION>
1995 1994
-------- --------
<S> <C> <C>
ASSETS
Current assets
Cash and cash equivalents..................................................... $ 21,810 $ 22,527
Accounts receivable
from related parties....................................................... 2,177 1,864
from others................................................................ 17,947 12,723
Acquisition project receivables............................................... 8,805 --
Prepaid expenses and other current assets..................................... 5,491 4,256
-------- --------
Total current assets.................................................. 56,230 41,370
Property, plant and equipment, net.............................................. 447,751 335,453
Investments in power projects................................................... 8,218 11,114
Capitalized project costs....................................................... 1,123 645
Notes receivable from related parties........................................... 19,391 16,882
Notes receivable from Coperlasa................................................. 6,394 --
Restricted cash................................................................. 9,627 10,813
Deferred charges and other assets............................................... 5,797 5,095
-------- --------
Total assets.......................................................... $554,531 $421,372
======== ========
LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities
Current non-recourse project financing........................................ $ 84,708 $ 22,800
Notes payable to bank and short-term borrowings............................... 1,177 4,500
Accounts payable.............................................................. 6,876 1,869
Accrued payroll and related expenses.......................................... 2,789 2,624
Accrued interest payable...................................................... 7,050 5,622
Other accrued expenses........................................................ 2,657 2,517
-------- --------
Total current liabilities............................................. 105,257 39,932
Long-term line of credit........................................................ 19,851 --
Non-recourse long-term project financing, less current portion.................. 190,642 196,806
Notes payable................................................................... 6,348 5,296
Senior Notes Due 2004........................................................... 105,000 105,000
Deferred income taxes, net...................................................... 97,621 50,928
Deferred revenue................................................................ 4,585 4,761
-------- --------
Total liabilities..................................................... 529,304 402,723
-------- --------
Commitments and contingencies (Note 25)
Stockholder's equity
Common stock, authorized 33,760 shares, issued and
outstanding -- 10,388 shares in 1995 and 1994.............................. 10 10
Additional paid-in capital.................................................... 6,214 6,214
Retained earnings............................................................. 19,034 12,456
Cumulative translation adjustment............................................. (31) (31)
-------- --------
Total stockholder's equity............................................ 25,227 18,649
-------- --------
Total liabilities and stockholder's equity............................ $554,531 $421,372
======== ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-4
<PAGE> 99
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
1995 1994 1993
-------- -------- --------
<S> <C> <C> <C>
Revenue
Electricity and steam sales.............................. $127,799 $ 90,295 $ 53,000
Service contract revenue from related parties............ 7,153 7,221 16,896
Income (loss) from unconsolidated investments in power
projects.............................................. (2,854) (2,754) 19
-------- ------- -------
Total revenue.................................... 132,098 94,762 69,915
-------- ------- -------
Cost of revenue
Plant operating expenses................................. 33,162 14,944 9,078
Depreciation............................................. 26,264 21,202 12,272
Production royalties..................................... 10,574 11,153 6,814
Operating lease expense.................................. 1,542 -- --
Service contract expenses................................ 5,846 5,546 14,337
-------- ------- -------
Total cost of revenue............................ 77,388 52,845 42,501
-------- ------- -------
Gross profit............................................... 54,710 41,917 27,414
Project development expenses............................. 3,087 1,784 1,280
General and administrative expenses...................... 8,937 7,323 5,080
Provision for write-off of project development costs..... -- 1,038 --
-------- ------- -------
Income from operations........................... 42,686 31,772 21,054
Other (income) expense
Interest expense
Related party......................................... 1,663 375 2,613
Other................................................. 30,491 23,511 11,212
Other income, net........................................ (1,895) (1,988) (1,133)
-------- ------- -------
Income before provision for income taxes and
cumulative effect of change in accounting
principle........................................... 12,427 9,874 8,362
Provision for income taxes............................... 5,049 3,853 4,195
-------- ------- -------
Income before cumulative effect of change in
accounting principle................................ 7,378 6,021 4,167
Cumulative effect of adoption of SFAS No. 109............ -- -- (413)
-------- ------- -------
Net income....................................... $ 7,378 $ 6,021 $ 3,754
======== ======= =======
As adjusted earnings per share assuming conversion of
preferred stock:
14,151
As adjusted weighted average shares outstanding.......... ========
$ 0.52
Net income per share..................................... ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-5
<PAGE> 100
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
(IN THOUSANDS)
<TABLE>
<CAPTION>
COMMON STOCK ADDITIONAL CUMULATIVE
--------------- PAID-IN RETAINED TRANSLATION
SHARES AMOUNT CAPITAL EARNINGS ADJUSTMENT TOTAL
------ ------ ---------- -------- ---------- -------
<S> <C> <C> <C> <C> <C> <C>
Balance, December 31, 1992....................... 10,388 $ 10 $6,214 $ 4,281 $ -- $10,505
Dividend ($0.08 per share)..................... -- -- -- (800 ) -- (800)
Net income..................................... -- -- -- 3,754 -- 3,754
Cumulative translation adjustment.............. -- -- -- -- (31) (31)
----- --- ------- ---- -------
Balance, December 31, 1993....................... 10,388 10 6,214 7,235 (31) 13,428
Dividend ($0.08 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 ($0.08 per share)..................... -- -- -- (800 ) -- (800)
Net income..................................... -- -- -- 7,378 -- 7,378
----- --- ------- ---- -------
Balance, December 31, 1995....................... 10,388 $ 10 $6,214 $19,034 $(31) $25,227
===== === ======= ==== =======
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-6
<PAGE> 101
CALPLNE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
(IN THOUSANDS)
<TABLE>
<CAPTION>
1995 1994 1993
-------- ------- -------
<S> <C> <C> <C>
Cash flows from operating activities
Net income................................................. $ 7,378 $ 6,021 $ 3,754
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization, net...................... 25,931 20,342 11,318
Deferred income taxes, net.............................. (1,027) 3,180 4,619
(Income) loss from unconsolidated investments in power
projects.............................................. 2,854 2,754 (19)
Distributions from investments in power projects........ -- -- 7,352
Provision for write-off of project development costs.... -- 1,038 --
Change in operating assets and liabilities:
Accounts receivable................................... (3,354) (2,578) (615)
Acquisition project receivables....................... (8,805) -- --
Other current assets.................................. (737) 79 (956)
Accounts payable and accrued expenses................. 6,847 6,218 (3,040)
Deferred revenue...................................... (2,434) (2,858) 1,897
-------- -------- --------
Net cash provided by operating activities.......... 26,653 34,196 24,310
-------- -------- --------
Cash flows from investing activities
Acquisition of property, plant and equipment............... (17,434) (7,023) (8,445)
Acquisition of Greenleaf, net of cash on hand.............. (14,830) -- --
Investment in Watsonville, net of cash on hand............. 494 -- --
Acquisition of TPC, net of cash on hand.................... -- (62,770) --
Acquisition of CGC, net of CGC cash on hand................ -- -- (20,296)
Increase in notes receivable............................... (6,348) (13,556) --
Investments in power projects.............................. -- (118) (627)
Capitalized project costs.................................. (1,258) (175) (952)
Decrease (increase) in restricted cash..................... 1,186 (900) 2,968
Other, net................................................. (307) 98 270
-------- -------- --------
Net cash used in investing activities.............. (38,497) (84,444) (27,082)
-------- -------- --------
Cash flows from financing activities
Payment of dividends....................................... (800) (800) (800)
Borrowings from line of credit............................. 34,851 -- 23,000
Repayments of line of credit............................... (15,000) (52,595) (5,873)
Borrowings from non-recourse project financing............. 76,026 60,000 --
Repayments of non-recourse project financing............... (79,388) (12,735) (8,800)
Short-term borrowings...................................... 2,683 4,500 --
Repayments of short-term borrowings........................ (6,006) -- --
Senior Notes Due 2004...................................... -- 105,000 --
Financing costs............................................ (1,239) (3,921) (749)
Repayment of note payable to shareholder................... -- (1,200) --
Proceeds from note payable................................. -- 5,167 --
Repayment of notes payable -- FMRP......................... -- (36,807) --
-------- -------- --------
Net cash provided by financing activities.......... 11,127 66,609 6,778
-------- -------- --------
Net increase (decrease) in cash and cash equivalents......... (717) 16,361 4,006
Cash and cash equivalents, beginning of period............... 22,527 6,166 2,160
-------- -------- --------
Cash and cash equivalents, end of period..................... $ 21,810 $22,527 $ 6,166
======== ======== ========
Supplementary information -- cash paid during the year for:
Interest................................................... $ 32,162 $19,890 $15,084
Income taxes............................................... 4,294 683 13
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-7
<PAGE> 102
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
1. ORGANIZATION AND OPERATIONS OF THE COMPANY
Calpine Corporation (Calpine) and subsidiaries (collectively, the Company)
are engaged in the development, acquisition, ownership and operation of power
generation facilities in the United States. 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, 1995, primarily all electricity and steam sales revenue from consolidated
subsidiaries was derived from sales to two customers in Northern California (see
Note 24), of which 73% related to geothermal activities.
Founded in 1984, the Company is wholly owned by Electrowatt Services, Inc.,
which is wholly owned by Electrowatt Ltd. (Electrowatt), a Swiss company. The
Company has expertise in the areas of engineering, finance, construction and
plant operations and maintenance.
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. During 1993, the Company acquired the remaining
interests in Calpine Geysers Company, L.P. (CGC) (see Note 3). Prior to the
acquisition, the Company recognized its share of the net income of CGC under the
equity method of accounting. 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).
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 for further information regarding
TPC.
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 4), the estimated "free steam" liability (see Revenue Recognition and
Deferred Revenue), receivables which the Company believes to be collectible (see
Note 10), and the realization of deferred income taxes (see Note 19).
Revenue Recognition and Deferred Revenue -- 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
F-8
<PAGE> 103
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
May 1992. Had the Company applied this principle, the revenues of the Company
recorded for the years ended December 31, 1995 and 1994, and for the period from
April 19, 1993 to December 31, 1993, would have been approximately $12.6
million, $11.9 million and $6.5 million less, respectively.
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. In May 1994, the Company 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 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.
The Company performs operations and maintenance services for projects in
which it has an interest. Revenue from investees is recognized on these
contracts when the services are performed. Revenue from consolidated
subsidiaries are 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, their carrying value approximates fair value. Such cash
is excluded from cash and cash equivalents for the purposes of the statements of
cash flows.
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 five
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 8).
Property, Plant and Equipment -- Property, plant and equipment are stated
at cost less accumulated depreciation and amortization.
The Company capitalizes costs incurred in connection with the development
of geothermal properties, including costs of drilling wells and overhead
directly related to development activities, together with the costs of
production equipment, the related facilities and the operating power plants.
Geothermal properties include the value attributable to the geothermal resources
of CGC and all of the property, plant and equipment of 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
F-9
<PAGE> 104
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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. Depreciation of office equipment is provided on the straight-line method
over useful lives of three to five years. Amortization of leasehold improvements
is provided based on the straight-line method over the lesser of the useful life
of the asset or the life of the 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, 1995 and 1994, the components of property, plant and
equipment are (in thousands):
<TABLE>
<CAPTION>
1995 1994
-------- --------
<S> <C> <C>
Geothermal properties.......................................... $216,042 $209,243
Buildings...................................................... 147,532 29,149
Machinery and equipment........................................ 50,826 47,125
Wells and well pads............................................ 44,706 43,982
Steam gathering and control systems............................ 28,363 28,296
Roads.......................................................... 7,384 7,384
Miscellaneous assets........................................... 2,425 1,694
-------- --------
497,278 366,873
Less accumulated depreciation and amortization................. 60,511 34,020
-------- --------
436,767 332,853
Land........................................................... 754 413
Construction in progress....................................... 10,230 2,187
-------- --------
Property, plant and equipment, net........................... $447,751 $335,453
======== ========
</TABLE>
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 11).
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 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.
As Adjusted Earnings Per Share -- Net income per share is computed using
weighted average shares outstanding, which includes the net additional number of
shares which would be issuable upon the exercise of outstanding stock options,
assuming that the Company used the proceeds received to purchase additional
shares at an assumed public offering price. Net income per share also gives
effect, even if antidilutive, to common equivalent shares from preferred stock
that will automatically convert upon the closing of the
F-10
<PAGE> 105
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Company's initial public offering (using the as-if-converted method). If the
offering contemplated by the Company is consummated, all of the convertible
preferred stock outstanding as of the closing date will automatically be
converted into shares of common stock based on the shares of convertible
preferred stock outstanding at June 30, 1996.
Reclassifications -- Prior years' amounts in the consolidated financial
statements have been reclassified where necessary to conform to the 1995
presentation.
3. CALPINE GEYSERS COMPANY, L.P.
CGC, an indirect 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 terms of the agreements which began in 1989, CGC is paid
for energy delivered based upon a fixed price which escalates annually through
December 1998, and upon PG&E's full short-run avoided operating costs for the
subsequent ten years. CGC also receives capacity payments from PG&E. Under
certain circumstances, if CGC is unable to deliver firm capacity, then CGC may
owe PG&E certain minimum damages as specified in the agreements.
Under the steam sales agreements with PG&E and SMUD, the price paid for the
steam is determined annually and semiannually, respectively, based on contract
price formulas and steam delivery terms.
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 (see Note 2). 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.
Prior to April 19, 1993 the Company owned a minority interest in CGC and
recognized its share of CGC's net income under the equity method. 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 from Natomas Energy Company (Natomas), a wholly owned subsidiary of
Maxus Energy Company, pursuant to a Stock Purchase Agreement dated June 27,
1994. Under the terms of the Stock Purchase Agreement, Calpine Thermal acquired
the 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. At or subsequent to the closing of the
acquisition, Calpine received payments of $3.0 million from Natomas, 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.
The Company funded the cash portion of the purchase price in the acquisition
F-11
<PAGE> 106
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
through a two-year non-recourse secured financing provided by The Bank of Nova
Scotia pursuant to a Credit Agreement dated September 9, 1994 (see Note 16).
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, a wholly owned subsidiary of Unocal
Corporation, 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, Calpine Thermal
experienced extensive curtailments of steam production due to low gas prices and
abundant hydro power.
In March 1995, PG&E notified Union Oil and TPC of its plan to accelerate
the retirement of the geothermal power plants to which steam is supplied.
Calpine Thermal had considered plant retirements in its analysis leading to the
acquisition of TPC in September 1994. Calpine Thermal had no assurance that PG&E
would follow the accelerated schedule which was not in accordance with the terms
and conditions of the steam sales agreement, and, with Union Oil, entered into
intensive discussions with PG&E regarding alternatives. As a result of those
discussions, the March 1995 accelerated closure schedule has been reevaluated in
accordance with expected steam supply projections, curtailment levels, and
actual contract terms and conditions to result in estimates of future project
output and revised closure schedules. Closure schedules will continue to be
modified throughout the life of the power sales agreement to be consistent with
actual production levels based on competitive energy prices and weather.
On August 9, 1995, the Company, Union Oil and PG&E executed a letter
agreement on alternative steam pricing for the calendar year 1995. Under this
agreement, all steam delivered up to 40% of field capacity remained at the
original contract rate, and all other steam was sold at a 33% reduction to the
contract rate, thus lowering the cost to PG&E and enhancing production and
revenue from The Geysers to Union Oil and Calpine Thermal. On February 1, 1996,
the Company and Union Oil entered into an alternative steam pricing agreement
with PG&E for the month of February 1996, which was subsequently extended
through at least March 15, 1996. The parties to this agreement are currently in
the process of negotiating a longer term alternative pricing agreement. The
Company is unable to predict the sales and prices that may result from such an
alternative pricing program.
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 two years 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-12
<PAGE> 107
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) from Radnor Power Corporation (Radnor)
for $80.5 million pursuant to a Share Purchase Agreement dated March 30, 1995.
The Acquired Companies own 100% of the assets of two 49.5 megawatt natural
gas-fired cogeneration facilities (collectively, the Greenleaf facilities),
Greenleaf Unit One and Greenleaf Unit Two, located in Yuba City in Northern
California. The Greenleaf facilities burn natural gas in the cogeneration of
electrical and thermal energy. The Greenleaf facilities produce electrical power
for sale to PG&E pursuant to two long-term power sales agreements that provide
for electricity payments over an original thirty-year period (expiring in 2019)
at prices equal to PG&E's full short-run avoided operating costs, adjusted
annually. In addition, the Company receives 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 facilities due to hydro-spill or uneconomic cost conditions. The
thermal energy generated is used by thermal hosts adjacent to the Greenleaf
facilities. The Greenleaf facilities are qualifying facilities, as defined by
the Public Utility Regulatory Policies Act of 1978, as amended (PURPA).
Natural gas for the Greenleaf facilities is supplied by Montis Niger, Inc.
(MNI) pursuant to a long-term gas purchase agreement, and by Chevron USA
Production Company (Chevron). MNI is a wholly owned subsidiary of LFC Financial
Corporation, the parent company of Radnor. See Note 25 for further information
regarding these agreements.
The acquisition was accounted for as a purchase and the purchase price has
been allocated to the acquired assets and liabilities based on the estimated
fair values of the acquired assets and liabilities as shown below. The
allocation may be adjusted as additional information becomes available (in
thousands):
<TABLE>
<S> <C>
Current assets.................................................... $ 6,572
Property, plant and equipment..................................... 120,752
--------
Total assets.................................................... 127,324
--------
Current liabilities............................................... (944)
Deferred income taxes, net........................................ (45,844)
--------
Total liabilities............................................... (46,788)
--------
Net purchase price................................................ $ 80,536
========
</TABLE>
The purchase price included a cash payment of $20.3 million and the
assumption of project debt totalling $60.2 million. The final purchase price,
which is to be adjusted after the determination of the final net working capital
amount, was determined upon an arms-length transaction between Calpine and
Radnor. The parties are currently in dispute regarding certain provisions of the
Share Purchase Agreement, and the outcome of the dispute may affect the purchase
price.
The $20.3 million cash payment was funded by borrowings from the Credit
Suisse lines of credit described in Note 13 below. The $60.2 million debt
assumed by the Company in the acquisition of the Greenleaf facilities consisted
of $57.6 million of non-recourse long-term project financing payable to Credit
Suisse and $2.6 million of installment payments to individuals. On June 30,
1995, the Company refinanced the Greenleaf project by borrowing $76.0 million
from banks (described in Note 16 below). Net proceeds of $74.9 million were used
to repay $57.5 million of Credit Suisse debt including interest, and $2.9
million of installment and premium payments to individuals. The remaining $14.5
million of net proceeds and $500,000 of internal funds were used to repay the
Credit Suisse line of credit borrowings related to the Greenleaf project.
F-13
<PAGE> 108
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Pro forma consolidated results for the Company as if the Greenleaf
acquisition had been consummated on January 1, 1995 and as if the Greenleaf and
TPC acquisitions had been consummated on January 1, 1994, respectively, are (in
thousands, except per share amounts):
<TABLE>
<CAPTION>
YEAR ENDED
-----------------------------
DECEMBER 31, DECEMBER 31,
1995 1994
------------ ------------
(UNAUDITED)
<S> <C> <C>
Revenue.................................................... $137,412 $143,137
Net income................................................. $ 4,868 $ 11,708
Earnings per share (assuming stock split and conversion of
preferred stock; see Note 2)............................. $ 0.34
</TABLE>
The pro forma information does not purport to be indicative of results that
actually would have occurred had the acquisition been made on the dates
indicated or of results which may occur in the future.
Also in connection with the Greenleaf acquisition, the Company borrowed
$1.9 million on April 21, 1995 against an uncommitted demand loan facility with
The Bank of Nova Scotia to finance the prepayment for natural gas to be
delivered to the Greenleaf facilities from MNI (see Note 13 for further
information).
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 in Northern California. The Company acquired the
operating lease from Ford Motor Credit Company, acting through its agent, USL
Capital Corporation, for $900,000. The Watsonville plant sells electricity to
PG&E under the terms of a 20-year power sales agreement, generally at prices
equal to PG&E's full short-run avoided operating costs. Basic and contingent
lease rental payments are described in Note 25. As a cogenerator, the plant
provides steam to two local food processing plants, and is a qualifying facility
as defined by PURPA. The Company also provides project and fuels management
services.
In connection with this acquisition, the Company obtained a $5.0 million
uncommitted line of credit with The Bank of Nova Scotia for letters of credit.
On December 31, 1995, the Company had $2.9 million of letters of credit
outstanding (see Note 13 for further information).
7. CALPINE SISKIYOU GEOTHERMAL PARTNERS, L.P.
On August 24, 1994, the Company formed a partnership with Trans-Pacific
Geothermal Glass Mountain, Ltd. (TGGM), an affiliate of Trans-Pacific Geothermal
Corporation of Oakland, California, and is planning to build a geothermal power
generation facility. The power generation facility will be located at Glass
Mountain in Northern California near the Oregon border. The partnership is
consolidated as the Company owns a controlling interest.
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
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 will loan up to $18.5 million to
Coperlasa, and will receive fees for technical services provided to the project.
At December 31, 1995, notes receivable (see Note 12) totaled $4.9 million. In
February 1996, the Company loaned an additional $3.4 million to Coperlasa.
F-14
<PAGE> 109
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In December 1995, Calpine Vapor also paid $1.5 million for an option to
purchase an equity interest in Coperlasa. The option expires in May 1997 and is
being amortized over the estimated repayment period of the Coperlasa loan
(through the year 1999) using the interest method, as the Company views the
option as a loan acquisition fee. The unamortized balance of the option is also
included in notes receivable from Coperlasa.
9. ACCOUNTS RECEIVABLE
The Company has both billed and unbilled receivables. The components of
accounts receivable as of December 31, 1995 and 1994 are as follows (in
thousands):
<TABLE>
<CAPTION>
1995 1994
------- -------
<S> <C> <C>
Billed........................................................... $18,341 $13,809
Unbilled......................................................... 525 768
Other............................................................ 1,258 10
------- -------
$20,124 $14,587
======= =======
</TABLE>
Other accounts receivable consist primarily of disputed amounts related to
the Greenleaf facilities purchase price (see Note 5).
Accounts receivable from related parties at December 31, 1995 and 1994
include the following (in thousands):
<TABLE>
<CAPTION>
1995 1994
------ ------
<S> <C> <C>
O.L.S. Energy-Agnews, Inc.......................................... $ 806 $ 538
Geothermal Energy Partners, Ltd.................................... 462 793
Sumas Cogeneration Company, L.P.................................... 908 528
Electrowatt and subsidiaries....................................... 1 5
------ ------
$2,177 $1,864
====== ======
</TABLE>
10. ACQUISITION PROJECT RECEIVABLES
On October 17, 1995, in connection with the Company's unsuccessful bid to
acquire O'Brien Environmental Energy, Inc. (OEE) through the U.S. Bankruptcy
Court -- District of New Jersey proceedings, the Company purchased accounts
receivable of $1.9 million, and two notes receivable totaling $3.7 million. The
remaining balance of $3.2 million represents capitalized project acquisition
costs. The recovery of these costs is subject to approval by the U.S. Bankruptcy
Court in 1996.
The Company purchased $1.9 million of accounts receivable from two
cogeneration facilities owned by subsidiaries of OEE. Payments are made to the
Company based on cash availability for each project. In February 1996, the
Company received approximately $1.1 million against these receivables. The
Company currently expects repayment of the balance of these accounts receivable
during 1996.
The Company purchased for $900,000 from Stewart & Stevenson, Inc. (S&S) a
90% participation interest in a $1.0 million note issued by OEE (the O'Brien
Note). Calpine and S&S entered into an agreement in February 1996 whereby S&S
assigned 100% of its interest in the O'Brien Note to Calpine, without any
additional consideration. Interest accrues at approximately 5% after January 20,
1996. The Company currently expects repayment of the note receivable during
1996.
The Company entered into a purchase agreement for all of S&S's rights and
obligations in a Subordinated Loan Agreement dated March 11, 1994 between S&S
and O'Brien (Newark) Cogeneration, Inc. (O'Brien Newark), the Subordinated Note
relating thereto and any related documents and agreements. The purchase price
was $2.8 million and the notes bear interest at prime plus 2.0%. The Company
receives
F-15
<PAGE> 110
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
$80,000 per month until the note is fully amortized. As of December 31, 1995,
$2.7 million of principal was receivable bearing interest at 10.5%. Through
February 1996, the Company received $160,000 in payment of this note. The
Company currently expects repayment of the note receivable upon restructuring of
O'Brien Newark debt during 1996.
11. INVESTMENTS IN POWER PROJECTS
As of December 31, 1995, 1994 and 1993, the Company had unconsolidated
investments in power projects which are accounted for under the equity method.
Financial information related to these investments is as follows (in thousands):
<TABLE>
<CAPTION>
SUMAS O.L.S. GEOTHERMAL
COGENERATION ENERGY- ENERGY
COMPANY, AGNEWS, PARTNERS,
1995 L.P.(A) INC. LTD.
---------------------------------------- ------------ ------- ----------
<S> <C> <C> <C> <C>
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.......... (b) 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) 277
-------- ------- -------
</TABLE>
<TABLE>
<CAPTION>
SUMAS O.L.S. GEOTHERMAL
COGENERATION ENERGY- ENERGY
COMPANY, AGNEWS, PARTNERS,
1994 L.P.(A) INC. LTD.
---------------------------------------- ------------ ------- ----------
<S> <C> <C> <C> <C>
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.......... (b) 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
-------- ------- -------
</TABLE>
F-16
<PAGE> 111
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
<TABLE>
<CAPTION>
SUMAS O.L.S. GEOTHERMAL CALPINE
COGENERATION ENERGY- ENERGY GEYSERS
COMPANY, AGNEWS, PARTNERS, COMPANY,
1993 L.P.(A) INC. LTD. L.P.(C)
---------------------------------------- ------------ ------- ---------- -------
<S> <C> <C> <C> <C>
Operating revenue....................... $ 23,671 $12,485 $ 18,451 $20,759
Net income (loss)....................... (3,739) (931) 1,090 2,689
Assets.................................. 134,579 44,249 74,994 --
Liabilities............................. 123,279 42,249 61,503 --
Company's percentage ownership.......... (b) 20% 5% --
Equity investments in power projects.... 11,700 515 674 --
Project development costs............... 981 17 7 --
-------- ------- ------- -------
Total investments in power projects..... $ 12,681 $ 532 $ 681 $ --
Company's share of net income (loss).... (1,870) (127) 55 1,961
-------- ------- ------- -------
</TABLE>
- ---------------
(a) Commercial operations commenced April 1993 and dry kiln operations commenced
in May 1993.
(b) 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%.
(c) 1993 CGC information is for the period from January 1, 1993 to April 19,
1993, the date of the acquisition. Subsequent to April 19, 1993, the
operating results of CGC are included in the accounts of the Company.
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 is the owner and operator of a power generation facility (the
Generation Facility) in Sumas, Washington. The Generation Facility is a natural
gas-fired combined cycle electrical generation plant with a production capacity
of approximately 125 megawatts. In connection with the Generation Facility,
there 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 Generation Facility.
Sumas produces and sells electrical energy to Puget Sound Power & Light
Company (Puget) under a 20-year agreement for approximately 110 megawatts of
power, which was subsequently increased to an average 123 megawatts in 1994.
Sumas leases the dry kiln facility and sells steam to Socco, Inc. (Socco), a
custom lumber drying operation owned by an affiliated individual. Under the kiln
lease and steam sale agreements with Socco, both of which are for 20 years, the
Generating Facility is a qualifying facility as defined by PURPA.
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. Sumas established
and funded all reserve accounts as required under the terms of the loan
agreements with Prudential and Credit Suisse.
In addition to its interest stated above, the Company has been contracted
by Sumas to provide operations and maintenance services. For these services, the
Company receives a fixed fee of $1.1 million per year
F-17
<PAGE> 112
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
adjusted annually based on the Consumer Price Index, an annual base fee of
$150,000 per year also adjusted based on the Consumer Price Index and certain
other reimbursable expenses. In addition, 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, $1.9 million
and $1.4 million associated with this arrangement during the years ended
December 31, 1995, 1994 and 1993, respectively.
The Company has also provided construction management services to the Sumas
project. The Company recorded revenue of approximately $72,300 and $934,000
related to construction management services during the years ended December 31,
1994 and 1993, respectively. The Company defers the profit on these contracts,
to the extent of their ultimate ownership percentage, and amortizes it over the
life of the project.
Calpine Geysers Company, L.P. -- In addition to its interest as stated
above, the Company had been contracted by CGC to provide operations and
maintenance services at cost plus overhead and fees. The Company recorded
revenue of approximately $6.8 million associated with this service agreement and
for other services provided to CGC for the period from January 1, 1993 to April
19, 1993.
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, which commenced operations in December 1990, 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
$1.5 million, $1.4 million and $2.3 million associated with this service
agreement and for other services provided to the joint venture for the years
ended December 31, 1995, 1994 and 1993, 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 Facility 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 $3.5 million,
$3.7 million and $4.5 million associated with this service agreement to GEP for
the years ended December 31, 1995, 1994 and 1993, respectively.
The Company accounts for its investment in GEP under the equity methods
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.
12. NOTES RECEIVABLE
On May 25, 1993, in accordance with certain provisions of the Sumas
partnership agreement, the Company was entitled to receive a distribution of
$1.5 million. In addition, in accordance with provisions of
F-18
<PAGE> 113
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
the Sumas partnership agreement, SEI 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 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. The Company is deferring the
recognition of interest income from this note until Sumas generates net income.
On March 15, 1994, the Company completed a $10.0 million loan to the sole
shareholder of SEI, the Company's partner in Sumas. The loan matures in 10 years
and bears interest at 16.25%. The loan is secured by a pledge to Calpine of the
partner's interest in Sumas. In order to provide for the payment of principal
and interest on the loan, an additional 25% of the cash flow generated by Sumas,
estimated to begin in 1996, has been assigned to Calpine. The Company is
deferring the recognition of interest income from this note until Sumas
generates net income.
On August 25, 1994, the Company entered into a loan agreement providing for
loans up to $4.8 million to TGGM (see Note 7). The loan bears interest at 10%
and has a maturity date which is based on certain future events. Based on
current forecasts, the maturity date will be in the year 2022. The loan is
secured by a pledge to Calpine of the partner's interest in the project. The
Company is deferring the recognition of income from this note until the Glass
Mountain project generates sufficient income to support collectibility of
interest earned. As of December 31, 1995, $3.8 million was outstanding.
As of December 31, 1995, Calpine Vapor had notes receivable of $4.9 million
and unamortized loan acquisition fees of $1.5 million from Coperlasa (see Note
8). Interest accrues on the $4.9 million of outstanding notes receivable at
approximately 18.8% and is due semi-annually. Principal payments in six equal
installments are due beginning in May 1997 through November 1999. In January
1996, the Company loaned an additional $3.4 million to Coperlasa. The fair value
of the notes receivable approximates its carrying value since the loan was
entered into near the end of 1995.
13. REVOLVING CREDIT FACILITY AND LINES OF CREDIT
At December 31, 1995, the line of credit with Credit Suisse (whose parent
company owns approximately 44.9% of Electrowatt) provided for advances of $50.0
million. Interest may be paid at either LIBOR or the Credit Suisse base rate,
plus applicable margins in both cases. 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). At the Company's discretion, the debt outstanding
can be held for various maturity periods of up to six months. 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. No
stated amortization exists for this indebtedness. From January 1 to March 13,
1996, the Company borrowed an additional $8.8 million and issued a letter of
credit for $3.0 million to fund an additional loan to Coperlasa (see Note 8) and
other developmental project and working capital requirements. No borrowings were
outstanding at December 31, 1994. The credit agreement specifies that the
Company maintain certain covenants with which the Company was in compliance.
At December 31, 1995, the Company 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, with
interest 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). At December 31, 1994, no borrowings and $900,000 of letters
of credit were outstanding on these facilities. The credit agreements specify
that the Company maintain certain covenants with which the Company was in
compliance.
F-19
<PAGE> 114
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
14. 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, 1995. At
December 31, 1994, $4.5 million was outstanding under the working capital
agreement, with interest at 7.625%. The Company had letters of credit
outstanding of $459,000 at December 31, 1995 and 1994. Outstanding letters of
credit bear interest at 0.625% payable quarterly.
15. NOTE PAYABLE TO STOCKHOLDER
On December 31, 1991, the Company declared a dividend of $1.2 million to
its parent company, Electrowatt Services, Inc. On the same date, the Company
issued a note payable to Electrowatt Services, Inc. for $1.2 million. Interest
was paid quarterly at a rate of 4.25%, which approximated market. The note was
paid on June 30, 1994, the maturity date.
16. NON-RECOURSE PROJECT FINANCING
The components of non-recourse project financing as of December 31, 1995
and 1994 are (in thousands):
<TABLE>
<CAPTION>
1995 1994
-------- --------
<S> <C> <C>
Senior-term loans
Fixed rate portion............................................. $ 99,400 $116,800
Variable rate portion.......................................... 20,000 20,000
Premium on debt................................................ 2,959 4,341
-------- --------
Total senior-term loans................................ 122,359 141,141
Junior-term loans................................................ 19,965 19,965
Notes payable to banks........................................... 133,026 58,500
-------- --------
Total long-term debt................................... 275,350 219,606
Less current portion................................... 84,708 22,800
-------- --------
Long-term debt, less current portion................... $190,642 $196,806
======== ========
</TABLE>
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 0.75% to 1.25% (6.69% and 7.25% at December 31,
1995 and 1994, respectively) over the term of the loan, collateralized by all of
CGC's assets and the Company's interest in CGC. In connection with the
acquisition of CGC's assets in 1993, the Company recorded a premium on the fixed
rate portion of the senior-term loans reflecting the fixed rate in excess of
market. The premium is amortized over the life of the fixed rate portion of the
loan using the interest method, and the unamortized balance is included in
long-term debt outstanding.
On January 2, 1996, $5.4 million of principal was repaid, and $2.5 million
of interest calculated through January 1, 1996 was paid.
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 1.5% to 2.75% (7.69% and 8.5% at December 31, 1995 and 1994,
respectively) over the term of the loan, collateralized by all of CGC's assets
and the Company's interest in CGC.
F-20
<PAGE> 115
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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, with a commercial bank and a financing company, effectively fix the
interest on this portion at 9.93%. The Company records the fixed rate interest
as interest expense. At December 31, 1995, the swap agreements were applicable
to debt with a principal balance total of $99.4 million. The interest rate swap
agreements mature through December 31, 2000. The premium on debt was recorded in
conjunction with the acquisition as discussed above. The premium effectively
adjusts the recognized 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 1.0% (6.99%) at December 31, 1995 and LIBOR plus 0.75% (7.25%) at
December 31, 1994. The Company is exposed to credit risk in the event of non-
performance by the other parties to the agreements.
Notes Payable to Banks -- On September 9, 1994, the Company entered into a
two-year agreement with The Bank of Nova Scotia to finance the acquisition of
TPC. As of December 31, 1995, the Company had $57.0 million of non-recourse
project financing outstanding under this agreement. This indebtedness is secured
by TPC's interest in The Geysers steam field assets. Among other restrictions,
TPC is required to maintain an interest coverage ratio of at least 2.5 to 1.0,
and to maintain a loan to value ratio (as defined) of no more than 0.7 to 1.0.
At the Company's discretion, the debt outstanding can be held for various
maturity periods of at least 30 days up to the final maturity date, September 9,
1996. The entire outstanding balance bears interest at variable rates currently
based on LIBOR plus 1% (averaging 6.9% as of December 31, 1995). Interest is
paid on each maturity date, but not less often than quarterly, based on the
principal amount outstanding during the period. No stated principal amortization
exists for this indebtedness. The Company may elect to repay principal at any
time. All unpaid principal is due and payable on September 9, 1996. The Company
currently intends to refinance the $57.0 million of debt before September 9,
1996.
On June 26, 1995, the Company entered into an agreement with Sumitomo Bank
to finance the acquisition of the Greenleaf facilities. Of the $76.0 million
debt outstanding at December 31, 1995, $60.0 million bears interest fixed at
7.4%, with the remaining floating rate portion accruing interest at LIBOR plus
an applicable margin (6.5% as of December 31, 1995). This debt is secured by all
of the assets of Greenleaf Unit One and Greenleaf Unit Two. 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 $76.0 million debt will be repaid quarterly, with a final
maturity date of December 31, 2010.
The annual principal maturities of the non-recourse long-term debt
outstanding at December 31, 1995 are as follows (in thousands):
<TABLE>
<S> <C>
1996.............................................................. $ 84,708
1997.............................................................. 24,772
1998.............................................................. 25,993
1999.............................................................. 18,733
2000.............................................................. 17,991
Thereafter........................................................ 100,194
--------
272,391
Unamortized premium on fixed portion of senior loan............... 2,959
--------
Total................................................... $275,350
========
</TABLE>
The carrying value of $99.4 million and $116.8 million of the senior-term
loan as of December 31, 1995 and 1994, respectively, has an effective rate of
9.93% under the Company's interest rate swap agreements
F-21
<PAGE> 116
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(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, 1995 and 1994 is
approximately $107.3 million and $120.0 million, respectively. The carrying
value of the remaining $20.0 million of the senior and the $20.0 million
junior-term loans and the long-term notes payable to banks approximates the
debt's fair market value as the rates are variable and based on the current
LIBOR rate.
The non-recourse long-term 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.
17. LONG-TERM NOTES PAYABLE
At December 31, 1995, 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 $5.7 million at
December 31, 1995 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 $627,000 of the discounted non-interest bearing note at
December 31, 1995 approximates fair market value.
18. SENIOR NOTES DUE 2004
On February 17, 1994, the Company completed a $105.0 million public debt
offering of 9 1/4% Senior Notes Due 2004 (Senior Notes). The net proceeds of
$100.9 million were used to repay all of the indebtedness outstanding under the
Company's existing line of credit, and to repay the non-recourse notes payable
to FMRP plus accrued interest (see Note 3). The remaining proceeds were used for
general corporate purposes, including the loan to the sole shareholder of SEI
discussed in Note 12. The 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 Senior Notes using the interest
method.
The Senior Notes will mature on February 1, 2004 and bear interest at
9 1/4% payable semiannually on February 1 and August 1 of each year, commencing
August 1, 1994, to holders of record. Based on the traded yield to maturity, the
approximate fair market value of the Senior Notes was $97.0 million as of
December 31, 1995. The agreement specifies that the Company maintain certain
covenants with which the Company was in compliance.
Under provisions of the indenture applicable to the Senior Notes, 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.
19. PROVISION FOR INCOME TAXES
Effective January 1, 1993, the Company adopted Statement of Financial
Accounting Standard No. 109 Accounting for Income Taxes (SFAS No. 109) and
recorded $413,000 as the cumulative effect of adoption in the accompanying
financial statements. SFAS No. 109 requires that the Company follow the
liability method of accounting for income taxes whereby deferred income taxes
are recognized for the tax consequences of
F-22
<PAGE> 117
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
"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, 1995 and
1994 are (in thousands):
<TABLE>
<CAPTION>
1995 1994
--------- --------
<S> <C> <C>
Deferred state income taxes................................... $ 256 $ 1,389
Expenses deductible in a future period........................ 1,865 1,536
Net operating loss and credit carryforwards................... 19,797 15,566
Other differences............................................. 2,034 1,129
--------- --------
Deferred tax asset, before valuation allowance.............. 23,952 19,620
Valuation allowance........................................... (749) (749)
--------- --------
Deferred tax asset.......................................... 23,203 18,871
--------- --------
Property differences.......................................... (116,763) (66,552)
Difference in taxable income and income from investments
recorded on the equity method............................... (2,311) (2,119)
Other differences............................................. (1,750) (1,128)
--------- --------
Deferred tax liabilities.................................... (120,824) (69,799)
--------- --------
Net deferred tax liability............................... $ (97,621) $(50,928)
========= ========
</TABLE>
The net operating loss and credit carryforwards consist of Federal and
State net operating loss carryforwards which expire 2005 through 2010 and 1999,
respectively, and Federal and State alternative minimum tax credit carryforwards
which can be carried forward indefinitely. During 1991, the State of California
suspended the usage of net operating loss carryforwards available to reduce
taxable income for 1992 and 1991. In September 1993, the State of California
removed the suspension on utilization of net operating loss carryforwards,
although they can only be carried forward five years. Fifty percent of the State
net operating loss carryforwards are available to reduce future taxable income.
During 1993, the Company increased the tax provision by approximately $700,000
as a result of the change in the California State Tax regulations. At December
31, 1995, Federal and State net operating loss carryforwards were approximately
$41.8 million and $7.2 million, respectively. At December 31, 1995 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, 1995, Federal and State alternative minimum tax carryforwards were
approximately $3.2 million and $1.6 million, respectively.
Realization of the deferred tax assets and federal net operating loss
carryforwards is dependent on generating sufficient taxable income prior to
expiration of the loss carryforwards. 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.
F-23
<PAGE> 118
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The provision for income taxes for the years ended December 31, 1995, 1994
and 1993 consists of the following (in thousands):
<TABLE>
<CAPTION>
1995 1994 1993
------ ------ ------
<S> <C> <C> <C>
Current
Federal................................................ $3,085 $ 96 $ --
State.................................................. 1,163 365 11
Deferred
Federal, excluding items listed below.................. 816 2,546 2,581
Adjustment in federal tax rate...................... -- -- 88
State, excluding items listed below.................... (15) 547 1,250
Utilization of net operating loss carryforwards..... -- -- (192)
Increase in valuation allowance..................... -- 299 457
------ ------ ------
Total provision................................ $5,049 $3,853 $4,195
====== ====== ======
</TABLE>
The Company's effective rate for income taxes for the years ended December
31, 1995, 1994 and 1993 differs from the U.S. statutory rate for the same
periods due to state income taxes, depletion allowances and the limitation on
use of state net operating loss carryforwards discussed above, as reflected in
the following reconciliation.
<TABLE>
<CAPTION>
1995 1994 1993
---- ---- ----
<S> <C> <C> <C>
U.S. statutory tax rate........................................ 35.0% 35.0% 35.0%
State income tax, net of Federal benefit....................... 6.0 6.0 8.1
Depletion allowance............................................ (0.3) (8.6) --
Adjustment to deferred for change in tax rates................. -- -- 1.0
Utilization of state net operating loss carryforward........... -- -- (2.3)
Other, net..................................................... (0.1) (1.2) 2.9
Increase in valuation allowance................................ -- 7.8 5.5
---- ---- ----
Effective income tax rate................................. 40.6% 39.0% 50.2%
==== ==== ====
</TABLE>
20. 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 1995, 1994 and 1993 totaled $350,000, $311,000 and $293,000,
respectively.
21. COMMON STOCK
Prior to the merger and the stock split discussed in Note 26, the Company
had Class A and Class B common stock. Each class of common stock fully
participated in any dividends declared. Although Class A shareholders were
precluded from receiving stock dividends of Class B common stock, Class B shares
were convertible into Class A shares on a share-for-share basis at the option of
the holder. Each share of Class A common stock was entitled to one vote per
share, and each share of Class B common stock was entitled to ten votes per
share -- see Note 26.
F-24
<PAGE> 119
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
22. STOCK OPTION PROGRAM
The Company adopted a Stock Option Program effective December 31, 1992.
Under the plan, the Board of Directors may grant non-qualified stock options to
officers and other senior employees of the Company, not to exceed 35
participants, to purchase Class A common stock of the Company. The plan is
administered by a committee of the Board of Directors. The committee determines
the timing of awards, individuals to be granted awards, the number of options to
be awarded, and the price, term, vesting schedule and other conditions of the
options. The Company has reserved a total of 2,596,923 Class A common shares for
issuance under the plan.
Options outstanding to officers and other senior employees are:
<TABLE>
<CAPTION>
GRANT OPTIONS PER EXPIRATION
DATE OUTSTANDING SHARE DATE
-------------------------------------------- ----------- ----- -----------------
<S> <C> <C> <C>
December 31, 1992........................... 934,893 $ .50 December 31, 2002
April 1, 1993............................... 179,188 $1.85 April 1, 2003
October 1, 1994............................. 296,049 $4.57 October 1, 2004
January 1, 1995............................. 418,364 $4.91 January 1, 2005
June 16, 1995............................... 25,969 $4.91 June 16, 2005
-------
1,854,463
=======
</TABLE>
The options were granted at fair value as determined by the Board of
Directors based, in part or in whole, on the most recent applicable independent
appraisal. The options granted on December 31, 1992 were fully exercisable on
the date of grant. The options granted in 1993 and 1994 were vested 25% at the
date of issuance with the balance vesting equally over a three-year period. The
options granted on January 1, 1995 vest equally over a four-year period
beginning on January 1, 1996. The options granted on June 16, 1995 vest 50% on
June 16, 1997 and 50% on June 16, 1999. The number of options exercisable at
December 31, 1995 totaled 1,217,308. No options have been exercised to date.
23. 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. The
Company currently pays Electrowatt $200,000 per year for all services rendered
under the management services agreement. The management services agreement
terminates in January 1998.
During 1995, 1994 and 1993, the Company paid $106,000, $69,000 and
$474,000, 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
has 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 terminates in January 1998.
24. SIGNIFICANT CUSTOMERS
The Company's electricity and steam sales revenue is primarily from two
sources -- PG&E and SMUD. During 1994, the Company entered into a three-year
agreement to sell 5 megawatts of electricity to Northern California Power Agency
(NCPA). The Company terminated this agreement on December 31, 1994.
F-25
<PAGE> 120
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Revenues earned from these sources for the years ended December 31, 1995 and
1994 and for the period from April 19, 1993 to December 31, 1993 were (in
thousands):
<TABLE>
<CAPTION>
1995 1994 1993
-------- ------- -------
<S> <C> <C> <C>
PG&E................................................. $112,522 $77,010 $45,819
SMUD................................................. 12,345 9,296 9,014
NCPA................................................. -- 804 --
Other................................................ 173 -- --
-------- ------- -------
125,040 87,110 54,833
Revenues recognized (deferred) (see Note 2).......... 2,759 3,185 (1,833)
-------- ------- -------
Total electricity and steam sales.................... $127,799 $90,295 $53,000
======== ======= =======
</TABLE>
See Note 25 regarding CPUC Restructuring.
25. COMMITMENTS AND CONTINGENCIES
Capital Projects -- The Company has 1996 commitments for capital
expenditures totaling $6.8 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 initial permitting process is underway, with
construction of the facility planned to begin in late 1996 and to be completed
in 1998. The Company is currently evaluating options to finance the construction
of this facility. The Company issued a $3.0 million letter of credit and has a
1996 capital commitment of $3.0 million in connection with this facility. In a
separate transaction, as of March 15, 1996, the Company was negotiating the
potential acquisition of an operating lease for a 120 megawatt gas-fired
cogeneration facility located in Northern California.
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, and 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.
F-26
<PAGE> 121
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Expenses under these agreements for the years ended December 31, 1995 and
1994 and for the period from April 19,1993 to December 31, 1993, are (in
thousands):
<TABLE>
<CAPTION>
1995 1994 1993
------- ------- ------
<S> <C> <C> <C>
Production royalties................................... $10,574 $11,153 $6,814
Lease payments......................................... $ 225 $ 252 $ 172
</TABLE>
Natural Gas Purchases -- Natural gas for the Greenleaf facilities is
supplied by MNI pursuant to a long-term gas purchase agreement. Under the terms
of the gas purchase agreement, MNI may nominate on a monthly basis to provide
firm gas deliveries from certain specified wells. If MNI is unable to deliver
the nominated quantity of gas from its reserves, MNI must purchase and deliver
sufficient gas at no additional cost to the Company. The Company is committed to
purchase gas at the forecasted weighted average incremental cost per decatherm
of gas procured by PG&E at the California border, adjusted annually to actual
cost. The fuel purchase agreement may be terminated by the Company under
specified contract conditions, or upon disbursement of contract suspension
payments.
The Company is committed to purchase and receive natural gas from Chevron
in an amount sufficient to satisfy the requirements of the Greenleaf facilities,
in excess of the nominated quantity supplied by MNI. If MNI supplies less than
the nominated quantity, Chevron shall supply the volumes of natural gas
constituting the difference between the volumes of gas delivered by MNI and the
nominated volumes (make-up gas). Chevron will have the option to be the
exclusive provider of make-up gas if Chevron agrees to sell at a price less than
or equal to 100% of the average gas rate at the burner tip for utility electric
generation as posted by PG&E for the month of delivery. If MNI supplies volumes
of gas greater than its nomination, Chevron will reduce its deliveries in a
corresponding amount. The gas supply agreement is effective through June 30,
1996, continuing month to month thereafter unless either party terminates the
agreement upon sixty days written notice.
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, 1995, future basic rent payments
are $2.9 million for each year from 1996 to 2000, and $27.3 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,
Santa Rosa office facilities and certain office equipment under noncancellable
operating leases expiring through 2000. Future minimum lease payments under
these leases are (in thousands):
<TABLE>
<S> <C>
1996................................................................ $ 899
1997................................................................ 905
1998................................................................ 907
1999................................................................ 776
2000................................................................ 745
thereafter.......................................................... 286
-----
Total future minimum lease commitments.............................. $4,518
=====
</TABLE>
Lease payments are subject to adjustment for the Company's pro rata portion
of annual increases or decreases in building operating costs. In 1995, 1994 and
1993, rent expense for noncancellable operating leases amounted to $733,000,
$663,000 and $636,000, respectively.
F-27
<PAGE> 122
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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. The proposed restructuring provides for phased-in customer choice,
development of non-discriminatory market structure, recovery of utilities'
stranded costs, sanctity of existing contracts, and continuation of existing
public policy programs including the promotion of fuel diversity through a
renewable energy purchase requirement.
As the proposed restructuring has widespread impact and the market
structure requires the participation and oversight of the Federal Energy
Regulatory Commission (FERC), the CPUC will seek to build a California consensus
involving the legislature, the Governor, public and municipal utilities, and
customers. The consensus would then be placed before the FERC so that both the
CPUC and FERC would implement the new market structure no later than January 1,
1998. There can be no assurance that the proposed restructuring will be enacted
in substantially the same form as discussed above. The Company is unable to
predict the ultimate outcome of the restructuring.
Litigation -- The Company, together with over 100 other parties, was named
as a defendant in the second amended complaint 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. This complaint alleges that, in
conjunction with top executives of Bonneville and with the alleged assistance of
the other 100 defendants, the Company engaged in a broad conspiracy and fraud.
The complaint has been amended a number of times. The Company has answered each
version of the complaint by denying all claims and is in the process of
conducting discovery. In August 1994, the Company successfully moved for an
order severing the trustee's claim against the Company from the claims against
the other defendants. Although the case involves over 25 separate financial
transactions entered into by Bonneville, the severed case concerns the Company
in respect of only one of these transactions. In 1988, the Company invested $2.0
million in a partnership formed with Bonneville to develop four hydroelectric
projects in the State of Hawaii. The projects were not successfully developed by
the partnership, and, subsequent to Bonneville's Chapter 11 filing, the Company
filed a claim as a creditor against Bonneville's bankruptcy estate. The trustee
alleges that the equity investment was actually a "sham" loan designed to
inflate Bonneville's earnings. The trustee further alleges that Calpine is one
of many defendants in this case responsible for Bonneville's insolvency and the
amount of damages attributable to the Company based on the $2.0 million
partnership investment is alleged to be $577.2 million. The trustee is seeking
to hold each of the other defendants liable for a portion, all or, in certain
cases, more than this amount. The Company expects the matter will be set for
trial in 1996. The Company believes the claims against it are without merit and
will continue to defend the action vigorously. The Company further believes that
the resolution of this matter will not have a material adverse effect on its
financial position or results of operations.
ENCO terminated protracted contract negotiations with two Canadian natural
gas suppliers in January 1995. One of the suppliers notified ENCO it considered
a draft contract to be effective although it had not been executed by ENCO. The
supplier indicated it may pursue legal action if ENCO would not execute the
contract. As of March 15, 1996, no legal action has been served on ENCO.
Management believes if legal action is commenced, ENCO has significant defenses
and believes such action will not result in any material adverse impact to the
Company's financial condition or results of operations.
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.
F-28
<PAGE> 123
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
26. SUBSEQUENT EVENT
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 equity offering. Also, the Board of Directors approved a stock
split at a ratio of approximately 5.194 to 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.
F-29
<PAGE> 124
CALPINE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)
<TABLE>
<CAPTION>
AS ADJUSTED
JUNE 30,
1996
STOCKHOLDER'S
EQUITY
ASSUMING
CONVERSION
OF PREFERRED
STOCK (NOTE DECEMBER 31,
12) 1995
JUNE 30, ------------- ------------
1996 (UNAUDITED)
--------
(UNAUDITED)
<S> <C> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents............................ $ 38,403 $ 21,810
Accounts receivable.................................. 38,691 20,124
Acquisition project receivables...................... 4,536 8,805
Collateral securities, current portion............... 9,745 --
Prepaid expenses..................................... 6,978 3,447
Inventory............................................ 3,444 1,377
Other current assets................................. 2,947 677
--------
Total current assets......................... 104,744 56,230
Property, plant and equipment, net..................... 530,203 447,751
Investments in power projects.......................... 12,693 8,218
Collateral securities, net of current portion.......... 88,669 --
Notes receivable from related parties.................. 20,894 19,391
Notes receivable from Coperlasa........................ 16,492 6,094
Restricted cash........................................ 8,477 9,627
Deferred charges and other assets...................... 10,640 7,220
--------
Total assets................................. $792,812 $554,531
========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current non-recourse long-term project financing..... $ 27,178 $ 84,708
Notes payable to bank and short-term borrowings...... -- 1,177
Accounts payable..................................... 9,530 6,876
Accrued payroll and related expenses................. 2,336 2,789
Accrued interest payable............................. 8,693 7,050
Other accrued expenses............................... 5,121 2,657
--------
Total current liabilities.................... 52,858 105,257
Long-term line of credit............................... -- 19,851
Non-recourse long-term project financing, less current
portion.............................................. 180,974 190,642
Notes payable.......................................... 6,598 6,348
Senior Notes........................................... 285,000 105,000
Deferred income taxes, net............................. 100,068 97,621
Deferred lease incentive............................... 81,495 --
Other liabilities...................................... 6,163 4,585
--------
Total liabilities............................ 713,156 529,304
--------
Stockholder's equity
Preferred stock...................................... 5 -- --
Common stock......................................... 10 18 10
Additional paid-in capital........................... 56,209 56,206 6,214
Retained earnings.................................... 23,432 23,432 19,003
-------- --------
Total stockholder's equity................... 79,656 79,656 25,227
-------- --------
Total liabilities and stockholder's equity... $792,812 $ 792,812 $554,531
======== ========
</TABLE>
The accompanying notes are an integral part of these condensed consolidated
financial statements.
F-30
<PAGE> 125
CALPINE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30,
-----------------------
1996 1995
-------- --------
<S> <C> <C>
Revenue:
Electricity and steam sales........................................ $ 72,030 $ 49,014
Service contract revenue from related parties...................... 4,616 3,129
Service revenue from others........................................ 818 --
Income (loss) from unconsolidated investments in power projects.... 1,713 (1,791)
Interest income on loans to power projects......................... 2,817 --
-------- --------
Total revenue.............................................. 81,994 50,352
-------- --------
Cost of revenue:
Plant operating expenses, depreciation, operating lease expense and
production royalties............................................ 46,835 28,344
Service contract expenses and other................................ 4,484 2,274
-------- --------
Total cost of revenue...................................... 51,319 30,618
-------- --------
Gross profit......................................................... 30,675 19,734
Project development expenses......................................... 1,410 1,308
General and administrative expenses.................................. 5,874 3,659
-------- --------
Income from operations..................................... 23,391 14,767
Other (income) expense:
Interest expense................................................... 18,665 15,116
Other income, net.................................................. (2,777) (855)
-------- --------
Income before provision for income taxes................... 7,503 506
Provision for income taxes........................................... 3,080 208
-------- --------
Net income................................................. $ 4,423 $ 298
======== ========
As adjusted earnings per share assuming conversion of preferred
stock:
14,400
As adjusted weighted average shares outstanding.................... ========
$ 0.31
Net income per share............................................... ========
</TABLE>
The accompanying notes are an integral part of these condensed consolidated
financial statements.
F-31
<PAGE> 126
CALPINE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
(UNAUDITED)
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE
30,
----------------------
1996 1995
--------- --------
<S> <C> <C>
Net cash provided by operating activities............................. $ 5,035 $ 5,126
--------- --------
Cash flows from investing activities:
Acquisition of property, plant and equipment........................ (8,061) (9,324)
Investment in Greenleaf, net of cash on hand........................ -- (16,958)
Investment in Watsonville, net of cash on hand...................... -- 494
Investment in King City, net of cash on hand........................ (4,877) --
Investment in King City collateral securities....................... (98,414) --
Investments in power projects and capitalized costs................. (2,983) (579)
Loans to Coperlasa.................................................. (12,104) --
Increase in notes receivable from related party..................... (250) (250)
Decrease in restricted cash......................................... 1,150 2,766
Other, net.......................................................... (512) (23)
--------- --------
Net cash used in investing activities............................ (126,051) (23,874)
--------- --------
Cash flows from financing activities:
Proceeds from issuance of Senior Notes Due 2006..................... 180,000 --
Proceeds from issuance of preferred stock........................... 50,000 --
Borrowings from line of credit...................................... 33,800 20,851
Repayment of line of credit......................................... (53,651) (15,000)
Borrowing from Bank................................................. 45,000 --
Repayments to Bank.................................................. (46,177) --
Borrowings of non-recourse project financing........................ -- 77,925
Repayment of non-recourse project financing......................... (66,600) (73,988)
Repayment of working capital loan................................... -- (4,500)
Financing costs..................................................... (4,763) (1,546)
--------- --------
Net cash provided by (used for) financing activities............. 137,609 3,742
--------- --------
Net increase (decrease) in cash and cash equivalents.................. 16,593 (15,006)
Cash and cash equivalents, beginning of period........................ 21,810 22,527
--------- --------
Cash and cash equivalents, end of period.............................. $ 38,403 $ 7,521
========= ========
Supplementary information:
Cash paid during the period for:
Interest......................................................... $ 16,517 $ 17,530
Income taxes..................................................... $ 955 $ 125
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-32
<PAGE> 127
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 1996
1. ORGANIZATION AND OPERATION OF THE COMPANY
Calpine Corporation (Calpine) and subsidiaries (collectively, the Company)
are engaged in the development, acquisition, ownership and operation of power
generation facilities in the United States. The Company has ownership interests
in or operates geothermal steam fields, geothermal power generation facilities,
and natural gas-fired cogeneration facilities in Northern California, Washington
and Mexico. 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. Founded in 1984, the Company
is wholly owned by Electrowatt Services, Inc., which is wholly owned by
Electrowatt Ltd (Electrowatt), a Swiss company. The Company has expertise in the
areas of engineering, finance, construction and plant operations and
maintenance.
In July 1996, the Company filed a registration statement with the United
States Securities and Exchange Commission relating to the initial public
offering of shares of the Company's Common Stock. In the offering, the Company
will sell newly issued shares of Common Stock and Electrowatt will sell shares
of Common Stock representing its entire ownership interest in Calpine. If the
offering is completed, Electrowatt will no longer own any interest in the
Company.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Interim Presentation
The accompanying interim condensed consolidated financial statements of the
Company have been prepared by the Company, without audit by independent public
accountants, pursuant to the rules and regulations of the Securities and
Exchange Commission. In the opinion of management, the condensed consolidated
financial statements include all and only normal recurring adjustments necessary
to present fairly the information required to be set forth therein. Certain
information and note disclosures normally included in financial statements
prepared in accordance with generally accepted accounting principles have been
condensed or omitted from these statements pursuant to such rules and
regulations and, accordingly, should be read in conjunction with the audited
consolidated financial statements of the Company included in the Company's
annual report on Form 10-K for the year ended December 31, 1995. The results for
interim periods are not necessarily indicative of the results for the entire
year.
As Adjusted Earnings Per Share and As Adjusted Stockholder's Equity
Net income per share is computed using weighted average shares outstanding,
which includes the net additional number of shares which would be issuable upon
the exercise of outstanding stock options, assuming that the Company used the
proceeds received to purchase additional shares at an assumed public offering
price. Net income per share also gives effect, even if antidilutive, to common
equivalent shares from preferred stock that will automatically convert upon the
closing of the Company's initial public offering (using the as-if-converted
method). If the offering contemplated by the Company is consummated, all of the
convertible preferred stock outstanding as of the closing date will
automatically be converted into shares of common stock based on the shares of
convertible preferred stock outstanding at June 30, 1996. Unaudited as adjusted
stockholder's equity at June 30, 1996, as adjusted for the conversion of
preferred stock, is disclosed on the balance sheet.
Impact of Recent Accounting Pronouncements
In March 1995, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards (SFAS) No. 121, Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets
F-33
<PAGE> 128
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
to be Disposed Of. This pronouncement requires that long-lived assets and
certain identifiable intangible assets be reviewed for impairment whenever
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. SFAS No. 121 must be adopted
for fiscal years beginning in 1996. 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 October 1995, the Financial Accounting Standards Board issued SFAS No.
123, Accounting for Stock Based Compensation. The disclosure requirements of
SFAS No. 123 are effective for the Company's 1996 fiscal year. The new
pronouncement did not have an impact on its results of operations since the
intrinsic value-based method prescribed by Accounting Principles Board Opinion
No. 25 and also allowed by SFAS No. 123 will continue to be used by the Company
to account for its stock-based compensation plans.
3. ACCOUNTS RECEIVABLE
The Company has both billed and unbilled receivables. The components of
accounts receivable as of June 30, 1996 and December 31, 1995 are as follows (in
thousands):
<TABLE>
<CAPTION>
DECEMBER 31,
1995
JUNE 30, ------------
1996
-----------
(UNAUDITED)
<S> <C> <C>
Projects:
Billed............................................ $37,622 $ 18,341
Unbilled.......................................... 845 525
Other............................................. 224 1,258
------- -------
$38,691 $ 20,124
======= =======
</TABLE>
Other accounts receivable consist primarily of disputed amounts related to
the Greenleaf facilities purchase price. In May 1996, the Company reclassified
such accounts receivable to property, plant and equipment as an adjustment to
the purchase price of the Greenleaf facilities (see Note 6).
Accounts receivable from related parties as of June 30, 1996 and December
31, 1995 are comprised of the following (in thousands):
<TABLE>
<CAPTION>
DECEMBER 31,
1995
JUNE 30, ------------
1996
-----------
(UNAUDITED)
<S> <C> <C>
O.L.S. Energy-Agnews, Inc. ......................... $ 589 $ 806
Geothermal Energy Partners, Ltd. ................... 979 462
Sumas Cogeneration Company, L.P. ................... 1,206 908
Electrowatt and subsidiaries........................ 2 1
------- -------
$ 2,776 $ 2,177
======= =======
</TABLE>
F-34
<PAGE> 129
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
4. INVESTMENTS IN POWER PROJECTS
The Company has unconsolidated investments in power projects which are
accounted for under the equity method. Unaudited financial information for the
six months ended June 30, 1996 and 1995 related to these investments is as
follows (in thousands):
<TABLE>
<CAPTION>
1996 1995
----------------------------------- ----------------------------------
SUMAS O.L.S. GEOTHERMAL SUMAS O.L.S. GEOTHERMAL
COGENERATION ENERGY- ENERGY COGENERATION ENERGY- ENERGY
COMPANY, AGNEWS, PARTNERS, COMPANY, AGNEWS, PARTNERS,
L.P. INC. LTD. L.P. INC. LTD.
------------ ------- ---------- ------------ ------ ----------
<S> <C> <C> <C> <C> <C> <C>
Revenue........................................ $ 21,561 $4,604 $9,576 $ 15,265 $4,612 $9,847
Operating expenses............................. 12,752 4,349 6,219 13,530 4,300 5,064
------- ------ ------ ------ ------ ------
Income (loss) from operations.................. 8,809 255 3,357 1,735 312 4,783
Other expenses, net............................ 5,098 1,040 2,444 5,283 1,034 2,865
------- ------ ------ ------ ------ ------
Net income (loss).......................... $ 3,711 $ (785 ) $ 913 $ (3,548) $(722 ) $1,918
======= ====== ====== ====== ====== ======
Company's share of net income (loss)........... $ 1,855 $ (179 ) $ 37 $ (1,774) $(130 ) $ 113
======= ====== ====== ====== ====== ======
</TABLE>
5. THERMAL POWER COMPANY
In March 1996, Thermal Power Company (TPC) a wholly owned subsidiary of the
company, and Union Oil Company of California (Union Oil) entered into an
alternative pricing agreement with Pacific Gas and Electric Company (PG&E) for
any steam produced in excess of 40% of average field capacity. The alternative
pricing strategy is effective through December 31, 2000. Under the agreement,
PG&E would purchase a portion of the steam that PG&E would likely curtail under
TPC's existing steam sales agreement. The price for this portion of steam will
be set by TPC and Union Oil with the intent that it be at competitive market
prices. TPC and Union Oil will solely determine the price and duration of these
alternative price offers.
6. GREENLEAF TRANSACTION
In April 1995, the Company purchased the capital stock of the companies
which owned 100% of the assets of two 49.5 megawatt natural gas-fired
cogeneration facilities (collectively, the Greenleaf facilities) located in Yuba
City in Northern California. The initial purchase price included a cash payment
of $20.3 million and the assumption of project debt totalling $60.2 million. In
April 1996, the Company finalized the purchase price in accordance with the
Share Purchase Agreement dated March 30, 1995.
The acquisition was accounted for as a purchase and the purchase price has
been allocated to the acquired assets and liabilities based on the estimated
fair values of the acquired assets and liabilities as shown below. The adjusted
allocation of the purchase price is as follows (in thousands):
<TABLE>
<S> <C>
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
========
</TABLE>
F-35
<PAGE> 130
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
7. 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 combined cycle facility located in King City, California. The facility
generates electricity for sale to PG&E pursuant to a long-term power sales
agreement through 2019. Natural gas for the facility is supplied by Chevron USA
Inc. pursuant to a contract which expires June 30, 1997.
Under the terms of the operating lease, the Company makes semi-annual lease
payments to BAF on each February 15 and August 15, a portion of which is
supported by a $98.4 million collateral fund owned by the Company. The
collateral fund consists of a portfolio of investment grade and U.S. Treasury
Securities that will mature serially in amounts equal to a portion of the lease
payments. The collateral fund securities are accounted for as held-to-maturity
investments under SFAS No. 115, Accounting for Certain Investments in Debt and
Equity Securities. As of June 30, 1996, future rent payments are $11.8 million
for the remainder of 1996, $24.4 million for 1997, $23.8 million for 1998, $19.4
million for 1999, $20.1 million for 2000 and $204.1 million thereafter.
The Company has recorded the value of the above-market pricing provided in
the power sales agreement (PSA) as an asset which is included in property, plant
and equipment, since the Company has, in substance, assumed the rights of the
PSA. The Company has also recorded a deferred lease incentive 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.
The Company financed the collateral fund and other transaction costs with
$50.0 million of proceeds from the issuance of preferred stock to Electrowatt by
Calpine (see Note 10) and other short-term borrowings, which included $13.3
million of borrowings under the Credit Suisse Credit Facility (see Note 8) below
and a $45.0 million loan from The Bank of Nova Scotia. The Company repaid the
short-term borrowings from a portion of the net proceeds of the Senior Notes Due
2006 issued in May 1996 (see Note 9).
8. LINES OF CREDIT
At June 30, 1996, the Company had borrowings under its $50.0 million Credit
Facility with Credit Suisse (whose parent company owns 44.9% of Electrowatt) and
had a letter of credit outstanding thereunder for $3,025,000. Borrowings under
the Credit Facility bear interest at the London Interbank Offered Rate (LIBOR)
plus 0.5%. Interest is paid on the last day of each interest period for such
loan, but not less often than quarterly, based on the principal amount
outstanding during the period. No stated principal amortization exists for this
indebtedness. Upon completion of the Company's proposed initial public offering,
the Credit Facility will terminate and is expected to be replaced by a
comparable facility. On July 20, 1996, the Company entered into a commitment
letter with The Bank of Nova Scotia to provide a $50 million three-year
Revolving Credit Facility. Such Revolving Credit Facility will become effective
upon the completion of the Company's initial public offering.
9. SENIOR NOTES DUE 2006
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 $175.2 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
borrowing from The Bank of Nova Scotia. The remaining $19.5 million was
available for general corporate purposes. Transaction costs of $4.8 million
incurred in connection with the public debt offering were recorded as a
F-36
<PAGE> 131
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
deferred charge and are amortized over the ten-year life of the Senior Notes Due
2006 using the straight line method.
The Senior Notes Due 2006 will mature on May 15, 2006. The Company has no
sinking fund or mandatory redemption obligations with respect to the Senior
Notes Due 2006. Interest is payable semi-annually on May 15 and November 15 of
each year while the Senior Notes Due 2006 are outstanding, commencing on
November 15, 1996.
10. PREFERRED STOCK
The Company has 5,000,000 authorized shares of Series A Preferred Stock,
all of which were issued on March 21, 1996 and outstanding as of June 30, 1996.
All of the shares of Series A Preferred Stock are held by Electrowatt. The
shares of Series A Preferred Stock are not publicly traded. No dividends are
payable on the Series A Preferred Stock. The Series A Preferred Stock contains
provisions regarding liquidation and conversion rights. Upon the consummation of
the Company's proposed initial public offering, the Series A Preferred Stock
will be converted into Common Stock and sold to the public in the offering.
11. CONTINGENCIES
The Company, together with over 100 other parties, was named as a defendant
in the second amended complaint 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"). This complaint alleges that, in conjunction
with top executives of Bonneville and with the alleged assistance of the other
100 defendants, the Company engaged in a broad conspiracy and fraud. The
complaint has been amended a number of times. The Company has answered each
version of the complaint by denying all claims and is in the process of
conducting discovery. In August 1994, the Company successfully moved for an
order severing the trustee's claim against the Company from the claims against
the other defendants. Although the case involves over 25 separate financial
transactions entered into by Bonneville, the severed case concerns the Company
in respect of only one of these transactions. In 1988, the Company invested $2.0
million in a partnership formed with Bonneville to develop four hydroelectric
projects in the State of Hawaii. The projects were not successfully developed by
the partnership, and, subsequent to Bonneville's Chapter 11 filing, the Company
filed a claim as a creditor against Bonneville's bankruptcy estate. The trustee
alleges that the equity investment was actually a "sham" loan designed to
inflate Bonneville's earnings. The trustee initially alleged that Calpine is one
of many defendants in this case responsible for Bonneville's "deepening
insolvency" and the amount of damages attributable to the Company based on the
$2.0 million partnership investment was alleged to be $577.2 million. Based upon
statements made by the Court and the trustee in July 1996, the Company believes
that the maximum compensatory damages which the trustee may seek will not exceed
$5 million. There can be no assurance, however, of the actual amount of damages
to be sought by the Trustee. The Company believes the claims against it are
without merit and will continue to defend the action vigorously. The Company
further believes that the resolution of this matter will not have a material
adverse effect on its financial position or results of operations.
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.
12. SUBSEQUENT EVENT
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 equity offering. Also, the Board of Directors approved a stock
split at a ratio of approximately 5.194 to 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.
F-37
<PAGE> 132
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, 1995 and 1994, and
the related consolidated statements of operations, changes in partners' deficit,
and cash flows for each of the three years ended December 31, 1995. 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, 1995 and 1994 and
the results of their operations and cash flows for each of the three years ended
December 31, 1995, in conformity with generally accepted accounting principles.
MOSS ADAMS LLP
Everett, Washington
January 19, 1996
F-38
<PAGE> 133
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------------------
1995 1994
------------ ------------
<S> <C> <C>
ASSETS
Current assets
Cash and cash equivalents..................................... $ 199,169 $ 353,936
Current portion of restricted cash and cash equivalents....... 2,937,884 6,409,185
Accounts receivable........................................... 3,090,213 4,108,206
Prepaid expenses.............................................. 222,828 232,325
------------ ------------
Total current assets....................................... 6,450,094 11,103,652
Restricted cash and cash equivalents, net of current portion.... 8,017,758 7,454,923
Property, plant and equipment, at cost, net..................... 95,589,737 97,039,459
Other assets.................................................... 12,744,480 14,550,228
------------ ------------
$122,802,069 $130,148,262
============ ============
LIABILITIES AND PARTNERS' DEFICIT
Current liabilities
Accounts payable and accrued liabilities...................... $ 2,051,178 $ 3,651,799
Current portion of related party payables
Calpine Corporation........................................ 4,864 41,871
National Energy Systems Company............................ 1,861 1,430
Current portion of long-term debt............................. 2,000,000 400,000
------------ ------------
Total current liabilities.................................. 4,057,903 4,095,100
Related party payable -- Calpine Corporation, net of current
portion....................................................... 908,679 446,624
Long-term debt, net of current portion.......................... 117,000,003 119,000,002
Future removal and site restoration costs....................... 502,600 309,600
Deferred income taxes........................................... 907,800 773,800
Commitments and contingency (Notes 6 and 8)
Partners' (deficit) equity...................................... (574,916) 5,523,136
------------ ------------
$122,802,069 $130,148,262
============ ============
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-39
<PAGE> 134
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
CONSOLIDATED STATEMENT OF OPERATIONS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------
1995 1994 1993
------------ ------------ -----------
<S> <C> <C> <C>
Revenues
Power sales......................................... $ 30,603,018 $ 29,206,469 $19,525,098
Natural gas sales, net.............................. 893,690 2,832,668 2,104,407
Other............................................... 29,146 20,490 116,895
------------ ------------ -----------
Total revenues.............................. 31,525,854 32,059,627 21,746,400
------------ ------------ -----------
Costs and expenses
Operating and production costs...................... 18,493,245 19,032,754 11,779,505
Depletion, depreciation and amortization............ 6,965,496 6,715,156 4,986,300
General and administrative.......................... 1,400,129 1,412,326 1,563,509
------------ ------------ -----------
Total costs and expenses.................... 26,858,870 27,160,236 18,329,314
------------ ------------ -----------
Income from operations................................ 4,666,984 4,899,391 3,417,086
------------ ------------ -----------
Other income (expense)
Interest income..................................... 490,071 436,741 250,675
Interest expense.................................... (11,006,056) (10,172,959) (6,707,183)
Other expense....................................... (60,664) (359,000) --
------------ ------------ -----------
Total other expense......................... (10,576,649) (10,095,218) (6,456,508)
------------ ------------ -----------
Loss before provision for income taxes................ (5,909,665) (5,195,827) (3,039,422)
Provision for income taxes............................ (188,387) (581,190) (337,431)
------------ ------------ -----------
Net loss.............................................. $ (6,098,052) $ (5,777,017) $(3,376,853)
============ ============ ===========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-40
<PAGE> 135
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' DEFICIT
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
<TABLE>
<S> <C>
Partners' equity, December 31, 1992............................................. $14,688,436
Capital contributions........................................................... 1,500,000
Capital distributions........................................................... (1,500,000)
Net loss........................................................................ (3,376,853)
Cumulative foreign exchange translation adjustment.............................. (11,430)
-----------
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)
===========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-41
<PAGE> 136
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
CONSOLIDATED STATEMENT OF CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------
1995 1994 1993
----------- ----------- -----------
<S> <C> <C> <C>
Cash flows from operating activities
Net loss.......................................... $(6,098,052) $(5,777,017) $(3,376,853)
Adjustments to reconcile net loss to net cash from
operating activities
Depletion, depreciation and amortization....... 6,965,496 6,715,156 4,986,300
Deferred income taxes.......................... 134,000 532,400 241,400
Changes in operating assets and liabilities
Accounts receivable.......................... 1,017,993 (1,254,639) (2,064,616)
Prepaid expenses............................. 9,497 (30,342) 203,904
Accounts payable and accrued liabilities..... (1,407,621) 1,081,431 1,168,892
Related party payables....................... 425,479 132,296 --
----------- ----------- -----------
Net cash from operating activities........ 1,046,792 1,399,285 1,159,027
----------- ----------- -----------
Cash flows from investing activities
Decrease (increase) in restricted cash and cash
equivalents.................................... 2,908,466 2,922,819 (13,286,927)
Acquisition of property, plant and equipment...... (3,710,025) (3,690,399) (16,558,101)
Other assets...................................... -- (167,483) (5,700,537)
Accounts payable and accrued liabilities.......... -- -- (3,847,743)
----------- ----------- -----------
Net cash from investing activities........ (801,559) (935,063) (39,393,308)
----------- ----------- -----------
Cash flows from financing activities
Proceeds from long-term debt...................... -- -- 38,710,000
Repayment of long-term debt....................... (400,000) (400,025) (199,973)
Capital contributions............................. -- -- 1,500,000
Capital distributions............................. -- -- (1,500,000)
Payments to related parties....................... -- -- (864,890)
----------- ----------- -----------
Net cash from financing activities........ (400,000) (400,025) 37,645,137
----------- ----------- -----------
Effect of exchange rate changes on cash............. -- -- (11,430)
----------- ----------- -----------
Net increase (decrease) in cash and cash
equivalents....................................... (154,767) 64,197 (600,574)
Cash and cash equivalents, beginning of year........ 353,936 289,739 890,313
----------- ----------- -----------
Cash and cash equivalents, end of year.............. $ 199,169 $ 353,936 $ 289,739
=========== =========== ===========
Supplementary disclosure of cash flow information
Cash paid for interest during the year............ $11,006,056 $10,172,959 $ 8,868,183
=========== =========== ===========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-42
<PAGE> 137
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1995, 1994 AND 1993
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. 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.
Prior to the commencement of commercial operation as discussed below, the
Partnership was considered to be a development stage company in the process of
developing, constructing and owning 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 on April 16, 1993. In addition, the Generation Facility
includes a lumber dry kiln facility and a 3.5 mile private natural gas pipeline.
The lumber dry kiln commenced commercial operation in May 1993.
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 production 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 electricity capacity 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:
<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31, MEGAWATTS REVENUE
---------------------------------------------------- --------- -----------
<S> <C> <C>
1995................................................ 1,026,000 $30,603,000
1994................................................ 1,000,400 $29,206,000
1993................................................ 696,400 $19,525,000
</TABLE>
The Partnership leases a kiln facility and sells steam under a 20-year
agreement for the purchase and sale of steam and lease of the kiln (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 $6,239,000 and
$5,619,000 at December 31, 1995 and 1994, respectively, and to SEI of
approximately $441,000 and $363,000 at December 31, 1995 and 1994, 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,
F-43
<PAGE> 138
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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%.
(c) DISTRIBUTIONS -- Distributions of operating cash flows are permitted
quarterly after required deposits are made and minimum cash balances are met,
and subject to certain other restrictions. During 1995 and 1994, there were no
distributions of operating cash flow. In 1993 Whatcom received a distribution of
$1,500,000, reducing its equity investment in the Partnership. Whatcom loaned
the sole shareholder of SEI $1,500,000, and the sole shareholder of SEI loaned
$1,500,000 to SEI. SEI then contributed $1,500,000 in additional equity to the
Partnership.
(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 $3,748,000 in 1995, $3,630,000
in 1994 and $3,026,400 in 1993. 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
$193,000 in 1995, $169,000 in 1994 and $110,000 in 1993, 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 -- During 1995 and 1994, 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 operations.
During 1993, ENCO's functional currency was Canadian dollars. As a result,
translation adjustments were reported separately and accumulated as separate
components of partners' equity.
(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
F-44
<PAGE> 139
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 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:
<TABLE>
<S> <C>
Organization, start-up and development costs..................... 5-30 years
Financing costs.................................................. 15 years
Gas contract costs............................................... 20 years
</TABLE>
(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
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------------------
1995 1994
------------ ------------
<S> <C> <C>
Land and land improvements.............................. $ 381,071 $ 381,071
Plant and equipment..................................... 84,061,359 82,759,005
Acquisition of gas properties, including development
thereon............................................... 25,030,165 22,815,964
Furniture and fixtures.................................. 195,914 188,444
------------ ------------
109,668,509 106,144,484
Less accumulated depreciation and depletion............. 14,078,772 9,105,025
------------ ------------
$ 95,589,737 $ 97,039,459
============ ============
</TABLE>
Depreciation expense was $3,316,748 in 1995, $3,069,446 in 1994 and
$2,133,711 in 1993. Depletion expense was $1,843,000 in 1995, $1,671,000 in 1994
and $1,332,000 in 1993.
F-45
<PAGE> 140
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 3 -- OTHER ASSETS
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------------
1995 1994
----------- -----------
<S> <C> <C>
Organization, start-up and development costs.............. $ 6,165,574 $ 7,487,943
Financing costs........................................... 4,254,719 4,598,746
Gas contract costs........................................ 2,324,187 2,463,539
----------- -----------
$12,744,480 $14,550,228
=========== ===========
</TABLE>
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).
Credit Suisse is an affiliate of Whatcom. At December 31, 1995 and 1994, amounts
outstanding under the term loan agreements, by entity, were as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------------------
1995 1994
------------ ------------
<S> <C> <C>
Sumas Cogeneration Company, L.P......................... $ 94,367,003 $ 94,684,202
ENCO Gas, Ltd........................................... 24,633,000 24,715,800
------------ ------------
119,000,003 119,400,002
Less current portion.................................... 2,000,000 400,000
------------ ------------
$117,000,003 $119,000,002
============ ============
</TABLE>
Scheduled annual principal payments under the loan agreements as of
December 31, 1995 are as follows:
<TABLE>
<CAPTION>
YEAR ENDING
DECEMBER 31, AMOUNT
--------------------------------------------------------------- ------------
<S> <C>
1996........................................................... $ 2,000,000
1997........................................................... 3,600,000
1998........................................................... 4,200,000
1999........................................................... 5,400,000
2000........................................................... 7,200,000
Thereafter..................................................... 96,600,003
------------
$119,000,003
============
</TABLE>
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% prior to
Loan Conversion to .875% after Loan Conversion as stated in the loan agreement.
During the year ended December 31, 1995, interest rates on the variable rate
loan ranged from 7.47% to 7.76%. 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
F-46
<PAGE> 141
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
December 31, 1995, interest rates on the variable rate loan ranged from 7.47% to
7.76%. The loans mature in May 2008.
The Partnership pays Prudential an agency fee of $50,000 per year, adjusted
annually by an inflation index, until the loan matures. The Partnership pays
Credit Suisse an agency fee of $40,000 per year, adjusted annually by an
inflation index, until the loan matures. 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 Partnership 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 noncurrent asset.
During 1993, the Company incurred and paid $8,868,183 of interest,
including $6,707,183, which was charged to operations and $2,161,000, which was
capitalized.
NOTE 5 -- INCOME TAXES
The provision for income taxes represents Canadian taxes which consist of
the following:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------
1995 1994 1993
-------- -------- --------
<S> <C> <C> <C>
Current
Federal large corporation tax.................... $ 34,625 $ 31,314 $ 45,262
British Columbia capital taxes................... 19,762 17,476 50,769
-------- -------- --------
54,387 48,790 96,031
Deferred........................................... 135,400 178,400 241,400
-------- -------- --------
189,787 227,190 337,431
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.... (49,100) 95,000 --
-------- -------- --------
$188,387 $581,190 $337,431
======== ======== ========
</TABLE>
F-47
<PAGE> 142
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The principal sources of temporary differences resulting in deferred tax
assets and liabilities are as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------
1995 1994
---------- ----------
<S> <C> <C>
Deferred tax asset
Canadian net operating loss carryforwards................. $ (840,900) $ (829,400)
Deferred tax liabilities
Acquisition and development costs of gas deducted for tax
purposes in excess of amounts deducted for financial
reporting purposes..................................... 1,748,700 1,603,200
---------- ----------
Net deferred tax liability........................ $ 907,800 $ 773,800
========== ==========
</TABLE>
The provision for income taxes differs from the Canadian statutory rate
principally due to the following:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------
1995 1994 1993
-------- -------- --------
<S> <C> <C> <C>
Canadian statutory rate............................ 44.62% 44.34% 44.3%
Income taxes based on statutory rate............... $(33,852) $ 82,909 $165,100
Capital taxes, net of deductible portion........... 47,028 36,678 75,587
Non-deductible provincial royalties, net of
resource allowance............................... 95,671 39,836 50,267
Depletion on gas properties with no tax basis...... 44,641 38,420 41,778
Other foreign exchange adjustments................. 36,299 29,347 4,699
-------- -------- --------
$189,787 $227,190 $337,431
======== ======== ========
</TABLE>
As of December 31, 1995, ENCO has non-capital loss carryforwards of
approximately $1,885,000 which may be applied against taxable income of future
periods which expire as follows:
<TABLE>
<S> <C>
1999............................................................. $1,625,000
2000............................................................. $ 260,000
</TABLE>
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 from June 1993 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 $258,000 in 1995,
$253,000 in 1994 and $151,000 in 1993 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.
Accordingly, the performance bonuses earned in 1995 and 1994 are included as a
non-current liability in the consolidated balance sheet. 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.
F-48
<PAGE> 143
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Approximately $2,031,000 in 1995, $1,946,000 in 1994 and $1,260,000 in 1993 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 $19,000 in
1995, $61,000 in 1994 and $6,000 in 1993.
(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 $100,000 in 1995, $101,000 in 1994 and
$96,000 in 1993 was paid under this agreement
(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 in accordance with
the agreement. The Partnership paid ENCO $2.26 per delivered MMBtu through
October 1995 and pays $2.43 per delivered MMBtu through 1996. Prices under the
agreement then escalate at an annual rate of 7.5% until October 31, 2000, and at
4% per annum thereafter. Partnership payments to ENCO under the agreement are
eliminated in consolidation. The agreement expires on the twentieth anniversary
of the date of commercial operation.
The Partnership has a gas supply agreement with 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 agreement. The agreement is expected to terminate on October
31, 1996.
The Partnership and ENCO have a gas management agreement with WGSI. WGSI is
paid a gas management fee for each MMBtu of gas delivered to the Generation
Facility. The gas management fee is adjusted annually based on the British
Columbia Consumer Price Index. The gas management agreement expires October 31,
2008 unless terminated earlier as provided for in the agreement.
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 $2,569,000 in 1995, $2,776,000 in 1994 and $1,347,000 in 1993.
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. As of December 31,
1995 and 1994, the letter of credit had a face amount of $2,500,000 and the
Partnership had a cash deposit of $2,500,000 held in a restricted money market
account as collateral for the letter of credit. As of December 31, 1995 and
1994, $2,500,000 held in a restricted money market account is included in the
current portion of restricted cash and cash equivalents. In January 1996, the
letter of credit was reduced in accordance with its terms to a face amount of
$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.
F-49
<PAGE> 144
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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.
(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 $48,400 in 1995 and 1994, and $45,300
in 1993.
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 $17,700 in 1995, $17,000 in 1994 and $16,000 in 1993.
Future minimum land and office lease commitments as of December 31, 1995
are as follows:
<TABLE>
<CAPTION>
YEAR ENDING
DECEMBER 31, AMOUNT
----------------------------------------------------------------- ----------
<S> <C>
1996............................................................. $ 66,800
1997............................................................. 51,000
1998............................................................. 49,300
1999............................................................. 49,300
2000............................................................. 52,500
Thereafter....................................................... 868,200
----------
$1,137,100
==========
</TABLE>
(h) PROJECT MANAGEMENT SERVICES -- NESCO entered into a project management
agreement with the Partnership for which it received $45,000 per month through
June 1993. Approximately $264,000 was paid to NESCO in 1993, under this
agreement.
(i) CONSTRUCTION MANAGEMENT SERVICES -- Calpine entered into a construction
management agreement with the Partnership for which it received $40,000 per
month through June 1993. Approximately $235,000 was paid to Calpine in 1993,
under this agreement.
(j) 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 made in connection with Loan Conversion (Note 1). 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 $119,000,003 at December 31, 1995. 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-50
<PAGE> 145
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 8 -- CONTINGENCY
ENCO terminated protracted contract negotiations with two Canadian natural
gas suppliers in January 1995. One of the suppliers notified ENCO it considered
a draft contract to be effective although it had not been executed by ENCO. The
supplier indicated it may pursue legal action if ENCO would not execute the
contract. As of January 19, 1996, no legal action has been served on ENCO.
Management believes if legal action is commenced, it has significant defenses
and believes such action will not result in any material adverse impact to the
Company's financial condition or results of operations.
F-51
<PAGE> 146
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Partners of Calpine Geysers Company, L.P.:
We have audited the accompanying statements of operations and cash flows
for the period from January 1, 1993 to April 18, 1993 of Calpine Geysers
Company, L.P., a Delaware limited partnership. These financial statements are
the responsibility of the Partnership's management. Our responsibility is to
express an opinion on these statements based on our audit.
We conducted our audit 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 audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the results of operations and cash flows of Calpine
Geysers Company, L.P. for the period from January 1, 1993 through April 18, 1993
in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
San Jose, California
March 18, 1994
F-52
<PAGE> 147
CALPINE GEYSERS COMPANY, L.P.
STATEMENT OF OPERATIONS
FOR THE PERIOD FROM JANUARY 1, 1993 TO APRIL 18, 1993
<TABLE>
<S> <C>
Revenue from power contracts.................................................... $20,759,116
-----------
Costs and expenses:
Production royalties.......................................................... 3,150,076
Operating expenses............................................................ 4,893,878
Depreciation and amortization................................................. 5,153,239
General and administrative.................................................... 787,005
-----------
Total costs and expenses.............................................. 13,984,198
-----------
Income from operations................................................ 6,774,918
Other (income) expense
Interest expense.............................................................. 4,794,952
Other income.................................................................. (193,179)
-----------
Net income............................................................ $ 2,173,145
===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-53
<PAGE> 148
CALPINE GEYSERS COMPANY, L.P.
STATEMENT OF CASH FLOWS
FOR THE PERIOD FROM JANUARY 1, 1993 TO APRIL 18, 1993
<TABLE>
<S> <C>
Cash flows from operating activities:
Net income................................................................... $ 2,173,145
Adjustments to reconcile net income to net cash provided by operating
activities:
Depreciation and amortization............................................. 5,153,239
Amortization of deferred costs............................................ 146,277
Changes in operating assets and liabilities:
Accounts receivable..................................................... 2,157,353
Supplies inventory...................................................... 81,061
Prepaid expenses........................................................ 837,841
Accounts payable and accrued liabilities................................ 2,634,254
Deferred revenue........................................................ 395,100
Payment on note payable................................................. (543,778)
------------
Net cash provided by operating activities............................ 13,034,492
------------
Cash flows from investing activities:
Acquisition of property, plant and equipment................................. (3,401,378)
Increase in restricted cash requirements..................................... (12,862)
------------
Net cash used for investing activities............................... (3,414,240)
------------
Cash flows from financing activities:
Repayment of debt............................................................ (2,200,000)
Partner distributions........................................................ (7,416,018)
------------
Net cash used for financing activities............................... (9,616,018)
------------
Net increase in cash and cash equivalents...................................... 4,234
Cash and cash equivalents at beginning of period............................... 2,700,135
------------
Cash and cash equivalents at end of period..................................... $ 2,704,369
============
Supplementary information:
Cash paid during the period for interest..................................... $ 3,914,710
============
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-54
<PAGE> 149
CALPINE GEYSERS COMPANY, L.P.
NOTES TO FINANCIAL STATEMENTS
FOR THE PERIOD FROM JANUARY 1, 1993 TO APRIL 18, 1993
1. BUSINESS AND FORMATION OF THE PARTNERSHIP
Business
Calpine Geysers Company, L.P. ("CGC"), a Delaware limited partnership, was
formed on April 5, 1990. CGC is the owner of two operating geothermal power
plants and their respective steam fields, and three geothermal steam fields
located in The Geysers area of northern California. Electricity and steam
generated by CGC is sold to two utilities under long-term power sales contracts
(see Note 9).
Formation of the Partnership
CGC was formed by Sonoma Geothermal Partners, L.P. ("SGP"), wholly owned by
Calpine Corporation ("Calpine"), and Freeport-McMoRan Resource Partners, Limited
Partnership ("FMRP") for the purpose of acquiring from FMRP the assets
constituting the geothermal business described above. On July 2, 1990, FMRP
contributed an undivided 15.93 percent interest in the existing assets and
geothermal business and $1,178,567 in cash for financing costs. SGP contributed
$22,165,718 in cash, including financing and closing costs of $2,008,000.
Concurrent with the formation of CGC, an agreement was entered into between
CGC and FMRP to purchase the remaining undivided 84.07 percent interest in the
existing assets and geothermal business for $227.0 million in cash plus the
assumption of the liabilities, not including existing project debt. The amount
was funded by SGP's contribution and a new nonrecourse credit arrangement with a
consortium of banks (see Note 5).
Under the CGC partnership agreement, profits are allocated first to SGP to
the extent necessary to achieve a target return, as defined. Thereafter, profits
are allocated 22.5 percent to SGP and 77.5 percent to FMRP.
Upon liquidation, equity is allocated first to SGP to the extent necessary
to achieve a target return as defined; second, equity is allocated to achieve
the target capital account ratios (22.5 percent to SGP and 77.5 percent to
FMRP); and third, equity is allocated 22.5 percent to SGP and 77.5 percent to
FMRP.
Cash distributions are allocated 99 percent to SGP and 1 percent to FMRP
until the target return is reached. Distributions made during the period from
January 1, 1993 to April 18, 1993 were $7,352,017 to SGP and $64,001 to FMRP.
Acquisition of FMRP Interest in CGC
On April 19, 1993, Calpine purchased all of FMRP's interest in CGC for
$59.8 million, terminating the partnership with FMRP. The purchase price
includes a $23.0 million cash payment by Calpine and a $36.8 million note
payable to FMRP.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Cash and Cash Equivalents
CGC's cash, cash equivalents and restricted cash are primarily held by one
major international financial institution. CGC considers all highly liquid
instruments purchased with an original maturity of three months or less to be
cash equivalents. The carrying amount of these instruments approximates fair
value because of their short maturity.
F-55
<PAGE> 150
CALPINE GEYSERS COMPANY, L.P.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Restricted Cash
CGC is required to maintain cash balances that are restricted by provisions
of its debt agreements and by regulatory agencies. CGC'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, their carrying value
approximates fair value.
Supplies Inventory
Supplies are valued at the lower of cost or market. Cost for large
replacement parts is determined using the specific identification method. For
the remaining supplies, cost is determined using the weighted average cost
method.
Property, Plant and Equipment
CGC uses the full cost method of accounting for costs incurred in
connection with the exploration and development of geothermal properties. All
such costs, including geological and geophysical expenses, costs of drilling
productive, nonproductive and reinjection wells and overhead directly related to
development activities, together with the costs of production equipment, the
related facilities and the operating power plants, are capitalized.
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 the
estimated remaining useful lives of the buildings and roads.
Proceeds from the sale of assets are applied against capitalized costs,
with no gain or loss recognized.
Deferred Costs
Deferred costs consist of financing costs, a commitment fee and Partnership
closing costs. These costs are amortized over the following periods:
<TABLE>
<S> <C>
Financing costs................................................. 15 years
Partnership closing costs....................................... 5 to 7 years
</TABLE>
Revenue Recognition
Revenues from sales of electricity are recognized as service is delivered.
Revenues from sales of steam are calculated considering a future period when
steam will be delivered without receiving corresponding revenue. This free steam
is being recorded at an average rate over future steam production as deferred
revenue.
A recent accounting principle requires companies to recognize revenue on
power sales agreements entered into after May 1992 using the lower of the actual
cash received or the average rate measured on a cumulative basis. CGC's power
sales agreements were entered into prior to May 1992. Had CGC applied this
principle, the revenues CGC recorded for the period from January 1, 1993 to
April 18, 1993 would have been approximately $488,000 less.
Income Taxes
Income taxes are the responsibility of the individual partners; therefore,
there is no provision for Federal and state income taxes in the financial
statements.
F-56
<PAGE> 151
CALPINE GEYSERS COMPANY, L.P.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
3. WORKING CAPITAL LOAN
CGC has a working capital agreement with a bank providing for advances not
to exceed $5.0 million less any outstanding letters of credit. The aggregate
unpaid principal of the working capital loan is payable in full at least once a
year commencing in 1991, with the final payment of principal, interest and fees
due June 30, 1995; interest accrues at the London Interbank Offered Rate (LIBOR)
plus .625 percent over the term of the loan.
4. NOTE PAYABLE
During 1992, CGC entered into a note payable with a financing company for
$543,778. The note bears interest at 3.79 percent annually and was repaid in two
installments in January and April 1993.
5. LONG-TERM DEBT
CGC has a $200.0 million ($176.8 million outstanding at April 18, 1993)
loan agreement with a bank, the components of which are as follows:
Senior term loans: $156.8 million outstanding at April 18, 1993 with
principal and interest payable in quarterly installments at variable
amounts beginning September 30, 1990 and the final payment of principal,
interest and fees due June 30, 2002; interest on $136.8 million is fixed at
9.93 percent with the remainder accruing at LIBOR plus .75 percent to 1.25
percent over the term of the loan; collateralized by all of CGC's assets
and the partners' interest.
Junior term loans: $20.0 million outstanding at April 18, 1993 with
principal and interest payable in quarterly installments at variable
amounts beginning September 30, 2002 and the final payment of principal,
interest and fees due June 30, 2005; interest accrues at LIBOR plus 1.5
percent to 2.75 percent over the term of the loan; the loan is
collateralized by all of CGC's assets and the partners' interest.
The annual principal maturities of the long-term debt outstanding at April
18, 1993 are as follows:
<TABLE>
<S> <C>
1993........................................................... $ 8,800,000
1994........................................................... 16,000,000
1995........................................................... 18,000,000
1996........................................................... 21,000,000
1997........................................................... 22,000,000
Thereafter..................................................... 91,000,000
------------
$176,800,000
============
</TABLE>
The senior and junior term loan agreements contain a number of covenants.
Two of these covenants require that CGC maintain restricted cash balances as
defined in the agreements, and that CGC maintain certain insurance coverages.
During the period from January 1, 1993 to April 18, 1993, CGC did not meet the
insurance covenant and has obtained a waiver for this violation.
The carrying value of the $136.8 million portion of the senior term notes
has an effective rate of 9.93 percent under CGC's interest rate swap agreements
(see Note 6). Based on the borrowing rates currently available to CGC for bank
loans with similar terms and maturities, the fair value of the debt as of April
18, 1993 is approximately $150.2 million.
The carrying value of the remaining $20.0 million of the senior and the
$20.0 million junior term loans approximates the debt's fair market value as the
rates are variable and are based on current LIBOR.
F-57
<PAGE> 152
CALPINE GEYSERS COMPANY, L.P.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
6. INTEREST RATE SWAP AGREEMENTS:
CGC entered into two interest rate swap agreements to minimize the impact
of changes in interest rates by effectively fixing its interest rate at 9.93
percent on a portion of its senior term note. The interest rate swap agreements
mature through December 31, 2000. CGC is exposed to credit loss in the event of
nonperformance by the other parties to the interest rate swap agreements.
7. COMMITMENTS AND CONTINGENCIES
Royalties and Leases
CGC is committed under several geothermal and right of way leases. The
geothermal leases generally provide for royalties based on production revenue,
with reductions for property taxes paid and the right of way leases are based on
flat rates and are not material. Under the terms of certain geothermal land
leases, royalties accrue at rates ranging from 7 percent to 12.5 percent of
electricity, steam and effluent revenue, net of property taxes. Certain
properties also have net profits and overriding royalty interests ranging from
approximately 1.7 percent to 23.5 percent, which are in addition to the land
lease royalties. CGC also has a working interest agreement with a third party
providing for the sharing of approximately 30 percent of drilling and other well
costs, various percentages of other operating costs and 30 percent of revenues
on specified wells of Unit 13 and Unit 16.
Most lease agreements contain clauses providing for minimum lease payments
to leaseholders if production temporarily ceases or if production falls below a
specified level.
Expenses under these agreements for the period from January 1, 1993 to
April 18, 1993 are as follows:
<TABLE>
<S> <C>
Production royalties............................................. $3,150,076
Lease payments................................................... 119,081
</TABLE>
Litigation
CGC is a party to lawsuits and claims arising out of the normal course of
business, principally related to royalty interests on geothermal property sites.
Management believes that the outcome of these claims and lawsuits will not have
a material adverse effect on CGC's financial position and results of operations.
8. RELATED PARTY TRANSACTIONS
The power plants and steam fields of CGC are operated by Calpine Operating
Plant Services, Inc. ("COPS"), wholly owned by Calpine Corporation, under an
Operating and Maintenance Agreement. Under the agreement, COPS is obligated to
perform all operation and maintenance services in connection with the business,
including operation, repair and maintenance of the power plants and steam
fields, arranging for new well drilling, providing administrative and billing
services, and performing technical analyses and contract administration.
For performance of these services, COPS is reimbursed for its direct costs
plus a general and administrative recovery rate of 12 percent for direct labor
costs, 10 percent for specific costs, and 5 percent for capital expenditures up
to $5.0 million per year, then 2 percent for additional capital expenditures. In
addition, the contract also includes an annual operating fee of $1.0 million,
escalating in relation to the Consumer Price Index. During the period from
January 1, 1993 to April 18, 1993, total charges under the Operating and
Maintenance Agreement amounted to approximately $7.1 million, including
approximately $3.7 million for capital expenditures.
F-58
<PAGE> 153
CALPINE GEYSERS COMPANY, L.P.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Calpine also charges CGC directly for expenses in connection with its
duties as general partner, and for technical and administrative services. During
the period from January 1, 1993 to April 18, 1993, charges amounted to
approximately $185,000.
FMRP has a royalty interest in one of the properties in production. During
the period from January 1, 1993 to April 18, 1993, production royalty expense
related to FMRP amounted to approximately $397,000.
9. SIGNIFICANT CUSTOMERS AND SUMMARY OF OPERATIONS:
CGC's revenue is derived primarily from two sources -- Pacific Gas and
Electric ("PG&E") and Sacramento Municipal Utility District ("SMUD"). Revenue
for the period from January 1, 1993 to April 18, 1993 is as follows:
<TABLE>
<S> <C>
PG&E............................................................ $17,323,683
SMUD............................................................ 3,830,533
-----------
21,154,216
Less revenues deferred.......................................... (395,100)
-----------
Total................................................. $20,759,116
===========
</TABLE>
Operating Geothermal Power Plants
Electricity from CGC's two operating geothermal power plants, Bear Canyon
and West Ford Flat, is sold to PG&E under the terms of twenty-year contracts
which began in 1989.
Under the terms of the contracts, CGC is paid for energy delivered based
upon a fixed price which escalates annually for the first ten years of the
contract and upon PG&E's full short-run avoided operating costs for the second
ten years.
CGC also receives capacity payments from PG&E. Under certain circumstances,
if CGC is unable to deliver firm capacity, then CGC may owe PG&E certain minimum
damages, as specified in the contracts.
Geothermal Steam Fields
Steam from CGC's three geothermal steam fields is sold to PG&E and SMUD
under contracts. PG&E is obligated to operate the plants (Unit 13 and Unit 16)
as close to full capacity and as continuously as possible. SMUD is obligated to
make its best effort to continuously accept steam generated by the plant, except
during outages.
Under the terms of the PG&E contract, the price paid for steam is adjusted
annually based upon prices paid by PG&E for fossil fuels (oil and natural gas)
and nuclear fuel. Under the terms of the SMUD contract, the price paid for steam
is adjusted bi-annually based upon inflation and price indices reflecting the
economy and the cost of fuel.
The contracts with both PG&E and SMUD also provide that CGC receive an
additional amount per mwh of net output as compensation for the cost of
disposing of liquid effluents, primarily steam condensate.
In the event the quantity of steam delivered at any of the plants is less
than 50 percent of the units rated capacity during any given month, PG&E or SMUD
is not required to pay for steam delivered during such month until the cost of
the power plants has been completely amortized.
The contracts may be terminated upon written notice under conditions
specified in the contract if further operation of the plants becomes
uneconomical. In the event that the contract is terminated by CGC, and if
requested by either PG&E or SMUD, CGC must assign to PG&E (Unit 13 and Unit 16)
or SMUD (SMUDGEO #1) all rights, title and interest to the wells, lands and
related facilities.
F-59
<PAGE> 154
REPORT OF INDEPENDENT ACCOUNTANTS
To the Shareholder of LFC No. 38 Corp. and Portsmouth Leasing Corporation:
We have audited the accompanying combined balance sheets of LFC No. 38 Corp. and
Portsmouth Leasing Corporation and Subsidiaries as of December 31, 1994 and
1993, and the related combined statements of operations, changes in
shareholder's deficiency and cash flows for the years then ended. These
financial statements are the responsibility of the Companies' management. Our
responsibility is to express an opinion on these 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 audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the combined financial position of LFC No. 38 Corp. and
Portsmouth Leasing Corporation and Subsidiaries as of December 31, 1994 and
1993, and the combined results of their operations and their cash flows for the
years then ended in conformity with generally accepted accounting principles.
As discussed in Note 4 to the financial statements, the Companies changed their
method of accounting for income taxes in 1993.
COOPERS & LYBRAND L.L.P.
2400 Eleven Penn Center
Philadelphia, Pennsylvania
February 3, 1995, except
as to the information presented
in Note 7 for which the date is
March 30, 1995
F-60
<PAGE> 155
LFC NO. 38 CORP. AND PORTSMOUTH LEASING CORPORATION AND SUBSIDIARIES
COMBINED BALANCE SHEETS
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------------
1994 1993
----------- -----------
<S> <C> <C>
ASSETS
Current assets
Cash and equivalents............................................ $ 2,986,606 $ 3,911,692
Accounts receivable............................................. 1,888,467 1,774,335
Other current assets............................................ 74,729 145,754
----------- -----------
Total current assets.................................... 4,949,802 5,831,781
Power production facility, less accumulated depreciation of
$6,086,660 and $5,057,568, respectively......................... 24,228,646 25,239,115
Project development rights, less accumulated amortization of
$1,093,026 and $915,778, respectively........................... 4,287,918 4,465,166
Deferred costs, less accumulated amortization of $1,335,381 and
$1,215,708, respectively........................................ 712,224 831,898
Land.............................................................. 340,938 340,938
----------- -----------
Total assets............................................ $34,519,528 $36,708,898
=========== ===========
LIABILITIES AND SHAREHOLDER'S DEFICIENCY
Current liabilities
Accounts payable and accrued liabilities........................ $ 1,372,360 $ 1,606,528
Accrued interest payable........................................ 136,294 245,135
Notes payable................................................... 1,819,071 1,633,676
Due to affiliates............................................... 224,413 555,185
----------- -----------
Total current liabilities............................... 3,552,138 4,040,524
Notes payable..................................................... 26,767,423 28,553,740
Liability for major maintenance................................... 1,850,728 1,266,518
Deferred income taxes............................................. 9,233,673 8,613,266
----------- -----------
Total liabilities....................................... 41,403,962 42,474,048
----------- -----------
Shareholder's deficiency
Common stock $1 par value, 2,000 shares authorized,
2,000 shares issued.......................................... 2,000 2,000
Capital in excess of par value.................................. 1,279 1,279
Accumulated deficit............................................. (565,743) (1,668,429)
----------- -----------
(562,464) (1,665,150)
Advances to affiliates.......................................... (6,321,970) (4,100,000)
----------- -----------
Total shareholder's deficiency.......................... (6,884,434) (5,765,150)
----------- -----------
Total liabilities and shareholder's deficiency.......... $34,519,528 $36,708,898
=========== ===========
</TABLE>
See Accompanying Notes to Combined Financial Statements
F-61
<PAGE> 156
LFC NO. 38 CORP. AND PORTSMOUTH LEASING CORPORATION AND SUBSIDIARIES
COMBINED STATEMENT OF OPERATIONS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------
1994 1993
----------- -----------
<S> <C> <C>
Revenues
Power sales....................................................... $17,431,700 $18,134,824
Interest income................................................... 234,154 89,318
----------- -----------
17,665,854 18,224,142
----------- -----------
Expenses
Operating costs................................................... 12,702,761 9,271,110
Depreciation and amortization..................................... 1,338,734 1,515,297
Interest expense.................................................. 1,738,152 1,740,675
----------- -----------
15,779,647 12,527,082
----------- -----------
Income before income taxes.......................................... 1,886,207 5,697,060
Income tax provision................................................ 783,521 2,307,233
----------- -----------
Income before cumulative effect of change in accounting principle... 1,102,686 3,389,827
Cumulative effect of change in accounting for income taxes.......... -- (5,108,294)
----------- -----------
Net income (loss)......................................... $ 1,102,686 $(1,718,467)
=========== ===========
</TABLE>
See Accompanying Notes to Combined Financial Statements
F-62
<PAGE> 157
LFC NO. 38 CORP. AND PORTSMOUTH LEASING CORPORATION AND SUBSIDIARIES
COMBINED STATEMENTS OF CHANGES IN SHAREHOLDER'S DEFICIENCY
(FOR THE YEARS ENDED DECEMBER 31, 1994 AND 1993)
<TABLE>
<CAPTION>
RETAINED
CAPITAL IN EARNINGS SHAREHOLDER'S
COMMON EXCESS OF (ACCUMULATED ADVANCES TO EQUITY
STOCK PAR VALUE DEFICIT) AFFILIATES (DEFICIENCY)
------ ---------- ------------ ----------- -------------
<S> <C> <C> <C> <C> <C>
Balance, December 31, 1992............. $2,000 $1,279 $ 50,038 -- $ 53,317
Advance to affiliates.................. -- -- -- $(4,100,000) (4,100,000)
Net loss............................... -- -- (1,718,467) -- (1,718,467)
------ ------ --------- ---------- ----------
Balance, December 31, 1993............. 2,000 1,279 (1,668,429) (4,100,000) (5,765,150)
Advance to affiliates.................. -- -- -- (2,221,970) (2,221,970)
Net income............................. -- -- 1,102,686 -- 1,102,686
------ ------ --------- ---------- ----------
Balance, December 31, 1994............. $2,000 $1,279 $ (565,743) $(6,321,970) $ (6,884,434)
====== ====== ========= ========== ==========
</TABLE>
See Accompanying Notes to Combined Financial Statements
F-63
<PAGE> 158
LFC NO. 38 CORP. AND PORTSMOUTH LEASING CORPORATION AND SUBSIDIARIES
COMBINED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------
1994 1993
----------- -----------
<S> <C> <C>
Cash flows from operating activities
Net income (loss)............................................... $ 1,102,686 $(1,718,467)
Adjustments to reconcile net income (loss) to net cash provided
by operating activities
Depreciation and amortization................................ 1,338,734 1,515,297
Provision for major maintenance.............................. 584,210 710,872
Payments for major maintenance............................... -- (814,244)
Cumulative effect of change in accounting for income taxes... -- 5,108,294
Deferred income taxes........................................ 620,408 2,306,433
Changes in operating assets and liabilities
Accounts receivable........................................ (114,132) 476,265
Due to affiliates.......................................... (330,771) (161,838)
Accounts payable and accrued liabilities................... (234,169) (1,862,005)
Other current assets....................................... 71,025 (20,955)
Accrued interest payable................................... (108,842) (23,990)
----------- -----------
Net cash provided by operating activities....................... 2,929,149 5,515,662
----------- -----------
Cash flows used in investing activities
Investment in power production facility......................... (31,343) (10,433)
----------- -----------
Cash flows used in financing activities
Repayment of financing.......................................... (1,600,922) (1,416,935)
Advances to affiliates.......................................... (2,221,970) (4,100,000)
----------- -----------
Net cash used in financing activities........................... (3,822,892) (5,516,935)
----------- -----------
Net decrease in cash and equivalents.............................. (925,086) (11,706)
Cash and equivalents -- beginning of period....................... 3,911,692 3,923,398
----------- -----------
Cash and equivalents -- end of period............................. $ 2,986,606 $ 3,911,692
=========== ===========
</TABLE>
See Accompanying Notes to Combined Financial Statements
F-64
<PAGE> 159
LFC NO. 38 CORP. AND PORTSMOUTH LEASING CORPORATION AND SUBSIDIARIES
NOTES TO COMBINED FINANCIAL STATEMENTS
NOTE 1 -- THE PARTNERSHIP AND THE PROJECT
LFC No. 38 Corp. (the "Limited Partner"), a Delaware corporation, is the
sole Limited Partner and Greenleaf Unit One Associates, Inc. (the "General
Partner"), a California corporation, is the sole General Partner (collectively
the "Partners") of Greenleaf Unit One Associates, L.P. (the "Partnership"), a
California Limited Partnership. Portsmouth Leasing Corporation ("Portsmouth"), a
Delaware corporation, is the sole owner of the General Partner. Portsmouth and
the Partners are wholly owned subsidiaries of Radnor Energy Partners, L.P.
("L.P."). L.P. is, in turn, a majority-owned subsidiary of LFC Financial Corp
("Financial"). The combined financial statements include the accounts of the
Partners, the Partnership, and Portsmouth (collectively the "Company") after
elimination of all material intercompany balances and transactions.
The Partnership owns and operates a 49.5 megawatt natural gas fired
cogeneration facility located in Yuba City, California (the "Project"). The
facility, which was completed in March 1989, produces electrical power which it
sells to Pacific Gas and Electric Company ("PG&E") pursuant to a power purchase
agreement that provides for electricity and capacity payments over a thirty-year
period. The exhaust gas generated by the Project is used to dry wood chips. The
wood drying facility is operated by Wood Fuel Processing, Inc. ("WFP") pursuant
to a processing facilities agreement. The agreement provides that WFP will pay
certain royalties to the Partnership in the future based on the profitability of
the wood drying operation. Operations and maintenance of the Project is
performed by Stockmar Energy Inc., which does business as LFC Power Systems
Corporation ("Power Systems"), an affiliate. Power Systems is a wholly owned
subsidiary of LFC Energy Corporation ("Energy"), which, in turn, is a
majority-owned subsidiary of Financial.
NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Power Production Facility -- The power production facility, which was
constructed by Power Systems, includes the cogeneration plant (including the
wood drying facility) and the related equipment and is stated at cost.
Depreciation is recorded utilizing the straight-line method over the estimated
useful life of the Project of thirty years. Upon disposition, the cost and
related accumulated depreciation of equipment removed from the accounts and the
resulting gain (loss) is included in gains (losses) on equipment sales for the
period.
Project Development Rights -- The Project development rights include all of
the essential contracts, agreements, permits, licenses and other agreements
which were required to construct and operate the Project, as well as the
preliminary design of the Project, the power purchase agreement, the FERC
certification and other contracts and agreements. These Project development
rights are being amortized by the Partnership over a thirty-year period.
Deferred Costs -- Deferred costs include lender, legal, and other
professional fees incurred in connection with the acquisition and construction
of the Project and pre-operating expenses which were capitalized. Capitalized
fees are amortized over their estimated useful lives and pre-operating expenses
are amortized over sixty months.
Major Maintenance -- Major maintenance costs are accrued ratably over the
scheduled maintenance period and are included in operating costs. Costs
anticipated to be incurred within the next twelve months are classified as a
current liability.
Income Taxes -- Effective January 1, 1993, the Company adopted Statement of
Financial Accounting Standards No. 109 -- "Accounting For Income Taxes"
("SFAS109"). SFAS109 requires the recognition of deferred income tax liabilities
and assets for the future tax consequences of transactions that have been
recognized for financial reporting or income tax purposes and includes a
requirement for adjustment of deferred tax balances for tax rate changes. The
Company joins with L.P. and affiliated companies in the filing of a consolidated
U.S. federal income tax return. The Company's policy is to provide for federal
and state
F-65
<PAGE> 160
LFC NO. 38 CORP. AND PORTSMOUTH LEASING CORPORATION AND SUBSIDIARIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
income taxes on a separate return basis. In addition, the Company has a tax
sharing arrangement with L.P. that provides to the extent that net operating
loss or investment tax credit carryforwards are not utilized by the Company on a
separate return basis, but are utilized in the consolidated tax return of L.P.,
the Company will receive a portion of these tax benefits. These payments will be
classified as capital in excess of par value.
Statements of Cash Flows -- The Company considers all highly liquid
investments with a maturity of three months or less to be cash equivalents for
purposes of the statement of cash flows. Net cash provided by operating
activities includes cash payments for interest of $1,846,993 and $1,764,666 in
1994 and 1993, respectively.
NOTE 3 -- NOTES PAYABLE
Notes payable at December 31, 1994 and 1993 consist of the following:
<TABLE>
<CAPTION>
1994 1993
----------- -----------
<S> <C> <C>
Note payable -- Bank...................................... $25,996,000 $27,507,000
Note payable -- Individuals............................... 2,590,494 2,680,416
----------- -----------
Total........................................... 28,586,494 30,187,416
Less current portion...................................... 1,819,071 1,633,676
----------- -----------
Noncurrent portion........................................ $26,767,423 $28,553,740
=========== ===========
</TABLE>
The Partnership's note payable is payable pursuant to a credit agreement
with the New York branch of Credit Suisse ("Credit Suisse") and is
collateralized by substantially all of the Partnership's assets. The credit
agreement contains certain restrictive covenants including the maintenance of
certain debt service coverage ratios, working capital requirements, and
limitations on distributions. In addition, all cash and equivalents are
maintained in accounts at Credit Suisse. The loan bears interest at variable
rates or fixed rates at the option of the Partnership. The effective interest
rate on the loan was 8.05% at December 31, 1994. The loan is being repaid over
ten years, commencing in 1990, in level quarterly debt service payments on a
fourteen-year amortization schedule with a balloon payment at the end of the
tenth year.
The note payable-individuals is payable pursuant to a sale/purchase
agreement with the former owners of the General Partner. The loan bears interest
at a fixed rate of 8.25%. The loan is scheduled to be repaid in twenty (20)
annual installments plus interest, with each payment being based upon 1.59% of
power sales. If the obligation is repaid prior to maturity, the Company must
continue the payments as defined until the payment period ends, 2010.
The required principal payments by year are as follows:
<TABLE>
<S> <C>
1995....................................................... $ 1,819,071
1996....................................................... 2,016,092
1997....................................................... 2,231,533
1998....................................................... 2,529,127
1999....................................................... 2,794,776
2000....................................................... 16,092,618
Thereafter................................................. 1,103,277
-----------
Total............................................ $28,586,494
===========
</TABLE>
F-66
<PAGE> 161
LFC NO. 38 CORP. AND PORTSMOUTH LEASING CORPORATION AND SUBSIDIARIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 4 -- INCOME TAXES
Effective January 1, 1993, the Company adopted SFAS109, which requires the
liability method of accounting for income taxes. The cumulative effect of the
change in method of accounting for income taxes of $5,108,294 was reported in
the 1993 statement of operations and as an increase in the net deferred tax
liability at January 1, 1993.
The income tax provision is comprised of the following:
<TABLE>
<CAPTION>
1994 1993
-------- ----------
<S> <C> <C>
Current
State...................................................... $ 26,944 $ 800
Federal.................................................... 136,169 --
Deferred
State...................................................... 175,417 529,827
Federal.................................................... 444,991 1,776,606
-------- ----------
Total $783,521 $2,307,233
======== ==========
</TABLE>
The provision for income taxes as a percentage of income before income tax
can be reconciled to the federal statutory rate as follows:
<TABLE>
<CAPTION>
1994 1993
---- ----
<S> <C> <C>
Federal statutory tax rate............................................. 34% 34%
State tax, net of federal benefit...................................... 6% 6%
Other.................................................................. 2% --
-- -
---
Provision for income taxes............................................. 42% 40%
=== ===
</TABLE>
The net deferred tax liability (determined in accordance with SFAS109)
consists of:
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------------
1994 1993
----------- -----------
<S> <C> <C>
Deferred tax liabilities:
Accumulated depreciation................................ $10,872,804 $11,353,409
----------- -----------
Deferred tax assets:
Liability for major maintenance......................... 742,845 508,355
Investment tax credit carryforward...................... 821,862 1,254,862
Net operating loss carryforward......................... 74,424 976,926
----------- -----------
1,639,131 2,740,143
----------- -----------
Net deferred tax liability................................ $ 9,233,673 $ 8,613,266
=========== ===========
</TABLE>
As of December 31, 1994, the Company had, on a separate company basis, a
state net operating loss carryforward of $800,260 which expires in 1996 through
1999 and investment tax credit carryforwards of $821,862 which expires in 2003.
NOTE 5 -- RELATED PARTIES AND OPERATING COSTS
The Partnership incurred operating costs through Power Systems of
$1,976,599 and $1,910,189 in 1994 and 1993, respectively. The Partnership's 1994
and 1993 operating costs include $3,264,328 and $2,680,216, respectively, for
the purchase of natural gas from affiliates. Affiliates also provided gathering,
transportation and fuel management services at a cost of $2,328,028 and $725,000
to the Partnership in 1994 and 1993,
F-67
<PAGE> 162
LFC NO. 38 CORP. AND PORTSMOUTH LEASING CORPORATION AND SUBSIDIARIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
respectively. The Partnership incurred $1,307,649 and $104,114 in 1994 and 1993,
respectively, for management services provided by L.P.
NOTE 6 -- COMMON STOCK
The combined common stock of the Company as of December 31, 1994 and 1993
consists of the following:
<TABLE>
<CAPTION>
CAPITAL
SHARES IN
AUTHORIZED $1 PAR EXCESS OF
AND ISSUED VALUE PAR VALUE
---------- ------ ---------
<S> <C> <C> <C>
LFC No. 38 Corp....................................... 1,000 $1,000 --
Portsmouth Leasing Corporation........................ 1,000 1,000 $ 1,279
----- ------ ------
Total....................................... 2,000 $2,000 $ 1,279
===== ====== ======
</TABLE>
NOTE 7 -- SUBSEQUENT EVENTS
On March 30, 1995, Financial entered into a stock purchase agreement to
sell the stock of the Company to Calpine Corporation. The transaction is
scheduled to close by April 28, 1995. No effect of the proposed sale has been
recognized in the accompanying financial statements.
F-68
<PAGE> 163
REPORT OF INDEPENDENT ACCOUNTANTS
To the Shareholder of LFC No. 60 Corp.:
We have audited the accompanying consolidated balance sheets of LFC No. 60 Corp.
and Subsidiary as of December 31, 1994 and 1993, and the related consolidated
statements of operations, changes in shareholder's deficiency and cash flows for
the years then ended. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of LFC No. 60 Corp.
and Subsidiary as of December 31, 1994 and 1993, and the consolidated results of
their operations and their cash flows for the years then ended in conformity
with generally accepted accounting principles.
As discussed in Note 4 to the financial statements, the Company changed its
method of accounting for income taxes in 1993.
COOPERS & LYBRAND L.L.P.
2400 Eleven Penn Center
Philadelphia, Pennsylvania
February 3, 1995, except
as to the information presented
in Note 6 for which the date is
March 30, 1995
F-69
<PAGE> 164
LFC NO. 60 CORP. AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------------
1994 1993
----------- -----------
<S> <C> <C>
ASSETS
Current assets
Cash and equivalents............................................ $ 2,088,588 $ 2,491,825
Accounts receivable, net of allowance for doubtful accounts of
$200,000 in 1993............................................. 2,076,594 1,967,998
Due from affiliates............................................. 776,253 --
Prepaid assets.................................................. 513,954 266,690
----------- -----------
Total current assets.................................... 5,455,389 4,726,513
Power production facility, less accumulated depreciation of
$5,430,948 and $4,339,447, respectively......................... 26,636,147 27,711,561
Project development rights, less accumulated amortization of
$330,417 and $265,417, respectively............................. 1,619,583 1,684,583
Deferred costs, less accumulated amortization of $1,410,676 and
$1,148,992, respectively........................................ 580,706 842,390
----------- -----------
Total assets............................................ $34,291,825 $34,965,047
=========== ===========
LIABILITIES AND SHAREHOLDER'S DEFICIENCY
Current liabilities
Accounts payable and accrued liabilities........................ $ 1,785,800 $ 882,746
Due to affiliates............................................... -- 634,451
Accrued interest payable........................................ 13,972 131,200
Note payable.................................................... 600,000 600,000
Liability for major maintenance................................. -- 969,996
----------- -----------
Total current liabilities............................... 2,399,772 3,218,393
Note payable...................................................... 31,600,000 32,200,000
Liability for major maintenance................................... 1,737,908 1,273,328
Deferred income taxes............................................. 6,368,319 5,764,303
----------- -----------
Total liabilities....................................... 42,105,999 42,456,024
----------- -----------
Shareholder's deficiency
Common stock $1 par value, authorized, issued and outstanding --
1,000 shares................................................. 1,000 1,000
Capital in excess of par value.................................. 1,199,000 1,199,000
Deficit......................................................... (395,931) (1,290,977)
----------- -----------
804,069 (90,977)
Advances to affiliates.......................................... (8,618,243) (7,400,000)
----------- -----------
Total shareholder's deficiency.......................... (7,814,174) (7,490,977)
----------- -----------
Total liabilities and shareholder's deficiency.......... $34,291,825 $34,965,047
=========== ===========
</TABLE>
See Accompanying Notes to Consolidated Financial Statements
F-70
<PAGE> 165
LFC NO. 60 CORP. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------
1994 1993
----------- -----------
<S> <C> <C>
Revenues
Power sales..................................................... $18,495,832 $19,223,155
Steam sales..................................................... 61,780 62,496
Interest income................................................. 155,715 68,247
----------- -----------
18,713,327 19,353,898
----------- -----------
Expenses
Operating costs................................................. 13,961,525 12,620,397
Depreciation and amortization................................... 1,418,185 1,436,668
Interest expense................................................ 1,773,839 1,702,354
----------- -----------
17,153,549 15,759,419
----------- -----------
Income before income taxes........................................ 1,559,778 3,594,479
Income tax provision.............................................. (664,732) (1,616,815)
----------- -----------
Income before cumulative effect of change in accounting
principle....................................................... 895,046 1,977,664
Cumulative effect of change in accounting for income taxes........ -- (2,773,609)
----------- -----------
Net income (loss)................................................. $ 895,046 $ (795,945)
=========== ===========
</TABLE>
See Accompanying Notes to Consolidated Financial Statements
F-71
<PAGE> 166
LFC NO. 60 CORP. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S DEFICIENCY
(FOR THE YEARS ENDED DECEMBER 31, 1994 AND 1993)
<TABLE>
<CAPTION>
CAPITAL IN
COMMON EXCESS OF ADVANCES TO
STOCK PAR VALUE DEFICIT AFFILIATES TOTAL
------ ---------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Balance December 31, 1992.... $1,000 $1,199,000 $ (495,032) $(3,600,000) $(2,895,032)
Net loss..................... -- -- (795,945) -- (795,945)
Advance to affiliates........ -- -- -- (3,800,000) (3,800,000)
------ ---------- ----------- ----------- -----------
Balance December 31, 1993.... 1,000 1,199,000 (1,290,977) (7,400,000) (7,490,977)
Net income................... -- -- 895,046 -- 895,046
Advance to affiliates........ -- -- -- (1,218,243) (1,218,243)
------ ---------- ----------- ----------- -----------
Balance, December 31, 1994... $1,000 $1,199,000 $ (395,931) $(8,618,243) $(7,814,174)
====== ========= ========== ========== ==========
</TABLE>
See Accompanying Notes to Consolidated Financial Statements
F-72
<PAGE> 167
LFC NO. 60 CORP. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------------
1994 1993
----------- -----------
<S> <C> <C>
Cash flows from operating expenses
Net income (loss)............................................... $ 895,046 $ (795,945)
Adjustments to reconcile net income (loss) to net cash provided
by operating activities
Depreciation and amortization................................ 1,418,185 1,436,668
Provision for major maintenance.............................. 331,134 818,329
Payments for major maintenance............................... (836,550) --
Provision for doubtful accounts.............................. -- 200,000
Cumulative effect of change in accounting principle.......... -- 2,773,609
Deferred income tax provision................................ 604,016 1,364,083
Changes in operating assets and liabilities
Accounts receivable........................................ (108,595) 41,995
Due from affiliates........................................ (1,410,704) (112,443)
Accounts payable and accrued liabilities................... 903,054 (1,184,769)
Prepaid assets............................................. (247,264) (19,510)
Accrued interest payable................................... (117,228) (20,866)
----------- -----------
Net cash provided by operating activities....................... 1,431,094 4,501,151
----------- -----------
Cash flows used in investing activities
Investment in power production facility......................... (16,088) (21,968)
----------- -----------
Cash flows used in financing activities
Repayment of financing.......................................... (600,000) (600,000)
Advances to affiliates.......................................... (1,218,243) (3,800,000)
----------- -----------
Net cash used in financing activities........................... (1,818,243) (4,400,000)
----------- -----------
Net increase (decrease) in cash and equivalents................... (403,237) 79,183
Cash and equivalents -- beginning of period....................... 2,491,825 2,412,642
----------- -----------
Cash and equivalents -- end of period............................. $ 2,088,588 $ 2,491,825
=========== ===========
</TABLE>
See Accompanying Notes to Consolidated Financial Statements
F-73
<PAGE> 168
LFC NO. 60 CORP. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 -- THE COMPANY AND THE PROJECT
LFC No. 60 Corp., a Delaware corporation, is a wholly-owned subsidiary of
Radnor Energy Partners, L.P. ("L.P."). L.P. is, in turn, a majority-owned
subsidiary of LFC Financial Corp ("Financial"). LFC No. 60 Corp. owns 100% of
the Greenleaf Unit Two Associates, Inc. ("GUTA"). The consolidated financial
statements include the accounts of LFC No. 60 Corp. and GUTA (the "Company")
after elimination of all material intercompany balances and transactions.
GUTA is a California corporation which owns and operates a 49.5 megawatt
natural gas fired cogeneration plant located in Yuba City, California (the
"Project"). The facility, which was completed in December 1989, produces
electrical power which it sells to Pacific Gas and Electric Company ("PG&E")
pursuant to a power purchase agreement that provides for electricity and
capacity payments over a thirty year period. The steam produced by the Project
is sold to Sunsweet Growers, Inc. under a long-term steam purchase agreement.
Operations and maintenance of the Project is performed by Stockmar Energy Inc.,
which does business as LFC Power Systems Corporation ("Power Systems"), an
affiliate. Power Systems is a wholly-owned subsidiary of LFC Energy Corporation
("Energy"), which, in turn, is a majority-owned subsidiary of Financial.
NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Power Production Facility -- The power production facility, which was
constructed by Power Systems, includes the cogeneration plant and the related
equipment and is stated at cost. Depreciation is recorded utilizing the
straight-line method over the estimated useful life of the Project of thirty
years. Upon disposition, the cost and related accumulated depreciation of
equipment is removed from the accounts and the resulting gain (loss) is included
in gains (losses) on equipment sales for the period.
Project Development Rights -- The Project development rights include all of
the essential contracts, agreements, permits, licenses and other agreements
which were required to construct and operate the Project as well as the
preliminary design of the Project, the power purchase agreement, the FERC
certification and other contracts and agreements. These Project development
rights are being amortized by the Company over a thirty-year period.
Deferred Costs -- Deferred costs include lender, legal, and other
professional fees incurred in connection with the acquisition and construction
of the Project and pre-operating expenses which were capitalized. Capitalized
fees are amortized over their estimated useful lives and pre-operating expenses
are amortized over sixty months.
Major Maintenance -- Major maintenance costs are accrued ratably over the
scheduled maintenance period and are included in operating costs. Costs
anticipated to be incurred within the next twelve months are classified as a
current liability.
Income Taxes -- Effective January 1, 1993, the Company adopted Statement of
Financial Accounting Standards No. 109 -- "Accounting For Income Taxes" ("SFAS
109"). SFAS109 requires the recognition of deferred income tax liabilities and
assets for the future tax consequences of transactions that have been recognized
for financial reporting or income tax purposes and includes a requirement for
adjustment of deferred tax balances for tax rate changes. The Company joins with
L.P. and affiliated companies in the filing of a consolidated U.S. federal
income tax return. The Company's policy is to provide for federal and state
income taxes on a separate return basis. In addition, the Company has a tax
sharing arrangement with L.P. that provides to the extent that net operating
loss or investment tax credit carryforwards are not utilized by the Company on a
separate return basis, but are utilized in the consolidated tax return of L.P.,
the Company will receive a portion of these tax benefits. These payments will be
classified as capital in excess of par value.
F-74
<PAGE> 169
LFC NO. 60 CORP. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Statements of Cash Flows -- The Company considers all highly liquid
investments purchased with a maturity of three months or less to be cash
equivalents for purposes of the statement of cash flows. Net cash provided by
operating activities includes cash payments for interest of $1,891,067 and
$1,723,220 in 1994 and 1993, respectively.
NOTE 3 -- NOTE PAYABLE
The Company's note payable is payable pursuant to a credit agreement with
the New York branch of Credit Suisse ("Credit Suisse") and is collateralized by
substantially all of the Company's assets. The credit agreement contains certain
restrictive covenants including the maintenance of certain debt service coverage
ratios, working capital requirements, and limitations on distributions. In
addition, all cash and equivalents are maintained in accounts at Credit Suisse.
The note bears interest at variable or fixed rates at the option of the Company.
The effective interest rate on the note was 7.81% at December 31, 1994. The note
is being repaid in quarterly payments through 2005.
The required principal payments by year are as follows:
<TABLE>
<S> <C>
1995....................................................... $ 600,000
1996....................................................... 600,000
1997....................................................... 600,000
1998....................................................... 2,000,000
1999....................................................... 2,500,000
Thereafter................................................. 25,900,000
-----------
Total................................................. $32,200,000
===========
</TABLE>
NOTE 4 -- INCOME TAXES
Effective January 1, 1993, the Company adopted SFAS 109, which requires the
liability method of accounting for income taxes. The cumulative effect of the
change in method of accounting for income taxes of $2,773,609 was reported in
the 1993 statement of operations and as an increase in the net deferred tax
liability at January 1, 1993.
The income tax provision is comprised of the following:
<TABLE>
<CAPTION>
1994 1993
-------- ----------
<S> <C> <C>
Deferred
Federal.................................................... $490,009 $1,293,236
State...................................................... 114,007 70,847
Current -- State............................................. 60,716 252,732
-------- ----------
Total.............................................. $664,732 $1,616,815
======== ==========
</TABLE>
The provision for income taxes as a percentage of income before income
taxes can be reconciled to the federal statutory rate as follows:
<TABLE>
<CAPTION>
1994 1993
---- ----
<S> <C> <C>
Federal statutory tax rate............................................. 34% 34%
State Tax.............................................................. 8% 6%
Other.................................................................. 1% 5%
-- --
Provision for income taxes........................................... 43% 45%
== ==
</TABLE>
F-75
<PAGE> 170
LFC NO. 60 CORP. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The net deferred tax liability (determined in accordance with SFAS109)
consists of:
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------
1994 1993
---------- ----------
<S> <C> <C>
Deferred tax liabilities:
Accumulated depreciation.................................. $9,123,465 $8,509,818
---------- ----------
Deferred tax assets:
Liability for major maintenance........................... 713,324 922,858
Investment tax credit carryforward........................ 1,333,448 1,333,448
Net operating loss carryforward........................... 708,374 418,977
Other..................................................... -- 70,232
---------- ----------
2,755,146 2,745,515
---------- ----------
Net deferred tax liability.................................. $6,368,319 $5,764,303
========== ==========
</TABLE>
As of December 31, 1994, the Company had a tax net operating loss carry
forward determined on a separate company basis of $2,023,928 which expires in
2007 through 2009. As of December 31, 1994, the Company had ITC carryforwards
determined on a separate company basis of $1,333,448 which expire in 2004.
NOTE 5 -- RELATED PARTIES AND OPERATING COSTS
The Company incurred operating costs of $1,610,780 and $2,330,001 through
Power Systems in 1994 and 1993, respectively. The Company's 1994 and 1993
operating costs include $1,088,550 and $1,421,558, respectively, for the
purchase of natural gas from affiliates. Affiliates provided gathering,
transportation and fuel management services at a cost of $2,181,758 and $400,000
in 1994 and 1993, respectively. The Company incurred $1,307,465 and $104,106 in
1994 and 1993, respectively, for management services provided by L.P.
NOTE 6 -- SUBSEQUENT EVENT
On March 30, 1995, Financial entered into a stock purchase agreement to
sell the stock of the Company and certain affiliates to Calpine Corporation. The
transaction is scheduled to close by April 28, 1995. No effect of the proposed
sale has been recognized in the accompanying financial statements.
F-76
<PAGE> 171
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the General Partner of
BAF Energy, A California Limited Partnership:
We have audited the accompanying balance sheets of BAF Energy, A California
Limited Partnership, as of October 31, 1995 and 1994, and the related statements
of income, partners' equity and cash flows for each of the three years ended
October 31, 1995, 1994 and 1993. These financial statements are the
responsibility of the Partnership's management. Our responsibility is to express
an opinion on these 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 audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of BAF Energy, A California
Limited Partnership, as of October 31, 1995 and 1994, and the results of its
operations and its cash flows for each of the three years ended October 31,
1995, 1994 and 1993 in conformity with generally accepted accounting principles.
As explained in Note 1 to the financial statements, effective November 1,
1994, the Company changed its method of accounting for investments.
As discussed in Note 8 to the financial statements, subsequent to October
31, 1995, the Partnership signed a letter agreement with a third party to lease
substantially all of its property, plant and equipment and assign all related
contracts to a third party.
ARTHUR ANDERSEN LLP
San Francisco, California
December 6, 1995
F-77
<PAGE> 172
BAF ENERGY,
A CALIFORNIA LIMITED PARTNERSHIP
BALANCE SHEETS
OCTOBER 31, 1995 AND 1994
<TABLE>
<CAPTION>
1995 1994
------------ ------------
<S> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents..................................... $ 3,757,921 $ 5,363,057
Available for sale securities................................. 1,919,184 --
Restricted available-for-sale securities...................... 7,241,305 12,332,244
Accounts receivable -- trade.................................. 10,916,919 5,277,413
Supplies inventory............................................ 2,153,129 2,060,935
Prepaid insurance............................................. 288,383 251,375
------------ ------------
Total current assets.................................. 26,276,841 25,285,024
------------ ------------
Property, plant and equipment................................... 100,258,434 100,210,960
Accumulated depreciation and amortization..................... (24,387,912) (20,854,389)
------------ ------------
75,870,522 79,356,571
------------ ------------
Total assets.......................................... $102,147,363 $104,641,595
============ ============
LIABILITIES AND PARTNERS' EQUITY
Current liabilities
Accounts payable.............................................. $ 1,598,177 $ 2,824,110
Interest payable.............................................. 1,309,566 1,396,495
Payable to affiliate.......................................... 166,569 615,881
Current portion of long-term liabilities...................... 5,444,386 5,283,785
------------ ------------
Total current liabilities............................. 8,518,698 10,120,271
------------ ------------
Long-term liabilities........................................... 66,804,704 71,157,714
------------ ------------
Commitments and contingencies (Note 6)
Partners' equity:
Contributed equity............................................ 9,901,600 9,901,600
Undistributed earnings........................................ 16,922,361 13,462,010
------------ ------------
Total partners' equity................................ 26,823,961 23,363,610
------------ ------------
Total liabilities and partners' equity................ $102,147,363 $104,641,595
============ ============
</TABLE>
The accompanying notes are an integral part of these statements.
F-78
<PAGE> 173
BAF ENERGY,
A CALIFORNIA LIMITED PARTNERSHIP
STATEMENTS OF INCOME
FOR THE YEARS ENDED OCTOBER 31, 1995, 1994 AND 1993
<TABLE>
<CAPTION>
1995 1994 1993
----------- ----------- -----------
<S> <C> <C> <C>
Operating Revenues.................................. $43,835,619 $47,955,622 $49,738,504
Operating Expenses:
Fuel.............................................. 9,193,490 14,079,684 16,449,118
Depreciation and amortization..................... 3,578,572 3,575,442 3,576,710
Labor, supplies and other......................... 6,614,543 6,959,891 6,343,755
----------- ----------- -----------
Total operating expenses.................. 19,386,605 24,615,017 26,369,583
----------- ----------- -----------
Operating income.......................... 24,449,014 23,340,605 23,368,921
----------- ----------- -----------
Other Income and Expense:
Interest income and other......................... 955,299 477,666 448,961
General and administrative........................ (773,610) (784,401) (653,373)
Interest expense.................................. (8,165,273) (8,654,453) (9,091,695)
----------- ----------- -----------
Total other income and expense............ (7,983,584) (8,961,188) (9,296,107)
----------- ----------- -----------
Partnership Income.................................. $16,465,430 $14,379,417 $14,072,814
=========== =========== ===========
</TABLE>
The accompanying notes are an integral part of these statements.
F-79
<PAGE> 174
BAF ENERGY,
A CALIFORNIA LIMITED PARTNERSHIP
STATEMENTS OF PARTNERS' EQUITY
FOR THE YEARS ENDED OCTOBER 31, 1995, 1994 AND 1993
<TABLE>
<CAPTION>
GENERAL LIMITED UNREALIZED TOTAL
PARTNERS' PARTNERS' UNDISTRIBUTED LOSSES ON PARTNERS'
EQUITY EQUITY EARNINGS SECURITIES EQUITY
--------- ---------- ------------- ----------- ------------
<S> <C> <C> <C> <C> <C>
Balance, October 31, 1992.......... $ 100 $9,901,500 $ 13,509,779 $ -- $ 23,411,379
Net income....................... -- -- 14,072,814 -- 14,072,814
Cash distributions............... -- -- (15,000,000) -- (15,000,000)
---- ---------- ------------ ------- ----
Balance, October 31, 1993.......... 100 9,901,500 12,582,593 -- 22,484,193
Net income....................... -- -- 14,379,417 -- 14,379,417
Cash distributions............... -- -- (13,500,000) -- (13,500,000)
---- ---------- ------------ ------- ----
Balance, October 31, 1994.......... 100 9,901,500 13,462,010 -- 23,363,610
Net income....................... -- -- 16,465,430 -- 16,465,430
Cash distributions............... -- -- (13,000,000) -- (13,000,000)
Change in unrealized losses on
available-for-sale
securities.................... -- -- -- (5,079) (5,079)
---- ---------- ------------ ------- ----
Balance, October 31, 1995.......... $ 100 $9,901,500 $ 16,927,440 $ (5,079) $ 26,823,961
==== ========== ============ ======= ====
</TABLE>
The accompanying notes are an integral part of these statements.
F-80
<PAGE> 175
BAF ENERGY,
A CALIFORNIA LIMITED PARTNERSHIP
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED OCTOBER 31, 1995, 1994 AND 1993
<TABLE>
<CAPTION>
1995 1994 1993
------------ ------------ ------------
<S> <C> <C> <C>
Cash flows from operating activities:
Partnership income............................. $ 16,465,430 $ 14,379,417 $ 14,072,814
Adjustments to reconcile partnership income to
net cash provided from operating
activities --
Depreciation and amortization............. 3,578,572 3,575,442 3,576,710
Realized (gains) losses on sales of
available-for-sale securities, net..... (465) 10,189 (22,701)
Change in operating assets &
liabilities --
Accounts receivable -- trade........... (5,639,506) 7,560,768 (6,403,581)
Supplies inventory..................... (92,194) (301,309) (11,406)
Prepaid insurance...................... (37,008) (69,663) 4,270
Accounts payable....................... (1,225,933) (1,375,739) 1,516,130
Interest payable....................... (86,929) (77,740) (69,540)
Payable to affiliate................... (449,312) 463,194 (1,130,695)
Other, net............................. (45,049) -- --
---------- ---------- ----------
Net cash provided by operating
activities........................ 12,467,606 24,164,559 11,532,001
---------- ---------- ----------
Cash flows from investing activities:
Purchases of available-for-sale securities..... (34,628,300) (25,334,642) (16,319,709)
Proceeds from sales and maturities of
available-for-sale securities............... 37,795,441 20,232,824 20,074,603
Additions to property, plant and equipment,
net......................................... (47,474) (21,066) (131,924)
---------- ---------- ----------
Net cash provided by (used in)
investing activities.............. 3,119,667 (5,122,884) 3,622,970
---------- ---------- ----------
Cash flows from financing activities:
Reductions of long-term liabilities, net....... (4,192,409) (3,587,576) (3,250,397)
Cash distributions to partners................. (13,000,000) (13,500,000) (15,000,000)
---------- ---------- ----------
Net cash used in financing
activities........................ (17,192,409) (17,087,576) (18,250,397)
---------- ---------- ----------
Net (decrease) increase in cash and cash
equivalents.................................... (1,605,136) 1,954,099 (3,095,426)
Cash and cash equivalents, beginning of year..... 5,363,057 3,408,958 6,504,384
---------- ---------- ----------
Cash and cash equivalents, end of year........... $ 3,757,921 $ 5,363,057 $ 3,408,958
========== ========== ==========
Supplemental disclosure of noncash investing and
financing activities
Unrealized holding losses, net, on
available-for-sale securities, recorded as
additions to undistributed earnings......... $ (5,079) $ -- $ --
</TABLE>
The accompanying notes are an integral part of these statements.
F-81
<PAGE> 176
BAF ENERGY,
A CALIFORNIA LIMITED PARTNERSHIP
NOTES TO FINANCIAL STATEMENTS
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Organization
Basic American, Inc. (BAI) formed BAF Energy, A California Limited
Partnership (BAF Energy or the Partnership) on March 25, 1986, for the purpose
of developing, constructing and operating a cogeneration facility. The term of
the Partnership is through December 2020 unless terminated earlier in accordance
with the Partnership Agreement. The facility produces and sells electricity and
steam. On December 6, 1995, the Partnership signed a letter agreement with a
third party to lease substantially all of the Partnership's property, plant and
equipment and to assign all related contracts. The third party lessee will
operate the cogeneration facility through April, 2019 (see Note 8).
BAF Energy, Inc. (BEI) is the general partner of the Partnership and has an
ownership interest of 1 percent. BEI is a wholly owned subsidiary of Basic
Vegetable Products, Inc. (BVP). BVP is a wholly owned subsidiary of BAI. As of
October 31, 1995, BAI also owned approximately 51 percent of the Limited
Partnership units of BAF Energy then outstanding.
Distributions and profit and loss are allocated 99 percent to the limited
partners, based on their proportionate share of limited partnership units, and 1
percent to the general partner.
Reclassifications
Certain reclassifications have been made to the 1994 and 1993 financial
statements to be consistent with the current year presentation.
Cash and Cash Equivalents
For purposes of reporting cash flows, cash and cash equivalents include
cash on deposit with banks, money market funds, and commercial paper. Cash paid
for interest during the years ended October 31, 1995, 1994 and 1993 was
$8,252,202, $8,732,052 and $9,161,241, respectively.
Available-for-Sale Securities
Effective November 1, 1994, the Partnership adopted Statement of Financial
Accounting Standards No. 115, "Accounting for Certain Investments in Debt and
Equity Securities" (SFAS 115). The Partnership has classified its investments as
available-for-sale securities and as restricted available-for-sale securities
and has recorded all securities holdings at fair value. Unrealized gains and
losses are reported as a separate component of partners' equity until realized.
Premiums and discounts are amortized over the life of the related security
as an adjustment to interest income using the effective interest method.
Interest income is recognized when earned. Realized gains and losses on
securities transactions are included in net income and are derived using the
specific identification method for determining the cost of securities sold.
Prior to the November 1, 1994 adoption of SFAS 115, the Partnership's
short-term investments were included in cash and short-term investments and were
valued at the lower of aggregate cost or market. Such securities have been
reclassified as available-for-sale securities to conform with SFAS 115
presentation requirements.
The effect of adopting SFAS 115 was to recognize net unrealized holding
losses of $32,599 as a decrease in partners' equity as of November 1, 1994. At
October 31, 1995, net unrealized holding losses were $5,079.
Restricted securities are required under the term loans described in Note
4.
F-82
<PAGE> 177
BAF ENERGY,
A CALIFORNIA LIMITED PARTNERSHIP
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Property, Plant and Equipment
Property, plant and equipment are stated at cost less accumulated
depreciation and amortization. Depreciation and amortization of property, plant
and equipment are computed on a straight-line method principally over the
following estimated useful lives:
<TABLE>
<CAPTION>
YEARS
--------
<S> <C>
Buildings and improvements.......................................... 30
Machinery and equipment............................................. 5 to 30
</TABLE>
Major Maintenance Accruals
The Partnership accrues for the estimated future costs of major overhauls
and equipment replacement based upon engineering studies.
Income Taxes
Federal and state income tax regulations provide that no income taxes are
levied on a partnership. Instead, each partners' share of partnership profit or
loss is reported on his or her separate income tax return. Accordingly, no
partnership income taxes are provided for in the accompanying financial
statements.
(2) AVAILABLE-FOR-SALE SECURITIES
As of October 31, 1995, the amortized cost and estimated fair values of the
Partnership's investments in tax-exempt municipal securities are summarized as
follows:
<TABLE>
<CAPTION>
RESTRICTED
AVAILABLE- AVAILABLE-
FOR-SALE FOR-SALE
SECURITIES SECURITIES TOTAL
---------- ---------- ----------
<S> <C> <C> <C>
Amortized cost......................... $1,919,184 $7,246,384 $9,165,568
Gross unrealized losses................ -- (5,079) (5,079)
---------- ---------- ----------
Estimated fair value................... $1,919,184 $7,241,305 $9,160,489
========== ========== ==========
</TABLE>
The amortized cost and estimated fair value of tax-exempt municipal
securities by contractual maturity are shown below.
<TABLE>
<CAPTION>
AMORTIZED ESTIMATED
DUE IN FISCAL YEAR ENDING OCTOBER 31, COST FAIR VALUE
---------------------------------------------------- ---------- ----------
<S> <C> <C>
1996................................................ $2,137,292 $2,134,000
1997-2000........................................... 7,028,276 7,026,489
---------- ----------
Total..................................... $9,165,568 $9,160,489
========== ==========
</TABLE>
Proceeds from sales of investments for the year ended October 31, 1995 are
as follow:
<TABLE>
<S> <C>
Gross proceeds.................................................. $26,099,037
Gross gains..................................................... $ 4,404
Gross losses.................................................... $ 3,939
</TABLE>
F-83
<PAGE> 178
BAF ENERGY,
A CALIFORNIA LIMITED PARTNERSHIP
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(3) PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment and accumulated depreciation and amortization
consist of:
<TABLE>
<CAPTION>
1995 1994
------------ ------------
<S> <C> <C>
Cost
Buildings and improvements............................ $ 1,410,873 $ 1,313,304
Machinery and equipment............................... 98,847,561 98,897,656
------------ ------------
100,258,434 100,210,960
Accumulated depreciation and amortization............... (24,387,912) (20,854,389)
------------ ------------
$ 75,870,522 $ 79,356,571
============ ============
</TABLE>
On December 6, 1995, the Partnership signed a letter agreement with a third
party to lease substantially all of the Partnership's property, plant and
equipment (see Note 8).
(4) LONG-TERM LIABILITIES
Long-term liabilities are summarized as follows:
<TABLE>
<CAPTION>
1995 1994
----------- -----------
<S> <C> <C>
Term loan at 10.88%, due in equal installments through
March 2004, non-recourse to the Partnership, secured by
the facility and associated contracts................... $60,514,066 $64,678,085
Term loan at 15.65%, due in equal installments through
March 2004, with recourse to BEI, secured by the
facility and associated contracts....................... 8,137,159 8,575,025
Major maintenance accruals................................ 3,597,865 3,188,389
----------- -----------
72,249,090 76,441,499
Less -- Current maturities................................ 5,444,386 5,283,785
----------- -----------
$66,804,704 $71,157,714
=========== ===========
</TABLE>
Annual Maturities,
Annual maturities of long-term liabilities at October 31, 1995 are
summarized as follows:
<TABLE>
<CAPTION>
YEAR ENDING OCTOBER 31, AMOUNT
---------------------------------------------------------------- -----------
<S> <C>
1996............................................................ $ 5,444,386
1997............................................................ 6,121,107
1998............................................................ 6,716,700
1999............................................................ 7,224,887
2000............................................................ 10,541,918
Thereafter...................................................... 36,200,092
-----------
$72,249,090
===========
</TABLE>
(5) RELATED PARTY TRANSACTIONS
The Partnership Agreement requires that the Partnership pay BEI a monthly
administrative fee. This fee amounted to $146,596, $139,613 and $132,966 for the
years ended October 31, 1995, 1994 and 1993, respectively.
F-84
<PAGE> 179
BAF ENERGY,
A CALIFORNIA LIMITED PARTNERSHIP
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
The Partnership has entered into a ground lease with a remaining term of 23
years with BAI for the land on which the facility is located. The lease includes
options to extend the lease term up to an additional 30 years. Rent was
$146,572, $139,593 and $132,946 for the years ended October 31, 1995, 1994 and
1993, respectively. Rents will escalate at the rate of 5% each year. In fiscal
1996, this lease will be assigned to a third party lessee pursuant to a letter
agreement discussed at Note 8.
The Partnership negotiated a steam sales contract with a remaining term of
23 years with Basic Vegetable Products, LP (BVP, LP). The General Partner of
BVP, LP is BVP. Under the contract, the Partnership supplies steam to BVP, LP's
King City, California food processing plant. Revenues recorded under the
contract totaled $669,341, $840,959 and $1,068,141 in 1995, 1994 and 1993,
respectively. In fiscal 1996, this contract will also be assigned (see Note 8).
(6) COMMITMENTS AND CONTINGENCIES
Facilities
The Partnership executed an Operations and Maintenance (O & M) Agreement
with Bechtel North American Power Corporation (Bechtel) in which Bechtel is
required to operate and maintain the facility for a term of five years from May
1989. The Partnership reimburses Bechtel for all costs incurred in the
performance of the service. O & M expenses paid totaled $3,665,168, $3,884,943
and $4,556,321 in 1995, 1994 and 1993, respectively, including a payment of base
fees of $275,000, $387,456 and $500,000 per year, respectively, and a payment of
earned fees of $380,000, $306,803 and $902,430 per year, respectively. The
agreement also provided for a "high performance" bonus fee dependent on meeting
certain performance standards. In April 1994, the O & M Agreement was
renegotiated and extended through October 1998. The renegotiated terms include
payment of base fees of $275,000 and elimination of the high performance bonus
fee. The bonus paid in 1994 and 1995 totaled $3,107 and $175,327, respectively.
In connection with the anticipated transaction described at Note 8, the
Partnership will sever its O & M Agreement with Bechtel. The severance payment
will be made with funds directly contributed by the third party lessee.
Financing
Calcorp Group, Inc. (CGI), a limited partner, has a put option to sell its
23 percent investment in the Partnership back to the Partnership at fair market
value in certain circumstances. The put is subject to a subordination agreement
with the Partnership's lenders. CGI has entered into a technical support
agreement with the Partnership, wherein CGI is reimbursed for services rendered
based upon time and expenses incurred.
(7) REVENUE RECOGNITION
BEI has an exclusive Power Purchase Agreement with Pacific Gas and Electric
(PG&E) under which PG&E pays capacity payments, as defined in the agreement, and
purchases all available energy, except for amounts sold to BVP, LP (see Note 5).
The Partnership receives substantially all of its capacity payments from PG&E
during May through October, and receives payment for energy sales to PG&E during
May through January. In fiscal 1996, this agreement will be assigned to a third
party lessee pursuant to a letter agreement discussed at Note 8.
(8) SIGNIFICANT LEASE TRANSACTION
On December 6, 1995, BAF Energy signed a letter agreement with a third
party to enter into a 23-year lease of the cogeneration property, plant and
equipment and to assign all related contracts. Under the terms of the lease, the
lessee will assume all rights and responsibilities related to the ground lease
(see Note 5), the BVP, LP steam sales contract (see Note 5), and the PG&E Power
Purchase Agreement (see Note 7). BAF Energy expects to sign the lease in early
1996.
F-85
<PAGE> 180
BAF ENERGY,
A CALIFORNIA LIMITED PARTNERSHIP
CONDENSED BALANCE SHEETS
<TABLE>
<CAPTION>
OCTOBER 31,
1995
JANUARY 31, -------------
1996
-----------
(UNAUDITED)
<S> <C> <C>
ASSETS
Current Assets:
Cash and cash equivalents..................................... $ 2,211,511 $ 3,757,921
Available for sale securities................................. -- 1,919,184
Restricted available-for-sale securities...................... 10,953,152 7,241,305
Accounts receivable -- trade.................................. 2,703,251 10,916,919
Supplies inventory............................................ 2,128,361 2,153,129
Prepaid insurance............................................. 144,633 288,383
------------ ------------
Total current assets.................................. 18,140,908 26,276,841
------------ ------------
Property, Plant and Equipment................................... 100,258,434 100,258,434
Accumulated depreciation and amortization..................... (25,280,413) (24,387,912)
------------ ------------
74,978,021 75,870,522
------------ ------------
$93,118,929 $ 102,147,363
============ ============
LIABILITIES AND PARTNERS' EQUITY
Current Liabilities:
Accounts payable.............................................. $ 811,919 $ 1,598,177
Interest payable.............................................. 3,273,915 1,309,566
Payable to affiliate.......................................... 38,428 166,569
Current portion of long-term liabilities...................... 5,546,361 5,444,386
------------ ------------
Total current liabilities............................. 9,670,623 8,518,698
------------ ------------
Long-Term Liabilities........................................... 66,702,729 66,804,704
------------ ------------
Commitments and Contingencies................................... -- --
Partners' Equity:
Contributed equity............................................ 9,901,600 9,901,600
Undistributed earnings........................................ 6,843,977 16,922,361
------------ ------------
Total partners' equity................................ 16,745,577 26,823,961
------------ ------------
$93,118,929 $ 102,147,363
============ ============
</TABLE>
The accompanying notes are an integral part of these statements.
F-86
<PAGE> 181
BAF ENERGY,
A CALIFORNIA LIMITED PARTNERSHIP
CONDENSED STATEMENTS OF INCOME
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED
JANUARY 31,
---------------------------
1996 1995
----------- -----------
<S> <C> <C>
OPERATING REVENUES................................................ $ 4,957,368 $ 7,941,577
OPERATING EXPENSES:
Fuel............................................................ 1,479,116 3,408,912
Depreciation and amortization................................... 892,500 1,072,028
Labor, supplies and other....................................... 1,066,580 1,431,321
----------- -----------
Total operating expenses................................ 3,438,196 5,912,261
----------- -----------
Operating income...................................... 1,519,172 2,029,316
----------- -----------
OTHER INCOME AND EXPENSE:
Interest income and other....................................... 154,073 130,313
General and administrative...................................... (290,763) (201,340)
Interest expense................................................ (1,965,945) (2,094,761)
----------- -----------
Total other income and expense.......................... (2,102,635) (2,165,788)
----------- -----------
PARTNERSHIP LOSS.................................................. $ (583,463) $ (136,472)
=========== ===========
</TABLE>
The accompanying notes are an integral part of these statements.
F-87
<PAGE> 182
BAF ENERGY,
A CALIFORNIA LIMITED PARTNERSHIP
CONDENSED STATEMENTS OF CASH FLOWS
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED
JANUARY 31,
-----------------------------
1996 1995
------------ ------------
<S> <C> <C>
Net Cash Provided by Operating Activities....................... $ 9,779,417 $ 2,298,789
------------ ------------
Cash Flows from Investing Activities:
Purchases of available-for-sale securities.................... (25,170,795) (12,290,102)
Proceeds from sales and redemptions of available-for-sale
securities................................................. 23,344,968 12,841,335
Additions to property, plant and equipment, net............... -- (20,189)
------------ ------------
Net cash (used in) provided by investing activities... (1,825,827) 531,044
------------ ------------
Cash Flows From Financing Activities:
Increase in long-term liabilities, net........................ -- 307,110
Cash distributions to partners................................ (9,500,000) (8,500,000)
------------ ------------
Net cash used in financing activities................. (9,500,000) (8,192,890)
------------ ------------
Net Decrease in Cash and Cash Equivalents....................... (1,546,410) (5,363,057)
Cash and Cash Equivalents, beginning of period.................. 3,757,921 5,363,057
------------ ------------
Cash and Cash Equivalents, end of period........................ $ 2,211,511 $ --
============ ============
Supplementary Information:
Unrealized holding gains/losses, net, on available-for-sale
securities, recorded as additions to undistributed
earnings................................................... $ 5,079 $ --
Cash paid during the period for interest...................... $ -- $ --
</TABLE>
The accompanying notes are an integral part of these statements.
F-88
<PAGE> 183
BAF ENERGY,
A CALIFORNIA LIMITED PARTNERSHIP
NOTES TO CONDENSED FINANCIAL STATEMENTS
JANUARY 31, 1996
(UNAUDITED)
(1) GENERAL
Organization
BAF Energy, A California Limited Partnership (BAF Energy or the
Partnership) was founded in 1986 and is engaged in the development, construction
and operation of a cogeneration facility. The term of the Partnership is through
December 2020 unless terminated earlier in accordance with the Partnership
Agreement. The facility produces and sells electricity and steam.
BAF Energy, Inc. (BEI) is the general partner of the Partnership and has an
ownership interest of 1 percent. BEI is a wholly owned subsidiary of Basic
Vegetable Products, Inc. (BVP). BVP is a wholly owned subsidiary of Basic
American, Inc. (BAI). As of January 31, 1996, BAI also owned approximately 51
percent of the limited partnership units of BAF Energy then outstanding.
Distributions and profit and loss are allocated 99 percent to the limited
partners, based on their proportionate share of limited partnership units, and 1
percent to the general partner.
Basis of Interim Presentation
The accompanying interim condensed financial statements of the Partnership
have been prepared by the Partnership, without audit by independent public
accountants, pursuant to the rules and regulations of the Securities and
Exchange Commission. In the opinion of management, the condensed consolidated
financial statements include all normal recurring adjustments necessary to
present fairly the information required to be set forth therein. Certain
information and note disclosures normally included in financial statements
prepared in accordance with generally accepted accounting principles have been
condensed or omitted from these statements pursuant to such rules and
regulations and, accordingly, should be read in conjunction with the audited
financial statements of the Partnership for the year ended October 31, 1995.
Consistent with the operating schedule of the cogeneration facility, the
Partnership receives a majority of its operating revenue between May and
September. Therefore, the results of operations for the three months ended
January 31, 1996 and 1995 are not indicative of the results for the entire year.
(2) RELATED PARTY TRANSACTIONS
The Partnership Agreement requires that the Partnership pay BEI a monthly
administrative fee. This fee amounted to $37,558 and $35,770 for the quarters
ended January 31, 1996 and 1995, respectively.
The Partnership has entered into a ground lease with BAI for the land on
which the facility is located. Rent was $37,554 and $35,764 for the quarters
ended January 31, 1996 and 1995, respectively.
The Partnership negotiated a steam sales contract with Basic Vegetable
Products, LP (BVP, LP). The General Partner of BVP, LP is BVP. Under the
contract, the Partnership supplies steam to BVP, LP's food processing plant.
Revenues recorded under the contract totaled $38,333 and $55,788 for the
quarters ended January 31, 1996 and 1995, respectively.
(3) PARTNERS' EQUITY:
The Partnership made distributions of $9,500,000 and $8,500,000 for the
quarters ended January 31, 1996 and 1995, respectively.
F-89
<PAGE> 184
BAF ENERGY,
A CALIFORNIA LIMITED PARTNERSHIP
NOTES TO CONDENSED FINANCIAL STATEMENTS -- (CONTINUED)
JANUARY 31, 1996
(UNAUDITED)
(4) SIGNIFICANT LEASE TRANSACTION:
In April 1996, the Partnership signed an agreement with a third party to
enter into a 23-year lease of the cogeneration property, plant and equipment and
to assign all related contracts. Under the terms of the lease, the lessee will
assume all rights and responsibilities related to the ground lease with BAI (see
Note 2), the BVP, LP steam sales contract (see Note 2) and a Pacific Gas &
Electric (PG&E) Power Purchase Agreement. The ground lease has a remaining term
of 23 years with BAI for the land on which the facility is located. This lease
includes options to extend the lease term up to an additional 30 years. The BVP,
LP steam sales contract has a remaining term of 23 years. The PG&E Power
Purchase Agreement states that PG&E pays capacity payments, as defined in the
agreement, and purchases all available energy, except for amounts sold to BVP,
LP.
F-90
<PAGE> 185
REPORT OF INDEPENDENT AUDITORS
The Shareholder
Gilroy Energy Company
We have audited the accompanying balance sheets of Gilroy Energy Company
(the Company), a wholly owned subsidiary of Gilroy Foods, Inc. which in turn is
a wholly owned subsidiary of McCormick & Company, Inc., as of November 30, 1995
and 1994 and the related statements of income, shareholder's equity, and cash
flows for the years then ended. 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 audit.
We conducted our audit 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 audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Gilroy Energy Company at
November 30, 1995 and 1994 and the results of its operations and its cash flows
for the years then ended in conformity with generally accepted accounting
principles.
ERNST & YOUNG LLP
Baltimore, Maryland
July 18, 1996
F-91
<PAGE> 186
GILROY ENERGY COMPANY
(A WHOLLY OWNED SUBSIDIARY)
BALANCE SHEETS
(DOLLARS IN THOUSANDS)
ASSETS
<TABLE>
<CAPTION>
NOVEMBER 30
---------------------
1995 1994
MAY 31, -------- --------
1996
-----------
(UNAUDITED)
<S> <C> <C> <C>
Current assets:
Accounts receivable..................................... $ 4,428 $ 1,615 $ 1,503
Prepaid expenses........................................ 462 725 776
-------- -------- --------
Total current assets............................ 4,890 2,340 2,279
Property and equipment, at cost:
Buildings............................................... 2,720 2,720 2,720
Machinery and equipment................................. 93,421 93,349 93,098
Furniture and fixtures.................................. 64 64 62
Software................................................ 65 65 58
-------- -------- --------
96,270 96,198 95,938
Less accumulated depreciation and amortization............ 39,202 36,712 31,701
-------- -------- --------
57,068 59,486 64,237
Due from parent and affiliates............................ 64,780 69,422 61,522
-------- -------- --------
Total assets.............................................. $ 126,738 $131,248 $128,038
======== ======== ========
LIABILITIES
Current liabilities:
Bank overdraft.......................................... -- $ 58 $ 618
Accounts payable........................................ $ 1,653 2,678 1,767
Accrued interest........................................ 3,093 3,238 3,363
Other liabilities....................................... 336 993 241
Current portion of long-term debt....................... 2,848 2,468 2,152
-------- -------- --------
Total current liabilities....................... 7,930 9,435 8,141
Long-term debt, due after one year........................ 50,120 52,968 55,436
Other liabilities......................................... 399 49 1,083
-------- -------- --------
50,519 53,017 56,519
Shareholder's equity:
Common stock, no par value:
Authorized shares -- 10,000
Issued and outstanding shares -- 1,000............... 10 10 10
Additional paid-in capital.............................. 16,946 16,946 16,946
Retained earnings....................................... 51,333 51,840 46,422
-------- -------- --------
Total shareholder's equity...................... 68,289 68,796 63,378
-------- -------- --------
Total liabilities and shareholder's equity................ $ 126,738 $131,248 $128,038
======== ======== ========
</TABLE>
See accompanying notes.
F-92
<PAGE> 187
GILROY ENERGY COMPANY
(A WHOLLY OWNED SUBSIDIARY)
STATEMENTS OF INCOME
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
SIX MONTHS ENDED YEARS ENDED
MAY 31, NOVEMBER 30,
---------------- -------------------
1996 1995 1995 1994
------ ------- ------- -------
(UNAUDITED)
<S> <C> <C> <C> <C>
Net revenues:
Electricity revenue................................ $9,306 $11,158 $35,132 $40,037
Steam revenue from Gilroy Foods, Inc............... 185 260 1,089 1,367
------ ------- ------- -------
9,491 11,418 36,221 41,404
Cost of sales........................................ 6,525 8,125 18,825 23,766
------ ------- ------- -------
Gross margin......................................... 2,966 3,293 17,396 17,638
Operating expenses;
Selling, general and administrative................ 720 946 1,888 1,885
------ ------- ------- -------
Operating income..................................... 2,246 2,347 15,508 15,753
Interest expense..................................... 3,093 3,237 6,477 6,731
------ ------- ------- -------
(Loss) Income before income taxes.................... (847) (890) 9,031 9,022
Provision for income tax (benefit) expense........... (340) (356) 3,613 3,622
------ ------- ------- -------
Net (loss) income.................................... $ (507) $ (534) $ 5,418 $ 5,400
====== ======= ======= =======
</TABLE>
See accompanying notes.
F-93
<PAGE> 188
GILROY ENERGY COMPANY
(A WHOLLY OWNED SUBSIDIARY)
STATEMENT OF SHAREHOLDER'S EQUITY
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
COMMON STOCK ADDITIONAL TOTAL
----------------- PAID-IN RETAINED SHAREHOLDER'S
SHARES AMOUNT CAPITAL EARNINGS EQUITY
------ ------ ---------- -------- -------------
<S> <C> <C> <C> <C> <C>
Balance at November 30, 1993............. 1,000 $ 10 $ 16,946 $ 41,022 $57,978
Net income............................... -- -- -- 5,400 5,400
------ ------ ---------- -------- -------------
Balance at November 30, 1994............. 1,000 10 16,946 46,422 63,378
Net income............................... -- -- -- 5,418 5,418
------ ------ ---------- -------- -------------
Balance at November 30, 1995............. 1,000 10 16,946 51,840 68,796
Net (loss) (unaudited)................... -- -- -- (507) (507)
------ ------ ---------- -------- -------------
Balance at May 31, 1996
(unaudited)............................ 1,000 $ 10 $ 16,946 $ 51,333 $68,289
===== ====== ======= ======= ==========
</TABLE>
See accompanying notes.
F-94
<PAGE> 189
GILROY ENERGY COMPANY
(A WHOLLY OWNED SUBSIDIARY)
STATEMENTS OF CASH FLOWS
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
SIX MONTHS ENDED YEARS ENDED
MAY 31, NOVEMBER 30,
------------------- -------------------
1996 1995 1995 1994
------- ------- ------- -------
(UNAUDITED)
<S> <C> <C> <C> <C>
OPERATING ACTIVITIES:
Net income (loss)................................. $ (507) $ (534) $ 5,418 $ 5,400
Adjustments to reconcile net (loss) income to net
cash (used in) provided by operating
activities:
Depreciation and amortization.................. 2,490 2,482 5,011 4,880
Changes in operating assets and liabilities:
Accounts receivable.......................... (2,813) (3,577) (113) 51
Prepaid expenses............................. 263 325 52 49
Accounts payable............................. (1,025) (360) 912 (1,221)
Accrued expenses and other liabilities....... (452) (644) (408) 364
------- ------- ------- -------
Net cash (used in) provided by operating
activities........................................ (2,044) (2,308) 10,872 9,523
------- ------- ------- -------
INVESTING ACTIVITIES:
Due from parent and affiliates...................... 4,642 5,071 (7,900) (4,610)
Purchase of property and equipment.................. (72) (117) (260) (3,376)
------- ------- ------- -------
Net cash provided by (used in) investing
activities........................................ 4,570 4,954 (8,160) (7,986)
------- ------- ------- -------
FINANCING ACTIVITIES:
Principal payments on long-term debt................ (2,468) (2,152) (2,152) (2,152)
------- ------- ------- -------
Net cash (used in) financing activities............. (2,468) (2,152) (2,152) (2,152)
------- ------- ------- -------
Net decrease (increase) in bank overdraft........... 58 494 560 (615)
Bank overdraft at beginning of period............... (58) (618) (618) (3)
------- ------- ------- -------
Bank overdraft at end of period..................... $ -- $ (124) $ (58) $ (618)
======= ======= ======= =======
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Interest paid....................................... $ 3,238 $ 3,359 $ 6,602 $ 6,602
</TABLE>
See accompanying notes.
F-95
<PAGE> 190
GILROY ENERGY COMPANY
(A WHOLLY OWNED SUBSIDIARY)
NOTES TO FINANCIAL STATEMENTS
(DOLLARS IN THOUSANDS)
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization
Gilroy Energy Company (the Company) was incorporated in the State of
California in July 1984. The Company is a wholly owned subsidiary of Gilroy
Foods, Inc. which in turn is a wholly owned subsidiary of McCormick & Company,
Inc. (McCormick). The Company runs a cogeneration facility in Gilroy, California
which uses natural gas and steam turbine engines to generate steam for sale to
Gilroy Foods, Inc. and electricity for sale to Pacific Gas and Electric Company.
Sales to Pacific Gas and Electric Company represented approximately 97% of
total revenues for each of the years ended November 30, 1995 and 1994 and 98%
for the six months ended May 31, 1996 and 1995.
Approximately 80% of the Company's net revenues are recognized during the
months of May through October of each year. As such, the results of operations
for the six month periods ended May 31, 1996 and 1995 are not indicative of the
results of operations that may be realized for the full year.
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and the
disclosure of contingent assets and liabilities at the date of the financial
statements as well as the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Bank Overdrafts
The Company maintains a zero balance bank account. Amounts sufficient to
cover checks presented to the bank are deposited into the account by McCormick &
Company, Inc. The bank overdrafts represent checks that have been written but
have not cleared the bank as of the balance sheet date.
Property and Equipment
Property and equipment are recorded at cost. Depreciation and amortization
are computed using the straight-line method over the estimated useful lives of
the assets, ranging from five to forty years.
In 1995, the Financial Accounting Standards Board released Statement of
Financial Accounting Standards No. 121, "Accounting for Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed of " (FAS 121). FAS 121 requires
recognition of impairment of long-lived assets in the event that the net book
value of such assets exceeds the future undiscounted cash flows attributable to
such assets. The Company will be required to adopt FAS 121 in its 1997 fiscal
year. Management does not believe that the initial adoption of FAS 121 will have
a significant impact on the Company.
Repairs and Maintenance
The cogeneration plant requires a periodic shutdown for major overhauls of
its primary components every several years. The Company's policy is to accrue
the anticipated cost of these overhauls during the operating periods prior to
the scheduled overhaul dates. The amounts and period of accruals for overhaul
costs are revised annually based on management's estimate of time remaining
before the next scheduled overhaul and the estimated cost of the overhaul.
Repairs and maintenance expenditures that are not a part of major overhauls
or do not extend the useful life of the related equipment are charged to expense
when incurred.
F-96
<PAGE> 191
GILROY ENERGY COMPANY
(A WHOLLY OWNED SUBSIDIARY)
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
(DOLLARS IN THOUSANDS)
Due from Parent and Affiliates
The due from parent and affiliates included in the balance sheet represents
a net balance as the result of various transactions between the Company and
Gilroy Foods, Inc. and McCormick & Company, Inc. There are no terms of
settlement, or interest charges associated with the account balance. The balance
is primarily the result of the Company's participation in McCormick's central
cash management program, wherein all the Company's cash receipts are remitted to
McCormick and all cash disbursements are funded by McCormick. Other transactions
include steam sales to Gilroy Foods, Inc., the Company's estimated income tax
payable or receivable resulting from the current and prior years estimated
provisions, and miscellaneous other administrative expenses incurred by Gilroy
Foods, Inc. or McCormick & Company, Inc. on behalf of the Company.
An analysis of transactions in the due from parent and affiliates balance
for the six months ended May 31, 1996 and 1995 (unaudited) and each of the two
years in the period ended November 30, 1995 follows:
<TABLE>
<CAPTION>
SIX MONTHS ENDED YEARS ENDED
MAY 31, NOVEMBER 30,
------------------- -------------------
1996 1995 1995 1994
------- ------- ------- -------
(UNAUDITED)
<S> <C> <C> <C> <C>
Balance in due from parent and affiliates at
beginning of period............................... $69,422 $61,522 $61,522 $56,912
Net cash remitted (from) to Gilroy Foods, Inc. or
McCormick......................................... (4,616) (5,578) 10,671 7,729
Net intercompany sales.............................. 196 275 1,146 1,438
Net intercompany purchases for cost of sales........ (532) (3) (218) (6)
Net intercompany purchases for selling, general and
administrative expenses........................... (30) (121) (87) (929)
Benefit (provision) for income taxes................ 340 356 (3,612) (3,622)
------- ------- ------- -------
Balance in due from parent and affiliated at end of
period............................................ $64,780 $56,451 $69,422 $61,522
======= ======= ======= =======
Average balance during the period................... $66,384 $58,373 $61,811 $56,828
======= ======= ======= =======
</TABLE>
Gilroy Foods, Inc. provides certain administrative services to the Company
including the services of the President of Gilroy Energy Company, Inc.,
accounting, and other administrative services. It is the policy of Gilroy Foods,
Inc. to charge these expenses and all other central operating costs on the basis
of direct usage. In the opinion of management, no other costs of Gilroy Foods,
Inc. should be allocated to the Company.
McCormick provides various administrative services to the Company including
legal assistance and treasury services. McCormick does not charge the Company
for these services. In the opinion of management, the cost of the services
rendered by McCormick in these areas during each of the two years ended November
30, 1995 and 1994 and the six months ended May 31, 1996 and 1995 are nominal.
Concentration of Credit Risk
The Company sells electricity to Pacific Gas and Electric Company under a
long-term contract. All accounts receivable at May 31, 1996 (unaudited) and
November 30, 1995 and 1994 are due from this customer. No collateral is required
for accounts receivable. Management believes that no reserves are required for
potential credit losses at May 31, 1996 and November 30, 1995 and 1994.
F-97
<PAGE> 192
GILROY ENERGY COMPANY
(A WHOLLY OWNED SUBSIDIARY)
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
(DOLLARS IN THOUSANDS)
Sources of Supply
The Company purchases natural gas for the operation of the cogeneration
facility under a supply contract with one supplier. The supply contract requires
the Company to purchase substantially all of its natural gas needs from the
supplier at a price based on the market value determined in accordance with the
contract through July 31, 1997. Management believes that in the event that this
supplier is not able to meet its obligations under the contract, alternative
sources of supply for natural gas are readily available at comparable prices.
2. LONG-TERM DEBT
The Company's outstanding indebtedness is as follows:
<TABLE>
<CAPTION>
NOVEMBER 30,
-------------------
1995 1994
MAY 31, ------- -------
1996
-----------
(UNAUDITED)
<S> <C> <C> <C>
Note payable in annual installments through $52,968 $55,436 $57,588
2006 with interest at 11.68% per annum....
Less current portion........................ 2,848 2,468 2,152
------- ------- -------
$50,120 $52,968 $55,436
======= ======= =======
</TABLE>
The note payable requires the maintenance of a $5,000 maintenance fund and
a $10,000 debt service fund. The note holder has agreed to accept a guarantee of
up to $15,000 by McCormick & Company, Inc. in lieu of establishing these funds.
The terms of the note payable require the Company to comply with certain
nonfinancial covenants. Management believes that the Company was in compliance
with all applicable covenants at November 30, 1995 and 1994. The note payable is
secured by the cogeneration facility.
The note payable agreement provides for the payment of a prepayment penalty
in the event of early retirement. The amount of the prepayment penalty
approximates the present value of the differential between current market
interest rates and the stated rate over the remaining life of the debt as
defined by the agreement.
Aggregate maturities of long-term debt over the next five fiscal years
ending November 30 and thereafter are as follows:
<TABLE>
<S> <C>
1996....................................................... $ 2,468
1997....................................................... 2,848
1998....................................................... 3,101
1999....................................................... 3,481
2000....................................................... 3,797
Thereafter................................................. 39,741
-------
$55,436
=======
</TABLE>
3. INCOME TAXES
The Company is included in the consolidated federal and state income tax
returns of McCormick. McCormick does not have a formal tax sharing arrangement
with its subsidiaries. The income tax provisions included in the statements of
income has been provided under the liability method assuming that Gilroy Energy
Company had prepared separate income tax returns for the years ended November
30, 1995 and 1994 and the six months ended May 31, 1996 and 1995 (unaudited).
Any income taxes receivable or payable as a
F-98
<PAGE> 193
GILROY ENERGY COMPANY
(A WHOLLY OWNED SUBSIDIARY)
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
(DOLLARS IN THOUSANDS)
result of the income tax provisions, including any deferred amounts due or
payable resulting from the current or prior years provisions are included in due
from parent and affiliates.
The (benefit) provision for income taxes is summarized as follows:
<TABLE>
<CAPTION>
SIX MONTHS
ENDED YEARS ENDED
MAY 31, NOVEMBER 30,
--------------- -------------------
1996 1995 1995 1994
----- ----- ------- -------
(UNAUDITED)
<S> <C> <C> <C> <C>
Current:
Federal.............................. $(288) $(303) $ 3,877 $ 4,061
State................................ (52) (53) 1,169 1,225
----- ----- ------- -------
(340) (356) 5,046 5,286
----- ----- ------- -------
Deferred:
Federal.............................. -- -- (1,095) (1,278)
State................................ -- -- (338) (386)
----- ----- ------- -------
-- -- (1,433) (1,664)
----- ----- ------- -------
$(340) $(356) $ 3,613 $ 3,622
===== ===== ======= =======
</TABLE>
The reconciliation between income tax computed at the United States federal
statutory rate and income taxes actually provided follows:
<TABLE>
<CAPTION>
SIX MONTHS ENDED MAY 31, YEARS ENDED NOVEMBER 30,
------------------------------- -------------------------------
1996 1995 1995 1994
------------- ------------- ------------- -------------
AMOUNT % AMOUNT % AMOUNT % AMOUNT %
------ ---- ------ ---- ------ ---- ------ ----
(UNAUDITED)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Tax at federal rate....... $ (288) 34.0% $ (303) 34.0% $3,071 34.0% 3,067 34.0%
State income taxes, net of
federal benefit......... (52) 6.1% (53) 6.0% 542 6.0% 555 6.1%
------ ------ ------
Actual income taxes
(benefit) provided...... $ (340) 40.1% $ (356) 40.0% $3,613 40.0% $3,622 40.1%
====== ====== ======
</TABLE>
The temporary differences that give rise to significant portions of the
deferred tax assets and liabilities that have been netted in due from parent and
affiliates consist of the following:
<TABLE>
<CAPTION>
NOVEMBER 30,
-------------------
1995 1994
------- -------
<S> <C> <C>
Temporary differences resulting in deferred tax assets:
Repairs and maintenance expenditures................... $ 986 $ 1,082
------- -------
Temporary differences resulting in deferred tax
liabilities:
Depreciation........................................... 50,897 54,587
Prepaid expenses....................................... 810 758
Other.................................................. 357 357
------- -------
52,064 55,702
------- -------
$51,078 $54,620
======= =======
</TABLE>
No valuation allowance is provided for deferred tax assets.
F-99
<PAGE> 194
GILROY ENERGY COMPANY
(A WHOLLY OWNED SUBSIDIARY)
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
(DOLLARS IN THOUSANDS)
4. RELATED PARTY TRANSACTIONS
The Company sells substantially all of the steam, which is a byproduct of
the cogeneration process to Gilroy Foods, Inc. During the years ended November
30, 1995 and 1994, the amount of revenue recognized by the Company from steam
sales to Gilroy Foods, Inc. was $1,089 and $1,367, respectively. During the six
months ended May 31, 1996 and 1995, the amount of revenue recognized by the
Company from steam sales to Gilroy Foods, Inc. was $185 and $261, respectively.
Gilroy Foods, Inc. provides certain accounting and administrative services
to Gilroy Energy Company, Inc. A portion of the cost of these services is billed
directly to Gilroy Energy Company, Inc.
The Company leases the land where the cogeneration facility is located
under an operating lease with Gilroy Foods, Inc. The lease agreement runs
through 2018 and provides for minimum annual rental payments with provisions for
the escalation of costs every three years based on the average increase in the
Consumer Price Index. The future minimum lease payments under this lease,
excluding any future increases, are as follows:
<TABLE>
<S> <C>
1996.................................................................................. $ 40
1997.................................................................................. 40
1998.................................................................................. 40
1999.................................................................................. 40
2000.................................................................................. 40
2001 through 2018..................................................................... 715
----
$915
====
</TABLE>
Rent expense recognized under this lease was $38 and $37 in the years ended
November 30, 1995 and 1994, respectively, and $20 and $19 in the six months
ended May 31, 1996 and 1995, respectively.
5. COMMITMENTS AND CONTINGENCIES
The Company has an agreement with the Pacific Gas and Electric Company
(PG&E) to sell all electricity generated by the cogeneration facility to PG&E.
The agreement establishes the methodology used to calculate the purchase price
of the electricity, establishes the operating hours of the cogeneration
facility, and provides for the payment to the Company of additional capacity
payments if certain operating targets as defined are achieved. The current
provisions of this agreement extend through December 31, 1998. Subsequent to
December 31, 1998 and continuing through the expiration of the base agreement on
December 31, 2017, the pricing and operating provisions of the agreement will be
established by negotiation between PG&E and Gilroy Energy Company.
The Company has an agreement with Gilroy Foods, Inc. whereby Gilroy Foods,
Inc. has agreed to purchase substantially all of the steam produced by the
Company. The terms of the agreement, which extends through 2017, provide for the
establishment of the purchase price for steam based on the current cost of
alternative sources of energy available to Gilroy Foods, Inc.
The Company has an operating and maintenance agreement with an outside
party for the daily operation and maintenance of the cogeneration facility. This
agreement, which extends through November 1996, provides for all operating and
routine maintenance of the cogeneration facility at direct costs plus a minimum
annual fee of $100,000. The contract also provides for the payment of bonuses,
as defined, if certain operating targets are met.
F-100
<PAGE> 195
GILROY ENERGY COMPANY
(A WHOLLY OWNED SUBSIDIARY)
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
(DOLLARS IN THOUSANDS)
6. FAIR VALUE
The following methods and assumptions were used by the Company in
estimating fair value disclosures for financial instruments:
Accounts receivable, due from parent and affiliates, bank overdrafts,
current portion of long-term debt, accounts payable, and accrued
liabilities -- The amounts reported in the balance sheet approximate fair value.
Long-term debt. The fair value of long-term debt, based on a discounted
cash flow analysis using current interest rates for debt with similar
characteristics and maturities is as follows:
<TABLE>
<CAPTION>
NOVEMBER 30
---------------------------------------------
1995 1994
FAIR CARRYING FAIR CARRYING
VALUE VALUE VALUE VALUE
------- -------- ------- --------
<S> <C> <C> <C> <C>
Long-term debt............................ $68,100 $ 52,968 $63,000 $ 55,436
</TABLE>
7. SUBSEQUENT EVENT
In May 1996, McCormick & Company, Inc. announced its intention to sell the
assets and liabilities, excluding the due from parent and affiliates, the
current portion of long-term debt and the long-term debt of the Company to
Calpine Corporation. At the time of the closing of the sale, McCormick &
Company, Inc. will assume the due from parent and affiliates and will be
required to retire the current portion of the long-term debt and the long-term
debt. In addition to all remaining assets and liabilities of Gilroy Energy
Company, Calpine Corporation will assume all rights and obligations under the
following agreements to which Gilroy Energy Company is currently a party:
- Long-term contract to sell electricity to Pacific Gas and Electric
Company.
- Natural gas supply contract through July 31, 1997.
- Lease for the land with Gilroy Foods, Inc. upon which the cogeneration
facility is located.
- Steam sale contract with Gilroy Foods, Inc.
Upon closing of the sale, the management contract with the current operator
of the cogeneration facility will be terminated by McCormick & Company, Inc.
It is currently anticipated that the closing date for the sale of the
applicable assets and liabilities of Gilroy Energy Company to Calpine
Corporation will take place in the third quarter of 1996.
F-101
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<PAGE> 199
APPENDIX -- CALPINE GRAPHIC IMAGES
GRAPHIC (Domestic Inside Front Cover)
Upper Photo--Sumas 125 mw Gas-fired Facility
Lower Photo--King City 120 mw Gas-fired Facility
Calpine Logo
GRAPHIC (International Inside Front Cover-Alternate Page A-2)
Photo--Sumas 125 mw Gas-fired Facility
Calpine Logo
GRAPHIC (Inside Back Cover)
Upper Photo--Cerro Prieto 80 mw Geothermal Steam Field
The Power of Innovation
Lower Photo--West Ford Flat 27 mw Geothermal Facility
Calpine Logo
GRAPHIC (page 43)
CALPINE CORPORATION
1 - Calpine Corporation Headquarters
San Jose, California
2 - Calpine Corporation Geothermal Office
Santa Rosa, California
3 - Aidlin 20 mw Geothermal Facility
4 - Agnews 29 mw Cogeneration Facility
5 - Bear Canyon 20 mw Geothermal Facility
6 - Black Hills 80 mw Coal Project
7 - Cerro Prieto 80 mw Steam Fields
8 - Coso 150 mw Geothermal Project
9 - Gilroy 120 mw Cogeneration Facility
10 - Glass Mountain 145 mw Geothermal Project
11 - Greenleaf 1 49.5 mw Cogeneration Facility
12 - Greenleaf 2 49.5 mw Cogeneration Facility
13 - King City 120 mw Cogeneration Facility
14 - Navajo South 1,700 mw Coal Project
15 - Pasadena 240 mw Cogeneration Facility
16 - PG&E Unit 13 Steam Fields
17 - PG&E Unit 16 Steam Fields
18 - SMUDGEO #1 Steam Fields
19 - Sumas 125 mw Cogeneration Facility
20 - Thermal Power Company Steam Fields
21 - Watsonville 28.5 mw Cogeneration Facility
22 - West Ford Flat 27 mw Geothermal Facility
Map of western and southwestern United States indicating:
Corporate Headquarters
Corporate Geothermal Office
Operating Facility
Steam Fields
Future Projects
Graphic (page 40)
Illustration of a Combined Cycle Power Plant
Graphic (page 41)
Illustration of a Geothermal Power Plant
<PAGE> 200
- ------------------------------------------------------
NO DEALER, SALESPERSON OR OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATION NOT CONTAINED IN THIS PROSPECTUS, AND,
IF GIVEN OR MADE, SUCH INFORMATION OR REPRESENTATION MUST NOT BE RELIED UPON AS
HAVING BEEN AUTHORIZED BY THE COMPANY OR ANY UNDERWRITER. THIS PROSPECTUS DOES
NOT CONSTITUTE AN OFFER TO SELL OR A SOLICITATION OF AN OFFER TO BUY ANY OF THE
SECURITIES OFFERED HEREBY IN ANY JURISDICTION TO ANY PERSON TO WHICH IT IS
UNLAWFUL TO MAKE SUCH OFFER IN SUCH JURISDICTION. NEITHER THE DELIVERY OF THIS
PROSPECTUS NOR ANY SALE MADE HEREUNDER SHALL, UNDER ANY CIRCUMSTANCES, CREATE
ANY IMPLICATION THAT THE INFORMATION CONTAINED HEREIN IS CORRECT AS OF ANY TIME
SUBSEQUENT TO THE DATE HEREOF OR THAT THERE HAS BEEN NO CHANGE IN THE AFFAIRS OF
THE COMPANY SINCE SUCH DATE.
------------------
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Prospectus Summary.................... 3
Risk Factors.......................... 8
Use of Proceeds....................... 17
Dividend Policy....................... 17
Capitalization........................ 18
Dilution.............................. 19
Selected Consolidated Financial
Data................................ 20
Pro Forma Consolidated Financial
Data................................ 22
Management's Discussion and Analysis
of Financial Condition and Results
of Operations....................... 29
Business.............................. 38
Management............................ 70
Certain Transactions.................. 80
Principal and Selling Stockholders.... 82
Description of Capital Stock.......... 83
Shares Eligible for Future Sale....... 85
Certain United States Federal Tax
Consequences to Non-U.S. Holders.... 86
Underwriting.......................... 89
Notice to Canadian Residents.......... 92
Legal Matters......................... 92
Experts............................... 93
Available Information................. 93
Consolidated Financial Statements..... F-1
</TABLE>
------------------
UNTIL OCTOBER 14, 1996, ALL DEALERS EFFECTING TRANSACTIONS IN THE COMMON
STOCK OFFERED HEREBY, WHETHER OR NOT PARTICIPATING IN THIS DISTRIBUTION, MAY BE
REQUIRED TO DELIVER A PROSPECTUS. THIS IS IN ADDITION TO THE OBLIGATION OF
DEALERS TO DELIVER A PROSPECTUS WHEN ACTING AS UNDERWRITERS AND WITH RESPECT TO
THEIR UNSOLD ALLOTMENTS OR SUBSCRIPTIONS.
- ------------------------------------------------------
- ------------------------------------------------------
LOGO
18,045,000 Shares
Common Stock
PROSPECTUS
CS First Boston
Morgan Stanley & Co.
Incorporated
PaineWebber Incorporated
Salomon Brothers Inc
------------------------------------------------------
<PAGE> 201
Filed Pursuant to Rule 424(b)(4)
Registration Statement No. 333-07497
<TABLE>
<S> <C>
18,045,000 Shares
Calpine Corporation
LOGO Common Stock
($.001 par value)
</TABLE>
------------------
Of the shares of Common Stock, $.001 par value ("Common Stock"), of Calpine
Corporation (the "Company" or "Calpine") offered hereby, 5,477,820 shares are
being sold by the Company and 12,567,180 shares are being sold by the
Selling Stockholder named herein under "Principal and Selling
Stockholders." Of the 18,045,000 shares of Common Stock being offered,
3,609,000 shares are initially being offered outside the United States
and Canada (the "International Shares") by the Managers (the
"International Offering") and 14,436,000 shares are initially being
concurrently offered in the United States and Canada (the "U.S.
Shares") by the U.S. Underwriters (the "U.S. Offering" and,
together with the International Offering, the "Common Stock
Offering"). The offering price and underwriting discounts and
commissions of the International Offering and the U.S. Offering
are identical.
Prior to the Common Stock Offering, there has been no public market for the
Common Stock. For information relating to the factors considered in
determining the initial public offering price
to the public, see
"Subscription and Sale."
The Common Stock has been approved for listing on the New York Stock Exchange
under the symbol "CPN,"
subject to notice of issuance.
------------------
FOR A DISCUSSION OF CERTAIN FACTORS THAT SHOULD BE CONSIDERED IN CONNECTION WITH
AN INVESTMENT
IN THE COMMON STOCK, SEE "RISK FACTORS" BEGINNING ON PAGE 8 HEREIN.
------------------
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR
HAS THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE
SECURITIES COMMISSION PASSED UPON THE ACCURACY OR AD-
EQUACY OF THIS PROSPECTUS. ANY REPRESENTATION
TO THE CONTRARY IS A CRIMINAL
OFFENSE.
<TABLE>
<S> <C> <C> <C> <C>
Underwriting Proceeds to
Price to Discounts and Proceeds to Selling
Public Commissions Calpine(1) Stockholder(1)
---------------- ---------------- ---------------- ----------------
Per Share...................... $16.00 $.90 $15.10 $15.10
Total(2)....................... $288,720,000 $16,240,500 $82,715,082 $189,764,418
</TABLE>
(1) Before deduction of expenses payable by Calpine and the Selling Stockholder,
estimated at $1.5 million.
(2) The Company has granted the Managers and the U.S. Underwriters an option,
exercisable by CS First Boston Corporation for 30 days from the date of this
Prospectus, to purchase a maximum of 2,706,750 additional shares to cover
over-allotments of shares. If the option is exercised in full, the total
Price to Public will be $332,028,000, Underwriting Discounts and Commissions
will be $18,676,575, Proceeds to Calpine will be $123,587,007 and Proceeds
to Selling Stockholder will be $189,764,418.
------------------
The International Shares are offered by the several Managers when, as and if
delivered to and accepted by the Managers and subject to their right to reject
orders in whole or in part. It is expected that the International Shares will be
ready for delivery on or about September 25, 1996, against payment in
immediately available funds.
CS First Boston Morgan Stanley & Co.
International
PaineWebber International Salomon Brothers International Limited
Banque Nationale de Paris ING Barings
UBS Limited
The date of this Prospectus is September 19, 1996.
<PAGE> 202
NO DEALER, SALESPERSON OR OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATION NOT CONTAINED IN THIS PROSPECTUS, AND,
IF GIVEN OR MADE, SUCH INFORMATION OR REPRESENTATION MUST NOT BE RELIED UPON AS
HAVING BEEN AUTHORIZED BY THE COMPANY OR ANY UNDERWRITER. THIS PROSPECTUS DOES
NOT CONSTITUTE AN OFFER TO SELL OR A SOLICITATION OF AN OFFER TO BUY ANY OF THE
SECURITIES OFFERED HEREBY IN ANY JURISDICTION TO ANY PERSON TO WHICH IT IS
UNLAWFUL TO MAKE SUCH OFFER IN SUCH JURISDICTION. NEITHER THE DELIVERY OF THIS
PROSPECTUS NOR ANY SALE MADE HEREUNDER SHALL, UNDER ANY CIRCUMSTANCES, CREATE
ANY IMPLICATION THAT THE INFORMATION CONTAINED HEREIN IS CORRECT AS OF ANY TIME
SUBSEQUENT TO THE DATE HEREOF OR THAT THERE HAS BEEN NO CHANGE IN THE AFFAIRS OF
THE COMPANY SINCE SUCH DATE.
IN THIS PROSPECTUS, REFERENCES TO "DOLLARS" AND "$" ARE TO UNITED STATES
DOLLARS.
IN CONNECTION WITH THE COMMON STOCK OFFERING, CS FIRST BOSTON CORPORATION
ON BEHALF OF THE U.S. UNDERWRITERS AND MANAGERS MAY OVER-ALLOT OR EFFECT
TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICE OF THE COMMON STOCK AT
A LEVEL ABOVE THAT WHICH MIGHT OTHERWISE PREVAIL IN THE OPEN MARKET. SUCH
TRANSACTIONS MAY BE EFFECTED ON THE NEW YORK STOCK EXCHANGE OR OTHERWISE. SUCH
STABILIZING, IF COMMENCED, MAY BE DISCONTINUED AT ANY TIME.
DURING THE COMMON STOCK OFFERING, CERTAIN PERSONS AFFILIATED WITH PERSONS
PARTICIPATING IN THE DISTRIBUTION MAY ENGAGE IN TRANSACTIONS FOR THEIR OWN
ACCOUNTS OR FOR THE ACCOUNTS OF OTHERS IN THE COMMON STOCK PURSUANT TO
EXEMPTIONS FROM RULES 10B-6, 10B-7, AND 10B-8 UNDER THE SECURITIES EXCHANGE ACT
OF 1934.
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
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<S> <C>
Prospectus Summary........................ 3
Risk Factors.............................. 8
Use of Proceeds........................... 17
Dividend Policy........................... 17
Capitalization............................ 18
Dilution.................................. 19
Selected Consolidated Financial Data...... 20
Pro Forma Consolidated Financial Data..... 22
Management's Discussion and Analysis of
Financial Condition and Results of
Operations.............................. 29
Business.................................. 38
Management................................ 70
<CAPTION>
PAGE
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<S> <C>
Certain Transactions...................... 80
Principal and Selling Stockholders........ 82
Description of Capital Stock.............. 83
Shares Eligible for Future Sale........... 85
Certain United States Federal Tax
Consequences to Non-U.S. Holders........ 86
Subscription and Sale..................... 89
Notice to Canadian Residents.............. 92
Legal Matters............................. 92
Experts................................... 93
Available Information..................... 93
Consolidated Financial Statements......... F-1
</TABLE>
<PAGE> 203
PROSPECTUS SUMMARY
The following summary is qualified in its entirety by the more detailed
information and financial statements appearing elsewhere in this Prospectus.
This Prospectus contains forward-looking statements that involve risks and
uncertainties. The Company's actual results could differ materially from those
projected in such forward-looking statements as a result of certain factors,
including those set forth under "Risk Factors" and elsewhere in this Prospectus.
Unless the context indicates otherwise, (i) all references in this Prospectus to
the "Company" or "Calpine" include Calpine Corporation and its consolidated
subsidiaries, (ii) all references to "Common Stock" refer to the Company's
Common Stock, $.001 par value, (iii) all information in this Prospectus relating
to the Company's Common Stock assumes no exercise of the Underwriters'
over-allotment option, and (iv) all information in this Prospectus assumes the
following transactions are completed prior to or concurrent with the
consummation of the Common Stock Offering: (1) the reincorporation of the
Company in Delaware, (2) the conversion of the Company's outstanding Class B
Common Stock into Common Stock and the elimination of the Class A Common Stock
and Class B Common Stock, (3) a 5.194-for-1 stock split of the Company's Common
Stock, and (4) the conversion of the Company's outstanding Preferred Stock into
2,179,487 shares of Common Stock.
THE COMPANY
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
1,057 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 $41.2 million of total assets as of December 31,
1991 to $911.0 million of total assets on a pro forma basis as of June 30, 1996.
Calpine's revenue on a pro forma basis for 1995 increased to $224.3 million,
representing a compound annual growth rate of 55% since 1991. The Company's
EBITDA (as defined herein) on a pro forma basis for 1995 increased to $123.8
million. See "Pro Forma Consolidated 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 power generation facilities, as well
as marketing power and energy services to utilities and other end users.
THE MARKET
The power generation industry represents the third largest industry in the
United States, with an estimated end user market of approximately $207.5 billion
of electricity sales and 3 million gigawatt hours of production in 1995. In
response to increasing customer demand for access to low cost electricity and
enhanced services, new regulatory initiatives are currently being adopted or
considered at both state and federal levels to increase competition in the
domestic power generation industry. To date, such initiatives are under
consideration at the federal level and in approximately thirty states. For
example, in April 1996, the Federal Energy Regulatory Commission ("FERC")
adopted Order No. 888, opening wholesale power sales to competition and
providing for open and fair electric transmission services by public utilities.
In addition, the California Public Utilities Commission ("CPUC") has issued an
electric industry restructuring decision which envisions commencement of
deregulation and implementation of customer choice of electricity supplier by
January 1, 1998. Calpine believes that industry trends and such regulatory
initiatives will lead to the transformation of the existing market, which is
largely characterized by electric utility monopolies selling to a captive
customer base, to a more competitive market where end users may purchase
electricity from a variety of suppliers, including non-utility generators, power
marketers, public utilities and others. The Company believes that these market
trends will create substantial opportunities for companies such as Calpine that
are low cost power producers and have an integrated power services capability
which enables them to produce and sell energy to customers at competitive rates.
The Company also believes that these market trends will result in the
disposition of power generation facilities by utilities, independent power
producers and industrial companies. Utilities such as Pacific Gas & Electric
Company ("PG&E") and Southern California Edison Company have announced their
intentions to sell power generation facilities totalling approximately 3,150
megawatts and 5,000 megawatts, respectively. The independent power industry,
which represents approximately 8% of the installed capacity in the United
States, or approximately 59,000 megawatts, and has accounted for approximately
50% of all additional capacity in the United States since 1990, is currently
undergoing significant consolidation. Many independent producers operating a
limited number of power plants are seeking to dispose of such plants in response
to
3
<PAGE> 204
competitive pressures, and industrial companies are selling their power plants
to redeploy capital in their core businesses. Over 200 independent power plant
and portfolio sale transactions have occurred in the past two years. The Company
believes that this consolidation will continue in the highly fragmented
independent power industry.
The power generation industry outside the United States is approximately
three times larger than the domestic market, and the demand for electricity is
growing rapidly. In 1996, it has been estimated that in excess of 590 gigawatts
of new capacity will be required outside the United States over the ensuing
ten-year period. In order to satisfy this anticipated increase in demand, many
countries have adopted active government programs designed to encourage private
investment in power generation facilities. The Company believes that these
market trends will create significant opportunities to acquire and develop power
generation facilities in such countries.
STRATEGY
Calpine's objective is to become a leading power company by capitalizing on
these emerging opportunities in the domestic and international power markets.
The key elements of the Company's strategy are as follows:
Expand and diversify 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
since 1993.
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 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 completion of financing and
obtaining required approvals. See "Business -- 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 in excess 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
has established an integrated power marketing capability, conducted through its
wholly owned subsidiary, Calpine Power Services Company ("CPSC"). In 1995, CPSC
received approval from the 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
an investment in 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
4
<PAGE> 205
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.
BACKGROUND
Calpine was founded in 1984 by Peter Cartwright, the Company's President
and Chief Executive Officer. Through 1988, the Company provided engineering,
management, finance and operating and maintenance services to the emerging
independent power production industry. Since 1989, the Company has focused on
the acquisition, development, ownership, operation and maintenance of gas-fired
and geothermal power generation facilities. Prior to the Common Stock Offering,
the Company has been a wholly owned subsidiary of Electrowatt Ltd.
("Electrowatt"), a major utility, industrial products and engineering services
company based in Zurich, Switzerland. Electrowatt has advised the Company that
its current strategy is to focus its resources on its industrial business. As a
result of the Common Stock Offering, Electrowatt will no longer own any interest
in the Company and Calpine management will hold stock options representing
approximately 11.7% of the Company's Common Stock.
Calpine was incorporated under the laws of the State of California in 1984
and was reincorporated in the State of Delaware in September 1996. The principal
executive offices of the Company are located at 50 West San Fernando Street, San
Jose, California 95113, and its telephone number is (408) 995-5115.
RISK FACTORS
Prospective investors should carefully consider the information presented
in this Prospectus, particularly the matters set forth under the caption "Risk
Factors."
THE COMMON STOCK OFFERING
Of the Common Stock offered hereby, 14,436,000 shares are initially being
offered in the United States and Canada by the U.S. Underwriters in the U.S.
Offering and 3,609,000 shares are initially being concurrently offered outside
the United States and Canada by the Managers in the International Offering.
<TABLE>
<S> <C>
Total Common Stock offered................... 18,045,000 shares
By the Company
U.S. Offering........................... 4,382,256 shares
International Offering.................. 1,095,564 shares
Total.............................. 5,477,820 shares
By the Selling Stockholder
U.S. Offering........................... 10,053,744 shares
International Offering.................. 2,513,436 shares
Total.............................. 12,567,180 shares
Common Stock to be outstanding after
the Common Stock Offering.................. 18,045,000 shares(1)
Use of proceeds.............................. The net proceeds of the sale of shares of
Common Stock by the Company will be used for
repayment of approximately $13.0 million of
outstanding indebtedness and for working
capital and general corporate purposes,
including the development and acquisition
of power generation facilities. See "Use of
Proceeds."
NYSE trading symbol.......................... CPN
</TABLE>
- ---------------
(1) Excludes 2,392,026 shares of Common Stock reserved for issuance upon
exercise of options previously granted and outstanding as of June 30, 1996
under the Company's Stock Option Program. Of such amount, options to
purchase 1,366,696 shares were exercisable as of June 30, 1996. See
"Management -- Stock Option Program" and "-- 1996 Stock Incentive Plan."
5
<PAGE> 206
SUMMARY CONSOLIDATED FINANCIAL DATA
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, SIX MONTHS ENDED JUNE 30,
------------------------------------------------------------------------ --------------------------------------
1991 1992 1993 1994 1995 1995 1996
--------- --------- --------- --------- ------------------------ --------- -------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
PRO FORMA(1)
ACTUAL ------------ ACTUAL PRO FORMA(2)
--------- --------- -------------
(DOLLARS AND SHARES IN THOUSANDS, EXCEPT PER SHARE DATA)
STATEMENT OF
OPERATIONS
DATA:
Total
revenue.... $39,052 $39,577 $69,915 $94,762 $132,098 $224,261 $50,352 $81,994 $93,068
Cost of
revenue.... 25,064 25,921 42,501 52,845 77,388 142,298 30,618 51,319 65,940
Gross
profit..... 13,988 13,656 27,414 41,917 54,710 81,963 19,734 30,675 27,128
Project
development
expenses... 1,067 806 1,280 1,784 3,087 3,087 1,308 1,410 1,410
General and
administrative
expenses... 3,443 3,924 5,080 7,323 8,937 8,937 3,659 5,874 5,874
Income from
operations... 9,478 6,902 21,054 31,772 42,686 69,939 14,767 23,391 19,844
Interest
expense.... 1,925 1,225 13,825 23,886 32,154 57,523 15,116 18,665 27,900
Other income,
net........ (416) (310) (1,133) (1,988) (1,895) (9,158) (855) (2,777) (5,303)
Net income
(loss)..... 5,958 3,460 3,754 6,021 7,378 12,810 298 4,423 (1,623)
Weighted
average
shares
outstanding(3)... 14,151 14,151 14,400 14,400
Net income
(loss) per
share(3)... $0.52 $0.91 $0.31 $(0.11)
OTHER
FINANCIAL
DATA:
Depreciation
and
amortization... $ 219 $ 232 $12,540 $21,580 $ 26,896 $42,734 $ 9,882 $15,757 $21,302
EBITDA(4).... $ 4,909 $ 9,898 $42,370 $53,707 $ 69,515 $123,770 $25,440 $41,345 $46,993
SELECTED
OPERATING
INFORMATION:(5)
Power plants:
Electricity
revenue:(6)
Energy... $33,426 $38,325 $37,088 $45,912 $54,886 $89,292 $22,323 $34,362 $36,839
Capacity... $ 7,562 $ 7,707 $ 7,834 $ 7,967 $30,485 $83,591 $ 9,051 $19,774 $28,364
Megawatt
hours
produced... 392,471 403,274 378,035 447,177 1,033,566 2,387,730 324,059 736,739 860,969
Average
energy
price per
kilowatt
hour(7)... 8.517c 9.503c 9.811c 10.267c 5.310c 3.740c 6.889c 4.664c 4.279c
Steam fields:
Steam
revenue:
Calpine... $36,173 $33,385 $31,066 $32,631 $39,669 $39,669 $17,639 $15,866 $15,866
Other
interest... $ 2,820 $ 2,501 $ 2,143 $ 2,051 -- -- -- -- --
Megawatt
hours
produced... 2,095,576 2,105,345 2,014,758 2,156,492 2,415,059 2,415,059 1,027,317 1,040,271 1,040,271
Average
price per
kilowatt
hour..... 1.861c 1.705c 1.648c 1.608c 1.643c 1.643c 1.717c 1.525c 1.525c
</TABLE>
<TABLE>
<CAPTION>
AS OF JUNE 30, 1996
AS OF DECEMBER 31, -----------------------------------------
---------------------------------------------------------- PRO PRO FORMA AS
1991 1992 1993 1994 1995 ACTUAL FORMA(2) ADJUSTED(2)(8)
------- ------- -------- -------- -------- -------- --------- --------------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Cash and cash
equivalents........ $ 958 $ 2,160 $ 6,166 $ 22,527 $ 21,810 $ 38,403 $ 16,047 $ 98,307
Property, plant and
equipment, net..... 351 424 251,070 335,453 447,751 530,203 657,724 657,724
Total assets......... 41,245 55,370 302,256 421,372 554,531 792,812 910,977 993,237
Total liabilities.... 34,624 44,865 288,827 402,723 529,304 713,156 831,321 831,321
Stockholder's
equity............. 6,621 10,505 13,429 18,649 25,227 79,656 79,656 161,916
(see footnotes on next page)
</TABLE>
6
<PAGE> 207
- ------------
(1) The pro forma information presented under statement of operations data and
other financial data for the year ended December 31, 1995 gives effect to
the following transactions as if such transactions had occurred on January
1, 1995: (i) the acquisition by the Company of the Greenleaf 1 and 2
Facilities (the "Greenleaf Transaction"); (ii) the acquisition by the
Company of the lease for the Watsonville Facility (the "Watsonville
Transaction"); (iii) the entry by the Company into the agreements in
respect of the Cerro Prieto Steam Fields (the "Cerro Prieto Transaction");
(iv) the entry by the Company into a transaction involving a lease for the
King City Facility (the "King City Transaction"); (v) the acquisition by
the Company of the Gilroy Facility (the "Gilroy Transaction"); (the
Greenleaf Transaction, the Watsonville Transaction, the Cerro Prieto
Transaction, the King City Transaction and the Gilroy Transaction being
collectively referred to as the "Transactions"); (vi) the $50.0 million
Preferred Stock investment in Calpine by Electrowatt (the "Preferred Stock
Investment") and the application of the proceeds therefrom; and (vii) the
sale of the Company's 10 1/2% Senior Notes Due 2006 (the "10 1/2% Senior
Notes") and the application of the net proceeds therefrom. The pro forma
information presented under selected operating information for the year
ended December 31, 1995 gives effect to the Greenleaf Transaction, the
Watsonville Transaction, the King City Transaction and the Gilroy
Transaction as if such transactions had occurred on January 1, 1995. See
"Pro Forma Consolidated Financial Data," "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and
"Business -- Description of Facilities."
(2) The pro forma information presented under statement of operations data,
other financial data and selected operating information for the six months
ended June 30, 1996 gives effect to (i) the King City Transaction, (ii) the
Gilroy Transaction and (iii) the sale of the 10 1/2% Senior Notes and the
application of the net proceeds therefrom as if such transactions had
occurred on January 1, 1996. The pro forma information presented under
balance sheet data as of June 30, 1996 gives effect to the Gilroy
Transaction as if such transaction had occurred on June 30, 1996. See "Pro
Forma Consolidated Financial Data," "Management's Discussion and Analysis
of Financial Condition and Results of Operations" and
"Business -- Description of Facilities."
(3) The actual and pro forma weighted average shares outstanding and net income
(loss) per share for the year ended December 31, 1995 and the six months
ended June 30, 1996 give effect to the issuance of Common Stock upon the
conversion of the Company's outstanding Preferred Stock.
(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) For an explanation of such selected operating information, see
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Selected Operating Information."
(6) The significant increase in capacity revenue and the accompanying decline
in average energy price per kilowatt hour since 1994 reflects the increase
in the Company's megawatt hour production as a result of acquisitions of
gas-fired cogeneration facilities by the Company.
(7) Average energy price per kilowatt hour represents energy revenue divided by
the kilowatt hours produced.
(8) Adjusted to reflect the sale of the 5,477,820 shares of Common Stock
offered by the Company hereby.
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RISK FACTORS
Prospective purchasers of the Common Stock should carefully consider the
factors set forth below, as well as the other information contained in this
Prospectus, in evaluating an investment in the Common Stock.
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 June 30, 1996, the Company's total consolidated
indebtedness was $499.8 million, its total consolidated assets were $792.8
million and its stockholder's equity was $79.7 million. At such date, on a pro
forma basis after giving effect to the Gilroy Transaction, the Company's total
consolidated indebtedness would have been $615.8 million, its total consolidated
assets would have been $911.0 million and its stockholder's equity would have
been $79.7 million. See "Capitalization," "Pro Forma Consolidated Financial
Data" and "Management's Discussion and Analysis of Financial Condition and
Results of Operations." 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 May 16, 1996 (the "10 1/2% Indenture") relating to the
Company's 10 1/2% Senior Notes and the Indenture dated 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") contain certain
restrictive covenants. Such restrictions will affect, and in many respects will
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 certain change of control
transactions, to make an offer to purchase the 10 1/2% Senior Notes and the
9 1/4% Senior Notes. The Common Stock Offering will not constitute a change of
control transaction under the Indentures. There can be no assurance that the
Company will have the financial resources necessary to purchase the 10 1/2%
Senior Notes and the 9 1/4% Senior Notes upon a change of control. 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 10 1/2% Senior Notes and the
9 1/4% 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. See "-- Possible Unavailability of Financing,"
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and "Certain Transactions."
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
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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 has relied on Electrowatt, currently the
Company's sole stockholder, to provide funding for a substantial portion of its
facility equity commitments. The Company currently has an existing $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 Common Stock
Offering, Electrowatt will sell 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 will terminate.
On July 20, 1996, the Company entered into a Commitment Letter with The
Bank of Nova Scotia for a $50.0 million three-year revolving credit facility
(the "Bank of Nova Scotia Facility"). The Bank of Nova Scotia Facility will
become effective upon the completion of the Common Stock Offering, and will
contain certain restrictions that will 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. See "Management's Discussion and
Analysis of Result of Operations and Financial Condition -- Liquidity and
Capital Resources."
The Company's power generation facilities have been financed using a
variety of leveraged financing structures, consisting of corporate debt,
non-recourse debt and lease obligations. As of June 30, 1996, on a pro forma
basis after giving effect to the Gilroy Transaction, the Company would have had
approximately $615.8 million of total consolidated indebtedness, of which
approximately 53% would have represented non-recourse subsidiary debt. See "Pro
Forma Consolidated Financial Data." 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. See "Business -- Description of
Facilities."
The Company has from time to time guaranteed certain obligations of its
subsidiaries and other affiliates. There can be no assurance that, in respect of
any financings of facilities in the future, lenders or lessors will not require
the Company to guarantee the indebtedness of such future facilities, rendering
the Company's general corporate funds vulnerable in the event of a default by
such facility or related subsidiary. If the lenders or lessors were to require
such guarantees, and the Company were unable to incur indebtedness in respect of
such
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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 Facility, the Bear Canyon Facility, 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 Facilities. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- General" and
"Business -- Description of Facilities." 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 the Public Utility Regulatory Policies Act of 1978,
as amended ("PURPA")). The currently prevailing avoided cost of energy is
substantially lower than the fixed energy prices under these power sales
agreements and is generally expected
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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. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- General" and "Business -- Description of Facilities." 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. See
"Business -- Description of Facilities -- 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
1995, certain of the Company's power generation facilities experienced maximum
curtailment primarily as a result of a high degree of precipitation during the
period, which resulted in higher levels of energy generation by hydroelectric
power facilities that supply electricity. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations." 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 1996 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. See "Business -- Description of Facilities."
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
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favorable prices or, to the extent that any opportunities are identified, that
the Company will be able to consummate such acquisitions.
START-UP RISKS
The commencement of operation of a newly constructed power plant or steam
field involves many risks, including start-up problems, the breakdown or failure
of equipment or processes and performance below expected levels of output or
efficiency. New plants have no operating history and may employ recently
developed and technologically complex equipment. Insurance is maintained to
protect against certain of these risks, warranties are generally obtained for
limited periods relating to the construction of each project and its equipment
in varying degrees, and contractors and equipment suppliers are obligated to
meet certain performance levels. Such insurance, warranties or performance
guarantees may not be adequate to cover lost revenues or increased expenses and,
as a result, a project may be unable to fund principal and interest payments
under its financing obligations and may operate at a loss. A default under such
a financing obligation could result in the Company losing its interest in such
power generation facility or steam field. See "-- Possible Unavailability of
Financing."
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 in
which it has an interest, except for two steam fields. See
"Business -- Description of Facilities." 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 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. See "-- Possible Unavailability of
Financing."
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 1995, approximately 87% and 9% of
the Company's 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
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1995, 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.
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. The
Company believes that this strategy will enhance the earning potential of its
operating assets, generate additional revenue and expand its customer base.
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. See
"Business -- Government Regulation."
The Company's operations are subject to the provisions of various energy
laws and regulations, including PURPA, the Public Utility Holding Company Act of
1935, as amended ("PUHCA"), and state and local regulations. See
"Business -- Government Regulation." PUHCA provides for the extensive regulation
of public utility holding companies and their subsidiaries. PURPA provides to
qualifying facilities ("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
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another exemption. In order to be a QF, a facility must be not more than 50%
owned by an electric utility or electric utility holding company. A QF that is a
cogeneration facility must produce not only electricity, but also useful thermal
energy for use in an industrial or commercial process or heating or cooling
applications in certain proportions to the facility's total energy output, and
it must meet certain energy efficiency standards. Therefore, loss of a thermal
energy customer could jeopardize a cogeneration facility's QF status. All
geothermal power plants up to 80 megawatts that meet PURPA's ownership
requirements and certain other standards are considered QFs. If one of the power
plants in which the Company has an interest were to lose its QF status and not
otherwise receive a PUHCA exemption, the project subsidiary or partnership in
which the Company has an interest owning or leasing that plant could become a
public utility company, which could subject the Company to significant federal,
state and local laws, including rate regulation and regulation as a public
utility holding company under PUHCA. This loss of QF status, which may be
prospective or retroactive, in turn, could cause all of the Company's other
power plants to lose QF status because, under FERC regulations, a QF cannot be
owned by an electric utility or electric utility holding company. In addition, a
loss of QF status could, depending on the power sales agreement, allow the power
purchaser to cease taking and paying for electricity or to seek refunds of past
amounts paid and thus could cause the loss of some or all contract revenues or
otherwise impair the value of a project and could trigger defaults under
provisions of the applicable project contracts and financing agreements
(rendering such debt immediately due and payable). If a power purchaser ceased
taking and paying for electricity or sought to obtain refunds of past amounts
paid, there can be no assurance that the costs incurred in connection with the
project could be recovered through sales to other purchasers. See
"Business -- Government Regulation -- Federal Energy 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.
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
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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.
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 has launched an initiative designed to give all electric consumers the
ability to choose between competing suppliers of electricity. See
"Business -- Government Regulation -- State Regulation." 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. See "Business -- Competition."
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. See
"Management."
ANTI-TAKEOVER PROVISIONS
Certain provisions of Delaware law applicable to the Company could have the
effect of delaying, deterring or preventing a change in control of the Company,
including Section 203 of the Delaware General Corporation Law, which prohibits a
Delaware corporation from engaging in any business combination with any
interested stockholder for a period of three years from the date the person
became an interested stockholder unless certain conditions are met. In addition,
the Company's Certificate of Incorporation and By-laws contain certain
provisions that could discourage potential takeover attempts and make more
difficult attempts by stockholders to change management. The Company's Board of
Directors is classified into three classes of directors serving staggered,
three-year terms and has the authority without action by the Company's
stockholders to fix the rights and preferences and issue shares of Preferred
Stock, and to impose various procedural and other requirements that could make
it more difficult for stockholders to effect certain corporate actions. The
Company's Certificate of Incorporation provides that Directors may be removed
only by the affirmative vote of the holders of two-thirds of the shares of
capital stock of the Company entitled to vote. Any vacancy on the Board of
Directors may be filled only by vote of the majority of Directors then in
office. Further, the Company's Certificate of Incorporation provides that any
"Business Combination" (as therein defined) requires the affirmative vote of the
holders of two-thirds of the shares of capital stock of the Company entitled to
vote, voting together as a single class. These provisions, and certain other
provisions of the Certificate of Incorporation which may have the effect of
delaying proposed stockholder actions until the next annual meeting of
stockholders, could have the effect of delaying or preventing a tender offer for
the Company's Common Stock or other changes of control or management of the
Company, which could adversely affect the market price of the Company's Common
Stock. See "Description of Capital Stock."
NO PRIOR MARKET; STOCK PRICE VOLATILITY; DILUTION
Prior to the Common Stock Offering, there has been no public market for the
Company's Common Stock. Consequently, the initial public offering price was
determined by negotiations among the Company, the Selling Stockholder and the
Representatives of the Underwriters and may not be indicative of the prices that
prevail in the public market. There can be no assurance that an active public
market for the Common Stock will develop or be sustained after the Common Stock
Offering. The trading price of the Company's
15
<PAGE> 216
Common Stock could be subject to wide fluctuations in response to
quarter-to-quarter variations in operating results, announcements of new
acquisitions or power projects by the Company or its competitors, general
conditions in the independent power production industry, and other events or
factors. In addition, stock markets have experienced extreme price and trading
volume volatility in recent years. This volatility has had a substantial effect
on the market prices of securities of many companies for reasons frequently
unrelated to the operating performance of the specific companies. These broad
market fluctuations may adversely affect the market price of the Company's
Common Stock. Moreover, investors in the Common Stock Offering will incur
immediate, substantial book value dilution. See "Dilution" and "Subscription and
Sale."
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. The market price of the Common Stock could be subject to
significant fluctuations in response to those variations in quarterly operating
results and other factors. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Quarterly Results of Operations
and Seasonality."
SHARES ELIGIBLE FOR FUTURE SALE
Sales of substantial amounts of Common Stock in the public market after the
Common Stock Offering could adversely affect the prevailing market price of the
Common Stock. Other than the 18,045,000 shares of Common Stock offered hereby,
there will be no shares of Common Stock outstanding immediately following the
completion of the Common Stock Offering. All of the shares of Common Stock sold
in the Common Stock Offering will be freely transferable without registration or
further registration under the Securities Act of 1933, as amended (the
"Securities Act"), unless held by an "affiliate" of the Company (as defined in
the Securities Act). As of the date of this Prospectus, options to purchase
2,392,026 shares of Common Stock were outstanding under the Company's Stock
Option Program. Of such amount, options to purchase 1,366,696 shares were
exercisable, all of which will become eligible for sale 180 days after the date
of this Prospectus, upon expiration of certain lock-up agreements with the
Underwriters and pursuant to Rule 701, subject in some cases to certain volume
and other resale restrictions. See "Shares Eligible for Future Sale."
16
<PAGE> 217
USE OF PROCEEDS
The aggregate net proceeds to the Company from the sale of the 5,477,820
shares of Common Stock offered by the Company in the Common Stock Offering
(after deducting underwriting discounts and commissions and estimated offering
expenses) will be approximately $82.3 million ($123.1 million if the
Underwriters' over-allotment option is exercised in full). The Company expects
to use a portion of the net proceeds from the Common Stock Offering to repay the
outstanding balance on the Credit Suisse Credit Facility. The outstanding
balance is approximately $13.0 million as of the date of this Prospectus and
bears interest at 6.0% per annum. The remaining net proceeds are expected to be
used for working capital and general corporate purposes, and for the development
and acquisition of power generation facilities, including investments in the
Pasadena Cogeneration Project and the Indonesian Geothermal Project. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources" and "Business -- Development and
Future Projects." Pending such uses, the Company expects to invest the net
proceeds in short-term, interest-bearing securities.
DIVIDEND POLICY
The Company does not anticipate paying any cash dividends on its Common
Stock in the foreseeable future because it intends to retain its earnings to
finance the expansion of its business and for general corporate purposes. In
addition, the Company's ability to pay cash dividends is restricted under the
Indentures and will be restricted under the Bank of Nova Scotia Facility. Future
cash dividends, if any, will be at the discretion of the Company's Board of
Directors and will depend upon, among other things, the Company's future
operations and earnings, capital requirements, general financial condition,
contractual restrictions and such other factors as the Board of Directors may
deem relevant.
17
<PAGE> 218
CAPITALIZATION
The following table sets forth, as of June 30, 1996: (i) the actual
consolidated capitalization of the Company; (ii) the pro forma consolidated
capitalization of the Company after giving effect to the Gilroy Transaction and
the conversion of the Company's outstanding Preferred Stock into Common Stock in
connection with the Common Stock Offering; and (iii) the pro forma as adjusted
consolidated capitalization of the Company after giving effect to the sale of
the shares of Common Stock offered by the Company hereby and the application of
the estimated net proceeds therefrom (after deducting underwriting discounts and
commissions and estimated offering expenses). This table should be read in
conjunction with "Pro Forma Consolidated Financial Data" and the consolidated
financial statements and related notes thereto appearing elsewhere in this
Prospectus.
<TABLE>
<CAPTION>
AS OF JUNE 30, 1996
--------------------------------------------
PRO FORMA
ACTUAL PRO FORMA AS ADJUSTED
-------- ----------- -----------
(IN THOUSANDS)
<S> <C> <C> <C>
Short-term debt:
Current portion of non-recourse project
financing....................................... $ 27,178 $ 27,178 $ 27,178
======== ========= =========
Long-term debt:
Long-term line of credit........................... -- -- --
Non-recourse long-term project financing, less
current portion................................. $180,974 $ 296,974 $ 296,974
Notes payable...................................... 6,598 6,598 6,598
Senior notes....................................... 285,000 285,000 285,000
-------- ----------- -----------
Total long-term debt............................ 472,572 588,572 588,572
-------- ----------- -----------
Stockholder's equity:
Preferred Stock, $.001 par value: 5,000,000 shares
authorized and outstanding; pro forma and pro
forma as adjusted, 10,000,000 shares authorized,
no shares outstanding........................... 5 -- --
Common Stock, $.001 par value: 33,760,000 shares
authorized, 10,387,693 shares outstanding; pro
forma, 33,760,000 shares authorized, 12,567,180
shares outstanding; pro forma as adjusted,
100,000,000 shares authorized, 18,045,000 shares
outstanding(1).................................. 10 13 18
Additional paid-in capital......................... 56,209 56,211 138,466
Retained earnings.................................. 23,463 23,463 23,463
Cumulative translation adjustment.................. (31) (31) (31)
-------- ----------- -----------
Total stockholder's equity...................... 79,656 79,656 161,916
-------- ----------- -----------
Total capitalization.......................... $552,228 $ 668,228 $ 750,488
======== ========= =========
</TABLE>
- ------------
(1) Does not include 2,392,026 shares of Common Stock reserved for issuance upon
exercise of options previously granted and outstanding as of June 30, 1996
under the Company's Stock Option Program. See "Management -- Stock Option
Program" and "-- 1996 Stock Incentive Plan."
18
<PAGE> 219
DILUTION
The net tangible book value of the Company as of June 30, 1996 was $69.7
million, or $5.55 per share of Common Stock. Net tangible book value per share
is equal to the Company's total assets (excluding deferred financing and
offering expenses) less its total liabilities, divided by the total number of
outstanding shares of Common Stock. After giving effect to the sale of 5,477,820
shares of Common Stock offered by the Company hereby and the receipt and
application of the net proceeds therefrom, the pro forma net tangible book value
of the Company as of June 30, 1996 would have been approximately $152.0 million
or $8.42 per share. This represents an immediate dilution of $7.58 per share to
new stockholders purchasing shares in the Common Stock Offering. The following
table illustrates this per share dilution:
<TABLE>
<S> <C> <C>
Initial public offering price............................. $16.00
Net tangible book value before the Common Stock
Offering............................................. $5.55
Increase attributable to new stockholders............... 2.87
-----
Pro forma net tangible book value after the Common Stock
Offering................................................ 8.42
------
Total dilution to new stockholders........................ $ 7.58
======
</TABLE>
The calculations in the table set forth above assume no exercise of the
Underwriters' over-allotment option and do not reflect 2,392,026 shares of
Common Stock reserved for issuance pursuant to options granted and outstanding
as of June 30, 1996 under the Company's Stock Option Program. See
"Management -- Stock Option Program" and "-- 1996 Stock Incentive Plan."
19
<PAGE> 220
SELECTED CONSOLIDATED FINANCIAL DATA
The consolidated financial data set forth below for and as of the five
years ended December 31, 1995 have been derived from the audited consolidated
financial statements of the Company. The consolidated financial data for the six
months ended June 30, 1995 and June 30, 1996 and as of June 30, 1996 are
unaudited, but have been prepared on the same basis as the audited consolidated
financial statements and, in the opinion of management, contain all adjustments,
consisting only of normal recurring adjustments necessary for the fair
presentation of the financial position and results of operations for these
periods. Consolidated operating results for the six months ended June 30, 1996
are not necessarily indicative of the results that may be expected for the
entire year. 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 Prospectus, and "Management's Discussion and
Analysis of Financial Condition and Results of Operations."
<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
-------------------------------------------------------- -------------------
1991 1992 1993 1994 1995 1995 1996
------- ------- ------- ------- -------- ------- -------
<S> <C> <C> <C> <C> <C> <C> <C>
(DOLLARS AND SHARES IN THOUSANDS, EXCEPT PER SHARE DATA)
STATEMENT OF OPERATIONS DATA:
Revenue:
Electricity and steam sales............. -- -- $53,000 $90,295 $127,799 $49,014 $72,030
Service contract revenue................ $29,067 $29,817 16,896 7,221 7,153 3,129 5,434
Income (loss) from unconsolidated
investments in power projects......... 9,985 9,760 19 (2,754) (2,854) (1,791) 1,713
Interest income on loans to power
projects.............................. -- -- -- -- -- -- 2,817
-------- -------- -------- -------- -------- -------- --------
Total revenue......................... 39,052 39,577 69,915 94,762 132,098 50,352 81,994
Cost of revenue........................... 25,064 25,921 42,501 52,845 77,388 30,618 51,319
-------- -------- -------- -------- -------- -------- --------
Gross profit.............................. 13,988 13,656 27,414 41,917 54,710 19,734 30,675
Project development expenses.............. 1,067 806 1,280 1,784 3,087 1,308 1,410
General and administrative expenses....... 3,443 3,924 5,080 7,323 8,937 3,659 5,874
Compensation expense related to stock
options(1).............................. -- 1,224 -- -- -- -- --
Provision for write-off of project
development costs(2).................... -- 800 -- 1,038 -- -- --
-------- -------- -------- -------- -------- -------- --------
Income from operations.................... 9,478 6,902 21,054 31,772 42,686 14,767 23,391
Interest expense.......................... 1,925 1,225 13,825 23,886 32,154 15,116 18,665
Other income, net......................... (416) (310) (1,133) (1,988) (1,895) (855) (2,777)
-------- -------- -------- -------- -------- -------- --------
Income before provision for income
taxes, extraordinary item and
cumulative effect of change in
accounting
principle........................... 7,969 5,987 8,362 9,874 12,427 506 7,503
Provision for income taxes................ 3,149 2,527 4,195 3,853 5,049 208 3,080
-------- -------- -------- -------- -------- -------- --------
Income before extraordinary item and
cumulative effect of change in
accounting principle................ 4,820 3,460 4,167 6,021 7,378 298 4,423
Extraordinary item:
Utilization of net operating loss
carryforward.......................... 1,138 -- -- -- -- -- --
-------- -------- -------- -------- -------- -------- --------
Income before cumulative effect of
change in accounting principle...... 5,958 3,460 4,167 6,021 7,378 298 4,423
Cumulative effect of adoption of SFAS No.
109..................................... -- -- (413) -- -- -- --
-------- -------- -------- -------- -------- -------- --------
Net income........................ $ 5,958 $ 3,460 $ 3,754 $ 6,021 $ 7,378 $ 298 $ 4,423
======== ======== ======== ======== ======== ======== ========
Weighted average shares outstanding(3).... 14,151 14,400
======== ========
Net income per share(3)................... $ 0.52 $ 0.31
======== ========
OTHER FINANCIAL DATA:
Depreciation and amortization........... $ 219 $ 232 $12,540 $21,580 $ 26,896 $ 9,882 $15,757
EBITDA(4)............................... $ 4,909 $ 9,898 $42,370 $53,707 $ 69,515 $25,440 $41,345
</TABLE>
(See footnotes on next page)
20
<PAGE> 221
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
---------------------------------------------------------- AS OF JUNE 30,
1991 1992 1993 1994 1995 1996
------- ------- -------- -------- -------- --------------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Cash and cash equivalents.................. $ 958 $ 2,160 $ 6,166 $ 22,527 $ 21,810 $ 38,403
Property, plant and equipment, net......... 351 424 251,070 335,453 447,751 530,203
Total assets............................... 41,245 55,370 302,256 421,372 554,531 792,812
Total liabilities.......................... 34,624 44,865 288,827 402,723 529,304 713,156
Stockholder's equity....................... 6,621 10,505 13,429 18,649 25,227 79,656
</TABLE>
- ------------
(1) Represents a non-cash charge for compensation expense associated with the
grant of certain options under the Company's Stock Option Program. See
"Management -- 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, 1995 and the six months ended June 30, 1996 give effect
to the issuance of Common Stock upon the conversion of the Company's
outstanding Preferred Stock.
(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).
21
<PAGE> 222
PRO FORMA CONSOLIDATED FINANCIAL DATA
The following unaudited pro forma consolidated statement of operations for
the year ended December 31, 1995 gives effect to: (i) the Transactions; (ii) the
Preferred Stock Investment and the application of the proceeds therefrom; and
(iii) the sale of the 10 1/2% Senior Notes and the application of the net
proceeds therefrom as if such transactions had occurred on January 1, 1995. The
following unaudited pro forma consolidated statement of operations for the six
months ended June 30, 1996 gives effect to: (i) the King City Transaction; (ii)
the Gilroy Transaction; and (iii) the sale of the 10 1/2% Senior Notes and the
application of the net proceeds therefrom, as if such transactions had occurred
on January 1, 1996. For further discussion regarding the Transactions, see
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and "Business -- Description of Facilities." The following unaudited
pro forma consolidated balance sheet as of June 30, 1996 gives effect to the
Gilroy Transaction as if such transaction had occurred on June 30, 1996. The
following unaudited pro forma consolidated financial data does not give effect
to the Common Stock Offering or the application of the net proceeds therefrom.
The pro forma consolidated financial data and accompanying notes should be
read in conjunction with the consolidated financial statements and related notes
thereto appearing elsewhere in this Prospectus. The pro forma adjustments are
based upon available information and certain assumptions that management
believes are reasonable and are described in the notes accompanying the pro
forma consolidated financial data. The pro forma consolidated financial data are
presented for informational purposes only and do not purport to represent what
the Company's results of operations or financial position would actually have
been had such transactions in fact occurred at such dates, or to project the
Company's results of operations or financial position at any future date or for
any future period. In the opinion of management, all adjustments necessary to
present fairly such pro forma consolidated financial data have been made.
22
<PAGE> 223
PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1995
----------------------------------------------------------------------
PRO FORMA FOR THE
TRANSACTIONS, THE
PREFERRED STOCK
ADJUSTMENTS FOR THE ADJUSTMENTS INVESTMENT AND THE
TRANSACTIONS AND THE FOR THE SALE SALE OF THE
PREFERRED STOCK OF THE 10 1/2% 10 1/2% SENIOR
ACTUAL INVESTMENT(1) SENIOR NOTES NOTES
-------- -------------------- --------------- ------------------
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenue:
Electricity and steam sales............. $127,799 $ 89,349 -- $217,148
Service contract revenue................ 7,153 250 -- 7,403
Income (loss) from unconsolidated
investments in power projects......... (2,854) -- -- (2,854)
Interest income on loans to power
projects.............................. -- 2,564 -- 2,564
-------- -------- --------------- ----------
Total revenue......................... 132,098 92,163 -- 224,261
-------- -------- --------------- ----------
Cost of revenue:
Plant operating expenses................ 33,162 37,369 -- 70,531
Depreciation and amortization........... 26,264 15,838 -- 42,102
Operating lease expense................. 1,542 11,703 -- 13,245
Service contract expense................ 5,846 -- -- 5,846
Production royalties.................... 10,574 -- -- 10,574
-------- -------- --------------- ----------
Total cost of revenue................. 77,388 64,910 -- 142,298
-------- -------- --------------- ----------
Gross profit.............................. 54,710 27,253 -- 81,963
Project development expenses.............. 3,087 -- -- 3,087
General and administrative expenses....... 8,937 -- -- 8,937
-------- -------- --------------- ----------
Income from operations................ 42,686 27,253 -- 69,939
Interest expense.......................... 32,154 16,193 $ 9,176(2) 57,523
Other income, net......................... (1,895) (7,263) -- (9,158)
-------- -------- --------------- ----------
Income before provision for income
taxes................................. 12,427 18,323 (9,176) 21,574
Provision for income taxes................ 5,049 7,443 (3,728) 8,764
-------- -------- --------------- ----------
Net income.......................... $ 7,378 $ 10,880 $(5,448) $ 12,810
========= ================== ============== ==================
Net income per share................ $ 0.52 $ 0.91
========= ==================
OTHER FINANCIAL DATA:
Depreciation and amortization............. $ 26,896 $ 42,734
EBITDA.................................... $ 69,515 $123,770
</TABLE>
See Notes to Pro Forma Consolidated Statements of Operations
23
<PAGE> 224
PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30, 1996
-----------------------------------------------------------------------------------------
PRO FORMA FOR THE
KING CITY
ADJUSTMENTS TRANSACTION,
ADJUSTMENTS ADJUSTMENTS FOR THE THE GILROY
FOR THE FOR THE SALE OF THE TRANSACTION AND
KING CITY GILROY 10 1/2% THE SALE OF THE
ACTUAL TRANSACTION(3)(5) TRANSACTION(4)(5) SENIOR NOTES 10 1/2% SENIOR NOTES
------- ------------------- ----------------- ------------- ---------------------
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenue:
Electricity and steam
sales..................... $72,030 $ 1,583 $ 9,491 -- $83,104
Service contract revenue.... 5,434 -- -- -- 5,434
Income (loss) from
unconsolidated investments
in power projects......... 1,713 -- -- -- 1,713
Interest income on loans to
power
projects.................. 2,817 -- -- -- 2,817
------- ------- ------- -------- ------
Total revenue............. 81,994 1,583 9,491 -- 93,068
------- ------- ------- -------- ------
Cost of revenue:
Plant operating expenses.... 22,901 1,669 4,035 -- 28,605
Depreciation and
amortization.............. 15,413 2,800 2,745 -- 20,958
Operating lease expense..... 3,239 3,372 -- -- 6,611
Service contract expense.... 4,484 -- -- -- 4,484
Production royalties........ 5,282 -- -- -- 5,282
------- ------- ------- -------- ------
Total cost of revenue..... 51,319 7,841 6,780 -- 65,940
------- ------- ------- -------- ------
Gross profit.................. 30,675 (6,258) 2,711 -- 27,128
Project development
expenses.................... 1,410 -- -- -- 1,410
General and administrative
expenses.................... 5,874 -- -- -- 5,874
------- ------- ------- -------- ------
Income from operations.... 23,391 (6,258) 2,711 -- 19,844
Interest expense.............. 18,665 1,391 4,585 $ 3,259(6) 27,900
Other income, net............. (2,777) (2,526) -- -- (5,303)
------- ------- ------- -------- ------
Income (loss) before
provision for income
taxes................... 7,503 (5,123) (1,874) (3,259) (2,753)
Provision for (benefit from)
income taxes................ 3,080 (2,103) (769) (1,338) (1,130)
------- ------- ------- -------- ------
Net income (loss).... $ 4,423 $(3,020) $(1,105) $(1,921) $(1,623)
======= ======= ======= ======== ======
Net income (loss) per
share.............. $ 0.31 $ (0.11)
======= ======
OTHER FINANCIAL DATA:
Depreciation and
amortization................ $15,757 $21,302
EBITDA........................ $41,345 $46,993
</TABLE>
See Notes to Pro Forma Consolidated Statements of Operations
24
<PAGE> 225
NOTES TO PRO FORMA CONSOLIDATED STATEMENTS OF OPERATIONS
(1) Represents the pro forma results of operations for the facilities involved
in the Transactions for the periods during 1995 prior to the completion of
the Transactions, as if the Transactions had been completed on January 1,
1995, including: (i) the Greenleaf 1 and 2 Facilities for the period
through April 21, 1995; (ii) the Watsonville Facility for the period
through June 28, 1995; (iii) the Cerro Prieto Steam Fields for the period
through December 14, 1995; (iv) the King City Facility for the period
through December 31, 1995; and (v) the Gilroy Facility for the period
through December 31, 1995. The information provided for the Cerro Prieto
Steam Fields does not include the portion of service contract revenue which
is contingent on future results. The pro forma adjustments reflect the
historical results of operations of the facilities, as adjusted to give
effect to the changes resulting from purchase price allocations and other
transaction effects, as applicable. Such adjustments include depreciation
and amortization applicable to new asset bases, interest expense amounts
applicable to debt instruments outstanding, income tax amounts at the
estimated effective rate of approximately 41%, and other adjustments. The
following table sets forth adjustments to results of operations for such
periods:
<TABLE>
<CAPTION>
GREENLEAF
1 AND 2 WATSONVILLE CERRO PRIETO KING CITY GILROY
FACILITIES FACILITY STEAM FIELDS FACILITY FACILITY TOTAL
--------- ----------- ------------ --------- -------- -------
<S> <C> <C> <C> <C> <C> <C>
(IN THOUSANDS)
STATEMENT OF OPERATIONS DATA:
Revenue:
Electricity and steam sales.................. $ 5,314 $ 3,978 -- $43,836 $ 36,221 $89,349
Service contract revenue..................... -- -- $ 250 -- -- 250
Income (loss) from unconsolidated investments
in power projects.......................... -- -- -- -- -- --
Interest income on loans to power projects... -- -- 2,564 -- -- 2,564
------- ------ ------ ------- -------
Total revenue.............................. 5,314 3,978 2,814 43,836 36,221 92,163
------- ------ ------ ------- -------
Cost of revenue:
Plant operating expenses..................... 5,954 2,857 -- 14,743 13,815 37,369
Depreciation and amortization................ 1,802 147 -- 8,399 5,490 15,838
Operating lease expense...................... -- 1,586 -- 10,117 -- 11,703
Service contract expense..................... -- -- -- -- -- --
Production royalties......................... -- -- -- -- -- --
------- ------ ------ ------- -------
Total cost of revenue...................... 7,756 4,590 -- 33,259 19,305 64,910
------- ------ ------ ------- -------
Gross profit................................... (2,442) (612) 2,814 10,577 16,916 27,253
Project development expenses................... -- -- -- -- -- --
General and administrative expenses............ -- -- -- -- -- --
------- ------ ------ ------- -------
Income from operations..................... (2,442) (612) 2,814 10,577 16,916 27,253
Interest expense............................... 1,921 -- 932 4,172 9,168 16,193
Other income, net.............................. (105) -- -- (7,158) -- (7,263)
------- ------ ------ ------- -------
Income before provision for income taxes... (4,258) (612) 1,882 13,563 7,748 18,323
Provision (benefit) for income taxes........... (1,730) (249) 765 5,509 3,148 7,443
------- ------ ------ ------- -------
Net income............................. $(2,528) $ (363) $1,117 $ 8,054 $ 4,600 $10,880
======= ====== ====== ======= =======
</TABLE>
The adjustments reflected in the table set forth above for the Greenleaf 1
and 2 Facilities and the Watsonville Facility are not necessarily
indicative of a full year's results. See "Risk Factors -- Quarterly
Fluctuations; Seasonality." Other income, net for the King City Facility
reflects interest income from amounts contractually invested pursuant to
collateral fund requirements. See "Business -- Description of
Facilities -- Power Generation Facilities -- King City Facility."
(2) Reflects $18.9 million of interest expense related to the 10 1/2% Senior
Notes and $540,000 of amortization expense for the costs associated with the
sale of the 10 1/2% Senior Notes, reduced by $4.4 million of actual
25
<PAGE> 226
interest expense in 1995 as a result of the repayment of the $57 million
loan from The Bank of Nova Scotia to Calpine Thermal Company, a wholly-owned
subsidiary of the Company (the "$57 Million Bank of Nova Scotia Loan"), $3.4
million of interest expense as a result of the repayment of the $45 million
loan from The Bank of Nova Scotia to the Company (the "$45 Million Bank of
Nova Scotia Loan") (assuming an interest rate of 7.5%) and $2.4 million of
interest expense as a result of the repayment of all amounts outstanding
under the Credit Suisse Credit Facility. The $2.4 million represents
$704,000 of actual interest expense in 1995 and $1.7 million of assumed
interest expense to fund the King City and Cerro Prieto Transactions
(assuming an interest rate of 6.0%).
(3) Represents the pro forma results of operations for the King City Facility
for the period of January 1 through April 30, 1996. Other income, net for
the King City Facility reflects interest income from amounts contractually
invested pursuant to collateral fund requirements. See
"Business -- Description of Facilities -- Power Generation
Facilities -- King City Facility."
(4) Represents the pro forma results of operations for the Gilroy Facility for
the period of January 1 through June 30, 1996.
(5) Results for the six months ended June 30, 1996 reflected in the Pro Forma
Consolidated Statement of Operations are not necessarily indicative of a
full year's results. See "Risk Factors -- Quarterly Fluctuations;
Seasonality."
(6) Reflects $7.0 million of interest expense related to the 10 1/2% Senior
Notes and $201,000 of amortization expense for the costs associated with the
sale of the 10 1/2% Senior Notes, reduced by $1.9 million of actual interest
expense as a result of the repayment of the $57 Million Bank of Nova Scotia
Loan, $1.1 million of interest expense as a result of the repayment of the
$45 Million Bank of Nova Scotia Loan (assuming an interest rate of 7.5%) and
$973,000 of interest expense as a result of the repayment of all amounts
outstanding under the Credit Suisse Credit Facility. The $973,000 represents
$707,000 of actual interest expense and $266,000 of assumed interest expense
to fund a portion of the King City Transaction (assuming an interest rate of
6.0%).
26
<PAGE> 227
PRO FORMA CONSOLIDATED BALANCE SHEET
<TABLE>
<CAPTION>
AS OF JUNE 30, 1996
-------------------------------------------
ADJUSTMENTS PRO FORMA
FOR THE FOR THE
GILROY GILROY
ACTUAL TRANSACTION TRANSACTION
-------- ------------ -----------------
(IN THOUSANDS)
<S> <C> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents.................................. $ 38,403 $(22,356)(1) $ 16,047
Accounts receivable........................................ 43,227 9,000(2) 52,227
Collateral securities, current portion..................... 9,745 -- 9,745
Other current assets....................................... 13,369 -- 13,369
-------- ------------ -----------------
Total current assets..................................... 104,744 (13,356) 91,388
Property, plant and equipment, net........................... 530,203 127,521(3) 657,724
Investments in power projects................................ 12,693 -- 12,693
Notes receivable............................................. 37,386 -- 37,386
Collateral securities, net of current portion................ 88,669 -- 88,669
Other assets................................................. 19,117 4,000(4) 23,117
-------- ------------ -----------------
Total assets............................................. $792,812 $118,165 $ 910,977
========= ============= ==================
LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities:
Current portion of non-recourse project financing.......... $ 27,178 $ -- $ 27,178
Other current liabilities.................................. 25,680 2,165(5) 27,845
-------- ------------ -----------------
Total current liabilities................................ 52,858 2,165 55,023
Long-term credit facility.................................... -- -- --
Non-recourse long-term project financing, less current
portion.................................................... 180,974 116,000(6) 296,974
Notes payable................................................ 6,598 -- 6,598
Senior Notes Due 2004........................................ 105,000 -- 105,000
Senior Notes Due 2006........................................ 180,000 -- 180,000
Deferred lease incentive..................................... 81,495 -- 81,495
Deferred income taxes, net................................... 100,068 -- 100,068
Other liabilities............................................ 6,163 -- 6,163
-------- ------------ -----------------
Total liabilities........................................ 713,156 118,165 831,321
-------- ------------ -----------------
Stockholder's equity:
Preferred stock............................................ 50,000 -- 50,000
Common stock............................................... 6,224 -- 6,224
Retained earnings.......................................... 23,463 -- 23,463
Cumulative translation adjustment.......................... (31) -- (31)
-------- ------------ -----------------
Total stockholder's equity............................... 79,656 -- 79,656
-------- ------------ -----------------
Total liabilities and stockholder's equity............... $792,812 $118,165 $ 910,977
========= ============= ==================
</TABLE>
See Notes to Pro Forma Consolidated Balance Sheet
27
<PAGE> 228
NOTES TO PRO FORMA CONSOLIDATED BALANCE SHEET
(1) Represents the cash required to finance, in part, the Gilroy Transaction.
(2) Represents the accounts receivable in the Gilroy Transaction.
(3) Represents the property, plant and equipment acquired in the Gilroy
Transaction.
(4) Represents debt reserve amount.
(5) Represents the accounts payable and accrued liabilities in the Gilroy
Transaction.
(6) Project financing required to finance, in part, the Gilroy Transaction.
28
<PAGE> 229
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion should be read in conjunction with, and is
qualified in its entirety by reference to, the consolidated financial statements
of the Company, including the notes thereto, appearing elsewhere in this
Prospectus.
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
1,057 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 $41.2 million of total assets as of December 31,
1991 to $911.0 million of total assets on a pro forma basis as of June 30, 1996.
Calpine's revenue on a pro forma basis for 1995 increased to $224.3 million,
representing a compound annual growth rate of 55% since 1991. The Company's
EBITDA on a pro forma basis for 1995 increased to $123.8 million. See "Pro Forma
Consolidated Financial Data."
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 Facilities, 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 Facility, 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
transaction involving a lease for the 120 megawatt King City Facility, which
required an investment of $108.3 million, primarily related to the collateral
fund requirements. On August 29, 1996, the Company acquired the 120 megawatt
Gilroy 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. See "Business -- Description of Facilities."
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 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.
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
1995, 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 1996 under its power sales agreements
for certain of its facilities. See "Business -- Description of 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. As part of its policy decision, the
CPUC indicated that power sales
29
<PAGE> 230
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. 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
affected, although there can be no assurance in this regard.
Electricity and steam sales represents the sale of electricity and
geothermal steam from the Company's majority-owned facilities to utilities under
the terms and conditions of long-term power and steam sales agreements. Revenue
attributable to the West Ford Flat Facility, the Bear Canyon Facility, the
Greenleaf 1 and 2 Facilities, the Watsonville Facility, the King City Facility,
the Gilroy Facility, the PG&E Unit 13 and Unit 16 Steam Fields, the Thermal
Power Company Steam Fields and the SMUDGEO #1 Steam Fields is included in
electricity and steam sales. See "Business -- Description of Facilities."
Service contract revenue consists of revenue earned on services performed
under operating and maintenance agreements for projects that are not
consolidated in the Company's consolidated financial statements. The Company
recognizes revenue on these agreements at the time services are performed.
Income from unconsolidated investments in power projects represents the
Company's share of income from projects that are not consolidated in the
Company's consolidated financial statements and, accordingly, are accounted for
under the equity method of accounting. The Company's share of income from such
projects is calculated according to the Company's equity ownership or in
accordance with the terms of the appropriate partnership agreement. The
Company's current investments which are accounted for under the equity method
consist of the Aidlin Facility, the Agnews Facility and the Sumas Facility.
Depreciation and amortization expense for natural gas-fired cogeneration
facilities is computed using a straight-line method over the estimated remaining
useful life. Depreciation and amortization expense also reflects the
amortization of the Company's geothermal power generation facilities and steam
fields using the units of production method of depreciation. The Company
capitalizes all capital costs related to the operating power plants and steam
fields, as well as the cost of drilling wells and estimated future development
and de-commissioning costs. These capital costs are then amortized using the
units of production method based on current production over the estimated useful
life of the geothermal resource. 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 and amortization
expense.
Capitalized project costs are costs related to the development or
acquisition of new projects which are capitalized upon the execution of a
memorandum of understanding or a power sales agreement. Upon the start-up of
plant operations or the completion of an acquisition, such costs are generally
transferred to property, plant and equipment and amortized over the estimated
useful life of the project. As of June 30, 1996, the Company had deferred $2.8
million of development costs associated with projects currently in the
development stage.
General and administrative expenses include administrative, accounting,
finance, legal, human resources, insurance and other expenses incurred in
connection with the Company's operations. In addition, general and
administrative expenses also include the expenses associated with management of
the Company's operating and maintenance agreements and the expenses incurred in
the management of the Company's project investments.
Provision for income taxes includes income taxes calculated at the
effective rate for each applicable period reflecting statutory rates and as
adjusted for percentage depletion in excess of basis and other items.
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 Facility, the Bear Canyon
Facility, the
30
<PAGE> 231
Greenleaf 1 and 2 Facilities and the Watsonville Facility since their
acquisitions on April 21, 1995 and June 29, 1995, respectively, and the King
City Facility subsequent to 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 and 1995, 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 Facility,
Bear Canyon Facility, 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. See "-- General."
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, SIX MONTHS ENDED JUNE 30,
------------------------------------------------------------------- ----------------------------------
1991 1992 1993 1994 1995
------- ------- ------- ------- -------
1995 1996
----------------------- -----------------------
PRO FORMA(1) PRO FORMA(2)
ACTUAL ------------ ACTUAL ------------
------- -------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
POWER PLANTS:
Electricity
revenue:
Energy........... $33,426 $38,325 $37,088 $45,912 $54,886 $ 89,292 $22,323 $34,362 $36,839
Capacity(3)...... $ 7,562 $ 7,707 $ 7,834 $ 7,967 $30,485 $ 83,591 $ 9,051 $19,774 $28,364
Megawatt hours
produced......... 392,471 403,274 378,035 447,177 1,033,566 2,387,730 324,059 736,759 860,969
Average energy
price per
kilowatt
hour(3).......... 8.517c 9.503c 9.811c 10.267c 5.310c 3.740c 6.889c 4.664c 4.279c
STEAM FIELDS:
Steam revenue:
Calpine.......... $36,173 $33,385 $31,066 $32,631 $39,669 $ 39,669 $17,639 $15,866 $15,866
Other interest... $ 2,820 $ 2,501 $ 2,143 $ 2,051 -- -- -- -- --
Megawatt hours
produced......... 2,095,576 2,105,345 2,014,758 2,156,492 2,415,059 2,415,059 1,027,317 1,040,271 1,040,271
Average price per
kilowatt hour.... 1.861c 1.705c 1.648c 1.608c 1.643c 1.643c 1.717c 1.525c 1.525c
</TABLE>
- ------------
(1) Pro forma results for the year ended December 31, 1995 give effect to the
Greenleaf Transaction, the Watsonville Transaction, the King City
Transaction and the Gilroy Transaction as if such transactions had occurred
on January 1, 1995.
(2) Pro forma results for the six months ended June 30, 1996 give effect to the
King City Transaction and the Gilroy Transaction as if such transactions had
occurred on January 1, 1996.
(3) Represents 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
SIX MONTHS ENDED JUNE 30, 1996 COMPARED TO SIX MONTHS ENDED JUNE 30, 1995
Revenue. Revenue increased 63% to $82.0 million for the six months ended
June 30, 1996 compared to $50.4 million for the comparable period in 1995.
Electricity and steam sales revenue increased 47% to $72.0 million for the six
months ended June 30, 1996, compared to $49.0 million for the comparable period
in 1995. The increase in electricity and steam sales revenue was primarily
attributable to $11.0 million of revenue from the King City Facility, an
increase in revenue of $6.0 million from the Greenleaf 1 and 2 Facilities, and
$3.9 million of revenue from the Watsonville Facility. The remaining increase in
electricity and steam sales revenue of $2.1 million is primarily a result of
higher generation and higher prices at other Company power generation facilities
and steam fields. Service contract revenue from related parties increased 48% to
$4.6 million for the six months ended June 30, 1996 compared to $3.1 million for
the same period in 1995, primarily as a result of service revenue earned in
connection with overhauls at the Aidlin Facility and the Agnews Facility. Income
from unconsolidated investments in power projects increased to $1.7 million for
the six months ended June 30, 1996 compared to a loss of $1.8 million for the
comparable period in 1995, primarily as a result of $1.9 million of equity
income from the Company's investment in the Sumas Facility. This increase is
primarily
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<PAGE> 232
attributable to a contractual increase in the energy price under the power sales
agreement. Interest income on loans to power projects increased to $2.8 million
for the six months ended June 30, 1996 as a result of $1.9 million attributable
to the recognition of interest income on loans to the sole shareholder of the
general partner in the Sumas Facility, and interest income of $962,000 on loans
to Coperlasa related to the Cerro Prieto Steam Fields.
Cost of revenue. Cost of revenue increased 68% to $51.3 million for the
six months ended June 30, 1996 compared to $30.6 million for the comparable
period in 1995. The increase was primarily due to plant operating, depreciation
and operating lease expenses attributable to (i) a full six months of operations
during 1996 at the Greenleaf 1 and 2 Facilities, which were purchased on April
21, 1995, (ii) a full six months of operations during 1996 at the Watsonville
Facility which was acquired on June 29, 1995, and (iii) operations at the King
City Facility subsequent to May 2, 1996. The increase in cost of revenue was
also due to the increase in service contract expenses as a result of expenses
related to the Cerro Prieto Steam Fields, partially offset by lower operating
and depreciation expenses at the Company's other existing power generation
facilities and steam fields.
General and administrative expenses. General and administrative expenses
increased 60% to $5.9 million for the six months ended June 30, 1996 compared to
$3.7 million for the comparable period in 1995. The increase was primarily due
to additional personnel and related expenses necessary to support the Company's
expanding operations.
Interest expense. Interest expense increased 24% to $18.7 million for the
six months ended June 30, 1996 compared to $15.1 million for the comparable
period in 1995. The increase was primarily attributable to $2.4 million of
interest on the Company's 10 1/2% Senior Notes issued in May 1996 and $1.7
million of interest expense related to the Greenleaf 1 and 2 Facilities acquired
in April 1995, offset in part by a $1.5 million decrease in interest expense as
a result of repayments of principal on certain indebtedness.
Other income, net. Other income, net increased to $2.8 million for the six
months ended June 30, 1996 compared to $855,000 for the comparable period in
1995. The increase was primarily due to $1.5 million of interest income on
collateral securities purchased in connection with the King City Transaction and
to an increase in interest income from the investment of the proceeds of the
Preferred Stock Investment and a portion of the proceeds from the sale of the
10 1/2% Senior Notes.
Provision for income taxes. The effective rate for the income tax
provision was approximately 41% for the six months ended June 30, 1996. The
effective rate was based on statutory tax rates.
YEAR ENDED DECEMBER 31, 1995 COMPARED TO YEAR ENDED DECEMBER 31, 1994
Revenue. 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 Facilities, $5.9 million of revenue from the Watsonville Facility, 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 Facilities 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
Facilities 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.
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 were previously calculated considering a future period
32
<PAGE> 233
when steam would be delivered without receiving corresponding revenue. See Note
2 of the notes to consolidated financial statements appearing elsewhere in this
Prospectus. 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 Facilities
subsequent to April 21, 1995, and (iii) operations at the Watsonville Facility
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 Facilities 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 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.
YEAR ENDED DECEMBER 31, 1994 COMPARED TO YEAR ENDED DECEMBER 31, 1993
Revenue. Revenue increased 36% to $94.8 million in 1994 from $69.9 million
in 1993, primarily due to a 70% increase in electricity and steam sales to $90.3
million in 1994 compared to $53.0 million in 1993. Such increases were primarily
attributable to the $5.8 million of revenue from the Thermal Power Company Steam
Fields, the $5.1 million and $3.0 million of additional revenue from the West
Ford Flat and the Bear Canyon Facilities, respectively, as a result of the
acquisition of the additional interests in such facilities in 1994, the effects
of curtailment at such facilities in 1993 as a result of higher precipitation in
1993 and the sale of $804,000 of electricity to the Northern California Power
Agency. These revenue increases were partially offset by a decrease of $3.5
million in electricity and steam sales from the SMUDGEO #1 Steam Fields as a
result of a four-month shut-down for major maintenance.
In May 1994, the Company recognized approximately $5.9 million of its
previously deferred revenue. The revenue was previously deferred when it was
expected that steam would have been delivered without receiving corresponding
revenue. Based on current estimates and analyses performed by the Company, the
Company no longer expects that it will be required to make these deliveries to
SMUD. This resulted in a $4.0 million increase in revenue during 1994, while the
remaining $1.9 million was treated as a purchase price reduction to property,
plant and equipment. Concurrently, $800,000 of the revenue increase was reserved
for future
33
<PAGE> 234
construction of gathering systems required for future production of the steam
fields, with the offset recorded in property, plant and equipment.
Service contract revenue decreased 57% to $7.2 million in 1994 compared to
$16.9 million in 1993, primarily reflecting the elimination of intercompany
revenue for services provided to the power generation facilities and steam
fields owned by CGC after the acquisition of the remaining interest in CGC in
April 1993. In addition, the decline reflected the higher revenue recognized in
1993 on services associated with the Aidlin Facility overhaul, maintenance at
the Agnews Facility, the start-up of the Sumas Facility and the completion of
the Sumas construction management project.
Unconsolidated investments in power projects contributed a loss of $2.8
million in 1994 compared to income of $19,000 in 1993. The decrease is partially
attributable to a full year of operating loss at the Sumas Facility of $2.9
million in 1994, as compared to approximately eight months of operating loss of
$1.9 million in 1993. The 1994 Sumas Facility operating loss is attributable to
higher interest, depreciation and general and administrative expenses. The
decrease from 1993 income from unconsolidated investments in power projects is
also attributable to $2.0 million of equity income from CGC recognized prior to
the April 1993 acquisition under the equity method of accounting.
Cost of revenue. Cost of revenue increased 24% to $52.8 million in 1994
from $42.5 million in 1993. The increase was attributable to higher plant
operating, production royalty and depreciation expenses due to a full year of
operations at CGC during 1994, and to additional expenses of Thermal Power
Company as a result of its acquisition by the Company on September 9, 1994.
Service contract expenses decreased by $8.8 million primarily due to the
elimination of $6.2 million of operation expenses incurred at CGC after the
acquisition of the remaining interest in April 1993, as well as higher 1993
costs incurred in connection with the Aidlin Facility overhaul and higher
maintenance expenses at the Agnews Facility.
Project development expenses. Project development expenses increased to
$1.8 million in 1994 from $1.3 million in 1993 due to increased expenses
attributable to new project development activities.
General and administrative expenses. General and administrative expenses
increased 43% to $7.3 million in 1994 from $5.1 million in 1993 due to
additional personnel and related expenses necessary to support the Company's
expanded operations.
Provision for write-off of project development expenses. The Company
established in 1994 a $1.0 million reserve for capitalized project costs
associated with the development of projects which the Company has determined may
not be consummated.
Interest expense. Interest expense increased to $23.9 million in 1994 from
$13.8 million in 1993. The Company incurred $8.5 million of interest expense
related to the 9 1/4% Senior Notes issued in February 1994. A portion of the
proceeds of the 9 1/4% Senior Notes was used to repay all of the $52.6 million
then outstanding under the Credit Suisse Credit Facility, and to repay the
non-recourse notes payable to Freeport-McMoran Resource Partners, L.P. ("FMRP")
plus accrued interest. Interest expense also increased approximately $1.0
million due to a full year of interest expense at higher interest rates related
to CGC debt. Additionally, interest expense of $1.3 million was incurred on the
new debt related to the Company's acquisition of Thermal Power Company in
September 1994.
Provision for income taxes. The effective rate for the income tax
provision was 39% in 1994 compared to 50% for 1993. The 1994 effective rate
reflects a reduction for a depletion in excess of tax basis benefit at Thermal
Power Company and CGC. The effective rate for 1993 reflects a provision of
$700,000 due to a change in the California state income tax regulations to
disallow 50% of net operating loss carryforwards.
QUARTERLY RESULTS OF OPERATIONS AND 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. The market price of the Common Stock
34
<PAGE> 235
could be subject to significant fluctuations in response to those variations in
quarterly operating results and other factors.
LIQUIDITY AND CAPITAL RESOURCES
To date, the Company has obtained cash from its operations, borrowings
under the Credit Suisse Credit Facility and other working capital lines, equity
contributions from Electrowatt and proceeds from non-recourse project financings
and other long-term debt. The Company utilized this cash to fund its operations,
service debt obligations, fund the acquisition, development and construction of
power generation facilities, finance capital expenditures and meet its other
cash and liquidity needs.
The following table summarizes the Company's cash flow activities for the
periods indicated:
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE
YEAR ENDED DECEMBER 31, 30,
---------------------------------- ----------------------
1993 1994 1995 1995 1996
-------- -------- -------- -------- ---------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Cash flows from:
Operating activities........... $ 24,310 $ 34,196 $ 26,653 $ 5,126 $ 5,035
Investing activities........... (27,082) (84,444) (38,497) (23,874) (126,051)
Financing activities........... 6,778 66,609 11,127 3,742 137,609
-------- -------- -------- -------- ---------
Total....................... $ 4,006 $ 16,361 $ (717) $(15,006) $ 16,593
======== ======== ======== ======== =========
</TABLE>
Operating activities for 1995 consisted of approximately $7.4 million of
net income from operations, $25.9 million of depreciation and amortization and a
$2.9 million loss from unconsolidated investments in power projects, offset by
an $8.5 million net increase in operating assets and liabilities. Operating
activities for the six months ended June 30, 1996 consisted of approximately
$4.4 million of net income from operations, $15.0 million of depreciation and
amortization and $1.7 million in deferred income taxes, offset by $1.7 million
of income from unconsolidated investments in power projects and a $14.4 million
net increase in operating assets and liabilities.
Investing activities used $38.5 million during 1995, primarily due to $17.4
million of capital expenditures, $14.8 million for the acquisition of the
Greenleaf 1 and 2 Facilities and a $6.3 million investment in notes receivable.
Investing activities used $126.1 million during the six months ended June 30,
1996, primarily due to $11.0 million of capital expenditures and capitalized
project costs, $98.4 million for the purchase of collateral securities, a $12.1
million investment in Coperlasa and $4.9 million for deferred transaction costs
in connection with the King City Transaction, offset by a $1.1 million decrease
in restricted cash requirements.
Financing activities provided $11.1 million of cash during 1995. Borrowings
in 1995 included $76.0 million of non-recourse project financing and $37.5
million from the Company's lines of credit. Proceeds were primarily used to
repay $60.4 million of project debt assumed in the acquisition of the Greenleaf
1 and 2 Facilities, and $15.0 million borrowed from the lines of credit for the
acquisition of the Greenleaf 1 and 2 Facilities. In addition, $19.0 million was
used to reduce the balance outstanding under non-recourse project financing, and
$6.0 million was used to repay short-term borrowings. Financing activities
provided $137.6 million of cash during the six months ended June 30, 1996. The
Company issued $50.0 million of Preferred Stock to Electrowatt, incurred the $45
Million Bank of Nova Scotia Loan and borrowed an additional $33.8 million under
the Credit Suisse Credit Facility and received net proceeds of $175.2 million
from the 10 1/2% Senior Notes during the six months ended June 30, 1996. In
addition, the Company repaid $46.2 million of bank debt and all of the $53.7
million of borrowings outstanding under the Credit Suisse Credit Facility and
$66.6 million of non-recourse project financing.
In 1995, working capital decreased $50.5 million and cash and cash
equivalents decreased $717,000. The decrease in working capital is primarily due
to the reclassification of the $57 Million Bank of Nova Scotia Loan from
long-term to current. On May 16, 1996, the Company issued the 10 1/2% Senior
Notes, a portion of the net proceeds of which was used to refinance current
indebtedness and to repay the $57 Million Bank of
35
<PAGE> 236
Nova Scotia Loan. As of June 30, 1996, cash and cash equivalents were $38.4
million and working capital was $51.9 million. For the six months ended June 30,
1996, working capital increased $100.9 million and cash and cash equivalents
increased $16.6 million as compared to the twelve months ended December 31,
1995. Working capital at December 31, 1995 included the $57 Million Bank of Nova
Scotia Loan. A portion of the net proceeds from the issuance of the 10 1/2%
Senior Notes was used to refinance current bank debt and borrowings under the
Credit Suisse Credit Facility and to repay the $57 Million Bank of Nova Scotia
Loan. Working capital also increased as a result of the investment of the
balance of the proceeds from the issuance of the 10 1/2% Senior Notes in
short-term marketable securities. The increase in working capital was also due
to the proceeds from the issuance of $50.0 million of preferred stock which were
invested until May 1, 1996 for the King City Transaction.
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.
At June 30, 1996, the Company had $208.2 million of non-recourse project
financing associated with power generating facilities and steam fields at the
West Ford Flat Facility, the Bear Canyon Facility, the PG&E Unit 13 and Unit 16
Steam Fields, the SMUDGEO #1 Steam Fields and the Greenleaf 1 and 2 Facilities.
As of June 30, 1996, the annual maturities for all non-recourse project debt
were $18.1 million for the remainder of 1996, $24.8 million for 1997, $26.0
million for 1998, $18.7 million for 1999, $18.0 million for 2000 and $100.2
million thereafter.
The Company currently has the Credit Suisse Credit Facility, which was
arranged by Electrowatt and provides for total borrowings of up to $50.0
million, with borrowings bearing interest at either LIBOR or at the Credit
Suisse base rate plus a mutually-agreed margin. As of June 30, 1996, the Company
had no borrowings outstanding under the Credit Suisse Credit Facility. Upon the
completion of the Common Stock Offering, the Credit Suisse Credit Facility will
terminate and is expected to be replaced by a comparable facility. On July 20,
1996, the Company entered into a Commitment Letter with The Bank of Nova Scotia
for a $50.0 million three-year revolving credit facility. The Bank of Nova
Scotia Facility will become effective upon the completion of the Common Stock
Offering.
The Company currently has outstanding $105.0 million of its 9 1/4% Senior
Notes which mature on February 1, 2004 and bear interest at 9 1/4% payable
semi-annually on February 1 and August 1 of each year and $180.0 million of its
10 1/2% Senior Notes which mature on May 15, 2006 and bear interest at 10 1/2%
payable semi-annually on May 15 and November 15 of each year. Under the
provisions of the 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. In addition, the Bank of Nova Scotia
Facility will contain certain restrictions that will 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 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 June 30, 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 had 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, which has
been discounted to yield 8% per annum, is due September 9, 1997.
On August 29, 1996, in connection with the acquisition of the Gilroy
Facility, the Company entered into a non-recourse project loan in the aggregate
amount of $116.0 million. Such loan, which was provided by Banque Nationale de
Paris, 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.
36
<PAGE> 237
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 June 30, 1996, the Company had commitments for capital expenditures in
1996 totaling $6.5 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
1995 were $17.4 million compared to $7.0 million for 1994, primarily due to the
purchase of new equipment and the additional working interest. For the six
months ended June 30, 1996, capital expenditures included $4.0 million for the
purchase of geothermal leases for the Glass Mountain Project and $2.7 million
for the new rotor at the PG&E Unit 13 facility.
The Company continues to pursue the acquisition and development of
geothermal resources and new power generation projects. The Company expects to
commit significant capital during the remainder of 1996 and in future years for
the acquisition and development of these projects. The Company's actual capital
expenditures may vary significantly during any year.
In April 1996, the Company entered into a transaction involving a lease of
the King City Facility. The Company financed this transaction with the $45
Million Bank of Nova Scotia Loan, $13.3 million of borrowings under the Credit
Suisse Credit Facility (both of which were repaid with a portion of the net
proceeds from the sale of the 10 1/2% Senior Notes) and $50.0 million of
proceeds from the Preferred Stock Investment by Electrowatt. See
"Business -- Description of Facilities -- King City Facility."
The Company believes that it will have sufficient liquidity from cash flow
from operations, borrowings available from lines of credit and working capital
lines to satisfy all obligations under outstanding indebtedness, to finance
anticipated capital expenditures and to fund working capital requirements.
IMPACT OF RECENT ACCOUNTING PRONOUNCEMENTS
In March 1995, the Financial Accounting Standards Board 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 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. SFAS No. 121 must be adopted for fiscal years
beginning in 1996. The Company has 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 of the Company as of January
1, 1996.
In October 1995, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards ("SFAS") No. 123, Accounting for Stock-Based
Compensation. The disclosure requirements of SFAS No. 123 are effective for the
Company's 1996 fiscal year. The Company does not expect the new pronouncement to
have an impact on its results of operations since the intrinsic value-based
method prescribed by APB Opinion No. 25 and also allowed by SFAS No. 123 will
continue to be used by the Company to account for its stock-based compensation
plans.
37
<PAGE> 238
BUSINESS
OVERVIEW
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
1,057 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 $41.2 million of total assets as of December 31,
1991 to $911.0 million of total assets on a pro forma basis as of June 30, 1996.
Calpine's revenue on a pro forma basis for 1995 increased to $224.3 million,
representing a compound annual growth rate of 55% since 1991. The Company's
EBITDA on a pro forma basis for 1995 increased to $123.8 million. See "Pro Forma
Consolidated 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 power generation facilities, as well as
marketing power and energy services to utilities and other end users.
THE MARKET
The power generation industry represents the third largest industry in the
United States, with an estimated end user market of approximately $207.5 billion
of electricity sales and 3.0 million gigawatt hours of production in 1995. In
response to increasing customer demand for access to low cost electricity and
enhanced services, new regulatory initiatives are currently being adopted or
considered at both state and federal levels to increase competition in the
domestic power generation industry. To date, such initiatives are under
consideration at the federal level and in approximately thirty states. For
example, in April 1996, FERC adopted Order No. 888, opening wholesale power
sales to competition and providing for open and fair electric transmission
services by public utilities. In addition, the CPUC has issued an electric
industry restructuring decision which envisions commencement of deregulation and
implementation of customer choice of electricity supplier by January 1, 1998.
Calpine believes that industry trends and such regulatory initiatives will lead
to the transformation of the existing market, which is largely characterized by
electric utility monopolies selling to a captive customer base, to a more
competitive market where end users may purchase electricity from a variety of
suppliers, including non-utility generators, power marketers, public utilities
and others. The Company believes that those market trends will create
substantial opportunities for companies such as Calpine that are low cost power
producers and have an integrated power services capability which enables them to
produce and sell energy to customers at competitive rates.
The Company also believes that these market trends will result in the
disposition of power generation facilities by utilities, independent power
producers and industrial companies. Utilities such as PG&E and Southern
California Edison Company have announced their intentions to sell power
generation facilities totalling approximately 3,150 megawatts and 5,000
megawatts, respectively. The independent power industry, which represents
approximately 8% of the installed capacity in the United States, or
approximately 59,000 megawatts, and has accounted for approximately 50% of all
additional capacity in the United States since 1990, is currently undergoing
significant consolidation. Many independent producers operating a limited number
of power plants are seeking to dispose of such plants in response to competitive
pressures, and industrial companies are selling their power plants to redeploy
capital in their core businesses. Over 200 independent power plant and portfolio
sale transactions have occurred in the past two years. The Company believes that
this consolidation will continue in the highly fragmented independent power
industry.
The power generation industry outside the United States is approximately
three times larger than the domestic market, and the demand for electricity is
growing rapidly. In 1996, it has been estimated that in excess of 590 gigawatts
of new capacity will be required outside the United States over the ensuing
ten-year
38
<PAGE> 239
period. In order to satisfy this anticipated increase in demand, many countries
have adopted active government programs designed to encourage private investment
in power generation facilities. The Company believes that these programs will
create significant opportunities to acquire and develop power generation
facilities in such countries.
STRATEGY
Calpine's objective is to become a leading power company by capitalizing on
these 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 since 1993.
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 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 completion of financing and
obtaining 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 in excess 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
has established an integrated power marketing capability, conducted through its
wholly owned subsidiary, CPSC. In 1995, CPSC received approval from the 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
an investment in 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
39
<PAGE> 240
investments in these projects will effectively position it for future expansion
in Southeast Asia and Latin America.
POWER GENERATION TECHNOLOGIES
NATURAL GAS-FIRED
Natural gas-fired power plants offer significant advantages over power
plants utilizing other fuel sources, such as coal, oil and nuclear energy,
including readily available supplies of natural gas, currently favorable prices,
highly efficient technology, higher availabilities, shorter construction periods
and lower capital and operating costs. In addition, natural gas-fired power
plants have fewer environmental impacts, including significantly lower emission
levels of certain pollutants than power plants utilizing other fossil fuels such
as coal and oil. During recent years, natural gas-fired power plants have
accounted for a substantial portion of the annual increase in independent power
capacity in the United States, and natural gas-fired power generation has become
the predominant power generation technology utilized for the production of
electricity by new power plants in the United States. Industry analysts have
predicted that natural gas will continue to be the dominant fuel for new power
generation facilities in the United States for the foreseeable future.
LOGO
GEOTHERMAL
Geothermal energy is a clean, alternative source of power that is produced
by utilizing hot water or steam that has been naturally heated by the earth.
Geothermal energy is found in areas of the world where heat within the earth's
crust is close to the surface. These areas generally coincide with the
boundaries of the earth's tectonic plates. Exploitable geothermal reservoirs
have three primary defining characteristics: (i) a high heat flow near the
surface, (ii) a porous geologic medium where water can circulate to become
heated
40
<PAGE> 241
and (iii) an impermeable cap rock to prevent dispersion of the heated fluids.
Factors that affect the ability to exploit geothermal energy include the ability
to drill wells and produce fluids from the porous medium, the temperature and
quantity of the fluids and the chemical characteristics of the fluids. In
addition, the productive capacity of geothermal wells decreases over time,
requiring the drilling of new wells in an effort to maintain production.
LOGO
Geothermal energy facilities, such as those currently owned and operated by
the Company, provide significant advantages over other alternative power
generation technologies, such as wind, solar or solid waste/biomass, including
lower operating and maintenance costs per kilowatt hour, shorter construction
periods and higher plant availability. Geothermal energy also provides a
reliable and environmentally preferred source of electricity, emitting
significantly lower levels of pollutants than are released from power plants
utilizing fossil fuels. As a result of these and other advantages, as well as
federal and state tax incentives that have been adopted to encourage the
development of geothermal power generation projects, the Company believes that
there will continue to be demand for the production of electricity using
geothermal energy.
The geothermal energy capacity of the United States is located
predominantly in the western states in tectonically active regions. Total
installed geothermal capacity in the United States was approximately 2,925
megawatts as of the end of 1995, with approximately 2,650 megawatts located in
California and 275 megawatts located in Nevada, Utah and Hawaii. The Geysers
constitute the world's largest developed geothermal reservoir. The Geysers steam
fields have been in commercial production since 1960, and currently are capable
of producing an amount of steam sufficient to generate 1,200 megawatts of
electricity.
DESCRIPTION OF FACILITIES
The Company has interests in 15 power generation facilities and steam
fields with a current aggregate capacity of approximately 1,057 megawatts,
consisting of seven natural gas-fired cogeneration facilities 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 468 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.
41
<PAGE> 242
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 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 Thermal Power
Company Steam Fields that produce steam for sale under steam sales agreements
and for use in producing electricity from its wholly owned geothermal power
generation facilities. See "-- 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
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
42
<PAGE> 243
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.
LOGO
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
"-- Government Regulation."
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<PAGE> 244
The table below sets forth certain information regarding the Company's
power generation facilities and steam fields currently in operation.
POWER GENERATION FACILITIES
<TABLE>
<CAPTION>
COMMENCEMENT TERM OF
POWER NAMEPLATE CALPINE CALPINE NET OF POWER
GENERATION CAPACITY INTEREST INTEREST COMMERCIAL UTILITY SALES
FACILITY TECHNOLOGY (MEGAWATTS)(1) (PERCENTAGE) (MEGAWATTS) OPERATION PURCHASER AGREEMENT
- --------------------- ------------ -------------- ---------- ----------- ------------ ------------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
Sumas................ Gas-Fired 125 75%(2) 93.8 1993 Puget Sound 2013
Cogeneration Power &
Light
King City............ Gas-Fired 120 100% 120 1989 Pacific Gas & 2019
Cogeneration Electric
Gilroy............... Gas-Fired 120 100% 120 1988 Pacific Gas & 2018
Cogeneration Electric
Greenleaf 1.......... Gas-Fired 49.5 100% 49.5 1989 Pacific Gas & 2019
Cogeneration Electric
Greenleaf 2.......... Gas-Fired 49.5 100% 49.5 1989 Pacific Gas & 2019
Cogeneration Electric
Agnews............... Gas-Fired 29 20% 5.8 1990 Pacific Gas & 2021
Cogeneration Electric
Watsonville.......... Gas-Fired 28.5 100% 28.5 1990 Pacific Gas & 2009
Cogeneration Electric
West Ford Flat....... Geothermal 27 100% 27 1988 Pacific Gas & 2008
Electric
Bear Canyon.......... Geothermal 20 100% 20 1988 Pacific Gas & 2008
Electric
Aidlin............... Geothermal 20 5% 1 1989 Pacific Gas & 2009
Electric
</TABLE>
STEAM FIELDS
<TABLE>
<CAPTION>
APPROXIMATE CALPINE CALPINE NET COMMENCEMENT
CAPACITY INTEREST INTEREST OF COMMERCIAL UTILITY ESTIMATED
STEAM FIELD (MEGAWATTS)(3) (PERCENTAGE) (MEGAWATTS) OPERATION PURCHASER LIFE(4)
- ------------------------------ ------------- ---------- ---------- ------------- ---------------- ---------
<S> <C> <C> <C> <C> <C> <C>
Thermal Power Company......... 151 100% 151 1960 Pacific Gas 2018
& Electric
PG&E Unit 13.................. 100 100% 100 1980 Pacific Gas 2018
& Electric
PG&E Unit 16.................. 78 100% 78 1985 Pacific Gas 2018
& Electric
SMUDGEO #1.................... 59 100% 59 1983 Sacramento 2018
Municipal
Utility District
Cerro Prieto.................. 80 100%(5) 80 1973 Comision 2000(6)
Federal de
Electricidad
</TABLE>
- ------------
(1) Nameplate capacity may not represent the actual output for a facility at any
particular time.
(2) See "-- Power Generation Facilities -- Sumas Facility" for a description of
the Company's interest in the Sumas partnership and current sales of power
by the Sumas Facility.
(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."
44
<PAGE> 245
POWER GENERATION FACILITIES
Sumas Facility
The Sumas cogeneration facility (the "Sumas Facility") 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 Facility. 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 Facility 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
bearing interest at 16.25% and matures in 2004. The Sumas Facility commenced
commercial operation in April 1993.
The Company managed the engineering, procurement and construction of the
power plant and related facilities of the Sumas Facility, including the gas
pipeline. The Sumas Facility was constructed by a Washington joint venture
formed by Industrial Power Corporation and Haskell Corporation. The Sumas
Facility 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 Facility has operated at an average
availability of approximately 96.5%.
The Sumas Facility'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 LIBOR, which are
amortized over a 15-year period.
Electrical energy generated by the Sumas Facility is sold to Puget Sound
Power & Light Company ("Puget") under the terms of a 20-year power sales
agreement terminating in 2013. Under the power sales agreement, Puget has agreed
to purchase an annual average of 123 megawatts of electrical energy.
The power sales agreement provides for the sale of electrical energy at a
total price equal to the sum of (i) a fixed price component and (ii) a variable
price component multiplied by an escalation factor for the year in which the
energy is delivered. The schedule of annual fixed average energy prices
(expressed in cents per kilowatt hour) in effect through 2013 under the Sumas
power sales agreement is as follows:
<TABLE>
<CAPTION>
FIXED FIXED FIXED
ENERGY ENERGY ENERGY
YEAR PRICE YEAR PRICE YEAR PRICE
- -------------------- ------ -------------------- ------ -------------------- ------
<S> <C> <C> <C> <C> <C>
1996................ 3.19c
1997................ 3.38c
1998................ 3.64c
1999................ 3.98c
2000................ 4.23c
2001................ 6.23c
2002................ 6.11c
2003................ 6.22c
2004................ 6.33c
2005................ 6.45c
2006................ 6.57c
2007................ 5.23c
2008................ 5.31c
2009................ 5.40c
2010................ 5.49c
2011................ 5.58c
2012................ 5.58c
2013................ 5.58c
</TABLE>
The variable price component is set according to a scheduled rate set forth in
the agreement, which in 1995 was .97c per kilowatt hour, and escalates annually
by a factor equal to the U.S. Gross National Product Implicit Price Deflator.
For 1995, the average price paid by Puget under the power sales agreement was
2.954c per kilowatt hour. Pursuant to the power sales agreement, Puget may
displace the production of the Sumas Facility when the cost of Puget's
replacement power is less than the Sumas Facility's incremental power generation
costs. Thirty-five percent of the savings to Puget under this displacement
provision are shared with
45
<PAGE> 246
the Sumas Facility. In 1995, the Sumas Facility's net profit was increased by
$278,000 as a result of the displacement provision. The Company currently
estimates a similar level of displacement in 1996 as that experienced in 1995.
In addition to the sale of electricity to Puget, pursuant to a long-term
steam supply and dry kiln lease agreement, the Sumas Facility 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 Facility's QF
status. See "-- Government Regulation."
In connection with the development of the Sumas Facility, 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 totalled 138 billion cubic feet as of January 1, 1996. 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 12,000 million British thermal units per day ("mmbtu/day") to the
Sumas Facility. The remaining 13,000 mmbtu/day requirement is being supplied
under a one-year contract with West Coast Gas Services, Inc. The Company
believes that the gas reserves owned by ENCO and the availability of
supplemental gas supplies are sufficient to fuel the Sumas Facility through the
year 2013.
The Company operates and maintains the Sumas Facility 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 Facility 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 1995, the Sumas Facility generated approximately 1,026,000,000
kilowatt hours of electrical energy and approximately $31.5 million of total
revenue. In 1995, the Company recognized a loss of approximately $3.0 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 Facility
The King City cogeneration facility (the "King City Facility") 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, A California Limited Partnership ("BAF").
Under the terms of the operating lease, Calpine makes semi-annual lease payments
to BAF, a portion of which is supported by a $100.7 million collateral fund,
owned by the Company. The collateral consists of a portfolio of investment grade
and U.S. Treasury Securities that will mature serially in amounts equal to a
portion of the lease payments.
The Company financed the collateral fund and other transaction costs with
the $45 Million Bank of Nova Scotia Loan and $13.3 million of borrowings under
the Credit Suisse Credit Facility (both of which were repaid with a portion of
the net proceeds from the sale of the 10 1/2% Senior Notes), as well as $50.0
million of proceeds from the Preferred Stock Investment by Electrowatt.
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 Facility commenced commercial operation in 1989 and has
operated at an average availability of approximately 97%.
46
<PAGE> 247
Electricity generated by the King City Facility is sold to PG&E under a
30-year power sales agreement terminating in 2019. The power sales agreement
contains payment provisions for capacity and energy. The power sales agreement
provides for a firm capacity payment of $184 per kilowatt year for 111 megawatts
for the term of the agreement so long as the King City Facility delivers 80% of
the firm capacity during designated periods of the year. Additional capacity
payments are received for as-delivered capacity in excess of 111 megawatts
delivered during peak and partial peak hours. The following schedule sets forth
the as-delivered capacity prices per kilowatt year:
<TABLE>
<CAPTION>
AS-DELIVERED
YEAR CAPACITY PRICE
---------------------------------------------------- --------------
<S> <C>
1996................................................ $176
1997................................................ $188
1998................................................ $188
</TABLE>
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 schedule of fixed average energy prices (expressed in cents per kilowatt
hour) in effect through 1998 under the King City Facility power sales agreement
is as follows:
<TABLE>
<CAPTION>
ENERGY
YEAR PRICE
-------------------------------------------------------- ------
<S> <C>
1996.................................................... 12.24c
1997.................................................... 13.14c
1998.................................................... 13.14c
</TABLE>
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 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 1995,
PG&E's avoided cost of energy averaged approximately 1.84c 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 Facility 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 .7c per
kilowatt hour for all energy delivered from the King City Facility.
In addition to the sale of electricity to PG&E, the King City Facility
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 Facility'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 Facility 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. The Company believes that
upon expiration of these agreements that it will be able to obtain sufficient
quantities and firm transportation of natural gas to operate the King City
Facility for the remaining term of the power sales agreement.
Fee title to the premises is owned by Basic American, Inc., who 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 Facility. The Company is subleasing the
premises, together with certain easements, from such affiliate of BAF pursuant
to a ground sublease for approximately 15 acres.
47
<PAGE> 248
Gilroy Facility
On August 29, 1996, the Company acquired the Gilroy cogeneration facility
(the "Gilroy Facility"), a 120 megawatt gas-fired cogeneration power plant
located in Gilroy, California, from McCormick & Company, Inc. The Company
purchased the Gilroy 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.
The acquisition of the Gilroy Facility was financed utilizing a
non-recourse project loan in the aggregate amount of $116.0 million. Such loan,
which was provided by Banque Nationale de Paris, consists of a 15-year tranche
in the amount of $81.0 million and an 18-year tranche in the amount of $35.0
million and bears interest at fixed and floating rates.
The 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 Facility commenced commercial operation in March 1988
and has operated at an average availability of approximately 98.5%.
Electricity generated by the Gilroy Facility 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 Facility 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. The following schedule sets forth the as-delivered capacity
prices per kilowatt year:
<TABLE>
<CAPTION>
AS-DELIVERED
YEAR CAPACITY PRICE
-------------------------------------------------------- --------------
<S> <C>
1996.................................................... $176
1997.................................................... $188
</TABLE>
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 period of dispatchable operation at a price equal
to PG&E's avoided cost of energy excluding adders (as determined by the CPUC).
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 varies from month to month and has
ranged from an annual average of 1.84c to 2.96c per kilowatt hour since 1992.
During 1995, PG&E's avoided cost of energy averaged approximately 1.84c 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 Facility operates.
In addition to the sale of electricity to PG&E, the Gilroy Facility
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 Facility, 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
Facility's QF status. See "-- Government Regulation."
Natural gas for the Gilroy Facility is supplied pursuant to a contract with
Amoco Energy Trading Corporation ("Amoco") expiring July 31, 1997. The Company
believes that upon expiration of this fuel supply agreement, it will be able to
obtain a sufficient quantity of natural gas to operate the Gilroy Facility for
the remaining term of the power sales agreement. Natural gas is transported
under a firm transportation agreement, expiring July 1, 1997, via a dedicated
300-yard pipeline owned and maintained by PG&E.
The Gilroy Facility is located on approximately five acres of land which is
leased to the Company by Gilroy Foods. The lease term runs concurrent with the
term of the power sales agreement.
48
<PAGE> 249
Greenleaf 1 and 2 Facilities
On April 21, 1995, Calpine completed the acquisition of the Greenleaf 1 and
2 cogeneration facilities (the "Greenleaf 1 and 2 Facilities") from Radnor Power
Corporation, an affiliate of LFC Financial Corporation ("LFC"), for an adjusted
purchase price of $81.5 million.
On June 30, 1995, Calpine refinanced the existing debt on the Greenleaf 1
and 2 Facilities 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 (6.5% as of
December 31, 1995) with the amortization of principal based on a fixed schedule
through December 31, 2010.
The Greenleaf 1 and 2 Facilities 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 that is connected to the facilities. Calpine Fuels is committed
to purchasing all gas produced by MNI under this agreement which terminates in
December 2019. The quantity of gas produced by MNI varies and is currently less
than the facilities' full requirements. As a result, Calpine Fuels has
supplemented the MNI gas supply with a short-term contract with Coastal Gas
Marketing Company, which expires on September 30, 1996. This gas is delivered
over PG&E's intrastate pipeline which is directly connected to each facility.
The Greenleaf 1 and 2 Facilities have interruptible transportation agreements
with PG&E, expiring in June 1997. The Company believes that it will be able to
obtain a sufficient quantity of natural gas to operate the Greenleaf 1 and 2
Facilities for the remaining term of the power sales agreement.
Greenleaf 1 Facility. The Greenleaf 1 cogeneration facility (the
"Greenleaf 1 Facility") is a 49.5 megawatt natural gas-fired cogeneration
facility located near Yuba City, California. The Greenleaf 1 Facility 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
Facility 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 94.4%.
Electricity generated by the Greenleaf 1 Facility is sold to PG&E under a
30-year power sales agreement terminating in 2019 which contains payment
provisions for capacity and energy. The power sales agreement provides for a
firm capacity payment of $184 per kilowatt year for 49.2 megawatts for the term
of the agreement, so long as the Greenleaf 1 Facility delivers 80% of its firm
capacity during certain designated periods of the year, and an as-delivered
capacity payment for an additional .3 megawatts of capacity. The following
schedule sets forth the as-delivered capacity prices per kilowatt year through
1997 under the Greenleaf 1 Facility power sales agreement:
<TABLE>
<CAPTION>
AS-DELIVERED
YEAR CAPACITY PRICE
---------------------------------------------------- --------------
<S> <C>
1996................................................ $176
1997................................................ $188
</TABLE>
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 1995, PG&E's avoided cost of
energy averaged approximately 1.84c per kilowatt hour.
49
<PAGE> 250
In accordance with the power sales agreement, PG&E is entitled to curtail
the Greenleaf 1 Facility during hydro-spill periods, or during periods of
negative avoided costs. During 1995, the Greenleaf 1 Facility did not experience
curtailment, and the Company does not expect to experience curtailment at such
facility during 1996. 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 Facility
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 Facility's QF
status. See "-- Government Regulation."
The Greenleaf 1 Facility is located on 77 acres owned by the Company near
the rural area of Yuba City, California.
From April 21, 1995 through December 31, 1995, the Greenleaf 1 Facility
generated approximately 258,921,000 kilowatt hours of electric energy for sale
to PG&E and approximately $13.9 million in revenue.
Greenleaf 2 Facility. The Greenleaf 2 cogeneration facility (the
"Greenleaf 2 Facility") is a 49.5 megawatt natural gas-fired cogeneration
facility located near Yuba City, California. The Greenleaf 2 Facility includes a
STIG LM5000 gas turbine manufactured by General Electric and a Deltak heat
recovery steam generator. The Greenleaf 2 Facility 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 95%.
Electricity generated by the Greenleaf 2 Facility 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 Facility delivers 80% of its firm
capacity during certain designated periods of the year, and an as-delivered
capacity payment for an additional .3 megawatts of capacity. The following
schedule sets forth the as-delivered capacity prices per kilowatt year through
1997 under the Greenleaf 2 Facility power sales agreement:
<TABLE>
<CAPTION>
AS-DELIVERED
YEAR CAPACITY PRICE
---------------------------------------------------- --------------
<S> <C>
1996................................................ $176
1997................................................ $188
</TABLE>
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 1995, PG&E's avoided cost of
energy averaged approximately 1.84c per kilowatt hour.
In accordance with the power sales agreement, PG&E is entitled to curtail
the Greenleaf 2 Facility during hydro-spill periods or during any period of
negative avoided costs. During 1995, the Greenleaf 2 Facility did not experience
curtailment, and the Company does not expect to experience curtailment at such
facility during 1996. 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 Facility
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 Facility as a QF. See "-- Government
Regulation."
The Greenleaf 2 Facility is located on 2.5 acres of land under a lease from
Sunsweet, which runs concurrent with the power sales agreement.
50
<PAGE> 251
From April 21, 1995 through December 31, 1995, the Greenleaf 2 Facility
generated approximately 276,038,000 kilowatt hours of electric energy for sale
to PG&E and approximately $14.5 million of revenue.
Agnews Facility
The Agnews cogeneration facility (the "Agnews Facility") 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 Facility 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 Facility. The Company and GATX managed the development and financing
of the Agnews Facility, which commenced commercial operations in December 1990.
The Company managed the engineering, construction and start-up of the
Agnews Facility. 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 Facility has operated at an average availability of
approximately 96.5%.
The total cost of the Agnews Facility was approximately $39 million. The
construction financing was provided by Credit Suisse in the amount of $28.0
million. After the commencement of commercial operation, the facility 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 Facility 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 Facility 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. The
following schedule sets forth the as-delivered capacity prices per kilowatt year
through 1998 under the Agnews Facility power sales agreement:
<TABLE>
<CAPTION>
AS-DELIVERED
YEAR CAPACITY PRICE
---------------------------------------------------- --------------
<S> <C>
1996................................................ $176
1997................................................ $188
1998................................................ $188
</TABLE>
Thereafter, the payment for as-delivered capacity will be at 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 1995, PG&E's avoided cost of energy averaged approximately
1.84c per kilowatt hour.
Under certain circumstances, PG&E may curtail energy deliveries for up to
1,000 off-peak hours per year. During 1995, PG&E curtailed the energy purchased
under the power sales agreement by 1,000 hours. The Company currently expects
the maximum amount of curtailment allowed under the agreement during 1996.
51
<PAGE> 252
In addition to the sale of electricity to PG&E, the Agnews Facility
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 Facility 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 Facility's QF status. See "-- Government Regulation."
The supply of natural gas for the Agnews Facility 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. The
Company believes that, upon expiration of this fuel supply agreement, it will be
able to obtain a sufficient quantity of natural gas to operate the Agnews
Facility for the remaining term of the power sales agreement. Intrastate
transportation is provided under a firm gas transportation agreement with PG&E
expiring in June 1997.
The Agnews Facility 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 has an initial term of six years expiring on
December 31, 1996 and may be automatically renewed for an additional six-year
term, provided certain performance standards are met, and thereafter upon
mutually agreeable terms. The Company expects the contract will be renewed on
December 31, 1996.
The Agnews Facility 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 Facility, as well as a purchase option
at fair market value.
During 1995, the Agnews Facility generated approximately 225,683,000
kilowatt hours of electrical energy and total revenue of $10.8 million. In 1995,
the Company recognized a loss of approximately $82,000 as a result of the
Company's 20% ownership interest and recorded revenue of $1.5 million for
services performed under the operating and maintenance agreement.
Watsonville Facility
The Watsonville cogeneration facility (the "Watsonville Facility") 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 Facility 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 96.5%.
Electricity generated by the Watsonville Facility 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 Facility 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 an additional 7.6 megawatts of
capacity. In addition, the power sales agreement provides for payments for up to
28.5 megawatts of electrical energy actually delivered. Through April of 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
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hour) and the as-delivered capacity prices per kilowatt year through 2000 for
energy deliveries under the Watsonville Facility power sales agreement:
<TABLE>
<CAPTION>
ENERGY AS-DELIVERED
YEAR PRICE CAPACITY PRICE
-------------------------------------------- ------- --------------
<S> <C> <C>
1996........................................ 12.24c $176
1997........................................ 13.14c $188
1998........................................ 13.90c $188
1999........................................ 13.90c $188
2000........................................ 13.90c $188
</TABLE>
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 1995, PG&E's avoided cost of energy averaged approximately
1.84c per kilowatt hour.
Under certain circumstances, PG&E may curtail energy deliveries for a block
of up to 400 hours between January 1 and April 15 and an additional 900 off-peak
hours from October 1 though April 30. From June 29, 1995 through December 31,
1995, PG&E curtailed energy purchases of 212 hours under the power sales
agreement.
In addition to the sale of electricity to PG&E, during 1995 the Watsonville
Facility 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 Facility has
constructed a water distillation facility on the site of the Watsonville
Facility 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 Facility's QF status. See "-- Government Regulation."
Amoco is the supplier of natural gas to the Watsonville Facility. The
Company has negotiated a contract with Amoco, which it expects to execute by
September 1, 1996 and which will be effective through June 30, 1997. In the
interim, the Company has executed a series of monthly contracts with Amoco. PG&E
provides firm gas transportation to the Watsonville Facility under a contract
expiring June 30, 1997. The Company believes that upon expiration of this fuel
supply agreement, it will be able to obtain a sufficient quantity of natural gas
to operate the Watsonville Facility for the remaining term of the power sales
agreement.
The Watsonville Facility is located on 1.8 acres of land leased from Dean
Foods under the terms of a 30-year lease expiring in 2010.
For the period from June 29, 1995 to December 31, 1995, the Watsonville
Facility generated approximately 117,147,000 kilowatt hours of electrical energy
for sale to PG&E and approximately $5.9 million in revenue.
West Ford Flat Facility
The West Ford Flat geothermal facility (the "West Ford Flat Facility")
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 Facility 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 Facility
commenced commercial operation in December 1988. Since start-up, the West Ford
Flat Facility has operated at an average availability of approximately 98%.
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<PAGE> 254
Electricity generated by the West Ford Flat Facility 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 Facility
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 schedule of fixed average energy prices (expressed in cents
per kilowatt hour) in effect through 1998 under the West Ford Flat Facility
power sales agreement is as follows:
<TABLE>
<CAPTION>
ENERGY
YEAR PRICE
-------------------------------------------------------- ------
<S> <C>
1996.................................................... 12.89c
1997.................................................... 13.83c
1998.................................................... 13.83c
</TABLE>
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 1995,
PG&E's avoided cost of energy averaged approximately 1.84c 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 1995, 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 1996.
The Company believes that the geothermal reserves that supply energy for
use by the West Ford Flat Facility will be sufficient to operate at full
capacity for the entire term of the power sales agreement due 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 Facility.
The West Ford Flat Facility 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 "-- Properties."
During 1995, the West Ford Flat Facility generated approximately
216,614,000 kilowatt hours of electrical energy for sale to PG&E and
approximately $29.4 million of revenue.
Bear Canyon Facility
The Bear Canyon facility (the "Bear Canyon Facility") 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 Facility. The Bear Canyon Facility 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
eight production wells, an injection well and steam reserves. The Bear Canyon
Facility commenced commercial operation in October 1988. Since start-up, the
Bear Canyon Facility has operated at an average availability of approximately
98.4%.
Electricity generated by the Bear Canyon Facility 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 Facility 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
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<PAGE> 255
through the initial ten-year term of the agreement ending September 1998. 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 1998 for energy deliveries under the Bear Canyon Facility power sales
agreements:
<TABLE>
<CAPTION>
ENERGY AS-DELIVERED
YEAR PRICE CAPACITY PRICE
-------------------------------------------- ------- --------------
<S> <C> <C>
1996........................................ 12.89c $176
1997........................................ 13.83c $188
1998........................................ 13.83c $188
</TABLE>
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 1995, PG&E's avoided cost of energy averaged approximately
1.84c 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 1995, 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 1996.
The Company believes that the geothermal reserves for the Bear Canyon
Facility 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 Facility.
The Bear Canyon Facility 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 "-- Properties."
During 1995, the Bear Canyon Facility generated approximately 164,847,000
kilowatt hours of electrical energy and approximately $21.8 million of revenue.
Aidlin Facility
The Aidlin geothermal facility (the "Aidlin Facility") 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 Facility. The Company's ownership
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 Facility.
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
Facility commenced commercial operation in May 1989.
The Aidlin Facility includes a power plant consisting of two turbine
generators manufactured by Fuji Electric and ABB Industries, Inc., as well as
seven production wells and two injection wells. Since start-up, the Aidlin
Facility has operated at an average availability of approximately 99%.
The construction of the Aidlin Facility 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 Facility 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
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<PAGE> 256
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
Facility delivers 80% of its capacity during certain designated periods of the
year. In addition, the Aidlin Facility power sales agreements provide for energy
payments for 20 megawatts based on a schedule of fixed energy prices (expressed
in cents per kilowatt hour) in effect through 1999 as follows:
<TABLE>
<CAPTION>
ENERGY
YEAR PRICE
-------------------------------------------------------- ------
<S> <C>
1996.................................................... 12.89c
1997.................................................... 13.83c
1998.................................................... 13.83c
1999.................................................... 13.83c
</TABLE>
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 1995,
PG&E's avoided cost of energy averaged approximately 1.84c 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 1995, PG&E curtailed the energy purchased
under this agreement by 1,000 hours. The Company currently expects the maximum
amount of curtailment under the agreement in 1996.
The output of the Aidlin Facility is expected to decline over the remaining
life of the facility unless additional reserves are developed on existing or
adjacent leases and enhanced water injection projects are successful in reducing
field declines. See "Risk Factors -- Risks Related to the Development and
Operation of Geothermal Energy Resources."
The Aidlin Facility 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 Facility 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 1995, the Aidlin Facility generated approximately 174,087,000
kilowatt hours of electrical energy and revenue of $21.7 million. In 1995, the
Company recognized revenue of approximately $277,000 as a result of the
Company's 5% ownership interest and $3.5 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 247 production wells,
19 injection wells and 52 miles of steam-transporting pipeline. See
"-- Properties." The 12 plants have a nameplate capacity of 978 megawatts and
currently have the capability to operate at 604 megawatts providing the Company
with an effective interest in 151 megawatts. The steam fields commenced
commercial operation in 1960.
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<PAGE> 257
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 1995
was 1.647c per kilowatt hour. In addition, the Company receives a monthly fee
for effluent disposal and maintenance. During 1995, such monthly fee was
$144,000 per month.
In March 1996, the Company and Union Oil Company of California ("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 strategy 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 million. Accordingly, the
Company's share of offsets in 1995 was $757,000. In approximately 1999, when
total offsets may exceed $15 million in accordance with the agreement, the
Company's share of offset payments to PG&E would be approximately 2 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 1995, the Thermal Power Company Steam Fields
experienced extensive 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 $12,800 per month during 1995. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations."
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
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<PAGE> 258
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 1995, the PG&E power plants produced 2,688,176,000 kilowatt hours of
electrical energy of which the Company's 25% share is 672,044,000 kilowatt hours
for approximately $11.0 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 "-- Properties." Unit 13 and Unit 16
have nameplate capacities of 134 and 113 megawatts, respectively, and currently
operate at outputs of approximately 100 and 78 megawatts, respectively. The PG&E
Unit 13 Steam Field includes 956 acres, 30 production wells, two injection wells
and five miles of pipeline, and commenced commercial operations in May 1980. The
PG&E Unit 16 Steam Field includes 675 acres, 19 producing wells, two injection
wells, and three miles of pipeline, and commenced commercial operation in
October 1985.
The PG&E Unit 13 and Unit 16 Steam Fields produce steam for sale to PG&E
under long-term steam sales agreements. Under the steam sales agreements with
PG&E, the Company is paid for steam on the basis of the amount of electricity
produced by Unit 13 and Unit 16. The price paid for steam under the PG&E Unit 13
and Unit 16 Steam Fields agreements is determined according to a formula that is
essentially a weighted average of PG&E's fossil (oil and gas) fuel price and
PG&E's nuclear fuel price. The price of steam for 1995 was 1.207c per kilowatt
hour. The price for 1996 is expected to be approximately .995c. The Company
receives an additional .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 64,000,000 kilowatt hours under
the steam sales agreement during 1995. The Company currently expects
approximately the same amount of curtailment under the agreement during 1996
that was experienced in 1995.
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 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
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<PAGE> 259
PG&E to operate at variable pressure operations which will optimize production
at the PG&E Unit 13 and Unit 16 Steam Fields.
The PG&E Unit 13 and Unit 16 Steam Fields currently supply steam sufficient
to operate Unit 13 and Unit 16 at approximately 72% 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 10% until curtailment of neighboring plants and Unit 13 and Unit
16 in 1995 reduced the decline to zero. The Company expects steam field
productivity to continue to decline in the future, but at decreasing 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 1995, the PG&E Unit 13 and Unit 16 Steam Fields produced sufficient
steam to permit Unit 13 and Unit 16 to produce approximately 1,296,900,000
kilowatt hours of electrical energy and approximately $16.3 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 SMUD SMUDGEO #1 steam fields (the "SMUDGEO
#1 Steam Fields"). See "-- 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 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 $1.746 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 .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 increased
in productivity in 1995 due to curtailment of neighboring plants, the Company
expects the SMUDGEO #1 Steam Fields' productivity to decline in the future.
During 1995, the SMUDGEO #1 Steam Fields produced approximately 6,600,835
thousand pounds of steam and approximately $12.3 million of revenue.
Cerro Prieto Steam Fields
On November 17, 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
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Company has agreed to invest up to $20 million in the Cerro Prieto steam fields
(the "Cerro Prieto Steam Fields") located in Baja California, Mexico. The Cerro
Prieto Steam Fields provide geothermal steam to three geothermal power plants
owned and operated by Comision Federal de Electricidad, the Mexican national
utility ("CFE").
The Company's investment consists of a loan of up to $18.5 million and a
$1.5 million payment for an option to purchase a 29% equity interest in
Coperlasa for $5.8 million, which payment was made in December 14, 1995. This
option expires in May 1997.
The $18.5 million loan was made in installments throughout 1996, which
provided capital to Coperlasa to fund the drilling of new wells and the repair
of existing wells to meet its performance under its agreement with CFE. The loan
matures in November 1999 and bears interest at an effective rate of 18.8% per
annum. Repayment of this loan will be interest only for the first 18 months.
Thereafter, 100% of the cash flow generated from the sale of steam less
operating expenses and capital expenditures will be used to pay principal and
interest on the loan. The Company's loan is senior to the existing debt at
Coperlasa.
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 -- Project Development Risks."
PASADENA COGENERATION PROJECT
Calpine was selected by Phillips Petroleum Company ("Phillips") to
negotiate for the development of a 240 megawatt gas-fired cogeneration project
at the Phillips Houston Chemical Complex ("HCC") located in Pasadena, Texas (the
"Pasadena Cogeneration Project"). In July 1995 and March 1996, the Company
entered into Energy Project Development Agreements with Phillips pursuant to
which the Company and Phillips propose to enter into 20-year agreements for the
purchase and sale of 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. Pursuant to the Energy Project Development
Agreements, the Company has agreed to make $3.5 million of capital expenditures
on the Pasadena Cogeneration Project during 1996. In addition, the Company has
provided a $3.0 million letter of credit to Phillips to secure the performance
under the Energy Project Development Agreement. On August 2, 1996, the Company
entered into a commitment letter with ING Capital Corporation to provide $100.0
million of non-recourse project financing for the Pasadena Cogeneration Project.
The Company expects to complete financing and commence construction in September
1996, with commercial operation scheduled to begin in August 1998. However,
there can be no assurances that the Company will be successful in completing
either the agreements with Phillips or any additional power sales agreements or
that the anticipated schedule for financing and construction will be met.
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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.
In August 1994, the Company entered into a partnership with Trans-Pacific
Geothermal Glass Mountain, Ltd. ("TGC") to construct and operate a 30 megawatt
project at Glass Mountain. 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 Calpine partnership and the relocation of the project to Glass Mountain. The
memorandum of understanding contemplates execution of a 45-year power purchase
agreement subject to satisfaction of certain conditions precedent and includes
an option for an additional 100 megawatts.
Subject to the execution of the power purchase agreement with BPA, the
Company plans to begin construction of an initial 45 megawatt phase of the Glass
Mountain Project in 1998. The Company is in the process of preparing an
Environmental Impact Statement and commercial operation is planned for 2000.
There can be no assurances, however, that the Company and BPA will enter into a
definitive agreement, that this project will be completed on this schedule, if
at all, or that commercial operation of this project will be successful.
In March 1996, the Company completed the acquisition of certain Glass
Mountain geothermal leases previously held by FMRP. As a result, the Company
currently holds an interest in approximately 29,000 acres of federal geothermal
leases at Glass Mountain. See "-- Properties."
COSO GEOTHERMAL PROJECT
In January 1992, the Company was selected by the Los Angeles Department of
Water and Power (the "Department") to negotiate for the development of up to 150
megawatts of electric generating capacity utilizing geothermal energy from the
Department's Coso geothermal leaseholds. Data from four deep exploration wells
and a number of shallow, temperature gradient wells indicate that a productive
area could exist with a capacity to support 200 megawatts or more. The resource
is on land leased by the Department from the United States Bureau of Land
Management ("BLM"), which is subleased to the Company.
The Company entered into definitive agreements with the Department in 1995
which granted the Company the right to develop the Department's Coso geothermal
leaseholds located in Inyo County, California and to produce steam or
electricity for sale to third parties. In addition, the agreements include an
amended power sales agreement with the Department which grants the Department an
option to purchase up to 150 megawatts of electricity from the geothermal
resource. The ordinance approving the agreements has been passed by the Los
Angeles City Council and approved by the Mayor.
In January 1996, certain litigation was filed against the Department
seeking to compel the Department to submit the agreements entered into with the
Company to a public bidding procedure in accordance with the Charter of the City
of Los Angeles. In August 1996, the court ruled that certain of the rights
granted by the Department in the agreements, including the right to produce
steam or electricity for sale to third parties, were void and were required to
be submitted to such a public bidding procedure. The Company is unable to
predict the impact of such ruling on the agreements and the development of the
Department's Coso geothermal leaseholds.
NAVAJO SOUTH COAL PROJECT
Calpine, BHP Minerals International Inc. and BHP Power Inc. have entered
into a memorandum of understanding to assess the development of the Navajo South
Project, a 1,700 megawatt coal-fired power generation facility in the Four
Corners area of New Mexico. It is anticipated that this new power plant will
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provide electricity to the west and southwest United States markets. BHP
Minerals International Inc. is the owner and operator of three coal mines in the
Four Corners area of New Mexico. One of these, the Navajo Mine, is located on
the Navajo Reservation.
BLACK HILLS COAL PROJECT
Calpine and Black Hills Corporation have entered into a joint venture
agreement to assess the development of the WYGEN Project, an 80 megawatt
coal-fired power generation facility located in northeastern Wyoming. It is
anticipated that this new power plant will provide electricity to the western
United States markets, with a commercial operation date expected in 1999. Black
Hills Corporation, the parent of Black Hills Power & Light Company, is a public
utility located in South Dakota.
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 1996 and 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 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.
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FEDERAL ENERGY REGULATION
PURPA
The enactment in 1978 of 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 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, 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. FERC regulations also permit QFs and utilities to negotiate
agreements for utility purchases of power at rates lower than the utility's
avoided costs. Due to increasing competition for utility contracts, the current
practice is for most power sales agreements to be awarded at a rate below
avoided cost. While public utilities are not explicitly required by PURPA to
enter into long-term power sales agreements, PURPA helped to create a regulatory
environment in which it has been common for long-term agreements to be
negotiated.
In order to be a QF, a cogeneration facility must produce not only
electricity, but also useful thermal energy for use in an industrial or
commercial process for heating or cooling applications in certain proportions to
the facility's total energy output and must meet certain energy efficiency
standards. Finally, a QF (including a geothermal or hydroelectric QF or other
qualifying small power producer) must not be controlled or more than 50% owned
by an electric utility or by most electric utility holding companies, or a
subsidiary of such a utility or holding company or any combination thereof.
The Company endeavors to develop its projects, monitor compliance by the
projects with applicable regulations and choose its customers in a manner which
minimizes the risks of any project losing its QF status. Certain factors
necessary to maintain QF status are, however, subject to the risk of events
outside the Company's control. For example, loss of a thermal energy customer or
failure of a thermal energy customer to take required amounts of thermal energy
from a cogeneration facility that is a QF could cause the facility to fail
requirements regarding the level of useful thermal energy output. Upon the
occurrence of such an event, the Company would seek to replace the thermal
energy customer or find another use for the thermal energy which meets PURPA's
requirements, but no assurance can be given that this would be possible.
If one of the projects in which the Company has an interest should lose its
status as a QF, the project would no longer be entitled to the exemptions from
PUHCA and the FPA. This could trigger certain rights of termination under the
power sales agreement, could subject the project to rate regulation as a public
utility under the FPA and state law and could result in the Company
inadvertently becoming a public utility holding company by owning more than 10%
of the voting securities of, or controlling, a facility that would no longer be
exempt from PUHCA. This could cause all of the Company's remaining projects to
lose their qualifying status, because QFs may not be controlled or more than 50%
owned by such public utility holding companies. Loss of QF status may also
trigger defaults under covenants to maintain QF status in the projects' power
sales agreements, steam sales agreements and financing agreements and result in
termination, penalties or
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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 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.
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Federal Natural Gas Transportation Regulation
The Company has an ownership interest in and operates six 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 broad authority to regulate
both the rates charged by and financial activities of electric utilities, and to
promulgate regulations implementing PURPA. Since a power sales contract will
become a part of a utility's cost structure (and therefore is generally
reflected in its retail rates), power sales contracts with independents are
potentially under the regulatory purview of PUCs, particularly the process by
which the utility has entered into the power sales contracts. If a PUC has
approved of the process by which a utility secures its power supply, a PUC
generally will be inclined to allow a utility to "pass through" the expenses
associated with an independent power contract to the utility's retail customers.
However, a regulatory commission may disallow the full reimbursement to a
utility for the purchase of electricity from QFs. 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 are considered to
be public utilities in many states and are subject to broad regulation by PUCs
ranging from the requirement of certificates of public convenience and necessity
to regulation of organizational, accounting, financial and other corporate
matters. In addition, states may assert jurisdiction over the siting and
construction of facilities not qualifying as QFs (as well as QFs), and over the
issuance of securities and the sale or other transfer of assets by these
facilities (but not QFs).
CPUC and the California Assembly 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 Order
Instituting Rulemaking and Order Instituting Investigation on the Commission
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, is also holding
hearings on policy issues related to a more competitive electric services
industry.
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On December 20, 1995, the CPUC issued an electric industry restructuring
decision which envisions commencement of deregulation and implementation of
customer choice beginning January 1, 1998, with all consumers participating by
2003. Because restructuring the California electric industry requires
participation and oversight by the FERC, the CPUC seeks to build a consensus
involving the California Legislature, the Governor, public and municipal
utilities, and customers. This consensus would be reflected in filings for
approval by the FERC and provides a cooperative spirit whereby both agencies
would move forward to implement the new market structure no later than January
1, 1998.
The decision provides for phased-in customer choice, development of a
non-discriminatory market structure, recovery of utilities stranded costs,
sanctity of existing contracts and continuation of existing public policy
programs including the promotion of fuel diversity through a renewable energy
purchase requirement.
On February 5, 1996, the CPUC issued a proposed procedural plan that
facilitates the transition of the electric generation market to competition by
January 1, 1998. This electric restructuring "roadmap" focuses on the multiple
and interrelated tasks that must be accomplished and sets forth the process to
achieve the necessary procedural milestones that must be completed in order to
meet the implementation goal.
In addition to the significant opportunity provided for power producers
such as Calpine resulting from the implementation of direct access, the decision
recognizes the sanctity of existing QF contracts. The decision recognizes that
horizontal market power concerns will likely require investor owned utilities to
divest themselves of a substantial portion of their generating assets and
requires the utilities to file with the Commission a plan for voluntary
divestiture of up to 50% of their fossil generating assets. The decision to
commit to the establishment of a restructuring policy maintains California's
resource diversity provided by existing renewal resources (including geothermal)
and encourages development of new renewable resources. The continued resource
diversity would be provided by a renewable portfolio standard which establishes
that a renewable purchase requirement be placed on providers of electricity and
creates a system of tradeable credits for meeting the purchase requirement.
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 intraprovincial
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
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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 stormwater 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 stormwater 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
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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 than the
Company.
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 July 31, 1996, the Company employed 235 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.
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 111 leases comprising 27,287 acres of federal, state and
private geothermal resource lands in The Geysers area in northern California.
These leases comprise its West Ford Flat Facility, Bear Canyon Facility, 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 23 leases
comprising approximately 29,000 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
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<PAGE> 269
initial terms varying from 10 to 20 years or for so long as geothermal resources
are produced and sold. Certain of the leases contain drilling or other
exploratory work requirements. In certain cases, if a requirement is not
fulfilled, the lease may be terminated and in other cases additional payments
may be required. The Company believes that its leases are valid and that it has
complied with all the requirements and conditions material to their continued
effectiveness. A number of the Company's leases for undeveloped properties may
expire in any given year. Before leases expire, the Company performs geological
evaluations in an effort to determine the resource potential of the underlying
properties. No assurance can be given that the Company will decide to renew any
expiring leases.
The Company, through its ownership of the Greenleaf 1 Facility, owns 77
acres in Sutter County, California.
See "-- 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.
LEGAL PROCEEDINGS
The Company, together with over 100 other parties, was named as a defendant
in the second amended complaint 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"). This complaint alleges that, in conjunction
with top executives of Bonneville and with the alleged assistance of the other
100 defendants, the Company engaged in a broad conspiracy and fraud. The
complaint has been amended a number of times. The Company has answered each
version of the complaint by denying all claims. In August 1994, the Company
successfully moved for an order severing the trustee's claims against the
Company from the claims against the other defendants. Although the case involves
over 25 separate financial transactions entered into by Bonneville, the severed
case concerns the Company in respect of only one of these transactions. In 1988,
the Company invested $2.0 million in a partnership formed with Bonneville to
develop four hydroelectric projects in the State of Hawaii. The projects were
not successfully developed by the partnership and, subsequent to Bonneville's
Chapter 11 filing, the Company filed a claim as a creditor against Bonneville's
bankruptcy estate. The trustee alleges that the investment was actually a loan
and was designed to inflate Bonneville's earnings. The trustee initially alleged
that Calpine is one of many defendants in this case responsible for Bonneville's
"deepening insolvency" and the amount of damages attributable to the Company
based on the $2.0 million partnership investment was alleged to be $577.2
million. Based upon statements made by the Court and the trustee at a pre-trial
hearing in September 1996, the Company believes that the maximum compensatory
damages which the trustee may seek will not exceed $2.0 million. There can be no
assurance, however, of the actual amount of damages to be sought by the trustee.
The Company believes the claims against it are without merit and will continue
to defend the action vigorously. The Company further believes that the
resolution of this matter will not have a material adverse effect on its
financial position or results of operations.
In connection with the Company's unsuccessful attempt to acquire O'Brien
Environmental Energy, Inc. ("O'Brien") in 1995 through the U.S. Bankruptcy Court
proceedings, the Company incurred approximately $3.6 million of third-party
expenses, all of which have been capitalized by the Company. Pursuant to the
terms of a contract with O'Brien, the Company is seeking the reimbursement of
$2.3 million of such expenses and a $2.0 million break-up fee, each of which is
subject to the approval of the Bankruptcy Court. On June 6, 1996, the Bankruptcy
Court ruled that the Company had the right to seek reimbursement of its fees and
expenses and conducted an evidentiary hearing on August 28, 1996 to determine
the amount to be awarded. The Bankruptcy Court is scheduled to decide this
matter on September 30, 1996. Although the Company believes it will be awarded
all or a substantial part of the fees and expenses which it is seeking, there
can be no assurance as to the ultimate resolution of this claim.
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.
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MANAGEMENT
BOARD OF DIRECTORS AND EXECUTIVE OFFICERS
The following table sets forth certain information as of June 30, 1996 with
respect to each person who is a Director, a nominee for Director or an executive
officer of the Company.
<TABLE>
<CAPTION>
NAME AGE POSITION
------------------------------------------ ---- ---------------------------------------------
<S> <C> <C>
Peter Cartwright.......................... 66 President, Chief Executive Officer, Director
and Chairman of the Board Nominee
Pierre Krafft............................. 66 Chairman of the Board
Hans-Peter Aebi........................... 48 Director
Rudolf Boesch............................. 59 Director
Ann B. Curtis............................. 45 Senior Vice President and Director Nominee
George J. Stathakis....................... 66 Director Nominee
Rodney M. Boucher......................... 53 Senior Vice President
Lynn A. Kerby............................. 58 Senior Vice President
Kenneth J. Kerr........................... 52 Senior Vice President
Peter W. Camp............................. 57 Vice President
Robert D. Kelly........................... 38 Vice President
Larry R. Krumland......................... 56 Vice President
Alicia N. Noyola.......................... 46 Vice President
John P. Rocchio........................... 58 Vice President
Ron A. Walter............................. 47 Vice President
</TABLE>
Set forth below is certain information with respect to each current
Director, nominee for Director and executive officer of the Company. Upon
completion of the Common Stock Offering, Mr. Krafft, Mr. Aebi and Mr. Boesch
will resign from the Board of Directors of the Company and Ms. Curtis and Mr.
Stathakis will be appointed to fill two of the vacancies. Accordingly, following
the Common Stock Offering, the Board of Directors will be comprised of Mr.
Cartwright, Ms. Curtis and Mr. Stathakis and Mr. Cartwright will serve as
Chairman of the Board. The Company is actively seeking to add up to four
additional independent Directors who are not directors, officers or employees of
the Company, Electrowatt or an affiliate of Electrowatt. The Company anticipates
that at least one additional independent Director will be appointed within six
months of the completion of the Common Stock Offering.
Peter Cartwright founded the Company in 1984 and has since served as a
Director and as the Company's President and Chief Executive Officer. Mr.
Cartwright will become Chairman of the Board of Directors of the Company
effective upon completion of the Common Stock Offering. From 1979 to 1984, Mr.
Cartwright was Vice President and General Manager of Gibbs & Hill, Inc.'s
Western Regional Office, an office which he established. Gibbs & Hill, Inc. is
an architect-engineering firm which specializes in power engineering projects.
From 1960 to 1979, Mr. Cartwright worked for General Electric's Nuclear Energy
Division. His responsibilities included plant construction, project management
and new business development. He served on the Board of Directors of nuclear
fuel manufacturing companies in Germany, Italy and Japan. Mr. Cartwright was
responsible for General Electric's technology development and licensing programs
in Europe and Japan. Mr. Cartwright obtained a Master of Science Degree in Civil
Engineering from Columbia University in 1953 and a Bachelor of Science Degree in
Geological Engineering from Princeton University in 1952. Mr. Cartwright is a
Professional Engineer licensed in the states of New York and California.
Pierre Krafft has been the Company's Chairman of the Board since March
1991. Mr. Krafft served as Executive Vice President of Electrowatt from 1971
until his retirement in April 1995. He also serves as a director of several
electric utility companies in Switzerland, Germany and France and as Chairman of
the Swiss National Committee of the World Energy Council. Mr. Krafft obtained a
Master of Science Degree in Electrical Engineering from the Georgia Institute of
Technology in 1956 and an undergraduate degree in Electrical Engineering from
the Federal Institute of Technology in 1953.
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<PAGE> 271
Hans-Peter Aebi has been a Director of the Company since June 1994. Mr.
Aebi has served as the President of Elektrizitats-Gesellschaft Laufenburg AG,
Executive Vice President of the Electric Power Operations Division and a member
of Electrowatt's executive management since October 1994. He was also named
Executive Vice President for Landis & Gyr AG in March 1996. He served as the
Senior Vice President of the Energy Division of Electrowatt from 1993 to 1994.
Mr. Aebi's prior experience includes 14 years with an Electrowatt affiliate,
CKW, in various capacities including Executive Vice President from 1991 to 1992,
and as the First Vice President from 1988 to 1990. Mr. Aebi obtained a Master of
Science Degree in Engineering from the Federal Institute of Technology in 1972.
Rudolf Boesch has been a Director of the Company since its inception in
1984. Dr. Boesch serves as a member of the Executive Committee of Electrowatt,
and as Executive Vice President of Electrowatt's Services Division. His prior
experience with Electrowatt includes over ten years in the areas of marketing
and sales and technical development. Dr. Boesch obtained a Ph.D. in Physics from
the Federal Institute of Technology in 1965.
Ann B. Curtis has served as the Company's Senior Vice President since
September 1992 and has been employed by the Company since its inception in 1984.
Ms. Curtis will become a Director of the Company effective upon the completion
of the Common Stock Offering. She is responsible for the Company's financial and
administrative functions, including the functions of general counsel, corporate
and project finance, accounting, human resources, public relations and investor
relations. Ms. Curtis also serves as Corporate Secretary for the Company, and
serves as an officer of each of the Company's subsidiaries. Ms. Curtis also
represents the Company on partnership management committees. From the Company's
inception in 1984 through 1992, she served as the Company's Vice President for
Management and Financial Services. Prior to joining Calpine, Ms. Curtis was
Manager of Administration for Gibbs & Hill, Inc.
George J. Stathakis has been a Senior Advisor to the Company since 1994 and
will be a Director of the Company effective upon completion of the Common Stock
Offering. Mr. Stathakis has been providing financial, business and management
advisory services to numerous international investment banks since 1985. He also
served as Chairman of the Board and Chief Executive Officer of Ramtron
International Corporation, an advanced technology semiconductor company, from
1990 to 1994. From 1986 to 1989, he served as Chairman of the Board and Chief
Executive Officer of International Capital Corporation, a subsidiary of American
Express. Prior to 1986, Mr. Stathakis served thirty-two years with General
Electric Corporation in various management and executive positions. During his
service with General Electric Corporation, Mr. Stathakis founded the General
Electric Trading Company and was appointed its first President and Chief
Executive Officer. Mr. Stathakis obtained a Bachelor of Science Degree in
Engineering from the University of California at Berkeley in 1952 and a Master
of Science Degree in Engineering from the University of California at Berkeley
in 1953.
Rodney M. Boucher joined the Company in June 1995 as Senior Vice President,
and as President and Chief Executive Officer of the Company's subsidiary,
Calpine Power Services Company. He is responsible for the purchase, sale and
marketing of electric power, as well as the restructuring of contract,
transmission and generation rights. Prior to joining the Company, Mr. Boucher
served as Chief Operating Officer of Citizens Power & Light Company from 1992 to
1995 and as Senior Vice President of Citizens Lehman Power L.P., in Boston,
Massachusetts from 1994 to 1995. Prior to joining Citizens he served as
President for Electrical Interconnections-International from 1991 to 1992. Mr.
Boucher also served as Vice President and Chief Information Officer with
PacifiCorp from 1984 to 1991, and held various other positions with PacifiCorp
since 1975. Mr. Boucher holds a Master of Science Degree in Power Systems from
Rensselaer Polytechnic Institute and a Bachelor of Science Degree in Electrical
Engineering from Oregon State University.
Lynn A. Kerby joined the Company in January 1991 and served as Vice
President of Operations through January 1993, at which time he became a Senior
Vice President for the Company. Prior to joining the Company, Mr. Kerby served
as Senior Vice President-Operations of Guy F. Atkinson Company, an engineering
and construction company, from 1989 to 1990, and served in various other
positions within Guy F. Atkinson since 1961. Mr. Kerby served on Calpine's Board
of Directors from 1984 to 1988 as a Guy F. Atkinson representative. He obtained
a Bachelor of Science Degree in Civil Engineering and Business from the
University of Idaho in 1961. Mr. Kerby holds a Class A Contractors License in
the states of California, Arizona and Hawaii.
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<PAGE> 272
Kenneth J. Kerr joined the Company in March 1996 as Senior Vice
President-International. Prior to joining the Company, he served as Senior Vice
President-Commercial Development for Magma Power Company from 1993 to 1995. From
1989 to 1993 he served as Business Vice President-Plastics, Pacific Area with
The Dow Chemical Company. From 1966 to 1989, he served in various marketing and
management positions also with The Dow Chemical Company. Mr. Kerr obtained a
Bachelor of Science Degree in Chemical Engineering from the University of
Delaware in 1966.
Peter W. Camp joined the Company in November 1993 and served as Director of
Project Development through January 1995, at which time he became a Vice
President of Project Development. From 1992 to 1993 he served as a full-time
consultant with the Company. From 1988 to 1992, he served as President for
Altran Corporation, a nuclear waste technology company. From 1975 to 1987, Mr.
Camp worked for General Electric Company as General Manager, Nuclear Fuel
Marketing and Projects Department, and as Manager, Nuclear Energy Strategic
Planning. He obtained a Master of Business Administration Degree from Stanford
University in 1970 and a Bachelor of Science Degree in Mechanical Engineering
from Yale University in 1962.
Robert D. Kelly has served as the Company's Vice President, Finance since
1994. Mr. Kelly's responsibilities include all project and corporate finance
activities. From 1991 to 1992, Mr. Kelly served as Project Finance Manager, and
from 1992 to 1994, he served as Director-Project Finance for the Company. Prior
to joining the Company, he was the Marketing Manager of Westinghouse Credit
Corporation from 1990 to 1991. From 1989 to 1990, Mr. Kelly was Vice President
of Lloyds Bank PLC. From 1982 to 1989, Mr. Kelly was employed in various
positions with The Bank of Nova Scotia. He obtained a Master of Business
Administration Degree from Dalhousie University, Canada in 1980 and a Bachelor
of Commerce Degree from Memorial University, Canada, in 1979.
Larry R. Krumland has served as the Company's Vice President of Asset
Management since January 1993. From 1990 to 1993, Mr. Krumland served as
Director-Asset Management. From 1984 to 1990, Mr. Krumland served as
Manager-Geothermal Development. Prior to joining the Company, he served as
Director of Sales and Manager of Geothermal Projects for Gibbs & Hill, Inc. Mr.
Krumland obtained a Master of Business Administration Degree in Business
Economics and Finance from the University of California, Los Angeles in 1972; a
Master of Science Degree in Engineering, Energy Systems, from the University of
California, Los Angeles in 1967; and a Bachelor of Science Degree in Mechanical
Engineering from the University of California at Berkeley in 1964.
Alicia N. Noyola joined the Company in March 1991 and served as a full-time
consultant through March 1992, at which time she became employed by the Company
as Special Counsel. Ms. Noyola became a Vice President of Project Development in
January 1993. From 1987 to 1991, Ms. Noyola was a partner in the San Francisco,
California-based law firm Thelen, Marrin, Johnson and Bridges, where she
concentrated on commercial and corporate finance. Ms. Noyola obtained a Juris
Doctor Degree in 1973 from Hastings College of the Law, University of California
and obtained a Bachelor of Arts Degree in Architecture in 1970 from the
University of California, Berkeley.
John P. Rocchio joined the Company at inception in 1984 as Vice President
of Project Development. Prior to joining the Company, he served as Manager of
Business Development for Gibbs & Hill, Inc. from 1979 to 1984. Prior to 1979,
Mr. Rocchio served for 17 years with General Electric in various positions,
including Manager International Sales for the Nuclear Energy Group from 1970 to
1979 and various engineering and marketing positions from 1962 to 1979. He
obtained a Bachelor of Science Degree in Marine Engineering from the U.S.
Merchant Marine Academy in 1959.
Ron A. Walter has served as the Company's Vice President of Project
Development since July 1990. From 1984 to 1990, Mr. Walter served as the
Company's Manager-Geothermal Projects. Prior to joining the Company, he served
as Director of Sales-Geothermal for the San Jose-based architect-engineering
firm, Gibbs & Hill, Inc. from 1983 to 1984 and Senior Engineer from 1982 to
1983. From 1981 to 1982 he served as Project Manager Geothermal Projects with
Rogers Engineering Co. and from 1972 to 1981 he served in engineering and
management positions with Batelle Northwest Laboratories. Mr. Walter obtained a
Master of Science Degree in Mechanical Engineering from Oregon State University
in 1976 and a Bachelor of Science Degree in Mechanical Engineering from the
University of Nebraska in 1971.
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CLASSIFIED BOARD OF DIRECTORS
The Company's Amended and Restated By-laws, which will become effective
upon the completion of the Common Stock Offering, will provide that the number
of directors shall be between three and nine, with the actual number of
directors to be established from time to time by resolution of the Board of
Directors. Following the Common Stock Offering, the Company's Board of Directors
will be divided into three classes, designated Class I, Class II and Class III,
with each class having a three-year term. Initially, Mr. Stathakis will serve in
Class I, Ms. Curtis will serve in Class II and Mr. Cartwright will serve in
Class III. The initial Directors in each class will hold office for terms of one
year, two years and three years, respectively. Thereafter each class will serve
a three-year term. The Company's Directors are elected by the stockholders at
the annual meeting of stockholders and will serve until their successors are
elected and qualified, or until their earlier resignation or removal. Additional
Directors will be designated to serve as Class I, Class II or Class III
Directors upon their appointment to the Board of Directors following the Common
Stock Offering.
COMMITTEES OF THE BOARD OF DIRECTORS
The Board of Directors will establish an Audit Committee and a Compensation
Committee upon completion of the Common Stock Offering. The Audit Committee will
review internal auditing procedures, the adequacy of internal controls and the
results and scope of the audit and other services provided by the Company's
independent auditors. The Compensation Committee will administer salaries,
incentives and other forms of compensation for officers and other employees of
the Company, as well as the incentive compensation and benefit plans of the
Company. Initially, Mr. Stathakis will serve as the sole Director on the Audit
Committee and the Compensation Committee. Thereafter, the Board of Directors
will designate one or more additional non-employee Directors to serve on the
Audit Committee and the Compensation Committee upon appointment to the Board of
Directors.
DIRECTOR COMPENSATION
Directors currently do not receive any compensation or other services as
members of the Board of Directors. The Company has determined that, following
the completion of the Common Stock Offering, non-employee Directors will receive
an annual fee of $25,000 and will be reimbursed for expenses incurred in
attending meetings of the Board of Directors or any committee thereof. The
chairman of the Compensation Committee and the chairman of the Audit Committee
will receive an additional annual fee of $5,000. In addition, Directors will be
eligible to participate in the Company's 1996 Stock Incentive Plan. See "-- 1996
Stock Incentive Plan."
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EXECUTIVE COMPENSATION
The following table provides certain summary information concerning the
compensation earned, paid or awarded for services rendered to the Company in all
capacities during each of the three years ended December 31, 1995 to the
Company's Chief Executive Officer and each of the five other most highly
compensated executive officers of the Company serving in that capacity as of
December 31, 1995.
SUMMARY COMPENSATION TABLE
<TABLE>
<CAPTION>
LONG-TERM
COMPENSATION
------------
ANNUAL COMPENSATION SHARES
---------------------------- UNDERLYING ALL OTHER
NAME AND PRINCIPAL POSITION YEAR SALARY BONUS OPTIONS COMPENSATION(1)
- ------------------------------------- ---- -------- -------- ------------ ---------------
<S> <C> <C> <C> <C> <C>
Peter 1995 $341,000 $255,750 178,668 $21,420
Cartwright........................... 1994 300,000 292,500 155,815 11,934
President and Chief Executive 1993 220,055 176,000 -- 7,722
Officer
Lynn A. 1995 195,000 72,000 53,600 4,815
Kerby................................ 1994 180,000 72,000 38,954 4,275
Senior Vice President 1993 173,250 90,000 41,551 4,228
Ann B. 1995 160,000 60,000 53,600 877
Curtis............................... 1994 130,000 75,000 38,954 694
Senior Vice President 1993 122,500 70,000 -- 648
Alicia N. 1995 140,000 45,000 13,400 1,288
Noyola............................... 1994 133,875 40,162 -- 1,134
Vice President 1993 124,417 40,000 31,163 660
Ron A. 1995 135,000 45,000 13,400 1,235
Walter............................... 1994 120,000 40,000 -- 1,027
Vice President 1993 112,500 30,000 -- 587
Robert D. 1995 126,684 42,000 22,334 436
Kelly................................ 1994 115,208 60,000 31,163 389
Vice President 1993 103,347 50,000 23,372 343
</TABLE>
- ------------
(1) Represents the taxable value of an employer-sponsored life insurance policy.
The amount is calculated based on the age of the employee and the life
insurance coverage in excess of $50,000.
EMPLOYMENT AGREEMENTS, CONSULTING AGREEMENT AND CHANGE OF CONTROL ARRANGEMENTS
The Company has entered into employment agreements with Mr. Peter
Cartwright, Mr. Lynn Kerby, Ms. Ann Curtis, Mr. Ron Walter and Mr. Robert Kelly.
Each of the employment agreements expires during 1999 unless earlier terminated
or subsequently extended. The employment agreements provide for the payment of a
base salary, subject to periodic adjustment by the Board of Directors, and
provide for annual bonuses and participation in all benefit and equity plans.
The employment agreements also provide for other employee benefits such as life
insurance and health care, in addition to certain disability and death benefits.
Severance benefits, including the acceleration of outstanding options, are also
payable upon an involuntary termination or a termination following a change of
control in the Company. Severance benefits would not be payable in the event
that termination was for cause.
On December 1, 1994, the Company entered into a Consulting Agreement with
Mr. George J. Stathakis, a Director nominee. The Consulting Agreement was
amended and restated effective June 3, 1996. Pursuant to the Consulting
Agreement, Mr. Stathakis has been retained to provide, among other things,
advice to the Company with regard to domestic and international business, to
identify project investment opportunities, and to provide advisory support to
the Company's management in identifying potential buyers for, and negotiating
the sale of, Electrowatt's equity interest in the Company. The Consulting
Agreement provides for a monthly retainer of $5,000. In addition, for services
rendered in connection with the Common Stock Offering, the Company will pay Mr.
Stathakis $250,000 plus 0.25% of all payments received by Electrowatt in excess
of $200 million. The Consulting Agreement terminates on January 1, 1997 unless
otherwise earlier terminated or extended by mutual agreement of the parties.
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<PAGE> 275
Should the Company be acquired by merger or asset sale, then all
outstanding options held by the Chief Executive Officer and the other executive
officers under the Company's Stock Option Program or the 1996 Stock Incentive
Plan will automatically accelerate and vest in full, except to the extent those
options are to be assumed by the successor corporation. In addition, the
Compensation Committee as Plan Administrator of the 1996 Stock Incentive Plan
will have the authority to provide for the accelerated vesting of the shares of
Common Stock subject to outstanding options held by the Chief Executive Officer
or any other executive officer or any unvested shares of Common Stock subject to
direct issuances held by such individual, in connection with the termination of
that individual's employment following: (i) a merger or asset sale in which
these options are assumed or are assigned or (ii) certain hostile changes in
control of the Company. However, certain executive officers have existing
employment agreements that provide for the acceleration of their options upon a
termination of their employment following certain changes in control or
ownership of the Company.
STOCK OPTION PROGRAM
The following table sets forth certain information concerning grants of
stock options during the fiscal year ended December 31, 1995 to each of the
executive officers named in the Summary Compensation Table above. The table also
sets forth hypothetical gains or "option spreads" for the options at the end of
their respective ten-year terms. These gains are based on the assumed rates of
annual compound stock price appreciation of 5% and 10% from the date the option
was granted over the full option term.
OPTION GRANTS IN LAST FISCAL YEAR
<TABLE>
<CAPTION>
INDIVIDUAL GRANTS(1) POTENTIAL REALIZABLE
------------------------------------------------------------- VALUE AT ASSUMED
PERCENTAGE OF ANNUAL RATES OF
TOTAL OPTIONS STOCK
GRANTED TO PRICE APPRECIATION
OPTIONS EMPLOYEES EXERCISE FOR OPTION TERM(4)
GRANTED IN FISCAL PRICE PER EXPIRATION --------------------
NAME (NO. OF SHARES)(2) YEAR(3) SHARE DATE 5% 10%
- ------------------------ ------------------ ------------- ----------- ---------- -------- ---------
<S> <C> <C> <C> <C> <C> <C>
Peter Cartwright........ 178,668 40% $4.91 1/1/05 $551,704 $1,398,126
Lynn A. Kerby........... 53,600 12 4.91 1/1/05 165,510 419,435
Ann B. Curtis........... 53,600 12 4.91 1/1/05 165,510 419,435
Alicia N. Noyola........ 13,400 3 4.91 1/1/05 41,377 104,859
Ron A. Walter........... 13,400 3 4.91 1/1/05 41,377 104,859
Robert D. Kelly......... 22,334 5 4.91 1/1/05 68,965 174,770
</TABLE>
- ------------
(1) The exercise price may be paid in cash, in shares of the Company's Common
Stock valued at fair market value on the exercise date or through a cashless
exercise procedure involving a same-day sale of the purchased shares. The
Company may also finance the option exercise by loaning the optionee
sufficient funds to pay the exercise price for the purchased shares,
together with any federal and state income tax liability incurred by the
optionee in connection with such exercise. The Compensation Committee of the
Board of Directors, as the Plan Administrator of the Company's 1996 Stock
Incentive Plan, will have the discretionary authority to reprice the options
through the cancellation of those options and the grant of replacement
options with an exercise price based on the fair market value of the option
shares on the grant date.
(2) Each option set forth in the table above was granted on January 1, 1995 and
has a maximum term of ten years measured from the grant date, subject to
earlier termination upon the executive officer's termination of service with
the Company. Each option is immediately exercisable, but the underlying
shares are subject to repurchase by the Company at the original exercise
price paid per share should the executive officer's service with the Company
cease prior to vesting in such shares. The Company's repurchase right will
lapse with respect to, and the executive officer will vest in, four equal
annual installments over the four-year period of service measured from the
grant date. The Company's right to repurchase with respect to the option
shares will terminate immediately upon an acquisition of the Company by
merger or asset sale if the options are not assumed by the successor
corporation.
(3) The Company granted options to purchase 446,930 shares of Common Stock
during the year ended December 31, 1995.
(4) The 5% and 10% assumed annual rates of compound stock price appreciation are
mandated by the rules of the Securities and Exchange Commission (the
"Commission") and do not represent the Company's estimate or a projection by
the Company of future stock prices.
In addition to the options described above, in March 1996 the Board of
Directors granted options to purchase shares of Common Stock under the Company's
Stock Option Program to the following individuals in the designated amounts; Mr.
Cartwright, an option for 181,785 shares; Mr. Kerby, an option for 41,551
shares; Ms. Curtis, an option for 51,938 shares; Ms. Noyola, an option for
20,775 shares; Mr. Walter, an option for
75
<PAGE> 276
20,775 shares; and Mr. Kelly, an option for 36,357 shares. The exercise price
for each option is $8.57 per share. Each option has a maximum term of ten (10)
years measured from the date of grant, subject to earlier termination in the
event of the optionee's cessation of service with the Company. The Company's
right of repurchase will lapse with respect to, and the optionee will vest in,
the option shares in a series of four equal annual installments over the
four-year period of service measured from January 1, 1996. The Company's right
to repurchase with respect to the option shares will terminate immediately upon
an acquisition of the Company by merger or asset sale if the options are not
assumed by the successor corporation.
No executive officer named in the Summary Compensation Table above
exercised stock options during the year ended December 31, 1995. The following
table sets forth certain information concerning the number of shares subject to
exercisable and unexercisable stock options held by the executive officers named
in the Summary Compensation Table above as of December 31, 1995. Also reported
are values for "in-the-money" options that represent the positive spread between
the respective exercise prices of outstanding stock options and the fair market
value of the Company's Common Stock.
AGGREGATE OPTION EXERCISES IN LAST FISCAL YEAR AND YEAR-END OPTION VALUES
<TABLE>
<CAPTION>
NUMBER OF UNEXERCISED OPTIONS VALUE OF UNEXERCISED IN-THE-
AT DECEMBER 31, 1995 (NO. OF MONEY OPTIONS AT
OPTIONS) DECEMBER 31, 1995(1)
----------------------------- -----------------------------
NAME EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
- ---------------------------------------- ----------- ------------- ----------- -------------
<S> <C> <C> <C> <C>
Peter Cartwright........................ 597,292 438,361 $ 8,940,672 $ 4,222,964
Lynn A. Kerby........................... 50,640 125,016 663,495 1,272,877
Ann B. Curtis........................... 144,129 125,016 2,154,639 1,203,077
Alicia N. Noyola........................ 23,372 41,966 330,662 413,207
Ron A. Walter........................... 114,265 34,176 1,771,040 302,998
Robert D. Kelly......................... 33,111 80,115 426,088 778,593
</TABLE>
- ---------------
(1) For purposes of the computation of the value of unexercised in-the-money
options at December 31, 1995, the table above assumes that the value of the
underlying shares is the initial public offering price of the shares offered
hereby.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
For 1995, the members of the Board of Directors, other than Mr. Cartwright,
acted as the Compensation Committee for the purposes of establishing the
compensation for Mr. Cartwright, the Company's President and Chief Executive
Officer. All decisions regarding the compensation of the Company's other
executive officers were made by Mr. Cartwright. Upon the consummation of the
Common Stock Offering, there will be established a Compensation Committee of the
Board of Directors. Following the Common Stock Offering, no member of the
Compensation Committee of the Board of Directors of the Company will serve as a
member of the board of directors or compensation committee of any entity that
has one or more executive officers serving as a member of the Company's Board of
Directors or Compensation Committee.
1996 STOCK INCENTIVE PLAN
The Company's 1996 Stock Incentive Plan (the "1996 Plan") is intended to
serve as the successor equity incentive program to the Company's Stock Option
Program (the "Predecessor Plan"). See "-- Stock Option Program." The 1996 Plan
became effective on July 17, 1996 upon adoption by the Board of Directors and
was approved by the Company's stockholder on July 17, 1996. The Company has
initially authorized 4,041,858 shares of Common Stock for issuance under the
1996 Plan. This initial share reserve is comprised of (i) the 2,596,923 shares
which remained available for issuance under the Predecessor Plan, including the
2,392,026 shares subject to outstanding options thereunder, plus (ii) an
additional increase of 1,444,935 shares. In addition, the share reserve will
automatically be increased on the first trading day of January each calendar
year, beginning in January 1997, by a number of shares equal to one percent (1%)
of the number of shares of Common Stock outstanding on the last trading day of
the immediately preceding calendar year. However, in
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<PAGE> 277
no event may any one participant in the 1996 Plan receive option grants or
direct stock issuances for more than 500,000 shares in the aggregate per
calendar year.
Outstanding options under the Predecessor Plan will be incorporated into
the 1996 Plan upon the consummation of the Common Stock Offering, and no further
option grants will be made under the Predecessor Plan. The incorporated options
will continue to be governed by their existing terms, unless the Plan
Administrator elects to extend one or more features of the 1996 Plan to those
options. However, except as otherwise noted below, the outstanding options under
the Predecessor Plan contain substantially the same terms and conditions
summarized below for the Discretionary Option Grant Program in effect under the
1996 Plan.
The 1996 Plan is divided into five separate components: (i) the
Discretionary Option Grant Program under which eligible individuals in the
Company's employ or service (including officers and other employees,
non-employee Board members and independent consultants) may, at the discretion
of the Plan Administrator, be granted options to purchase shares of Common Stock
at an exercise price not less than 85% of their fair market value on the grant
date, (ii) the Stock Issuance Program under which such individuals may, in the
Plan Administrator's discretion, be issued shares of Common Stock directly,
through the purchase of such shares at a price not less than 100% of their fair
market value at the time of issuance or as a bonus tied to the performance of
services, (iii) the Salary Investment Option Grant Program under which executive
officers and other highly compensated employees may elect to apply a portion of
their base salary to the acquisition of special stock option grants, (iv) the
Automatic Option Grant Program under which option grants will automatically be
made at periodic intervals to eligible non-employee Directors to purchase shares
of Common Stock at an exercise price equal to 100% of their fair market value on
the grant date and (v) the Director Fee Option Grant Program pursuant to which
the non-employee Directors may apply a portion of the annual retainer fee, if
any, otherwise payable to them in cash each year to the acquisition of special
stock option grants.
The Discretionary Option Grant, Stock Issuance and Salary Investment Option
Grant Programs will be administered by the Compensation Committee. The
Compensation Committee as Plan Administrator will have complete discretion to
determine which eligible individuals are to receive option grants or stock
issuances, the time or times when such option grants or stock issuance are to be
made, the number of shares subject to each such grant or issuance, the vesting
schedule to be in effect for the option grant or stock issuance, the maximum
term for which any granted option is to remain outstanding and the status of any
granted option as either an incentive stock option or a non-statutory stock
option under the Federal tax laws, except that all options granted under the
Salary Investment Option Grant Program will be non-statutory stock options. The
administration of the Automatic Option Grant and Director Fee Option Grant
Programs will be self-executing in accordance with the express provisions of
each such program.
The exercise price for the shares of Common Stock subject to option grants
made under the 1996 Plan may be paid in cash or in shares of Common Stock valued
at fair market value on the exercise date. The option may also be exercised
through a same-day sale program without any cash outlay by the optionee. In
addition, the Plan Administrator may provide financing to one or more optionees
in the exercise of their outstanding options by allowing such individuals to
deliver a full-recourse, interest-bearing promissory note in payment of the
exercise price and any associated withholding taxes incurred in connection with
such exercise.
In the event that the Company is acquired by merger or asset sale, each
outstanding option under the Discretionary Option Grant Program which is not to
be assumed by the successor corporation will automatically accelerate in full,
and all unvested shares under the Stock Issuance Program will immediately vest,
except to the extent the Company's repurchase rights with respect to those
shares are to be assigned to the successor corporation. The Plan Administrator
will have the authority under the Discretionary Option Grant and Stock Issuance
Programs to grant options and to structure repurchase rights so that the shares
subject to those options or repurchase rights will automatically vest in the
event the individual's service is terminated, whether involuntarily or through a
resignation for good reason, within a specified period (not to exceed 18 months)
following (i) a merger or asset sale in which those options are assumed or (ii)
a hostile
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change in control of the Company effected by a successful tender offer for more
than 50% of the outstanding voting stock or by proxy contest for the election of
Directors. Options currently outstanding under the Predecessor Plan will
accelerate upon an acquisition of the Company by merger or asset sale, unless
those options are assumed by the acquiring entity. However, such options under
the Predecessor Plan are not subject to acceleration upon the termination of the
optionee's service following an acquisition in which those options are assumed
or following a hostile change in control, except to the extent provided in any
employment contract or severance agreement in effect between the optionee and
the Company.
Stock appreciation rights may be issued in tandem with option grants made
under the Discretionary Option Grant Program. The holders of such rights will
have the opportunity to elect between the exercise of their outstanding stock
options for shares of Common Stock or the surrender of those options for an
appreciation distribution from the Company equal to the excess of (i) the fair
market value of the vested shares of Common Stock subject to the surrendered
option over (ii) the aggregate exercise price payable for such shares. Such
appreciation distribution may be made in cash or in shares of Common Stock.
There are currently no outstanding stock appreciation rights under the
Predecessor Plan.
The Plan Administrator has the authority to effect the cancellation of
outstanding options under the Discretionary Option Grant Program (including
options incorporated from the Predecessor Plan) in return for the grant of new
options for the same or different number of option shares with an exercise price
per share based upon the fair market value of the Common Stock on the new grant
date.
In the event the Plan Administrator elects to activate the Salary
Investment Option Grant Program for one or more calendar years, each executive
officer and other highly compensated employee of the Company selected for
participation may elect, prior to the start of the calendar year, to reduce his
or her base salary for that calendar year by a specified dollar amount not less
than $10,000 nor more than $50,000. If such election is approved by the Plan
Administrator, the officer will be granted, on or before the last trading day in
January in the calendar year for which the salary reduction is to be in effect,
a non-statutory option to purchase that number of shares of Common Stock
determined by dividing the salary reduction amount by two-thirds of the fair
market value per share of Common Stock on the grant date. The option will be
exercisable at a price per share equal to one-third of the fair market value of
the option shares on the grant date. As a result, the total spread on the option
shares at the time of grant will be equal to the amount of salary invested in
that option. The option will vest in a series of 12 equal monthly installments
over the calendar year for which the salary reduction is in effect and will be
subject to full and immediate vesting upon certain changes in the ownership or
control of the Company.
Under the Automatic Option Grant Program, each individual who is serving as
a non-employee Director on the date the Underwriting Agreement for the Common
Stock Offering is executed will receive at that time a stock option for 10,000
shares of Common Stock, provided that individual has not previously received an
option grant from the Company in connection with his or her service on the Board
of Directors. Each individual who becomes a non-employee Director after such
date will receive an option grant for 10,000 shares of Common Stock at the time
of his or her commencement of service on the Board of Directors, provided such
individual has not otherwise been in the prior employment of the Company. In
addition, at each Annual Stockholders Meeting, beginning with the 1997 Annual
Stockholders Meeting, each individual who is to continue to serve as a
non-employee Director will receive an option grant to purchase 1,500 shares of
Common Stock, whether or not such individual has been in the prior employment of
the Company or has previously received a stock option grant from the Company.
Each automatic grant will have an exercise price equal to the fair market
value per share of Common Stock on the grant date and will have a maximum term
of 10 years, subject to earlier termination following the optionee's cessation
of service on the Board of Directors. Each automatic option will be immediately
exercisable; however, any shares purchased upon exercise of the option will be
subject to repurchase, at the option exercise price paid per share, should the
optionee's service as a non-employee Director cease prior to vesting in the
shares. The 10,000-share grant will vest in four successive equal annual
installments over the optionee's period of service on the Board of Directors
measured from the grant date. Each annual 1,500-share grant will vest upon the
optionee's completion of one year of service on the Board of Directors measured
from
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<PAGE> 279
the grant date. However, each outstanding option will immediately vest upon (i)
certain changes in the ownership or control of the Company or (ii) the death or
disability of the optionee while serving as a Director.
Should the Director Fee Option Grant Program be activated in the future,
each non-employee Director would have the opportunity to apply all or a portion
of his or her annual retainer fee otherwise payable in cash to the acquisition
of a below-market option grant. The option grant would automatically be made on
the first trading day in January in the year for which the retainer fee would
otherwise be payable in cash. The option will have an exercise price per share
equal to one-third of the fair market value of the shares of Common Stock on the
grant date, and the number of shares subject to the option will be determined by
dividing the amount of the retainer fee applied to the program by two-thirds of
the fair market value per share of Common Stock on the grant date. As a result,
the total spread on the option (the fair market value of the option shares on
the grant date less the aggregate exercise price payable for those shares) will
be equal to the portion of the retainer fee invested in that option. The option
will become exercisable for the option shares in a series of installments over
the optionee's period of service on the Board of Directors as follows: one half
of the option shares will become exercisable upon the optionee's completion of
six months of service on the Board of Directors during the calendar year of the
option grant and the balance will become exercisable in six successive equal
monthly installments upon his or her completion of each additional month of
service on the Board of Directors in such calendar year. However, the option
will become immediately exercisable for all the option shares upon (i) certain
changes in the ownership or control of the Company or (ii) the death or
disability of the optionee while serving as a Director.
The Board of Directors may amend or modify the 1996 Plan at any time. The
1996 Plan will terminate on July 16, 2006, unless sooner terminated by the Board
of Directors.
EMPLOYEE STOCK PURCHASE PLAN
The Company's Employee Stock Purchase Plan (the "Purchase Plan") was
adopted by the Board of Directors on July 17, 1996. The Purchase Plan is
designed to allow eligible employees of the Company and participating
subsidiaries to purchase shares of Common Stock, at semi-annual intervals,
through their periodic payroll deductions under the Purchase Plan, and a reserve
of 275,000 shares of Common Stock has been established for this purpose.
The Purchase Plan will be implemented in a series of successive offering
periods, each with a maximum duration of 24 months. However, the initial
offering period will begin on the day the Underwriting Agreement is executed in
connection with the Common Stock Offering and will end on the last business day
in August 1998.
Individuals who are eligible employees on the start date of any offering
period may enter the Purchase Plan on that start date or on any subsequent
semi-annual entry date (March 1 or September 1 each year). Individuals who
become eligible employees after the start date of the offering period may join
the Purchase Plan on any subsequent semi-annual entry date within that period.
Payroll deductions may not exceed 15% of the participant's cash
compensation for each semi-annual period of participation, and the accumulated
payroll deductions will be applied to the purchase of shares on the
participant's behalf on each semi-annual purchase date (February 28 and August
31 each year, with the first such purchase date to occur on February 28, 1997)
at a purchase price per share not less than eighty-five percent (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. In no event, however, may any participant purchase
more than 300 shares on any one semi-annual purchase date. Should the fair
market value of the Common Stock on any semi-annual purchase date be less than
the fair market value of the Common Stock on the first day of the offering
period, then the current offering period will automatically end and a new
24-month offering period will begin, based on the lower fair market value.
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LIMITATION OF LIABILITY AND INDEMNIFICATION MATTERS
The Company's Certificate of Incorporation limits the liability of
directors to the maximum extent permitted by Delaware law. Delaware law provides
that a director of a corporation will not be personally liable for monetary
damages for breach of such individual's fiduciary duties as a director except
for liability (i) for any breach of such director's duty of loyalty to the
corporation, (ii) for acts or omissions not in good faith or that involve
intentional misconduct or a knowing violation of law, (iii) for unlawful
payments of dividends or unlawful stock repurchases or redemptions as provided
in Section 174 of the Delaware General Corporation Law, or (iv) for any
transaction from which a director derives an improper personal benefit.
The Company's Bylaws provide that the Company will indemnify its directors
and may indemnify its officers, employees and other agents to the full extent
permitted by law. The Company believes that indemnification under its Bylaws
covers at least negligence and gross negligence on the part of an indemnified
party and permits the Company to advance expenses incurred by an indemnified
party in connection with the defense of any action or proceeding arising out of
such party's status or service as a director, officer, employee or other agent
of the Company upon an undertaking by such party to repay such advances if it is
ultimately determined that such party is not entitled to indemnification.
The Company has entered into separate indemnification agreements with each
of its directors and officers. These agreements require the Company, among other
things, to indemnify such director or officer against expenses (including
attorneys' fees), judgments, fines and settlements (collectively, "Liabilities")
paid by such individual in connection with any action, suit or proceeding
arising out of such individual's status or service as a director or officer of
the Company (other than Liabilities arising from willful misconduct or conduct
that is knowingly fraudulent or deliberately dishonest) and to advance expenses
incurred by such individual in connection with any proceeding against such
individual with respect to which such individual may be entitled to
indemnification by the Company. The Company believes that its Certificate of
Incorporation and Bylaw provisions and indemnification agreements are necessary
to attract and retain qualified persons as directors and officers.
At present the Company is not aware of any pending litigation or proceeding
involving any director, officer, employee or agent of the Company where
indemnification will be required or permitted. The Company is not aware of any
threatened litigation or proceeding that might result in a claim for such
indemnification.
CERTAIN TRANSACTIONS
CS Holding, a Swiss corporation, holds approximately 44.9% of the
outstanding shares of Electrowatt, which indirectly holds 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 in May 1996. CS First Boston Corporation is acting as 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 Facility. The Company holds a 20% interest in O.L.S. Energy-Agnews.
The loan is collateralized by all of the assets of the Agnews Facility 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 of
the Agnews Facility, the Facility 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
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Company to $54.0 million. The Credit Suisse Credit Facility is unsecured and
bears 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 10 1/2%
Senior Notes 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
reduced to $50.0 million. Borrowings of approximately $13.0 million are
outstanding under the Credit Suisse Credit Facility as of the date of this
Prospectus. All of such borrowings will be repaid with a portion of the net
proceeds to the Company from the Common Stock Offering. Upon the completion of
the Common Stock Offering, the Credit Suisse Credit Facility will terminate.
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 Facility and acquisition of
associated gas reserves. See "Business -- Description of Facilities -- Power
Generation Facilities -- Sumas Facility." As of December 31, 1995, the
outstanding indebtedness of Sumas and ENCO under the term loan was $119.0
million.
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 has agreed to pay
Electrowatt $200,000 per year for all services rendered under the management
services agreement. Pursuant to this agreement, $200,000 was paid in 1995. Upon
the completion of the Common Stock Offering, the management services agreement
will terminate.
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 has 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 the completion of the Common Stock Offering, the
guarantee fee agreement will terminate.
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 Facilities at the time of the acquisition of such facilities.
In December 1994, the Company entered into a Consulting Agreement with Mr.
Stathakis, a Director nominee, which was amended and restated effective June 3,
1996. See "Management--Employment Agreements, Consulting Agreement and Change of
Control Agreements."
In March 1996, Electrowatt invested $50.0 million in the Company in the
form of shares of Preferred Stock, all of which have been converted into shares
of Common Stock in connection with the Common Stock Offering.
The Company believes that all transactions between the Company and its
officers, Directors, principal shareholders and affiliates have been and will be
on terms no less favorable to the Company than could be obtained from
unaffiliated parties.
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PRINCIPAL AND SELLING STOCKHOLDERS
The following table sets forth certain information regarding beneficial
ownership of the Company's Common Stock as of June 30, 1996 and as adjusted to
reflect the Common Stock Offering by: (i) each person known by the Company to be
the beneficial owner of more than five percent of the outstanding shares of the
Company's Common Stock, (ii) each Director and nominee for Director of the
Company, (iii) each executive officer of the Company listed in the Summary
Compensation Table, (iv) Electrowatt (the "Selling Stockholder"), and (v) all
executive officers and Directors and nominees for Director of the Company as a
group.
<TABLE>
<CAPTION>
SHARES BENEFICIALLY SHARES BENEFICIALLY
OWNED OWNED
PRIOR TO THE AFTER THE
COMMON STOCK COMMON STOCK
OFFERING(1) OFFERING(1)
NAME AND ADDRESS ----------------------- NUMBER OF SHARES ----------------------
OF BENEFICIAL OWNER NUMBER PERCENT BEING OFFERED(2) NUMBER PERCENT
- -------------------------------- ---------- ------- ---------------- --------- -------
<S> <C> <C> <C> <C> <C>
Electrowatt Ltd.(2)............. 12,567,180 100%(2) 12,567,180 -- --
Pierre Krafft................... -- -- -- -- --
Hans-Peter Aebi................. -- -- -- -- --
Rudolf Boesch................... -- -- -- -- --
Peter Cartwright(3)............. 641,959 4.9% -- 641,959 3.4%
Ann B. Curtis(3)................ 157,529 1.2% -- 157,529 *
George J. Stathakis............. -- -- -- -- --
Lynn A. Kerby(3)................ 74,428 * -- 74,428 *
Ron A. Walter(3)................ 117,615 * -- 117,615 *
Alicia N. Noyola(3)............. 34,513 * -- 34,513 *
Robert D. Kelly(3).............. 44,537 * -- 44,537 *
All executive officers and
Directors and nominees for
Director as a group (15
persons)(3)................... 1,366,696 9.8% -- 1,366,696 7.0%
</TABLE>
- ------------
* Less than one percent
(1) Beneficial ownership is determined in accordance with the rules of the
Commission and generally includes voting or investment power with respect to
securities. Shares of Common Stock subject to options, warrants and
convertible notes currently exercisable or convertible, or exercisable or
convertible within 60 days, are deemed outstanding for computing the
percentage of the person holding such options but are not deemed outstanding
for computing the percentage of any other person. Subject to community
property laws where applicable, the persons named in the table have sole
voting and investment power with respect to all shares of Common Stock shown
as beneficially owned by them.
(2) Electrowatt's address is: Bellerivestrasse 36, P.O. Box CH-8022, Zurich,
Switzerland.
(3) Represents shares of the Company's Common Stock issuable upon exercise of
options that are currently exercisable or will become exercisable within 60
days after June 30, 1996.
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DESCRIPTION OF CAPITAL STOCK
The authorized capital stock of the Company consists of 100,000,000 shares
of Common Stock, $.001 par value, and 10,000,000 shares of Preferred Stock,
$.001 par value. The following summary is qualified in its entirety by the
provisions of the Certificate of Incorporation and Bylaws of the Company, which
have been filed as exhibits to the Registration Statement of which this
Prospectus constitutes a part.
COMMON STOCK
There will be 18,045,000 shares of Common Stock outstanding upon the
completion of the Common Stock Offering. The holders of Common Stock are
entitled to one vote per share on all matters to be voted upon by the
stockholders. Subject to preferences that may be applicable to any outstanding
Preferred Stock, the holders of Common Stock are entitled to receive ratably
such dividends, if any, as may be declared from time to time by the Board of
Directors out of funds legally available therefor. See "Dividend Policy." In the
event of the liquidation, dissolution or winding up of the Company, the holders
of Common Stock are entitled to share ratably in all assets remaining after
payment of liabilities, subject to prior liquidation rights of Preferred Stock,
if any, then outstanding. The Common Stock has no preemptive or conversion
rights or other subscription rights. There are no redemption or sinking fund
provisions applicable to the Common Stock. All outstanding shares of Common
Stock to be outstanding upon the completion of the Common Stock Offering will be
fully paid and non-assessable.
PREFERRED STOCK
The Board of Directors has the authority to issue the Preferred Stock in
one or more series and to fix the rights, preferences, privileges and
restrictions granted to or imposed upon any wholly unissued shares of
undesignated preferred stock and to fix the number of shares constituting any
series and the designations of such series, without any further vote or action
by the stockholders. The Board of Directors, without stockholder approval, can
issue Preferred Stock with voting and conversion rights which could adversely
affect the voting power of the holders of Common Stock. The issuance of
Preferred Stock may have the effect of delaying, deferring or preventing a
change in control of the Company, or could delay or prevent a transaction that
might otherwise give stockholders of the Company an opportunity to realize a
premium over the then prevailing market price of the Common Stock. There will be
no shares of Preferred Stock outstanding upon the completion of the Common Stock
Offering.
ANTI-TAKEOVER EFFECTS OF PROVISIONS OF THE CERTIFICATE OF INCORPORATION, BYLAWS
AND DELAWARE LAW
Certificate of Incorporation and Bylaws
The Company's Certificate of Incorporation and Bylaws provide that the
Company's Board of Directors is classified into three classes of Directors
serving staggered, three-year terms. The Certificate of Incorporation also
provides that Directors may be removed only by the affirmative vote of the
holders of two-thirds of the shares of capital stock of the Company entitled to
vote. Any vacancy on the Board of Directors may be filled only by vote of the
majority of Directors then in office. Further, the Certificate of Incorporation
provides that any "Business Combination" (as therein defined) requires the
affirmative vote of the holders of two-thirds of the shares of capital stock of
the Company entitled to vote, voting together as a single class. The Certificate
of Incorporation also provides that all stockholder actions must be effected at
a duly called meeting and not by a consent in writing. The Bylaws provide that
the Company's stockholders may call a special meeting of stockholders only upon
a request of stockholders owning at least 50% of the Company's capital stock.
These provisions of the Certificate of Incorporation and Bylaws could discourage
potential acquisition proposals and could delay or prevent a change in control
of the Company. These provisions are intended to enhance the likelihood of
continuity and stability in the composition of the Board of Directors and in the
policies formulated by the Board of Directors and to discourage certain types of
transactions that may involve an actual or threatened change of control of the
Company. These provisions are designed to reduce the vulnerability of the
Company to an unsolicited acquisition proposal. The provisions also are intended
to discourage certain tactics that may be used in proxy fights. However, such
provisions could have the effect of
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discouraging others from making tender offers for the Company's shares and, as a
consequence, they also may inhibit fluctuations in the market price of the
Company's shares that could result from actual or rumored takeover attempts.
Such provisions also may have the effect of preventing changes in the management
of the Company. See "Risk Factors -- Anti-Takeover Provisions" and
"Management -- Classified Board of Directors."
Delaware Anti-Takeover Statute
The Company is subject to Section 203 of the Delaware General Corporation
Law ("Section 203"), which, subject to certain exceptions, prohibits a Delaware
corporation from engaging in any business combination with any interested
stockholder for a period of three years following the date that such stockholder
became an interested stockholder, unless: (i) prior to such date, the board of
directors of the corporation approved either the business combination or the
transaction that resulted in the stockholder becoming an interested stockholder;
(ii) upon consummation of the transaction that resulted in the stockholder
becoming an interested stockholder, the interested stockholder owned at least
85% of the voting stock of the corporation outstanding at the time the
transaction commenced, excluding for purposes of determining the number of
shares outstanding those shares owned (x) by persons who are directors and also
officers and (y) by employee stock plans in which employee participants do not
have the right to determine confidentially whether shares held subject to the
plan will be tendered in a tender or exchange offer; or (iii) on or subsequent
to such date, the business combination is approved by the board of directors and
authorized at an annual or special meeting of stockholders, and not by written
consent, by the affirmative vote of at least 66 2/3% of the outstanding voting
stock that is not owned by the interested stockholder.
Section 203 defines business combination to include: (i) any merger or
consolidation involving the corporation and the interested stockholder; (ii) any
sale, transfer, pledge or other disposition of 10% or more of the assets of the
corporation involving the interested stockholder; (iii) subject to certain
exceptions, any transaction that results in the issuance or transfer by the
corporation of any stock of the corporation to the interested stockholder; (iv)
any transaction involving the corporation that has the effect of increasing the
proportionate share of the stock of any class or series of the corporation
beneficially owned by the interested stockholder; or (v) the receipt by the
interested stockholder of the benefit of any loans, advances, guarantees,
pledges or other financial benefits provided by or through the corporation. In
general, Section 203 defines an interested stockholder as any entity or person
beneficially owning 15% or more of the outstanding voting stock of the
corporation and any entity or person affiliated with or controlling or
controlled by such entity or person.
TRANSFER AGENT AND REGISTRAR
The Transfer Agent and Registrar for the Company's Common Stock is First
Chicago Trust Company of New York. Its address is 525 Washington Boulevard,
Jersey City, New Jersey 07310 and its telephone number is (201) 222-4114.
LISTING
The Common Stock has been approved for listing on the New York Stock
Exchange under the trading symbol "CPN," subject to notice of issuance.
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SHARES ELIGIBLE FOR FUTURE SALE
Upon the completion of the Common Stock Offering, the Company will have
18,045,000 shares of Common Stock outstanding (assuming no exercise of the
Underwriters' over-allotment option and assuming no exercise of outstanding
options). All of the shares sold in the Common Stock Offering will be freely
tradeable without restriction or further registration under the Securities Act,
except that any shares purchased by "affiliates" of the Company, as that term is
defined under the Securities Act ("Affiliates"), may generally only be sold in
compliance with the limitations of Rule 144 described below.
SALES OF RESTRICTED SHARES
Shares of Common Stock not freely tradeable without restriction or further
registration under the Securities Act are deemed "restricted" under Rule 144 of
the Securities Act. The number of shares of Common Stock available for sale in
the public market is limited by restrictions under the Securities Act and
lock-up agreements under which the holders of such shares have agreed with the
Underwriters not to sell or otherwise dispose of any of their shares for a
period of 180 days after the date of this Prospectus without the prior written
consent of CS First Boston. The Company intends to register with the Commission
on a registration statement on Form S-8 a total of 4,041,858 shares of Common
Stock issuable pursuant to the Company's 1996 Plan, including the 2,392,026
shares of Common Stock subject to outstanding options previously granted under
the Predecessor Plan. Upon the effectiveness of such registration statement, the
shares issuable upon the exercise of outstanding options or otherwise under the
1996 Plan will become freely tradeable upon issuance thereof, subject to the
restrictions on Affiliates under the Securities Act.
In general, under Rule 144 of the Securities Act as currently in effect,
beginning 90 days after the Common Stock Offering, a person (or persons whose
shares are aggregated) who has beneficially owned "restricted" shares for at
least two years, including a person who may be deemed an Affiliate of the
Company, is entitled to sell within any three-month period a number of shares of
Common Stock that does not exceed the greater of 1% of the then-outstanding
shares of Common Stock of the Company (approximately 180,450 shares after giving
effect to the Common Stock Offering) or the average weekly trading volume of the
Common Stock on the New York Stock Exchange during the four calendar weeks
preceding such sale. Sales under Rule 144 are subject to certain restrictions
relating to manner of sale, notice and the availability of current public
information about the Company. A person (or persons whose shares are aggregated)
who is not an Affiliate of the Company at any time during the ninety days
preceding a sale, and who has beneficially owned shares for at least three
years, would be entitled to sell such shares immediately following the Common
Stock Offering without regard to the volume limitations, manner of sale
provisions or notice or other requirements of Rule 144 of the Securities Act
pursuant to Rule 144(k). However, the transfer agent may require an opinion of
counsel that a proposed sale of shares comes within the terms of Rule 144(k)
prior to effecting a transfer of such shares.
Prior to the Common Stock Offering, there has been no public market for the
Common Stock of the Company and no predictions can be made of the effect, if
any, that the sale or availability for sale of shares of additional Common Stock
will have on the market price of the Common Stock. Nevertheless, sales of
substantial amounts of such shares in the public market, or the perception that
such sales could occur, could adversely affect the market price of the Common
Stock and could impair the Company's future ability to raise capital through an
offering of its equity securities.
OPTIONS
As of the date of this Prospectus, options to purchase a total of 2,392,026
shares of Common Stock were outstanding under the Company's 1996 Plan. Of such
amount, options to purchase 1,366,696 shares were exercisable, all of which will
become eligible for sale 180 days after the date of this Prospectus upon
expiration of certain lock-up agreements with the Underwriters and pursuant to
Rule 701, subject in some cases to certain volume and other resale restrictions.
Rule 701 under the Securities Act provides that shares of Common Stock acquired
on the exercise of outstanding options may be resold (i) by persons other than
Affiliates, beginning 90 days after the date of this Prospectus, subject only to
the manner of sale provisions of
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Rule 144 and (ii) by Affiliates, beginning 90 days after the date of this
Prospectus, subject to all provisions of Rule 144 except its two-year minimum
holding period.
LOCK-UP AGREEMENTS
All holders of options to purchase shares of Common Stock have agreed with
the Underwriters that they will not, without the prior written consent of CS
First Boston, offer, sell, contract to sell or otherwise dispose of any shares
of Common Stock beneficially owned by them or any shares issuable upon exercise
of stock options for a period of 180 days from the date of this Prospectus. See
"Subscription and Sale."
CERTAIN UNITED STATES FEDERAL TAX CONSEQUENCES
TO NON-U.S. HOLDERS
The following is a general discussion of certain United States federal
income and estate tax consequences of an investment in Common Stock by a holder
that, for United States federal income tax purposes, is not a "United States
person" (a "Non-U.S. Holder"). For purposes of this discussion, a "United States
person" means a citizen or resident (as defined for United States federal income
and estate tax purposes, as the case may be) of the United States, a corporation
or partnership created or organized in the United States or under the laws of
the United States or of any State thereof or an estate or trust whose income is
includible in gross income for United States federal income tax purposes
regardless of its source. The discussion is based on the United States Internal
Revenue Code of 1986, as amended (the "Code"). Treasury regulations promulgated
thereunder, and judicial and administrative interpretations thereof, all as in
effect on the date hereof and all of which are subject to change, possibly
retroactively, and is for general information only. The discussion does not
address aspects of United States federal taxation other than income and estate
taxation and does not address all aspects of United States federal income and
estate taxation. The discussion does not consider any specific facts or
circumstances that may apply to a particular Non-U.S. Holder. PROSPECTIVE
INVESTORS ARE URGED TO CONSULT THEIR TAX ADVISORS WITH RESPECT TO THE UNITED
STATES FEDERAL, STATE, LOCAL AND NON-U.S. INCOME AND OTHER TAX CONSEQUENCES TO
THEM OF AN INVESTMENT IN COMMON STOCK.
DIVIDENDS
Dividends paid to a Non-U.S. Holder will generally be subject to
withholding of United States federal income tax at a rate equal to 30% of the
gross amount of the distribution (or at a lower rate prescribed by an applicable
tax treaty) unless the dividends are effectively connected with the conduct of a
trade or business within the United States by the Non-U.S. Holder, in which case
the dividends generally will not be subject to withholding (if the Non-U.S.
Holder files certain forms with the payor of the dividend) and generally will be
subject to the United States federal income tax on net income that applies to
United States persons generally (and, in the case of corporate holders,
effectively connected dividends may also, under certain circumstances, be
subject to the branch profits tax at a 30% rate or such lower rate as may be
specified by an applicable income tax treaty). An applicable income tax treaty
may, however, change these rules. To determine the applicability of a tax treaty
providing for a lower rate of withholding, dividends paid to an address in a
foreign country are presumed under current interpretation of existing Treasury
regulations to be paid to a resident of that country. Treasury regulations
proposed to be effective for payments made after December 31, 1997, which have
not been finally adopted, however, would require Non-U.S. Holders to file
certain new forms to obtain the benefit of any applicable tax treaty providing
for a lower rate of withholding tax on dividends. Such forms would contain the
holder's name and address and certain other information.
The gross amount of a distribution with respect to Common stock will be
treated as a dividend to the extent of the Company's current and accumulated
earnings and profits as determined for U.S. federal income tax purposes. In the
event that such a distribution exceeds the amount of the Company's earnings and
profits, it will be treated first as a non-taxable return of capital to the
extent of the Non-U.S. Holder's basis in Common Stock (but not below zero), and
thereafter as capital gain. A Non-U.S. Holder will have to file a refund claim
to obtain a refund of tax withheld on distributions in excess of the dividend
portion of any distribution.
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GAIN ON DISPOSITION
A Non-U.S. Holder generally will not be subject to United States federal
income tax on gain recognized upon a sale or other disposition of shares of
Common Stock unless (i) the gain is effectively connected with the conduct of a
trade or business within the United States by the Non-U.S. Holder, (ii) the
Non-U.S. Holder is an individual who has a tax home (as specifically defined
under the United States federal income tax laws) in the United States (or
maintains an office or other fixed place of business in the United States to
which the gain from the sale of the stock is attributable), holds the shares of
Common Stock as a capital asset, and is present in the United States for 183
days or more in the taxable year of the disposition or (iii) except as discussed
below, the Company is or has been a "United States real property holding
corporation" ("USRPHC") within the meaning of section 897(c)(2) of the Code at
any time within the shorter of the five year period preceding such disposition
or such holder's holding period.
Gain that is (or is treated as being) effectively connected with the
conduct of a trade or business within the United States by the Non-U.S. Holder
will be subject to the United States federal income tax on net income that
applies to United States persons generally (and, with respect to corporate
holders and under certain circumstances, the branch profits tax) but will not be
subject to withholding. If the Company is a USRPHC, a Non-U.S. Holder may be
subject to taxation under certain provisions of the Codes enacted pursuant to
the Foreign Investors Real Property Tax Act ("FIRPTA"). The determination of
whether the Company is a USRPHC depends in part upon unresolved issues of what
constitutes real property for purposes of the FIRPTA provisions and upon
difficult and uncertain questions of valuation. If the Company were or were to
become a USRPHC, gains realized upon a disposition of Common Stock by a Non-U.S.
Holder that is not deemed to own more than 5% of the Common Stock would not be
subject to tax under the FIRPTA provisions provided that the Common Stock is
"regularly traded" on an established securities market. Since the Common Stock
will trade on the New York Stock Exchange, the Company believes the Common Stock
will be "regularly traded" on an established securities market.
Non-U.S. Holders should consult applicable treaties, which may provide for
different rules (including possibly the exemption of certain capital gains from
tax).
FEDERAL ESTATE TAXES
Common stock owned or treated as owned by an individual who is not a
citizen or resident (as specially defined for United States federal estate tax
purposes) of the United States at the time of death will be includible in the
individual's gross estate for United States federal estate tax purposes, unless
an applicable estate tax treaty provides otherwise. Such individual's estate may
be subject to the United States federal estate tax on the property includible in
the estate for United States federal estate tax purposes.
BACKUP WITHHOLDING AND INFORMATION REPORTING
The Company or its designated paying agent (the "payor") must report
annually to the Internal Revenue Service (the "Service") and to each Non-U.S.
Holder the amount of dividends paid to, and the tax, if any, withheld with
respect to, such holder. That information may also be made available to the tax
authorities of the country in which the Non-U.S. Holder resides.
United States federal backup withholding (imposed at a 31% rate on certain
payments to nonexempt persons) and information reporting with respect to such
withholding will generally not apply to dividends paid to a Non-U.S. Holder that
are otherwise subject to withholding or taxed as effectively connected income as
described above under "Dividends."
The backup withholding and information reporting requirements also apply to
the payment of gross proceeds to a Non-U.S. Holder upon the disposition of
Common Stock by or through a United States office of a United States or foreign
broker, unless the holder certifies to the broker under penalties of perjury as
to its name, address, and status as a Non-U.S. Holder or the holder otherwise
establishes an exemption. Information reporting requirements (but not backup
withholding if the payor does not have actual knowledge that the payee is a
United States person) will apply to a payment of the proceeds of a disposition
of Common
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Stock by or through a foreign office of (i) a United States broker, (ii) a
foreign broker 50% or more of whose gross income for certain periods is
effectively connected with the conduct of a trade or business in the United
States or (iii) a foreign broker that is a "controlled foreign corporation" for
United States federal income tax purposes, unless the broker has documentary
evidence in its records that the holder is a Non-U.S. Holder and certain other
conditions are met, or the holder otherwise establishes an exemption. Neither
backup withholding nor information reporting will generally apply to a payment
of the proceeds of a disposition of Common Stock by or through a foreign office
of a foreign broker not subject to the preceding sentence.
Backup withholding is not an additional tax. Any amounts withheld under the
backup withholding rules will be refunded (or credited against the Non-U.S.
Holder's United States federal income tax liability, if any), provided that the
required information is furnished to the Service.
These information reporting and backup withholding rules are under review
by the United States Treasury and their application to the Common Stock could be
changed by future regulations. The Service recently issued proposed Treasury
regulations concerning the withholding of tax and reporting for certain amounts
paid to non-resident individuals and foreign corporations. The proposed Treasury
regulations, if adopted in their present form, would be effective for payments
made after December 31, 1997. Prospective investors should consult their tax
advisors concerning the potential adoption of such proposed Treasury regulations
and the potential effect on their ownership of the Common Stock.
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SUBSCRIPTION AND SALE
The institutions named below (the "Managers") have, pursuant to a
Subscription Agreement dated September 19, 1996 (the "Subscription Agreement"),
severally and not jointly, agreed with Calpine and the Selling Stockholder to
subscribe and pay for the following respective numbers of International Shares
as set forth opposite their names:
<TABLE>
<CAPTION>
NUMBER OF
MANAGER INTERNATIONAL SHARES
- -------------------------------------------------------------------------- --------------------
<S> <C>
CS First Boston Limited................................................... 702,252
Morgan Stanley & Co. International Limited................................ 702,250
PaineWebber International (U.K.) Limited.................................. 702,250
Salomon Brothers International Limited.................................... 702,250
Banque Nationale de Paris................................................. 266,666
ING Bank N.V.............................................................. 266,666
UBS Limited............................................................... 266,666
--------------------
Total........................................................... 3,609,000
==============
</TABLE>
The Subscription Agreement provides that the obligations of the Managers
are subject to certain conditions precedent and the Managers will be obligated
to purchase all of the International Shares offered hereby (other than those
shares covered by the over-allotment option described below) if any are
purchased. The Subscription Agreement provides that, in the event of a default
by a Manager, in certain circumstances the purchase commitments of the
non-defaulting managers may be increased or the Subscription Agreement may be
terminated.
Calpine has entered into an Underwriting Agreement (the "Underwriting
Agreement") with the U.S. Underwriters of the U.S. Offering (the "U.S.
Underwriters" and, together with the Managers, the "Underwriters") providing for
the concurrent offer and sale of the U.S. Shares in the United States and
Canada. The closing of the U.S. Offering is a condition to the closing of the
International Offering and vice versa.
Calpine has granted to the Managers and the U.S. Underwriters an option,
exercisable by CS First Boston Corporation, expiring at the close of business on
the 30th day after the date of this Prospectus to purchase up to 2,706,750
additional shares at the initial public offering price, less the underwriting
discounts and commissions, all as set forth on the cover page of this
Prospectus. Such option may be exercised only to cover over-allotments in the
sale of the shares of Common Stock offered hereby. To the extent that this
option to purchase is exercised, each Manager and each U.S. Underwriter will
become obligated, subject to certain conditions, to purchase approximately the
same percentage of additional shares being sold to the Managers and the U.S.
Underwriters as the number of International Shares set forth next to such
Manager's name in the preceding table and as the number set forth next to such
U.S. Underwriter's name in the corresponding table in the Prospectus relating to
the U.S. Offering bears to the sum of the total number of shares of Common Stock
in such tables.
Calpine has been advised by CS First Boston Limited, on behalf of the
Managers, that the Managers propose to offer the International Shares outside
the United States and Canada initially at the public offering price set forth on
the cover page of this Prospectus and, through the Managers, to certain dealers
at such price less a commission of $.54 per share and that the Managers and such
dealers may reallow a commission of $.10 per share on sales to certain other
dealers. After the initial public offering, the public offering price and
commission and reallowances may be changed by the Managers.
The offering price and the aggregate underwriting discounts and commissions
per share and per share commission and re-allowance to dealers for the
International Offering and the concurrent U.S. Offering will be identical.
Pursuant to an Agreement between the U.S. Underwriters and Managers (the
"Intersyndicate Agreement") relating to the Common Stock Offering, changes in
the offering price, the aggregate underwriting discounts and commissions per
share and per share commission and reallowance to dealers will be made
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only upon the mutual agreement of CS First Boston Limited, on behalf of the
Managers, and CS First Boston Corporation, on behalf of the U.S. Underwriters.
Pursuant to the Intersyndicate Agreement, each of the Managers has agreed
that, as part of the distribution of International Shares and subject to certain
exceptions, it has not offered or sold, and will not offer or sell, directly or
indirectly, any shares of Common Stock or distribute any prospectus relating to
the Common Stock in the United States or Canada or to any other dealer who does
not so agree. Each of the U.S. Underwriters has agreed that, as part of the
distribution of the U.S. Shares and subject to certain exceptions, it has not
offered or sold and will not offer or sell, directly or indirectly, any shares
of Common Stock or distribute any prospectus relating to the Common Stock to any
person outside the United States and Canada or to any other dealer who does not
so agree. The foregoing limitations do not apply to stabilization transactions
or to transactions between the Managers and the U.S. Underwriters pursuant to
the Intersyndicate Agreement. As used herein, "United States" means the United
States of America (including the State and the District of Columbia), its
territories, possessions and other areas subject to its jurisdiction. "Canada"
means Canada, its provinces, territories, possessions and other areas subject to
its jurisdiction, and an offer or sale shall be in the United States or Canada
if it is made to (i) any individual resident in the United States or Canada or
(ii) any corporation, partnership, pension, profit-sharing or other trust or
other entity (including any such entity acting as an investment adviser with
discretionary authority) whose office most directly involved with the purchase
is located in the United States or Canada.
Pursuant to the Intersyndicate Agreement, sales may be made between the
Managers and the U.S. Underwriters of such number of shares of Common Stock as
may be mutually agreed upon. The price of any shares so sold will be the public
offering price less such amount agreed upon by CS First Boston Limited, on
behalf of the Managers, and CS First Boston Corporation, as representative of
the U.S. Underwriters, but not exceeding the selling concession applicable to
such shares. To the extent there are sales between the Managers and the U.S.
Underwriters pursuant to the Intersyndicate Agreement, the number of shares of
Common Stock initially available for sale by the Managers or by the U.S.
Underwriters may be more or less than the amount appearing on the cover page of
this Prospectus. Neither the Managers nor the U.S. Underwriters are obligated to
purchase from the other any unsold shares of Common Stock.
Each of the Managers and the U.S. Underwriters severally represents and
agrees that: (i) it has not offered or sold and, prior to the date six months
after the date of issue of the Common Stock will not offer or sell, any Common
Stock to persons in the United Kingdom except to persons whose ordinary
activities involve them in acquiring, holding, managing or disposing of
investments (as principal or agent) for the purposes of their businesses or
otherwise in circumstances which do not constitute an offer to the public in the
United Kingdom for the purposes of the Public Offers of Securities Regulations
1995; (ii) it has complied and will comply with all applicable provisions of the
Public Offers of Securities Regulations 1995 and the Financial Services Act 1986
with respect to anything done by it in relation to the Common Stock in, from or
otherwise involving the United Kingdom; and (iii) it has only issued or passed
on and will only issue or pass on in the United Kingdom any document in
connection with the issue or sale of the Common Stock to a person who is of a
kind described in Article 11(3) of the Financial Services Act 1986 (Investment
Advertisements) (Exemptions) Order 1996 or is a person to whom such document may
otherwise lawfully be issued or passed on.
Calpine has agreed that it will not offer, sell, contract to sell, announce
its intention to sell, pledge or otherwise dispose of, directly or indirectly,
or file with the Securities and Exchange Commission a registration statement
under the Securities Act (other than a registration statement on Form S-8)
relating to, any additional shares of its Common Stock or securities convertible
into or exchangeable or exercisable for any shares of its Common Stock without
the prior written consent of CS First Boston Corporation for a period of 180
days after the date of this Prospectus, except issuances pursuant to the
exercise of employee stock options outstanding on the date hereof. In addition,
all holders of options to purchase shares of Common Stock have agreed that they
will not, without the prior written consent of CS First Boston Corporation,
offer, sell, contract to sell or otherwise dispose of any shares of Common Stock
beneficially owned by them or any shares issuable upon exercise of stock options
for a period of 180 days after the date of this Prospectus.
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Calpine has agreed to indemnify the Managers and the U.S. Underwriters
against certain liabilities, including civil liabilities under the Securities
Act, or to contribute to payments that the Managers and the U.S. Underwriters
may be required to make in respect thereof.
CS First Boston Corporation, one of the U.S. Underwriters, is an affiliate
of the Company. The Common Stock Offering therefore is being conducted in
accordance with the applicable provisions of Rule 2720 to the Conduct Rules of
the National Association of Securities Dealers, Inc. Rule 2720 requires that the
initial public offering price of the Common Stock not be higher than that
recommended by a "qualified independent underwriter" meeting certain standards.
Accordingly, PaineWebber Incorporated is assuming the responsibilities of acting
as the qualified independent underwriter in pricing the Common Stock Offering
and conducting due diligence. In connection with the Common Stock Offering,
PaineWebber Incorporated in its role as qualified independent underwriter has
performed due diligence investigations and reviewed and participated in the
preparation of this Prospectus and the Registration Statement of which this
Prospectus forms a part. The initial public offering price of the Common Stock
set forth on the cover page of this Prospectus is no higher than the price
recommended by PaineWebber Incorporated.
The Underwriters may not confirm sales to any discretionary account without
the prior specific written approval of the customer.
The decision made by CS First Boston Corporation and CS First Boston
Limited to underwrite the Common Stock Offering was made independently of the
Company, CS Holding and Electrowatt. The net proceeds from the Common Stock
Offering will not be applied for the benefit of CS First Boston Corporation or
CS First Boston Limited. CS First Boston Corporation and CS First Boston Limited
will not receive any benefit from the Common Stock Offering other than their
respective portion of the underwriting discounts and commissions.
The Common Stock has been approved for listing on the New York Stock
Exchange, subject to notice of issuance, under the symbol "CPN." In connection
with the listing of the Common Stock on the New York Stock Exchange, the
Underwriters have undertaken to sell round lots of 100 shares or more to a
minimum of 2,000 beneficial holders.
Prior to the Common Stock Offering, there has been no public market for the
shares of Common Stock offered hereby. The initial public offering price for the
shares was determined by negotiations among the Company, the Selling Stockholder
and CS First Boston Corporation, as one of the Representatives of the U.S.
Underwriters, and by CS First Boston Limited, on behalf of the Managers, and
does not necessarily reflect the secondary market prices for the Common Stock
following the initial offering hereby. Among the principal factors considered in
determining the initial public offering price were prevailing economic
prospects, the sales, earnings and financial and operating performance of the
Company in recent periods, the future prospects of the Company, market
valuations of companies in related businesses and the history and prospects for
the industries in which the Company competes. Additionally, consideration has
been given to the general condition of the securities markets, the market for
new issues of securities and the demand for securities of comparable companies.
In the ordinary course of their business, CS First Boston Corporation and
certain of the other Underwriters and their affiliates have engaged in and may
in the future engage in investment banking transactions with Calpine, including
the provision of certain advisory services to Calpine. CS Holding, a Swiss
corporation, holds approximately 44.9% of the outstanding shares of Electrowatt,
which indirectly holds 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 and of CSFBL. CS First Boston Corporation was one of the
Underwriters in connection with the public offering of the Company's 9 1/4%
Senior Notes in February 1994, one of the placement agents in connection with
the sale of the 10 1/2% Senior Notes in May 1996 and is one of the
Representatives of the U.S. Underwriters in the U.S. Offering, and CSFBL is one
of the Managers in the International Offering. See "Certain Transactions."
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NOTICE TO CANADIAN RESIDENTS
RESALE RESTRICTIONS
The distribution of the Common Stock in Canada is being made only on a
private placement basis exempt from the requirement that the Company prepare and
file a prospectus with the securities regulatory authorities in each province
where trades of Common Stock are effected. Accordingly, any resale of the Common
Stock in Canada must be made in accordance with applicable securities laws which
will vary depending on the relevant jurisdiction, and which may require resales
to be made in accordance with available statutory exemptions or pursuant to a
discretionary exemption granted by the applicable Canadian securities regulatory
authority. Purchasers are advised to seek legal advice prior to any resale of
the Common Stock.
REPRESENTATIONS OF PURCHASERS
Each purchaser of Common Stock in Canada who receives a purchase
confirmation will be deemed to represent to the Company and the dealer from whom
such purchase confirmation is received that (i) such purchaser is entitled under
applicable provincial securities laws to purchase such Common Stock without the
benefit of a prospectus qualified under such securities laws, (ii) where
required by law, that such purchaser is purchasing as principal and not as
agent, and (iii) such purchaser has reviewed the text above under "Resale
Restrictions."
RIGHTS OF ACTION AND ENFORCEMENT
The securities being offered are those of a foreign issuer and Ontario
purchasers will not receive the contractual right of action prescribed by
section 32 of the Regulation under the Securities Act (Ontario). As a result,
Ontario purchasers must rely on other remedies that may be available, including
common law rights of action for damages or rescission or rights of action under
the civil liability provisions of the U.S. federal securities laws.
All of the issuer's directors and officers as well as the experts named
herein may be located outside of Canada and, as a result, it may not be possible
for Ontario purchasers to effect service of process within Canada upon the
issuer or such persons. All or a substantial portion of the assets of the issuer
and such persons may be located outside of Canada and, as a result, it may not
be possible to satisfy a judgment against the issuer or such persons in Canada
or to enforce a judgment obtained in Canadian courts against such issuer or
persons outside of Canada.
NOTICE TO BRITISH COLUMBIA RESIDENTS
A purchaser of Common Stock to whom the Securities Act (British Columbia)
applies is advised that such purchaser is required to file with the British
Columbia Securities Commission a report within ten days of the sale of any
Common Stock acquired by such purchaser pursuant to this offering. Such report
must be in the form attached to British Columbia Securities Commission Blanket
Order BOR #95/17, a copy of which may be obtained from the Company. Only one
such report must be filed in respect of Common Stock acquired on the same date
and under the same prospectus exemption.
LEGAL MATTERS
The validity of the Common Stock will be passed upon for the Company by
Brobeck, Phleger & Harrison LLP, San Francisco, California and for the
Underwriters by Skadden, Arps, Slate, Meagher & Flom, New York, New York.
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EXPERTS
The consolidated financial statements and schedules of the Company as of
December 31, 1995 and 1994 and for the three years ended December 31, 1995, 1994
and 1993, the financial statements of Calpine Geysers Company, L.P. for the
period ended April 18, 1993 and the financial statements of BAF Energy, A
California Limited Partnership as of October 31, 1995 and 1994 and for the three
years ended October 31, 1995, 1994 and 1993 included in this Prospectus and
elsewhere in the Registration Statement have been audited by Arthur Andersen
LLP, independent public accountants, as indicated in their reports with respect
thereto, and are included herein in reliance upon authority of said firm as
experts in giving said reports. In the reports for the Company, that firm states
that with respect to Sumas Cogeneration Company, L.P., its opinion is based on
the reports of other independent public accountants, namely Moss Adams LLP.
The consolidated financial statements of Sumas Cogeneration Company, L.P.
and Subsidiary as of December 31, 1995 and 1994 and for the three years ended
December 31, 1995, 1994 and 1993 appearing in this Prospectus have been audited
by Moss Adams LLP, independent public accountants, as indicated in their reports
with respect thereto, and are included herein in reliance upon authority of said
firm as experts in giving said reports.
The combined financial statements of LFC No. 38 Corp. and Portsmouth
Leasing Corporation and Subsidiaries and the consolidated financial statements
of LFC No. 60 Corp. and Subsidiary as of December 31, 1994 and 1993 and for the
years then ended appearing in this Prospectus have been audited by Coopers &
Lybrand L.L.P., independent accountants, as indicated in their reports with
respect thereto, and are included herein in reliance upon authority of said firm
as experts in giving said reports.
The financial statements of Gilroy Energy Company, a wholly owned
subsidiary of Gilroy Foods, Inc. which in turn is a wholly owned subsidiary of
McCormick & Company, Inc., at November 30, 1995 and 1994, and for each of the
two years in the period ended November 30, 1995, appearing in this Prospectus
and Registration Statement have been audited by Ernst & Young LLP, independent
auditors, as set forth in their report thereon appearing elsewhere herein, and
are included in reliance upon such report given upon the authority of such firm
as experts in accounting and auditing.
AVAILABLE INFORMATION
The Company has filed with the Commission a Registration Statement on Form
S-1 under the Securities Act with respect to the Common Stock offered hereby. As
permitted by the rules and regulations of the Commission, this Prospectus omits
certain information, exhibits and undertakings contained in the Registration
Statement. The Company is subject to the informational requirements of the
Securities Exchange Act of 1934, as amended (the "Exchange Act"), and, in
accordance therewith, files periodic reports and other information with the
Commission. For further information with respect to the Company and the Common
Stock offered hereby, reference is made to the Registration Statement, including
the exhibits thereto and the financial statements, notes and schedules filed as
a part thereof, as well as the periodic reports and other information filed by
the Company with the Commission, which may be inspected and copied at the Public
Reference Section of the Commission at Room 1024, Judiciary Plaza, 450 Fifth
Street, N.W., Washington, D.C. 20549 and at the regional offices of the
Commission located at 7 World Trade Center, 13th Floor, New York, New York 10048
and Suite 1400, Northwestern Atrium Center, 500 West Madison Street, Chicago,
Illinois 60661-2511. Copies of such materials may be obtained from the Public
Reference Section of the Commission, Room 1024, Judiciary Plaza, 450 Fifth
Street, N.W., Washington, D.C. 20549, and its public reference facilities in New
York, New York and Chicago, Illinois, at the prescribed rates. The Commission
maintains a Web site that contains reports, proxy and information statements and
other information regarding registrants, such as the Company, that file
electronically with the Commission and the address of such site is
http://www.sec.gov. Statements contained in this Prospectus as to the contents
of any contract or other document are not necessarily complete, and in each
instance reference is made to the copy of such contract or document filed as an
exhibit to the Registration Statement, each such statement being qualified in
all respects by such reference.
93
<PAGE> 294
(This page intentionally left blank)
<PAGE> 295
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
CALPINE CORPORATION
Report of Independent Public Accountants.............................................. F-3
Consolidated Balance Sheets, December 31, 1995 and 1994............................... F-4
Consolidated Statements of Operations for the Years Ended December 31, 1995, 1994 and
1993................................................................................ F-5
Consolidated Statements of Stockholder's Equity for the Years Ended December 31, 1995,
1994 and 1993....................................................................... F-6
Consolidated Statements of Cash Flows for the Years Ended December 31, 1995, 1994 and
1993................................................................................ F-7
Notes to Consolidated Financial Statements for the Years Ended December 31, 1995, 1994
and 1993............................................................................ F-8
Condensed Consolidated Balance Sheets, June 30, 1996 (unaudited) and December 31,
1995................................................................................ F-30
Condensed Consolidated Statements of Operations for the Six Months Ended June 30, 1996
and 1995 (unaudited)................................................................ F-31
Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 1996
and 1995 (unaudited)................................................................ F-32
Notes to Condensed Consolidated Financial Statements for the Six Months Ended June 30,
1996 and 1995 (unaudited)........................................................... F-33
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
Report of Independent Public Accountants.............................................. F-38
Consolidated Balance Sheets, December 31, 1995 and 1994............................... F-39
Consolidated Statement of Operations for the Years Ended December 31, 1995, 1994 and
1993................................................................................ F-40
Consolidated Statement of Changes in Partners' Deficit for the Years Ended December
31, 1995, 1994 and 1993............................................................. F-41
Consolidated Statement of Cash Flows for the Years Ended December 31, 1995, 1994 and
1993................................................................................ F-42
Notes to Consolidated Financial Statements for the Years Ended December 31, 1995, 1994
and 1993............................................................................ F-43
CALPINE GEYSERS COMPANY, L.P.
Report of Independent Public Accountants.............................................. F-52
Statement of Operations for the Period from January 1, 1993 to April 18, 1993......... F-53
Statement of Cash Flows for the Period from January 1, 1993 to April 18, 1993......... F-54
Notes to Financial Statements for the Period from January 1, 1993 to April 18, 1993... F-55
LFC NO. 38 CORP. AND PORTSMOUTH LEASING CORPORATION AND SUBSIDIARIES
Report of Independent Accountants..................................................... F-60
Combined Balance Sheets, December 31, 1994 and 1993................................... F-61
Combined Statement of Operations for the Years Ended December 31, 1994 and 1993....... F-62
Combined Statements of Changes in Shareholder's Deficiency for the Years Ended
December 31, 1994 and 1993.......................................................... F-63
Combined Statements of Cash Flows for the Years Ended December 31, 1994 and 1993...... F-64
Notes to Combined Financial Statements for the Years Ended December 31, 1994 and
1993................................................................................ F-65
LFC NO. 60 CORP. AND SUBSIDIARY
Report of Independent Accountants..................................................... F-69
Consolidated Balance Sheets, December 31, 1994 and 1993............................... F-70
Consolidated Statements of Operations for the Years Ended December 31, 1994 and
1993................................................................................ F-71
Consolidated Statements of Changes in Shareholder's Deficiency for the Years Ended
December 31, 1994 and 1993.......................................................... F-72
Consolidated Statements of Cash Flows for the Years Ended December 31, 1994 and
1993................................................................................ F-73
Notes to Consolidated Financial Statements for the Years Ended December 31, 1994 and
1993................................................................................ F-74
</TABLE>
F-1
<PAGE> 296
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
BAF ENERGY, A CALIFORNIA LIMITED PARTNERSHIP
Report of Independent Public Accountants.............................................. F-77
Balance Sheets, October 31, 1995 and 1994............................................. F-78
Statements of Income for the Years Ended October 31, 1995, 1994 and 1993.............. F-79
Statements of Partners' Equity for the Years Ended October 31, 1995, 1994 and 1993.... F-80
Statements of Cash Flows for the Years Ended October 31, 1995, 1994 and 1993.......... F-81
Notes to Financial Statements for the Years Ended October 31, 1995, 1994 and 1993..... F-82
Condensed Balance Sheets as of January 31, 1996 (unaudited) and October 31, 1995...... F-86
Condensed Statements of Income for the Three Months Ended January 31, 1996 and 1995
(unaudited)......................................................................... F-87
Condensed Statements of Cash Flows for the Three Months Ended January 31, 1996 and
1995 (unaudited).................................................................... F-88
Notes to Condensed Financial Statements as of January 31, 1996........................ F-89
GILROY ENERGY COMPANY
Report of Independent Auditors........................................................ F-91
Balance Sheets, November 30, 1995 and 1994 and May 31, 1996 (unaudited)............... F-92
Statements of Income for the Years Ended November 30, 1995 and 1994 and for the Six
Months Ended May 31, 1996 and 1995 (unaudited)...................................... F-93
Statement of Shareholder's Equity for the Years Ended November 30, 1995 and 1994 and
for the Six Months Ended May 31, 1996 (unaudited)................................... F-94
Statements of Cash Flows for the Years Ended November 30, 1995 and 1994 and for the
Six Months Ended May 31, 1996 and 1995 (unaudited).................................. F-95
Notes to Financial Statements for the Years Ended November 30, 1995 and 1994 and for
the Six Months Ended May 31, 1996 and 1995 (unaudited).............................. F-96
</TABLE>
F-2
<PAGE> 297
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, 1995
and 1994, and the related consolidated statements of operations, stockholder's
equity and cash flows for each of the three years in the period ended December
31, 1995. 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% and 2% of the Company's
total assets at December 31, 1995 and 1994, respectively. The Company has
recorded a loss of $3.0 million, $2.9 million and $1.9 million representing its
share of the net loss of Sumas for the years ended December 31, 1995, 1994 and
1993, 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, 1995 and 1994, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 1995 in conformity with
generally accepted accounting principles.
ARTHUR ANDERSEN LLP
San Jose, California
March 15, 1996 (except with respect to
the matter discussed in Note 26, as to
which the date is September 13, 1996)
F-3
<PAGE> 298
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 1995 AND 1994
(IN THOUSANDS)
<TABLE>
<CAPTION>
1995 1994
-------- --------
<S> <C> <C>
ASSETS
Current assets
Cash and cash equivalents..................................................... $ 21,810 $ 22,527
Accounts receivable
from related parties....................................................... 2,177 1,864
from others................................................................ 17,947 12,723
Acquisition project receivables............................................... 8,805 --
Prepaid expenses and other current assets..................................... 5,491 4,256
-------- --------
Total current assets.................................................. 56,230 41,370
Property, plant and equipment, net.............................................. 447,751 335,453
Investments in power projects................................................... 8,218 11,114
Capitalized project costs....................................................... 1,123 645
Notes receivable from related parties........................................... 19,391 16,882
Notes receivable from Coperlasa................................................. 6,394 --
Restricted cash................................................................. 9,627 10,813
Deferred charges and other assets............................................... 5,797 5,095
-------- --------
Total assets.......................................................... $554,531 $421,372
======== ========
LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities
Current non-recourse project financing........................................ $ 84,708 $ 22,800
Notes payable to bank and short-term borrowings............................... 1,177 4,500
Accounts payable.............................................................. 6,876 1,869
Accrued payroll and related expenses.......................................... 2,789 2,624
Accrued interest payable...................................................... 7,050 5,622
Other accrued expenses........................................................ 2,657 2,517
-------- --------
Total current liabilities............................................. 105,257 39,932
Long-term line of credit........................................................ 19,851 --
Non-recourse long-term project financing, less current portion.................. 190,642 196,806
Notes payable................................................................... 6,348 5,296
Senior Notes Due 2004........................................................... 105,000 105,000
Deferred income taxes, net...................................................... 97,621 50,928
Deferred revenue................................................................ 4,585 4,761
-------- --------
Total liabilities..................................................... 529,304 402,723
-------- --------
Commitments and contingencies (Note 25)
Stockholder's equity
Common stock, authorized 33,760 shares, issued and
outstanding -- 10,388 shares in 1995 and 1994.............................. 10 10
Additional paid-in capital.................................................... 6,214 6,214
Retained earnings............................................................. 19,034 12,456
Cumulative translation adjustment............................................. (31) (31)
-------- --------
Total stockholder's equity............................................ 25,227 18,649
-------- --------
Total liabilities and stockholder's equity............................ $554,531 $421,372
======== ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-4
<PAGE> 299
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
1995 1994 1993
-------- -------- --------
<S> <C> <C> <C>
Revenue
Electricity and steam sales.............................. $127,799 $ 90,295 $ 53,000
Service contract revenue from related parties............ 7,153 7,221 16,896
Income (loss) from unconsolidated investments in power
projects.............................................. (2,854) (2,754) 19
-------- ------- -------
Total revenue.................................... 132,098 94,762 69,915
-------- ------- -------
Cost of revenue
Plant operating expenses................................. 33,162 14,944 9,078
Depreciation............................................. 26,264 21,202 12,272
Production royalties..................................... 10,574 11,153 6,814
Operating lease expense.................................. 1,542 -- --
Service contract expenses................................ 5,846 5,546 14,337
-------- ------- -------
Total cost of revenue............................ 77,388 52,845 42,501
-------- ------- -------
Gross profit............................................... 54,710 41,917 27,414
Project development expenses............................. 3,087 1,784 1,280
General and administrative expenses...................... 8,937 7,323 5,080
Provision for write-off of project development costs..... -- 1,038 --
-------- ------- -------
Income from operations........................... 42,686 31,772 21,054
Other (income) expense
Interest expense
Related party......................................... 1,663 375 2,613
Other................................................. 30,491 23,511 11,212
Other income, net........................................ (1,895) (1,988) (1,133)
-------- ------- -------
Income before provision for income taxes and
cumulative effect of change in accounting
principle........................................... 12,427 9,874 8,362
Provision for income taxes............................... 5,049 3,853 4,195
-------- ------- -------
Income before cumulative effect of change in
accounting principle................................ 7,378 6,021 4,167
Cumulative effect of adoption of SFAS No. 109............ -- -- (413)
-------- ------- -------
Net income....................................... $ 7,378 $ 6,021 $ 3,754
======== ======= =======
As adjusted earnings per share assuming conversion of
preferred stock:
14,151
As adjusted weighted average shares outstanding.......... ========
$ 0.52
Net income per share..................................... ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-5
<PAGE> 300
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
(IN THOUSANDS)
<TABLE>
<CAPTION>
COMMON STOCK ADDITIONAL CUMULATIVE
--------------- PAID-IN RETAINED TRANSLATION
SHARES AMOUNT CAPITAL EARNINGS ADJUSTMENT TOTAL
------ ------ ---------- -------- ---------- -------
<S> <C> <C> <C> <C> <C> <C>
Balance, December 31, 1992....................... 10,388 $ 10 $6,214 $ 4,281 $ -- $10,505
Dividend ($0.08 per share)..................... -- -- -- (800 ) -- (800)
Net income..................................... -- -- -- 3,754 -- 3,754
Cumulative translation adjustment.............. -- -- -- -- (31) (31)
----- --- ------- ---- -------
Balance, December 31, 1993....................... 10,388 10 6,214 7,235 (31) 13,428
Dividend ($0.08 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 ($0.08 per share)..................... -- -- -- (800 ) -- (800)
Net income..................................... -- -- -- 7,378 -- 7,378
----- --- ------- ---- -------
Balance, December 31, 1995....................... 10,388 $ 10 $6,214 $19,034 $(31) $25,227
===== === ======= ==== =======
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-6
<PAGE> 301
CALPLNE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
(IN THOUSANDS)
<TABLE>
<CAPTION>
1995 1994 1993
-------- ------- -------
<S> <C> <C> <C>
Cash flows from operating activities
Net income................................................. $ 7,378 $ 6,021 $ 3,754
Adjustments to reconcile net income to net cash provided by
operating activities:
Depreciation and amortization, net...................... 25,931 20,342 11,318
Deferred income taxes, net.............................. (1,027) 3,180 4,619
(Income) loss from unconsolidated investments in power
projects.............................................. 2,854 2,754 (19)
Distributions from investments in power projects........ -- -- 7,352
Provision for write-off of project development costs.... -- 1,038 --
Change in operating assets and liabilities:
Accounts receivable................................... (3,354) (2,578) (615)
Acquisition project receivables....................... (8,805) -- --
Other current assets.................................. (737) 79 (956)
Accounts payable and accrued expenses................. 6,847 6,218 (3,040)
Deferred revenue...................................... (2,434) (2,858) 1,897
-------- -------- --------
Net cash provided by operating activities.......... 26,653 34,196 24,310
-------- -------- --------
Cash flows from investing activities
Acquisition of property, plant and equipment............... (17,434) (7,023) (8,445)
Acquisition of Greenleaf, net of cash on hand.............. (14,830) -- --
Investment in Watsonville, net of cash on hand............. 494 -- --
Acquisition of TPC, net of cash on hand.................... -- (62,770) --
Acquisition of CGC, net of CGC cash on hand................ -- -- (20,296)
Increase in notes receivable............................... (6,348) (13,556) --
Investments in power projects.............................. -- (118) (627)
Capitalized project costs.................................. (1,258) (175) (952)
Decrease (increase) in restricted cash..................... 1,186 (900) 2,968
Other, net................................................. (307) 98 270
-------- -------- --------
Net cash used in investing activities.............. (38,497) (84,444) (27,082)
-------- -------- --------
Cash flows from financing activities
Payment of dividends....................................... (800) (800) (800)
Borrowings from line of credit............................. 34,851 -- 23,000
Repayments of line of credit............................... (15,000) (52,595) (5,873)
Borrowings from non-recourse project financing............. 76,026 60,000 --
Repayments of non-recourse project financing............... (79,388) (12,735) (8,800)
Short-term borrowings...................................... 2,683 4,500 --
Repayments of short-term borrowings........................ (6,006) -- --
Senior Notes Due 2004...................................... -- 105,000 --
Financing costs............................................ (1,239) (3,921) (749)
Repayment of note payable to shareholder................... -- (1,200) --
Proceeds from note payable................................. -- 5,167 --
Repayment of notes payable -- FMRP......................... -- (36,807) --
-------- -------- --------
Net cash provided by financing activities.......... 11,127 66,609 6,778
-------- -------- --------
Net increase (decrease) in cash and cash equivalents......... (717) 16,361 4,006
Cash and cash equivalents, beginning of period............... 22,527 6,166 2,160
-------- -------- --------
Cash and cash equivalents, end of period..................... $ 21,810 $22,527 $ 6,166
======== ======== ========
Supplementary information -- cash paid during the year for:
Interest................................................... $ 32,162 $19,890 $15,084
Income taxes............................................... 4,294 683 13
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-7
<PAGE> 302
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
1. ORGANIZATION AND OPERATIONS OF THE COMPANY
Calpine Corporation (Calpine) and subsidiaries (collectively, the Company)
are engaged in the development, acquisition, ownership and operation of power
generation facilities in the United States. 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, 1995, primarily all electricity and steam sales revenue from consolidated
subsidiaries was derived from sales to two customers in Northern California (see
Note 24), of which 73% related to geothermal activities.
Founded in 1984, the Company is wholly owned by Electrowatt Services, Inc.,
which is wholly owned by Electrowatt Ltd. (Electrowatt), a Swiss company. The
Company has expertise in the areas of engineering, finance, construction and
plant operations and maintenance.
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. During 1993, the Company acquired the remaining
interests in Calpine Geysers Company, L.P. (CGC) (see Note 3). Prior to the
acquisition, the Company recognized its share of the net income of CGC under the
equity method of accounting. 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).
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 for further information regarding
TPC.
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 4), the estimated "free steam" liability (see Revenue Recognition and
Deferred Revenue), receivables which the Company believes to be collectible (see
Note 10), and the realization of deferred income taxes (see Note 19).
Revenue Recognition and Deferred Revenue -- 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
F-8
<PAGE> 303
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
May 1992. Had the Company applied this principle, the revenues of the Company
recorded for the years ended December 31, 1995 and 1994, and for the period from
April 19, 1993 to December 31, 1993, would have been approximately $12.6
million, $11.9 million and $6.5 million less, respectively.
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. In May 1994, the Company 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 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.
The Company performs operations and maintenance services for projects in
which it has an interest. Revenue from investees is recognized on these
contracts when the services are performed. Revenue from consolidated
subsidiaries are 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, their carrying value approximates fair value. Such cash
is excluded from cash and cash equivalents for the purposes of the statements of
cash flows.
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 five
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 8).
Property, Plant and Equipment -- Property, plant and equipment are stated
at cost less accumulated depreciation and amortization.
The Company capitalizes costs incurred in connection with the development
of geothermal properties, including costs of drilling wells and overhead
directly related to development activities, together with the costs of
production equipment, the related facilities and the operating power plants.
Geothermal properties include the value attributable to the geothermal resources
of CGC and all of the property, plant and equipment of 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
F-9
<PAGE> 304
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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. Depreciation of office equipment is provided on the straight-line method
over useful lives of three to five years. Amortization of leasehold improvements
is provided based on the straight-line method over the lesser of the useful life
of the asset or the life of the 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, 1995 and 1994, the components of property, plant and
equipment are (in thousands):
<TABLE>
<CAPTION>
1995 1994
-------- --------
<S> <C> <C>
Geothermal properties.......................................... $216,042 $209,243
Buildings...................................................... 147,532 29,149
Machinery and equipment........................................ 50,826 47,125
Wells and well pads............................................ 44,706 43,982
Steam gathering and control systems............................ 28,363 28,296
Roads.......................................................... 7,384 7,384
Miscellaneous assets........................................... 2,425 1,694
-------- --------
497,278 366,873
Less accumulated depreciation and amortization................. 60,511 34,020
-------- --------
436,767 332,853
Land........................................................... 754 413
Construction in progress....................................... 10,230 2,187
-------- --------
Property, plant and equipment, net........................... $447,751 $335,453
======== ========
</TABLE>
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 11).
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 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.
As Adjusted Earnings Per Share -- Net income per share is computed using
weighted average shares outstanding, which includes the net additional number of
shares which would be issuable upon the exercise of outstanding stock options,
assuming that the Company used the proceeds received to purchase additional
shares at an assumed public offering price. Net income per share also gives
effect, even if antidilutive, to common equivalent shares from preferred stock
that will automatically convert upon the closing of the
F-10
<PAGE> 305
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Company's initial public offering (using the as-if-converted method). If the
offering contemplated by the Company is consummated, all of the convertible
preferred stock outstanding as of the closing date will automatically be
converted into shares of common stock based on the shares of convertible
preferred stock outstanding at June 30, 1996.
Reclassifications -- Prior years' amounts in the consolidated financial
statements have been reclassified where necessary to conform to the 1995
presentation.
3. CALPINE GEYSERS COMPANY, L.P.
CGC, an indirect 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 terms of the agreements which began in 1989, CGC is paid
for energy delivered based upon a fixed price which escalates annually through
December 1998, and upon PG&E's full short-run avoided operating costs for the
subsequent ten years. CGC also receives capacity payments from PG&E. Under
certain circumstances, if CGC is unable to deliver firm capacity, then CGC may
owe PG&E certain minimum damages as specified in the agreements.
Under the steam sales agreements with PG&E and SMUD, the price paid for the
steam is determined annually and semiannually, respectively, based on contract
price formulas and steam delivery terms.
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 (see Note 2). 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.
Prior to April 19, 1993 the Company owned a minority interest in CGC and
recognized its share of CGC's net income under the equity method. 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 from Natomas Energy Company (Natomas), a wholly owned subsidiary of
Maxus Energy Company, pursuant to a Stock Purchase Agreement dated June 27,
1994. Under the terms of the Stock Purchase Agreement, Calpine Thermal acquired
the 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. At or subsequent to the closing of the
acquisition, Calpine received payments of $3.0 million from Natomas, 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.
The Company funded the cash portion of the purchase price in the acquisition
F-11
<PAGE> 306
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
through a two-year non-recourse secured financing provided by The Bank of Nova
Scotia pursuant to a Credit Agreement dated September 9, 1994 (see Note 16).
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, a wholly owned subsidiary of Unocal
Corporation, 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, Calpine Thermal
experienced extensive curtailments of steam production due to low gas prices and
abundant hydro power.
In March 1995, PG&E notified Union Oil and TPC of its plan to accelerate
the retirement of the geothermal power plants to which steam is supplied.
Calpine Thermal had considered plant retirements in its analysis leading to the
acquisition of TPC in September 1994. Calpine Thermal had no assurance that PG&E
would follow the accelerated schedule which was not in accordance with the terms
and conditions of the steam sales agreement, and, with Union Oil, entered into
intensive discussions with PG&E regarding alternatives. As a result of those
discussions, the March 1995 accelerated closure schedule has been reevaluated in
accordance with expected steam supply projections, curtailment levels, and
actual contract terms and conditions to result in estimates of future project
output and revised closure schedules. Closure schedules will continue to be
modified throughout the life of the power sales agreement to be consistent with
actual production levels based on competitive energy prices and weather.
On August 9, 1995, the Company, Union Oil and PG&E executed a letter
agreement on alternative steam pricing for the calendar year 1995. Under this
agreement, all steam delivered up to 40% of field capacity remained at the
original contract rate, and all other steam was sold at a 33% reduction to the
contract rate, thus lowering the cost to PG&E and enhancing production and
revenue from The Geysers to Union Oil and Calpine Thermal. On February 1, 1996,
the Company and Union Oil entered into an alternative steam pricing agreement
with PG&E for the month of February 1996, which was subsequently extended
through at least March 15, 1996. The parties to this agreement are currently in
the process of negotiating a longer term alternative pricing agreement. The
Company is unable to predict the sales and prices that may result from such an
alternative pricing program.
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 two years 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-12
<PAGE> 307
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) from Radnor Power Corporation (Radnor)
for $80.5 million pursuant to a Share Purchase Agreement dated March 30, 1995.
The Acquired Companies own 100% of the assets of two 49.5 megawatt natural
gas-fired cogeneration facilities (collectively, the Greenleaf facilities),
Greenleaf Unit One and Greenleaf Unit Two, located in Yuba City in Northern
California. The Greenleaf facilities burn natural gas in the cogeneration of
electrical and thermal energy. The Greenleaf facilities produce electrical power
for sale to PG&E pursuant to two long-term power sales agreements that provide
for electricity payments over an original thirty-year period (expiring in 2019)
at prices equal to PG&E's full short-run avoided operating costs, adjusted
annually. In addition, the Company receives 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 facilities due to hydro-spill or uneconomic cost conditions. The
thermal energy generated is used by thermal hosts adjacent to the Greenleaf
facilities. The Greenleaf facilities are qualifying facilities, as defined by
the Public Utility Regulatory Policies Act of 1978, as amended (PURPA).
Natural gas for the Greenleaf facilities is supplied by Montis Niger, Inc.
(MNI) pursuant to a long-term gas purchase agreement, and by Chevron USA
Production Company (Chevron). MNI is a wholly owned subsidiary of LFC Financial
Corporation, the parent company of Radnor. See Note 25 for further information
regarding these agreements.
The acquisition was accounted for as a purchase and the purchase price has
been allocated to the acquired assets and liabilities based on the estimated
fair values of the acquired assets and liabilities as shown below. The
allocation may be adjusted as additional information becomes available (in
thousands):
<TABLE>
<S> <C>
Current assets.................................................... $ 6,572
Property, plant and equipment..................................... 120,752
--------
Total assets.................................................... 127,324
--------
Current liabilities............................................... (944)
Deferred income taxes, net........................................ (45,844)
--------
Total liabilities............................................... (46,788)
--------
Net purchase price................................................ $ 80,536
========
</TABLE>
The purchase price included a cash payment of $20.3 million and the
assumption of project debt totalling $60.2 million. The final purchase price,
which is to be adjusted after the determination of the final net working capital
amount, was determined upon an arms-length transaction between Calpine and
Radnor. The parties are currently in dispute regarding certain provisions of the
Share Purchase Agreement, and the outcome of the dispute may affect the purchase
price.
The $20.3 million cash payment was funded by borrowings from the Credit
Suisse lines of credit described in Note 13 below. The $60.2 million debt
assumed by the Company in the acquisition of the Greenleaf facilities consisted
of $57.6 million of non-recourse long-term project financing payable to Credit
Suisse and $2.6 million of installment payments to individuals. On June 30,
1995, the Company refinanced the Greenleaf project by borrowing $76.0 million
from banks (described in Note 16 below). Net proceeds of $74.9 million were used
to repay $57.5 million of Credit Suisse debt including interest, and $2.9
million of installment and premium payments to individuals. The remaining $14.5
million of net proceeds and $500,000 of internal funds were used to repay the
Credit Suisse line of credit borrowings related to the Greenleaf project.
F-13
<PAGE> 308
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Pro forma consolidated results for the Company as if the Greenleaf
acquisition had been consummated on January 1, 1995 and as if the Greenleaf and
TPC acquisitions had been consummated on January 1, 1994, respectively, are (in
thousands, except per share amounts):
<TABLE>
<CAPTION>
YEAR ENDED
-----------------------------
DECEMBER 31, DECEMBER 31,
1995 1994
------------ ------------
(UNAUDITED)
<S> <C> <C>
Revenue.................................................... $137,412 $143,137
Net income................................................. $ 4,868 $ 11,708
Earnings per share (assuming stock split and conversion of
preferred stock; see Note 2)............................. $ 0.34
</TABLE>
The pro forma information does not purport to be indicative of results that
actually would have occurred had the acquisition been made on the dates
indicated or of results which may occur in the future.
Also in connection with the Greenleaf acquisition, the Company borrowed
$1.9 million on April 21, 1995 against an uncommitted demand loan facility with
The Bank of Nova Scotia to finance the prepayment for natural gas to be
delivered to the Greenleaf facilities from MNI (see Note 13 for further
information).
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 in Northern California. The Company acquired the
operating lease from Ford Motor Credit Company, acting through its agent, USL
Capital Corporation, for $900,000. The Watsonville plant sells electricity to
PG&E under the terms of a 20-year power sales agreement, generally at prices
equal to PG&E's full short-run avoided operating costs. Basic and contingent
lease rental payments are described in Note 25. As a cogenerator, the plant
provides steam to two local food processing plants, and is a qualifying facility
as defined by PURPA. The Company also provides project and fuels management
services.
In connection with this acquisition, the Company obtained a $5.0 million
uncommitted line of credit with The Bank of Nova Scotia for letters of credit.
On December 31, 1995, the Company had $2.9 million of letters of credit
outstanding (see Note 13 for further information).
7. CALPINE SISKIYOU GEOTHERMAL PARTNERS, L.P.
On August 24, 1994, the Company formed a partnership with Trans-Pacific
Geothermal Glass Mountain, Ltd. (TGGM), an affiliate of Trans-Pacific Geothermal
Corporation of Oakland, California, and is planning to build a geothermal power
generation facility. The power generation facility will be located at Glass
Mountain in Northern California near the Oregon border. The partnership is
consolidated as the Company owns a controlling interest.
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
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 will loan up to $18.5 million to
Coperlasa, and will receive fees for technical services provided to the project.
At December 31, 1995, notes receivable (see Note 12) totaled $4.9 million. In
February 1996, the Company loaned an additional $3.4 million to Coperlasa.
F-14
<PAGE> 309
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In December 1995, Calpine Vapor also paid $1.5 million for an option to
purchase an equity interest in Coperlasa. The option expires in May 1997 and is
being amortized over the estimated repayment period of the Coperlasa loan
(through the year 1999) using the interest method, as the Company views the
option as a loan acquisition fee. The unamortized balance of the option is also
included in notes receivable from Coperlasa.
9. ACCOUNTS RECEIVABLE
The Company has both billed and unbilled receivables. The components of
accounts receivable as of December 31, 1995 and 1994 are as follows (in
thousands):
<TABLE>
<CAPTION>
1995 1994
------- -------
<S> <C> <C>
Billed........................................................... $18,341 $13,809
Unbilled......................................................... 525 768
Other............................................................ 1,258 10
------- -------
$20,124 $14,587
======= =======
</TABLE>
Other accounts receivable consist primarily of disputed amounts related to
the Greenleaf facilities purchase price (see Note 5).
Accounts receivable from related parties at December 31, 1995 and 1994
include the following (in thousands):
<TABLE>
<CAPTION>
1995 1994
------ ------
<S> <C> <C>
O.L.S. Energy-Agnews, Inc.......................................... $ 806 $ 538
Geothermal Energy Partners, Ltd.................................... 462 793
Sumas Cogeneration Company, L.P.................................... 908 528
Electrowatt and subsidiaries....................................... 1 5
------ ------
$2,177 $1,864
====== ======
</TABLE>
10. ACQUISITION PROJECT RECEIVABLES
On October 17, 1995, in connection with the Company's unsuccessful bid to
acquire O'Brien Environmental Energy, Inc. (OEE) through the U.S. Bankruptcy
Court -- District of New Jersey proceedings, the Company purchased accounts
receivable of $1.9 million, and two notes receivable totaling $3.7 million. The
remaining balance of $3.2 million represents capitalized project acquisition
costs. The recovery of these costs is subject to approval by the U.S. Bankruptcy
Court in 1996.
The Company purchased $1.9 million of accounts receivable from two
cogeneration facilities owned by subsidiaries of OEE. Payments are made to the
Company based on cash availability for each project. In February 1996, the
Company received approximately $1.1 million against these receivables. The
Company currently expects repayment of the balance of these accounts receivable
during 1996.
The Company purchased for $900,000 from Stewart & Stevenson, Inc. (S&S) a
90% participation interest in a $1.0 million note issued by OEE (the O'Brien
Note). Calpine and S&S entered into an agreement in February 1996 whereby S&S
assigned 100% of its interest in the O'Brien Note to Calpine, without any
additional consideration. Interest accrues at approximately 5% after January 20,
1996. The Company currently expects repayment of the note receivable during
1996.
The Company entered into a purchase agreement for all of S&S's rights and
obligations in a Subordinated Loan Agreement dated March 11, 1994 between S&S
and O'Brien (Newark) Cogeneration, Inc. (O'Brien Newark), the Subordinated Note
relating thereto and any related documents and agreements. The purchase price
was $2.8 million and the notes bear interest at prime plus 2.0%. The Company
receives
F-15
<PAGE> 310
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
$80,000 per month until the note is fully amortized. As of December 31, 1995,
$2.7 million of principal was receivable bearing interest at 10.5%. Through
February 1996, the Company received $160,000 in payment of this note. The
Company currently expects repayment of the note receivable upon restructuring of
O'Brien Newark debt during 1996.
11. INVESTMENTS IN POWER PROJECTS
As of December 31, 1995, 1994 and 1993, the Company had unconsolidated
investments in power projects which are accounted for under the equity method.
Financial information related to these investments is as follows (in thousands):
<TABLE>
<CAPTION>
SUMAS O.L.S. GEOTHERMAL
COGENERATION ENERGY- ENERGY
COMPANY, AGNEWS, PARTNERS,
1995 L.P.(A) INC. LTD.
---------------------------------------- ------------ ------- ----------
<S> <C> <C> <C> <C>
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.......... (b) 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) 277
-------- ------- -------
</TABLE>
<TABLE>
<CAPTION>
SUMAS O.L.S. GEOTHERMAL
COGENERATION ENERGY- ENERGY
COMPANY, AGNEWS, PARTNERS,
1994 L.P.(A) INC. LTD.
---------------------------------------- ------------ ------- ----------
<S> <C> <C> <C> <C>
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.......... (b) 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
-------- ------- -------
</TABLE>
F-16
<PAGE> 311
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
<TABLE>
<CAPTION>
SUMAS O.L.S. GEOTHERMAL CALPINE
COGENERATION ENERGY- ENERGY GEYSERS
COMPANY, AGNEWS, PARTNERS, COMPANY,
1993 L.P.(A) INC. LTD. L.P.(C)
---------------------------------------- ------------ ------- ---------- -------
<S> <C> <C> <C> <C>
Operating revenue....................... $ 23,671 $12,485 $ 18,451 $20,759
Net income (loss)....................... (3,739) (931) 1,090 2,689
Assets.................................. 134,579 44,249 74,994 --
Liabilities............................. 123,279 42,249 61,503 --
Company's percentage ownership.......... (b) 20% 5% --
Equity investments in power projects.... 11,700 515 674 --
Project development costs............... 981 17 7 --
-------- ------- ------- -------
Total investments in power projects..... $ 12,681 $ 532 $ 681 $ --
Company's share of net income (loss).... (1,870) (127) 55 1,961
-------- ------- ------- -------
</TABLE>
- ---------------
(a) Commercial operations commenced April 1993 and dry kiln operations commenced
in May 1993.
(b) 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%.
(c) 1993 CGC information is for the period from January 1, 1993 to April 19,
1993, the date of the acquisition. Subsequent to April 19, 1993, the
operating results of CGC are included in the accounts of the Company.
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 is the owner and operator of a power generation facility (the
Generation Facility) in Sumas, Washington. The Generation Facility is a natural
gas-fired combined cycle electrical generation plant with a production capacity
of approximately 125 megawatts. In connection with the Generation Facility,
there 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 Generation Facility.
Sumas produces and sells electrical energy to Puget Sound Power & Light
Company (Puget) under a 20-year agreement for approximately 110 megawatts of
power, which was subsequently increased to an average 123 megawatts in 1994.
Sumas leases the dry kiln facility and sells steam to Socco, Inc. (Socco), a
custom lumber drying operation owned by an affiliated individual. Under the kiln
lease and steam sale agreements with Socco, both of which are for 20 years, the
Generating Facility is a qualifying facility as defined by PURPA.
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. Sumas established
and funded all reserve accounts as required under the terms of the loan
agreements with Prudential and Credit Suisse.
In addition to its interest stated above, the Company has been contracted
by Sumas to provide operations and maintenance services. For these services, the
Company receives a fixed fee of $1.1 million per year
F-17
<PAGE> 312
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
adjusted annually based on the Consumer Price Index, an annual base fee of
$150,000 per year also adjusted based on the Consumer Price Index and certain
other reimbursable expenses. In addition, 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, $1.9 million
and $1.4 million associated with this arrangement during the years ended
December 31, 1995, 1994 and 1993, respectively.
The Company has also provided construction management services to the Sumas
project. The Company recorded revenue of approximately $72,300 and $934,000
related to construction management services during the years ended December 31,
1994 and 1993, respectively. The Company defers the profit on these contracts,
to the extent of their ultimate ownership percentage, and amortizes it over the
life of the project.
Calpine Geysers Company, L.P. -- In addition to its interest as stated
above, the Company had been contracted by CGC to provide operations and
maintenance services at cost plus overhead and fees. The Company recorded
revenue of approximately $6.8 million associated with this service agreement and
for other services provided to CGC for the period from January 1, 1993 to April
19, 1993.
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, which commenced operations in December 1990, 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
$1.5 million, $1.4 million and $2.3 million associated with this service
agreement and for other services provided to the joint venture for the years
ended December 31, 1995, 1994 and 1993, 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 Facility 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 $3.5 million,
$3.7 million and $4.5 million associated with this service agreement to GEP for
the years ended December 31, 1995, 1994 and 1993, respectively.
The Company accounts for its investment in GEP under the equity methods
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.
12. NOTES RECEIVABLE
On May 25, 1993, in accordance with certain provisions of the Sumas
partnership agreement, the Company was entitled to receive a distribution of
$1.5 million. In addition, in accordance with provisions of
F-18
<PAGE> 313
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
the Sumas partnership agreement, SEI 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 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. The Company is deferring the
recognition of interest income from this note until Sumas generates net income.
On March 15, 1994, the Company completed a $10.0 million loan to the sole
shareholder of SEI, the Company's partner in Sumas. The loan matures in 10 years
and bears interest at 16.25%. The loan is secured by a pledge to Calpine of the
partner's interest in Sumas. In order to provide for the payment of principal
and interest on the loan, an additional 25% of the cash flow generated by Sumas,
estimated to begin in 1996, has been assigned to Calpine. The Company is
deferring the recognition of interest income from this note until Sumas
generates net income.
On August 25, 1994, the Company entered into a loan agreement providing for
loans up to $4.8 million to TGGM (see Note 7). The loan bears interest at 10%
and has a maturity date which is based on certain future events. Based on
current forecasts, the maturity date will be in the year 2022. The loan is
secured by a pledge to Calpine of the partner's interest in the project. The
Company is deferring the recognition of income from this note until the Glass
Mountain project generates sufficient income to support collectibility of
interest earned. As of December 31, 1995, $3.8 million was outstanding.
As of December 31, 1995, Calpine Vapor had notes receivable of $4.9 million
and unamortized loan acquisition fees of $1.5 million from Coperlasa (see Note
8). Interest accrues on the $4.9 million of outstanding notes receivable at
approximately 18.8% and is due semi-annually. Principal payments in six equal
installments are due beginning in May 1997 through November 1999. In January
1996, the Company loaned an additional $3.4 million to Coperlasa. The fair value
of the notes receivable approximates its carrying value since the loan was
entered into near the end of 1995.
13. REVOLVING CREDIT FACILITY AND LINES OF CREDIT
At December 31, 1995, the line of credit with Credit Suisse (whose parent
company owns approximately 44.9% of Electrowatt) provided for advances of $50.0
million. Interest may be paid at either LIBOR or the Credit Suisse base rate,
plus applicable margins in both cases. 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). At the Company's discretion, the debt outstanding
can be held for various maturity periods of up to six months. 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. No
stated amortization exists for this indebtedness. From January 1 to March 13,
1996, the Company borrowed an additional $8.8 million and issued a letter of
credit for $3.0 million to fund an additional loan to Coperlasa (see Note 8) and
other developmental project and working capital requirements. No borrowings were
outstanding at December 31, 1994. The credit agreement specifies that the
Company maintain certain covenants with which the Company was in compliance.
At December 31, 1995, the Company 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, with
interest 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). At December 31, 1994, no borrowings and $900,000 of letters
of credit were outstanding on these facilities. The credit agreements specify
that the Company maintain certain covenants with which the Company was in
compliance.
F-19
<PAGE> 314
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
14. 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, 1995. At
December 31, 1994, $4.5 million was outstanding under the working capital
agreement, with interest at 7.625%. The Company had letters of credit
outstanding of $459,000 at December 31, 1995 and 1994. Outstanding letters of
credit bear interest at 0.625% payable quarterly.
15. NOTE PAYABLE TO STOCKHOLDER
On December 31, 1991, the Company declared a dividend of $1.2 million to
its parent company, Electrowatt Services, Inc. On the same date, the Company
issued a note payable to Electrowatt Services, Inc. for $1.2 million. Interest
was paid quarterly at a rate of 4.25%, which approximated market. The note was
paid on June 30, 1994, the maturity date.
16. NON-RECOURSE PROJECT FINANCING
The components of non-recourse project financing as of December 31, 1995
and 1994 are (in thousands):
<TABLE>
<CAPTION>
1995 1994
-------- --------
<S> <C> <C>
Senior-term loans
Fixed rate portion............................................. $ 99,400 $116,800
Variable rate portion.......................................... 20,000 20,000
Premium on debt................................................ 2,959 4,341
-------- --------
Total senior-term loans................................ 122,359 141,141
Junior-term loans................................................ 19,965 19,965
Notes payable to banks........................................... 133,026 58,500
-------- --------
Total long-term debt................................... 275,350 219,606
Less current portion................................... 84,708 22,800
-------- --------
Long-term debt, less current portion................... $190,642 $196,806
======== ========
</TABLE>
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 0.75% to 1.25% (6.69% and 7.25% at December 31,
1995 and 1994, respectively) over the term of the loan, collateralized by all of
CGC's assets and the Company's interest in CGC. In connection with the
acquisition of CGC's assets in 1993, the Company recorded a premium on the fixed
rate portion of the senior-term loans reflecting the fixed rate in excess of
market. The premium is amortized over the life of the fixed rate portion of the
loan using the interest method, and the unamortized balance is included in
long-term debt outstanding.
On January 2, 1996, $5.4 million of principal was repaid, and $2.5 million
of interest calculated through January 1, 1996 was paid.
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 1.5% to 2.75% (7.69% and 8.5% at December 31, 1995 and 1994,
respectively) over the term of the loan, collateralized by all of CGC's assets
and the Company's interest in CGC.
F-20
<PAGE> 315
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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, with a commercial bank and a financing company, effectively fix the
interest on this portion at 9.93%. The Company records the fixed rate interest
as interest expense. At December 31, 1995, the swap agreements were applicable
to debt with a principal balance total of $99.4 million. The interest rate swap
agreements mature through December 31, 2000. The premium on debt was recorded in
conjunction with the acquisition as discussed above. The premium effectively
adjusts the recognized 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 1.0% (6.99%) at December 31, 1995 and LIBOR plus 0.75% (7.25%) at
December 31, 1994. The Company is exposed to credit risk in the event of non-
performance by the other parties to the agreements.
Notes Payable to Banks -- On September 9, 1994, the Company entered into a
two-year agreement with The Bank of Nova Scotia to finance the acquisition of
TPC. As of December 31, 1995, the Company had $57.0 million of non-recourse
project financing outstanding under this agreement. This indebtedness is secured
by TPC's interest in The Geysers steam field assets. Among other restrictions,
TPC is required to maintain an interest coverage ratio of at least 2.5 to 1.0,
and to maintain a loan to value ratio (as defined) of no more than 0.7 to 1.0.
At the Company's discretion, the debt outstanding can be held for various
maturity periods of at least 30 days up to the final maturity date, September 9,
1996. The entire outstanding balance bears interest at variable rates currently
based on LIBOR plus 1% (averaging 6.9% as of December 31, 1995). Interest is
paid on each maturity date, but not less often than quarterly, based on the
principal amount outstanding during the period. No stated principal amortization
exists for this indebtedness. The Company may elect to repay principal at any
time. All unpaid principal is due and payable on September 9, 1996. The Company
currently intends to refinance the $57.0 million of debt before September 9,
1996.
On June 26, 1995, the Company entered into an agreement with Sumitomo Bank
to finance the acquisition of the Greenleaf facilities. Of the $76.0 million
debt outstanding at December 31, 1995, $60.0 million bears interest fixed at
7.4%, with the remaining floating rate portion accruing interest at LIBOR plus
an applicable margin (6.5% as of December 31, 1995). This debt is secured by all
of the assets of Greenleaf Unit One and Greenleaf Unit Two. 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 $76.0 million debt will be repaid quarterly, with a final
maturity date of December 31, 2010.
The annual principal maturities of the non-recourse long-term debt
outstanding at December 31, 1995 are as follows (in thousands):
<TABLE>
<S> <C>
1996.............................................................. $ 84,708
1997.............................................................. 24,772
1998.............................................................. 25,993
1999.............................................................. 18,733
2000.............................................................. 17,991
Thereafter........................................................ 100,194
--------
272,391
Unamortized premium on fixed portion of senior loan............... 2,959
--------
Total................................................... $275,350
========
</TABLE>
The carrying value of $99.4 million and $116.8 million of the senior-term
loan as of December 31, 1995 and 1994, respectively, has an effective rate of
9.93% under the Company's interest rate swap agreements
F-21
<PAGE> 316
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(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, 1995 and 1994 is
approximately $107.3 million and $120.0 million, respectively. The carrying
value of the remaining $20.0 million of the senior and the $20.0 million
junior-term loans and the long-term notes payable to banks approximates the
debt's fair market value as the rates are variable and based on the current
LIBOR rate.
The non-recourse long-term 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.
17. LONG-TERM NOTES PAYABLE
At December 31, 1995, 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 $5.7 million at
December 31, 1995 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 $627,000 of the discounted non-interest bearing note at
December 31, 1995 approximates fair market value.
18. SENIOR NOTES DUE 2004
On February 17, 1994, the Company completed a $105.0 million public debt
offering of 9 1/4% Senior Notes Due 2004 (Senior Notes). The net proceeds of
$100.9 million were used to repay all of the indebtedness outstanding under the
Company's existing line of credit, and to repay the non-recourse notes payable
to FMRP plus accrued interest (see Note 3). The remaining proceeds were used for
general corporate purposes, including the loan to the sole shareholder of SEI
discussed in Note 12. The 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 Senior Notes using the interest
method.
The Senior Notes will mature on February 1, 2004 and bear interest at
9 1/4% payable semiannually on February 1 and August 1 of each year, commencing
August 1, 1994, to holders of record. Based on the traded yield to maturity, the
approximate fair market value of the Senior Notes was $97.0 million as of
December 31, 1995. The agreement specifies that the Company maintain certain
covenants with which the Company was in compliance.
Under provisions of the indenture applicable to the Senior Notes, 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.
19. PROVISION FOR INCOME TAXES
Effective January 1, 1993, the Company adopted Statement of Financial
Accounting Standard No. 109 Accounting for Income Taxes (SFAS No. 109) and
recorded $413,000 as the cumulative effect of adoption in the accompanying
financial statements. SFAS No. 109 requires that the Company follow the
liability method of accounting for income taxes whereby deferred income taxes
are recognized for the tax consequences of
F-22
<PAGE> 317
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
"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, 1995 and
1994 are (in thousands):
<TABLE>
<CAPTION>
1995 1994
--------- --------
<S> <C> <C>
Deferred state income taxes................................... $ 256 $ 1,389
Expenses deductible in a future period........................ 1,865 1,536
Net operating loss and credit carryforwards................... 19,797 15,566
Other differences............................................. 2,034 1,129
--------- --------
Deferred tax asset, before valuation allowance.............. 23,952 19,620
Valuation allowance........................................... (749) (749)
--------- --------
Deferred tax asset.......................................... 23,203 18,871
--------- --------
Property differences.......................................... (116,763) (66,552)
Difference in taxable income and income from investments
recorded on the equity method............................... (2,311) (2,119)
Other differences............................................. (1,750) (1,128)
--------- --------
Deferred tax liabilities.................................... (120,824) (69,799)
--------- --------
Net deferred tax liability............................... $ (97,621) $(50,928)
========= ========
</TABLE>
The net operating loss and credit carryforwards consist of Federal and
State net operating loss carryforwards which expire 2005 through 2010 and 1999,
respectively, and Federal and State alternative minimum tax credit carryforwards
which can be carried forward indefinitely. During 1991, the State of California
suspended the usage of net operating loss carryforwards available to reduce
taxable income for 1992 and 1991. In September 1993, the State of California
removed the suspension on utilization of net operating loss carryforwards,
although they can only be carried forward five years. Fifty percent of the State
net operating loss carryforwards are available to reduce future taxable income.
During 1993, the Company increased the tax provision by approximately $700,000
as a result of the change in the California State Tax regulations. At December
31, 1995, Federal and State net operating loss carryforwards were approximately
$41.8 million and $7.2 million, respectively. At December 31, 1995 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, 1995, Federal and State alternative minimum tax carryforwards were
approximately $3.2 million and $1.6 million, respectively.
Realization of the deferred tax assets and federal net operating loss
carryforwards is dependent on generating sufficient taxable income prior to
expiration of the loss carryforwards. 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.
F-23
<PAGE> 318
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The provision for income taxes for the years ended December 31, 1995, 1994
and 1993 consists of the following (in thousands):
<TABLE>
<CAPTION>
1995 1994 1993
------ ------ ------
<S> <C> <C> <C>
Current
Federal................................................ $3,085 $ 96 $ --
State.................................................. 1,163 365 11
Deferred
Federal, excluding items listed below.................. 816 2,546 2,581
Adjustment in federal tax rate...................... -- -- 88
State, excluding items listed below.................... (15) 547 1,250
Utilization of net operating loss carryforwards..... -- -- (192)
Increase in valuation allowance..................... -- 299 457
------ ------ ------
Total provision................................ $5,049 $3,853 $4,195
====== ====== ======
</TABLE>
The Company's effective rate for income taxes for the years ended December
31, 1995, 1994 and 1993 differs from the U.S. statutory rate for the same
periods due to state income taxes, depletion allowances and the limitation on
use of state net operating loss carryforwards discussed above, as reflected in
the following reconciliation.
<TABLE>
<CAPTION>
1995 1994 1993
---- ---- ----
<S> <C> <C> <C>
U.S. statutory tax rate........................................ 35.0% 35.0% 35.0%
State income tax, net of Federal benefit....................... 6.0 6.0 8.1
Depletion allowance............................................ (0.3) (8.6) --
Adjustment to deferred for change in tax rates................. -- -- 1.0
Utilization of state net operating loss carryforward........... -- -- (2.3)
Other, net..................................................... (0.1) (1.2) 2.9
Increase in valuation allowance................................ -- 7.8 5.5
---- ---- ----
Effective income tax rate................................. 40.6% 39.0% 50.2%
==== ==== ====
</TABLE>
20. 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 1995, 1994 and 1993 totaled $350,000, $311,000 and $293,000,
respectively.
21. COMMON STOCK
Prior to the merger and the stock split discussed in Note 26, the Company
had Class A and Class B common stock. Each class of common stock fully
participated in any dividends declared. Although Class A shareholders were
precluded from receiving stock dividends of Class B common stock, Class B shares
were convertible into Class A shares on a share-for-share basis at the option of
the holder. Each share of Class A common stock was entitled to one vote per
share, and each share of Class B common stock was entitled to ten votes per
share -- see Note 26.
F-24
<PAGE> 319
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
22. STOCK OPTION PROGRAM
The Company adopted a Stock Option Program effective December 31, 1992.
Under the plan, the Board of Directors may grant non-qualified stock options to
officers and other senior employees of the Company, not to exceed 35
participants, to purchase Class A common stock of the Company. The plan is
administered by a committee of the Board of Directors. The committee determines
the timing of awards, individuals to be granted awards, the number of options to
be awarded, and the price, term, vesting schedule and other conditions of the
options. The Company has reserved a total of 2,596,923 Class A common shares for
issuance under the plan.
Options outstanding to officers and other senior employees are:
<TABLE>
<CAPTION>
GRANT OPTIONS PER EXPIRATION
DATE OUTSTANDING SHARE DATE
-------------------------------------------- ----------- ----- -----------------
<S> <C> <C> <C>
December 31, 1992........................... 934,893 $ .50 December 31, 2002
April 1, 1993............................... 179,188 $1.85 April 1, 2003
October 1, 1994............................. 296,049 $4.57 October 1, 2004
January 1, 1995............................. 418,364 $4.91 January 1, 2005
June 16, 1995............................... 25,969 $4.91 June 16, 2005
-------
1,854,463
=======
</TABLE>
The options were granted at fair value as determined by the Board of
Directors based, in part or in whole, on the most recent applicable independent
appraisal. The options granted on December 31, 1992 were fully exercisable on
the date of grant. The options granted in 1993 and 1994 were vested 25% at the
date of issuance with the balance vesting equally over a three-year period. The
options granted on January 1, 1995 vest equally over a four-year period
beginning on January 1, 1996. The options granted on June 16, 1995 vest 50% on
June 16, 1997 and 50% on June 16, 1999. The number of options exercisable at
December 31, 1995 totaled 1,217,308. No options have been exercised to date.
23. 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. The
Company currently pays Electrowatt $200,000 per year for all services rendered
under the management services agreement. The management services agreement
terminates in January 1998.
During 1995, 1994 and 1993, the Company paid $106,000, $69,000 and
$474,000, 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
has 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 terminates in January 1998.
24. SIGNIFICANT CUSTOMERS
The Company's electricity and steam sales revenue is primarily from two
sources -- PG&E and SMUD. During 1994, the Company entered into a three-year
agreement to sell 5 megawatts of electricity to Northern California Power Agency
(NCPA). The Company terminated this agreement on December 31, 1994.
F-25
<PAGE> 320
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Revenues earned from these sources for the years ended December 31, 1995 and
1994 and for the period from April 19, 1993 to December 31, 1993 were (in
thousands):
<TABLE>
<CAPTION>
1995 1994 1993
-------- ------- -------
<S> <C> <C> <C>
PG&E................................................. $112,522 $77,010 $45,819
SMUD................................................. 12,345 9,296 9,014
NCPA................................................. -- 804 --
Other................................................ 173 -- --
-------- ------- -------
125,040 87,110 54,833
Revenues recognized (deferred) (see Note 2).......... 2,759 3,185 (1,833)
-------- ------- -------
Total electricity and steam sales.................... $127,799 $90,295 $53,000
======== ======= =======
</TABLE>
See Note 25 regarding CPUC Restructuring.
25. COMMITMENTS AND CONTINGENCIES
Capital Projects -- The Company has 1996 commitments for capital
expenditures totaling $6.8 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 initial permitting process is underway, with
construction of the facility planned to begin in late 1996 and to be completed
in 1998. The Company is currently evaluating options to finance the construction
of this facility. The Company issued a $3.0 million letter of credit and has a
1996 capital commitment of $3.0 million in connection with this facility. In a
separate transaction, as of March 15, 1996, the Company was negotiating the
potential acquisition of an operating lease for a 120 megawatt gas-fired
cogeneration facility located in Northern California.
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, and 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.
F-26
<PAGE> 321
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Expenses under these agreements for the years ended December 31, 1995 and
1994 and for the period from April 19,1993 to December 31, 1993, are (in
thousands):
<TABLE>
<CAPTION>
1995 1994 1993
------- ------- ------
<S> <C> <C> <C>
Production royalties................................... $10,574 $11,153 $6,814
Lease payments......................................... $ 225 $ 252 $ 172
</TABLE>
Natural Gas Purchases -- Natural gas for the Greenleaf facilities is
supplied by MNI pursuant to a long-term gas purchase agreement. Under the terms
of the gas purchase agreement, MNI may nominate on a monthly basis to provide
firm gas deliveries from certain specified wells. If MNI is unable to deliver
the nominated quantity of gas from its reserves, MNI must purchase and deliver
sufficient gas at no additional cost to the Company. The Company is committed to
purchase gas at the forecasted weighted average incremental cost per decatherm
of gas procured by PG&E at the California border, adjusted annually to actual
cost. The fuel purchase agreement may be terminated by the Company under
specified contract conditions, or upon disbursement of contract suspension
payments.
The Company is committed to purchase and receive natural gas from Chevron
in an amount sufficient to satisfy the requirements of the Greenleaf facilities,
in excess of the nominated quantity supplied by MNI. If MNI supplies less than
the nominated quantity, Chevron shall supply the volumes of natural gas
constituting the difference between the volumes of gas delivered by MNI and the
nominated volumes (make-up gas). Chevron will have the option to be the
exclusive provider of make-up gas if Chevron agrees to sell at a price less than
or equal to 100% of the average gas rate at the burner tip for utility electric
generation as posted by PG&E for the month of delivery. If MNI supplies volumes
of gas greater than its nomination, Chevron will reduce its deliveries in a
corresponding amount. The gas supply agreement is effective through June 30,
1996, continuing month to month thereafter unless either party terminates the
agreement upon sixty days written notice.
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, 1995, future basic rent payments
are $2.9 million for each year from 1996 to 2000, and $27.3 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,
Santa Rosa office facilities and certain office equipment under noncancellable
operating leases expiring through 2000. Future minimum lease payments under
these leases are (in thousands):
<TABLE>
<S> <C>
1996................................................................ $ 899
1997................................................................ 905
1998................................................................ 907
1999................................................................ 776
2000................................................................ 745
thereafter.......................................................... 286
-----
Total future minimum lease commitments.............................. $4,518
=====
</TABLE>
Lease payments are subject to adjustment for the Company's pro rata portion
of annual increases or decreases in building operating costs. In 1995, 1994 and
1993, rent expense for noncancellable operating leases amounted to $733,000,
$663,000 and $636,000, respectively.
F-27
<PAGE> 322
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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. The proposed restructuring provides for phased-in customer choice,
development of non-discriminatory market structure, recovery of utilities'
stranded costs, sanctity of existing contracts, and continuation of existing
public policy programs including the promotion of fuel diversity through a
renewable energy purchase requirement.
As the proposed restructuring has widespread impact and the market
structure requires the participation and oversight of the Federal Energy
Regulatory Commission (FERC), the CPUC will seek to build a California consensus
involving the legislature, the Governor, public and municipal utilities, and
customers. The consensus would then be placed before the FERC so that both the
CPUC and FERC would implement the new market structure no later than January 1,
1998. There can be no assurance that the proposed restructuring will be enacted
in substantially the same form as discussed above. The Company is unable to
predict the ultimate outcome of the restructuring.
Litigation -- The Company, together with over 100 other parties, was named
as a defendant in the second amended complaint 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. This complaint alleges that, in
conjunction with top executives of Bonneville and with the alleged assistance of
the other 100 defendants, the Company engaged in a broad conspiracy and fraud.
The complaint has been amended a number of times. The Company has answered each
version of the complaint by denying all claims and is in the process of
conducting discovery. In August 1994, the Company successfully moved for an
order severing the trustee's claim against the Company from the claims against
the other defendants. Although the case involves over 25 separate financial
transactions entered into by Bonneville, the severed case concerns the Company
in respect of only one of these transactions. In 1988, the Company invested $2.0
million in a partnership formed with Bonneville to develop four hydroelectric
projects in the State of Hawaii. The projects were not successfully developed by
the partnership, and, subsequent to Bonneville's Chapter 11 filing, the Company
filed a claim as a creditor against Bonneville's bankruptcy estate. The trustee
alleges that the equity investment was actually a "sham" loan designed to
inflate Bonneville's earnings. The trustee further alleges that Calpine is one
of many defendants in this case responsible for Bonneville's insolvency and the
amount of damages attributable to the Company based on the $2.0 million
partnership investment is alleged to be $577.2 million. The trustee is seeking
to hold each of the other defendants liable for a portion, all or, in certain
cases, more than this amount. The Company expects the matter will be set for
trial in 1996. The Company believes the claims against it are without merit and
will continue to defend the action vigorously. The Company further believes that
the resolution of this matter will not have a material adverse effect on its
financial position or results of operations.
ENCO terminated protracted contract negotiations with two Canadian natural
gas suppliers in January 1995. One of the suppliers notified ENCO it considered
a draft contract to be effective although it had not been executed by ENCO. The
supplier indicated it may pursue legal action if ENCO would not execute the
contract. As of March 15, 1996, no legal action has been served on ENCO.
Management believes if legal action is commenced, ENCO has significant defenses
and believes such action will not result in any material adverse impact to the
Company's financial condition or results of operations.
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.
F-28
<PAGE> 323
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
26. SUBSEQUENT EVENT
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 equity offering. Also, the Board of Directors approved a stock
split at a ratio of approximately 5.194 to 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.
F-29
<PAGE> 324
CALPINE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)
<TABLE>
<CAPTION>
AS ADJUSTED
JUNE 30,
1996
STOCKHOLDER'S
EQUITY
ASSUMING
CONVERSION
OF PREFERRED
STOCK (NOTE DECEMBER 31,
12) 1995
JUNE 30, ------------- ------------
1996 (UNAUDITED)
--------
(UNAUDITED)
<S> <C> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents............................ $ 38,403 $ 21,810
Accounts receivable.................................. 38,691 20,124
Acquisition project receivables...................... 4,536 8,805
Collateral securities, current portion............... 9,745 --
Prepaid expenses..................................... 6,978 3,447
Inventory............................................ 3,444 1,377
Other current assets................................. 2,947 677
--------
Total current assets......................... 104,744 56,230
Property, plant and equipment, net..................... 530,203 447,751
Investments in power projects.......................... 12,693 8,218
Collateral securities, net of current portion.......... 88,669 --
Notes receivable from related parties.................. 20,894 19,391
Notes receivable from Coperlasa........................ 16,492 6,094
Restricted cash........................................ 8,477 9,627
Deferred charges and other assets...................... 10,640 7,220
--------
Total assets................................. $792,812 $554,531
========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current non-recourse long-term project financing..... $ 27,178 $ 84,708
Notes payable to bank and short-term borrowings...... -- 1,177
Accounts payable..................................... 9,530 6,876
Accrued payroll and related expenses................. 2,336 2,789
Accrued interest payable............................. 8,693 7,050
Other accrued expenses............................... 5,121 2,657
--------
Total current liabilities.................... 52,858 105,257
Long-term line of credit............................... -- 19,851
Non-recourse long-term project financing, less current
portion.............................................. 180,974 190,642
Notes payable.......................................... 6,598 6,348
Senior Notes........................................... 285,000 105,000
Deferred income taxes, net............................. 100,068 97,621
Deferred lease incentive............................... 81,495 --
Other liabilities...................................... 6,163 4,585
--------
Total liabilities............................ 713,156 529,304
--------
Stockholder's equity
Preferred stock...................................... 5 -- --
Common stock......................................... 10 18 10
Additional paid-in capital........................... 56,209 56,206 6,214
Retained earnings.................................... 23,432 23,432 19,003
-------- --------
Total stockholder's equity................... 79,656 79,656 25,227
-------- --------
Total liabilities and stockholder's equity... $792,812 $ 792,812 $554,531
======== ========
</TABLE>
The accompanying notes are an integral part of these condensed consolidated
financial statements.
F-30
<PAGE> 325
CALPINE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30,
-----------------------
1996 1995
-------- --------
<S> <C> <C>
Revenue:
Electricity and steam sales........................................ $ 72,030 $ 49,014
Service contract revenue from related parties...................... 4,616 3,129
Service revenue from others........................................ 818 --
Income (loss) from unconsolidated investments in power projects.... 1,713 (1,791)
Interest income on loans to power projects......................... 2,817 --
-------- --------
Total revenue.............................................. 81,994 50,352
-------- --------
Cost of revenue:
Plant operating expenses, depreciation, operating lease expense and
production royalties............................................ 46,835 28,344
Service contract expenses and other................................ 4,484 2,274
-------- --------
Total cost of revenue...................................... 51,319 30,618
-------- --------
Gross profit......................................................... 30,675 19,734
Project development expenses......................................... 1,410 1,308
General and administrative expenses.................................. 5,874 3,659
-------- --------
Income from operations..................................... 23,391 14,767
Other (income) expense:
Interest expense................................................... 18,665 15,116
Other income, net.................................................. (2,777) (855)
-------- --------
Income before provision for income taxes................... 7,503 506
Provision for income taxes........................................... 3,080 208
-------- --------
Net income................................................. $ 4,423 $ 298
======== ========
As adjusted earnings per share assuming conversion of preferred
stock:
14,400
As adjusted weighted average shares outstanding.................... ========
$ 0.31
Net income per share............................................... ========
</TABLE>
The accompanying notes are an integral part of these condensed consolidated
financial statements.
F-31
<PAGE> 326
CALPINE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
(UNAUDITED)
<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE
30,
----------------------
1996 1995
--------- --------
<S> <C> <C>
Net cash provided by operating activities............................. $ 5,035 $ 5,126
--------- --------
Cash flows from investing activities:
Acquisition of property, plant and equipment........................ (8,061) (9,324)
Investment in Greenleaf, net of cash on hand........................ -- (16,958)
Investment in Watsonville, net of cash on hand...................... -- 494
Investment in King City, net of cash on hand........................ (4,877) --
Investment in King City collateral securities....................... (98,414) --
Investments in power projects and capitalized costs................. (2,983) (579)
Loans to Coperlasa.................................................. (12,104) --
Increase in notes receivable from related party..................... (250) (250)
Decrease in restricted cash......................................... 1,150 2,766
Other, net.......................................................... (512) (23)
--------- --------
Net cash used in investing activities............................ (126,051) (23,874)
--------- --------
Cash flows from financing activities:
Proceeds from issuance of Senior Notes Due 2006..................... 180,000 --
Proceeds from issuance of preferred stock........................... 50,000 --
Borrowings from line of credit...................................... 33,800 20,851
Repayment of line of credit......................................... (53,651) (15,000)
Borrowing from Bank................................................. 45,000 --
Repayments to Bank.................................................. (46,177) --
Borrowings of non-recourse project financing........................ -- 77,925
Repayment of non-recourse project financing......................... (66,600) (73,988)
Repayment of working capital loan................................... -- (4,500)
Financing costs..................................................... (4,763) (1,546)
--------- --------
Net cash provided by (used for) financing activities............. 137,609 3,742
--------- --------
Net increase (decrease) in cash and cash equivalents.................. 16,593 (15,006)
Cash and cash equivalents, beginning of period........................ 21,810 22,527
--------- --------
Cash and cash equivalents, end of period.............................. $ 38,403 $ 7,521
========= ========
Supplementary information:
Cash paid during the period for:
Interest......................................................... $ 16,517 $ 17,530
Income taxes..................................................... $ 955 $ 125
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-32
<PAGE> 327
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 1996
1. ORGANIZATION AND OPERATION OF THE COMPANY
Calpine Corporation (Calpine) and subsidiaries (collectively, the Company)
are engaged in the development, acquisition, ownership and operation of power
generation facilities in the United States. The Company has ownership interests
in or operates geothermal steam fields, geothermal power generation facilities,
and natural gas-fired cogeneration facilities in Northern California, Washington
and Mexico. 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. Founded in 1984, the Company
is wholly owned by Electrowatt Services, Inc., which is wholly owned by
Electrowatt Ltd (Electrowatt), a Swiss company. The Company has expertise in the
areas of engineering, finance, construction and plant operations and
maintenance.
In July 1996, the Company filed a registration statement with the United
States Securities and Exchange Commission relating to the initial public
offering of shares of the Company's Common Stock. In the offering, the Company
will sell newly issued shares of Common Stock and Electrowatt will sell shares
of Common Stock representing its entire ownership interest in Calpine. If the
offering is completed, Electrowatt will no longer own any interest in the
Company.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Interim Presentation
The accompanying interim condensed consolidated financial statements of the
Company have been prepared by the Company, without audit by independent public
accountants, pursuant to the rules and regulations of the Securities and
Exchange Commission. In the opinion of management, the condensed consolidated
financial statements include all and only normal recurring adjustments necessary
to present fairly the information required to be set forth therein. Certain
information and note disclosures normally included in financial statements
prepared in accordance with generally accepted accounting principles have been
condensed or omitted from these statements pursuant to such rules and
regulations and, accordingly, should be read in conjunction with the audited
consolidated financial statements of the Company included in the Company's
annual report on Form 10-K for the year ended December 31, 1995. The results for
interim periods are not necessarily indicative of the results for the entire
year.
As Adjusted Earnings Per Share and As Adjusted Stockholder's Equity
Net income per share is computed using weighted average shares outstanding,
which includes the net additional number of shares which would be issuable upon
the exercise of outstanding stock options, assuming that the Company used the
proceeds received to purchase additional shares at an assumed public offering
price. Net income per share also gives effect, even if antidilutive, to common
equivalent shares from preferred stock that will automatically convert upon the
closing of the Company's initial public offering (using the as-if-converted
method). If the offering contemplated by the Company is consummated, all of the
convertible preferred stock outstanding as of the closing date will
automatically be converted into shares of common stock based on the shares of
convertible preferred stock outstanding at June 30, 1996. Unaudited as adjusted
stockholder's equity at June 30, 1996, as adjusted for the conversion of
preferred stock, is disclosed on the balance sheet.
Impact of Recent Accounting Pronouncements
In March 1995, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards (SFAS) No. 121, Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets
F-33
<PAGE> 328
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
to be Disposed Of. This pronouncement requires that long-lived assets and
certain identifiable intangible assets be reviewed for impairment whenever
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. SFAS No. 121 must be adopted
for fiscal years beginning in 1996. 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 October 1995, the Financial Accounting Standards Board issued SFAS No.
123, Accounting for Stock Based Compensation. The disclosure requirements of
SFAS No. 123 are effective for the Company's 1996 fiscal year. The new
pronouncement did not have an impact on its results of operations since the
intrinsic value-based method prescribed by Accounting Principles Board Opinion
No. 25 and also allowed by SFAS No. 123 will continue to be used by the Company
to account for its stock-based compensation plans.
3. ACCOUNTS RECEIVABLE
The Company has both billed and unbilled receivables. The components of
accounts receivable as of June 30, 1996 and December 31, 1995 are as follows (in
thousands):
<TABLE>
<CAPTION>
DECEMBER 31,
1995
JUNE 30, ------------
1996
-----------
(UNAUDITED)
<S> <C> <C>
Projects:
Billed............................................ $37,622 $ 18,341
Unbilled.......................................... 845 525
Other............................................. 224 1,258
------- -------
$38,691 $ 20,124
======= =======
</TABLE>
Other accounts receivable consist primarily of disputed amounts related to
the Greenleaf facilities purchase price. In May 1996, the Company reclassified
such accounts receivable to property, plant and equipment as an adjustment to
the purchase price of the Greenleaf facilities (see Note 6).
Accounts receivable from related parties as of June 30, 1996 and December
31, 1995 are comprised of the following (in thousands):
<TABLE>
<CAPTION>
DECEMBER 31,
1995
JUNE 30, ------------
1996
-----------
(UNAUDITED)
<S> <C> <C>
O.L.S. Energy-Agnews, Inc. ......................... $ 589 $ 806
Geothermal Energy Partners, Ltd. ................... 979 462
Sumas Cogeneration Company, L.P. ................... 1,206 908
Electrowatt and subsidiaries........................ 2 1
------- -------
$ 2,776 $ 2,177
======= =======
</TABLE>
F-34
<PAGE> 329
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
4. INVESTMENTS IN POWER PROJECTS
The Company has unconsolidated investments in power projects which are
accounted for under the equity method. Unaudited financial information for the
six months ended June 30, 1996 and 1995 related to these investments is as
follows (in thousands):
<TABLE>
<CAPTION>
1996 1995
----------------------------------- ----------------------------------
SUMAS O.L.S. GEOTHERMAL SUMAS O.L.S. GEOTHERMAL
COGENERATION ENERGY- ENERGY COGENERATION ENERGY- ENERGY
COMPANY, AGNEWS, PARTNERS, COMPANY, AGNEWS, PARTNERS,
L.P. INC. LTD. L.P. INC. LTD.
------------ ------- ---------- ------------ ------ ----------
<S> <C> <C> <C> <C> <C> <C>
Revenue........................................ $ 21,561 $4,604 $9,576 $ 15,265 $4,612 $9,847
Operating expenses............................. 12,752 4,349 6,219 13,530 4,300 5,064
------- ------ ------ ------ ------ ------
Income (loss) from operations.................. 8,809 255 3,357 1,735 312 4,783
Other expenses, net............................ 5,098 1,040 2,444 5,283 1,034 2,865
------- ------ ------ ------ ------ ------
Net income (loss).......................... $ 3,711 $ (785 ) $ 913 $ (3,548) $(722 ) $1,918
======= ====== ====== ====== ====== ======
Company's share of net income (loss)........... $ 1,855 $ (179 ) $ 37 $ (1,774) $(130 ) $ 113
======= ====== ====== ====== ====== ======
</TABLE>
5. THERMAL POWER COMPANY
In March 1996, Thermal Power Company (TPC) a wholly owned subsidiary of the
company, and Union Oil Company of California (Union Oil) entered into an
alternative pricing agreement with Pacific Gas and Electric Company (PG&E) for
any steam produced in excess of 40% of average field capacity. The alternative
pricing strategy is effective through December 31, 2000. Under the agreement,
PG&E would purchase a portion of the steam that PG&E would likely curtail under
TPC's existing steam sales agreement. The price for this portion of steam will
be set by TPC and Union Oil with the intent that it be at competitive market
prices. TPC and Union Oil will solely determine the price and duration of these
alternative price offers.
6. GREENLEAF TRANSACTION
In April 1995, the Company purchased the capital stock of the companies
which owned 100% of the assets of two 49.5 megawatt natural gas-fired
cogeneration facilities (collectively, the Greenleaf facilities) located in Yuba
City in Northern California. The initial purchase price included a cash payment
of $20.3 million and the assumption of project debt totalling $60.2 million. In
April 1996, the Company finalized the purchase price in accordance with the
Share Purchase Agreement dated March 30, 1995.
The acquisition was accounted for as a purchase and the purchase price has
been allocated to the acquired assets and liabilities based on the estimated
fair values of the acquired assets and liabilities as shown below. The adjusted
allocation of the purchase price is as follows (in thousands):
<TABLE>
<S> <C>
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
========
</TABLE>
F-35
<PAGE> 330
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
7. 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 combined cycle facility located in King City, California. The facility
generates electricity for sale to PG&E pursuant to a long-term power sales
agreement through 2019. Natural gas for the facility is supplied by Chevron USA
Inc. pursuant to a contract which expires June 30, 1997.
Under the terms of the operating lease, the Company makes semi-annual lease
payments to BAF on each February 15 and August 15, a portion of which is
supported by a $98.4 million collateral fund owned by the Company. The
collateral fund consists of a portfolio of investment grade and U.S. Treasury
Securities that will mature serially in amounts equal to a portion of the lease
payments. The collateral fund securities are accounted for as held-to-maturity
investments under SFAS No. 115, Accounting for Certain Investments in Debt and
Equity Securities. As of June 30, 1996, future rent payments are $11.8 million
for the remainder of 1996, $24.4 million for 1997, $23.8 million for 1998, $19.4
million for 1999, $20.1 million for 2000 and $204.1 million thereafter.
The Company has recorded the value of the above-market pricing provided in
the power sales agreement (PSA) as an asset which is included in property, plant
and equipment, since the Company has, in substance, assumed the rights of the
PSA. The Company has also recorded a deferred lease incentive 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.
The Company financed the collateral fund and other transaction costs with
$50.0 million of proceeds from the issuance of preferred stock to Electrowatt by
Calpine (see Note 10) and other short-term borrowings, which included $13.3
million of borrowings under the Credit Suisse Credit Facility (see Note 8) below
and a $45.0 million loan from The Bank of Nova Scotia. The Company repaid the
short-term borrowings from a portion of the net proceeds of the Senior Notes Due
2006 issued in May 1996 (see Note 9).
8. LINES OF CREDIT
At June 30, 1996, the Company had borrowings under its $50.0 million Credit
Facility with Credit Suisse (whose parent company owns 44.9% of Electrowatt) and
had a letter of credit outstanding thereunder for $3,025,000. Borrowings under
the Credit Facility bear interest at the London Interbank Offered Rate (LIBOR)
plus 0.5%. Interest is paid on the last day of each interest period for such
loan, but not less often than quarterly, based on the principal amount
outstanding during the period. No stated principal amortization exists for this
indebtedness. Upon completion of the Company's proposed initial public offering,
the Credit Facility will terminate and is expected to be replaced by a
comparable facility. On July 20, 1996, the Company entered into a commitment
letter with The Bank of Nova Scotia to provide a $50 million three-year
Revolving Credit Facility. Such Revolving Credit Facility will become effective
upon the completion of the Company's initial public offering.
9. SENIOR NOTES DUE 2006
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 $175.2 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
borrowing from The Bank of Nova Scotia. The remaining $19.5 million was
available for general corporate purposes. Transaction costs of $4.8 million
incurred in connection with the public debt offering were recorded as a
F-36
<PAGE> 331
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
deferred charge and are amortized over the ten-year life of the Senior Notes Due
2006 using the straight line method.
The Senior Notes Due 2006 will mature on May 15, 2006. The Company has no
sinking fund or mandatory redemption obligations with respect to the Senior
Notes Due 2006. Interest is payable semi-annually on May 15 and November 15 of
each year while the Senior Notes Due 2006 are outstanding, commencing on
November 15, 1996.
10. PREFERRED STOCK
The Company has 5,000,000 authorized shares of Series A Preferred Stock,
all of which were issued on March 21, 1996 and outstanding as of June 30, 1996.
All of the shares of Series A Preferred Stock are held by Electrowatt. The
shares of Series A Preferred Stock are not publicly traded. No dividends are
payable on the Series A Preferred Stock. The Series A Preferred Stock contains
provisions regarding liquidation and conversion rights. Upon the consummation of
the Company's proposed initial public offering, the Series A Preferred Stock
will be converted into Common Stock and sold to the public in the offering.
11. CONTINGENCIES
The Company, together with over 100 other parties, was named as a defendant
in the second amended complaint 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"). This complaint alleges that, in conjunction
with top executives of Bonneville and with the alleged assistance of the other
100 defendants, the Company engaged in a broad conspiracy and fraud. The
complaint has been amended a number of times. The Company has answered each
version of the complaint by denying all claims and is in the process of
conducting discovery. In August 1994, the Company successfully moved for an
order severing the trustee's claim against the Company from the claims against
the other defendants. Although the case involves over 25 separate financial
transactions entered into by Bonneville, the severed case concerns the Company
in respect of only one of these transactions. In 1988, the Company invested $2.0
million in a partnership formed with Bonneville to develop four hydroelectric
projects in the State of Hawaii. The projects were not successfully developed by
the partnership, and, subsequent to Bonneville's Chapter 11 filing, the Company
filed a claim as a creditor against Bonneville's bankruptcy estate. The trustee
alleges that the equity investment was actually a "sham" loan designed to
inflate Bonneville's earnings. The trustee initially alleged that Calpine is one
of many defendants in this case responsible for Bonneville's "deepening
insolvency" and the amount of damages attributable to the Company based on the
$2.0 million partnership investment was alleged to be $577.2 million. Based upon
statements made by the Court and the trustee in July 1996, the Company believes
that the maximum compensatory damages which the trustee may seek will not exceed
$5 million. There can be no assurance, however, of the actual amount of damages
to be sought by the Trustee. The Company believes the claims against it are
without merit and will continue to defend the action vigorously. The Company
further believes that the resolution of this matter will not have a material
adverse effect on its financial position or results of operations.
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.
12. SUBSEQUENT EVENT
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 equity offering. Also, the Board of Directors approved a stock
split at a ratio of approximately 5.194 to 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.
F-37
<PAGE> 332
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, 1995 and 1994, and
the related consolidated statements of operations, changes in partners' deficit,
and cash flows for each of the three years ended December 31, 1995. 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, 1995 and 1994 and
the results of their operations and cash flows for each of the three years ended
December 31, 1995, in conformity with generally accepted accounting principles.
MOSS ADAMS LLP
Everett, Washington
January 19, 1996
F-38
<PAGE> 333
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------------------
1995 1994
------------ ------------
<S> <C> <C>
ASSETS
Current assets
Cash and cash equivalents..................................... $ 199,169 $ 353,936
Current portion of restricted cash and cash equivalents....... 2,937,884 6,409,185
Accounts receivable........................................... 3,090,213 4,108,206
Prepaid expenses.............................................. 222,828 232,325
------------ ------------
Total current assets....................................... 6,450,094 11,103,652
Restricted cash and cash equivalents, net of current portion.... 8,017,758 7,454,923
Property, plant and equipment, at cost, net..................... 95,589,737 97,039,459
Other assets.................................................... 12,744,480 14,550,228
------------ ------------
$122,802,069 $130,148,262
============ ============
LIABILITIES AND PARTNERS' DEFICIT
Current liabilities
Accounts payable and accrued liabilities...................... $ 2,051,178 $ 3,651,799
Current portion of related party payables
Calpine Corporation........................................ 4,864 41,871
National Energy Systems Company............................ 1,861 1,430
Current portion of long-term debt............................. 2,000,000 400,000
------------ ------------
Total current liabilities.................................. 4,057,903 4,095,100
Related party payable -- Calpine Corporation, net of current
portion....................................................... 908,679 446,624
Long-term debt, net of current portion.......................... 117,000,003 119,000,002
Future removal and site restoration costs....................... 502,600 309,600
Deferred income taxes........................................... 907,800 773,800
Commitments and contingency (Notes 6 and 8)
Partners' (deficit) equity...................................... (574,916) 5,523,136
------------ ------------
$122,802,069 $130,148,262
============ ============
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-39
<PAGE> 334
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
CONSOLIDATED STATEMENT OF OPERATIONS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------
1995 1994 1993
------------ ------------ -----------
<S> <C> <C> <C>
Revenues
Power sales......................................... $ 30,603,018 $ 29,206,469 $19,525,098
Natural gas sales, net.............................. 893,690 2,832,668 2,104,407
Other............................................... 29,146 20,490 116,895
------------ ------------ -----------
Total revenues.............................. 31,525,854 32,059,627 21,746,400
------------ ------------ -----------
Costs and expenses
Operating and production costs...................... 18,493,245 19,032,754 11,779,505
Depletion, depreciation and amortization............ 6,965,496 6,715,156 4,986,300
General and administrative.......................... 1,400,129 1,412,326 1,563,509
------------ ------------ -----------
Total costs and expenses.................... 26,858,870 27,160,236 18,329,314
------------ ------------ -----------
Income from operations................................ 4,666,984 4,899,391 3,417,086
------------ ------------ -----------
Other income (expense)
Interest income..................................... 490,071 436,741 250,675
Interest expense.................................... (11,006,056) (10,172,959) (6,707,183)
Other expense....................................... (60,664) (359,000) --
------------ ------------ -----------
Total other expense......................... (10,576,649) (10,095,218) (6,456,508)
------------ ------------ -----------
Loss before provision for income taxes................ (5,909,665) (5,195,827) (3,039,422)
Provision for income taxes............................ (188,387) (581,190) (337,431)
------------ ------------ -----------
Net loss.............................................. $ (6,098,052) $ (5,777,017) $(3,376,853)
============ ============ ===========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-40
<PAGE> 335
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' DEFICIT
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
<TABLE>
<S> <C>
Partners' equity, December 31, 1992............................................. $14,688,436
Capital contributions........................................................... 1,500,000
Capital distributions........................................................... (1,500,000)
Net loss........................................................................ (3,376,853)
Cumulative foreign exchange translation adjustment.............................. (11,430)
-----------
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)
===========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-41
<PAGE> 336
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
CONSOLIDATED STATEMENT OF CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------
1995 1994 1993
----------- ----------- -----------
<S> <C> <C> <C>
Cash flows from operating activities
Net loss.......................................... $(6,098,052) $(5,777,017) $(3,376,853)
Adjustments to reconcile net loss to net cash from
operating activities
Depletion, depreciation and amortization....... 6,965,496 6,715,156 4,986,300
Deferred income taxes.......................... 134,000 532,400 241,400
Changes in operating assets and liabilities
Accounts receivable.......................... 1,017,993 (1,254,639) (2,064,616)
Prepaid expenses............................. 9,497 (30,342) 203,904
Accounts payable and accrued liabilities..... (1,407,621) 1,081,431 1,168,892
Related party payables....................... 425,479 132,296 --
----------- ----------- -----------
Net cash from operating activities........ 1,046,792 1,399,285 1,159,027
----------- ----------- -----------
Cash flows from investing activities
Decrease (increase) in restricted cash and cash
equivalents.................................... 2,908,466 2,922,819 (13,286,927)
Acquisition of property, plant and equipment...... (3,710,025) (3,690,399) (16,558,101)
Other assets...................................... -- (167,483) (5,700,537)
Accounts payable and accrued liabilities.......... -- -- (3,847,743)
----------- ----------- -----------
Net cash from investing activities........ (801,559) (935,063) (39,393,308)
----------- ----------- -----------
Cash flows from financing activities
Proceeds from long-term debt...................... -- -- 38,710,000
Repayment of long-term debt....................... (400,000) (400,025) (199,973)
Capital contributions............................. -- -- 1,500,000
Capital distributions............................. -- -- (1,500,000)
Payments to related parties....................... -- -- (864,890)
----------- ----------- -----------
Net cash from financing activities........ (400,000) (400,025) 37,645,137
----------- ----------- -----------
Effect of exchange rate changes on cash............. -- -- (11,430)
----------- ----------- -----------
Net increase (decrease) in cash and cash
equivalents....................................... (154,767) 64,197 (600,574)
Cash and cash equivalents, beginning of year........ 353,936 289,739 890,313
----------- ----------- -----------
Cash and cash equivalents, end of year.............. $ 199,169 $ 353,936 $ 289,739
=========== =========== ===========
Supplementary disclosure of cash flow information
Cash paid for interest during the year............ $11,006,056 $10,172,959 $ 8,868,183
=========== =========== ===========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-42
<PAGE> 337
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1995, 1994 AND 1993
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. 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.
Prior to the commencement of commercial operation as discussed below, the
Partnership was considered to be a development stage company in the process of
developing, constructing and owning 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 on April 16, 1993. In addition, the Generation Facility
includes a lumber dry kiln facility and a 3.5 mile private natural gas pipeline.
The lumber dry kiln commenced commercial operation in May 1993.
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 production 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 electricity capacity 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:
<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31, MEGAWATTS REVENUE
---------------------------------------------------- --------- -----------
<S> <C> <C>
1995................................................ 1,026,000 $30,603,000
1994................................................ 1,000,400 $29,206,000
1993................................................ 696,400 $19,525,000
</TABLE>
The Partnership leases a kiln facility and sells steam under a 20-year
agreement for the purchase and sale of steam and lease of the kiln (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 $6,239,000 and
$5,619,000 at December 31, 1995 and 1994, respectively, and to SEI of
approximately $441,000 and $363,000 at December 31, 1995 and 1994, 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,
F-43
<PAGE> 338
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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%.
(c) DISTRIBUTIONS -- Distributions of operating cash flows are permitted
quarterly after required deposits are made and minimum cash balances are met,
and subject to certain other restrictions. During 1995 and 1994, there were no
distributions of operating cash flow. In 1993 Whatcom received a distribution of
$1,500,000, reducing its equity investment in the Partnership. Whatcom loaned
the sole shareholder of SEI $1,500,000, and the sole shareholder of SEI loaned
$1,500,000 to SEI. SEI then contributed $1,500,000 in additional equity to the
Partnership.
(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 $3,748,000 in 1995, $3,630,000
in 1994 and $3,026,400 in 1993. 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
$193,000 in 1995, $169,000 in 1994 and $110,000 in 1993, 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 -- During 1995 and 1994, 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 operations.
During 1993, ENCO's functional currency was Canadian dollars. As a result,
translation adjustments were reported separately and accumulated as separate
components of partners' equity.
(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
F-44
<PAGE> 339
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 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:
<TABLE>
<S> <C>
Organization, start-up and development costs..................... 5-30 years
Financing costs.................................................. 15 years
Gas contract costs............................................... 20 years
</TABLE>
(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
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------------------
1995 1994
------------ ------------
<S> <C> <C>
Land and land improvements.............................. $ 381,071 $ 381,071
Plant and equipment..................................... 84,061,359 82,759,005
Acquisition of gas properties, including development
thereon............................................... 25,030,165 22,815,964
Furniture and fixtures.................................. 195,914 188,444
------------ ------------
109,668,509 106,144,484
Less accumulated depreciation and depletion............. 14,078,772 9,105,025
------------ ------------
$ 95,589,737 $ 97,039,459
============ ============
</TABLE>
Depreciation expense was $3,316,748 in 1995, $3,069,446 in 1994 and
$2,133,711 in 1993. Depletion expense was $1,843,000 in 1995, $1,671,000 in 1994
and $1,332,000 in 1993.
F-45
<PAGE> 340
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 3 -- OTHER ASSETS
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------------
1995 1994
----------- -----------
<S> <C> <C>
Organization, start-up and development costs.............. $ 6,165,574 $ 7,487,943
Financing costs........................................... 4,254,719 4,598,746
Gas contract costs........................................ 2,324,187 2,463,539
----------- -----------
$12,744,480 $14,550,228
=========== ===========
</TABLE>
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).
Credit Suisse is an affiliate of Whatcom. At December 31, 1995 and 1994, amounts
outstanding under the term loan agreements, by entity, were as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------------------
1995 1994
------------ ------------
<S> <C> <C>
Sumas Cogeneration Company, L.P......................... $ 94,367,003 $ 94,684,202
ENCO Gas, Ltd........................................... 24,633,000 24,715,800
------------ ------------
119,000,003 119,400,002
Less current portion.................................... 2,000,000 400,000
------------ ------------
$117,000,003 $119,000,002
============ ============
</TABLE>
Scheduled annual principal payments under the loan agreements as of
December 31, 1995 are as follows:
<TABLE>
<CAPTION>
YEAR ENDING
DECEMBER 31, AMOUNT
--------------------------------------------------------------- ------------
<S> <C>
1996........................................................... $ 2,000,000
1997........................................................... 3,600,000
1998........................................................... 4,200,000
1999........................................................... 5,400,000
2000........................................................... 7,200,000
Thereafter..................................................... 96,600,003
------------
$119,000,003
============
</TABLE>
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% prior to
Loan Conversion to .875% after Loan Conversion as stated in the loan agreement.
During the year ended December 31, 1995, interest rates on the variable rate
loan ranged from 7.47% to 7.76%. 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
F-46
<PAGE> 341
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
December 31, 1995, interest rates on the variable rate loan ranged from 7.47% to
7.76%. The loans mature in May 2008.
The Partnership pays Prudential an agency fee of $50,000 per year, adjusted
annually by an inflation index, until the loan matures. The Partnership pays
Credit Suisse an agency fee of $40,000 per year, adjusted annually by an
inflation index, until the loan matures. 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 Partnership 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 noncurrent asset.
During 1993, the Company incurred and paid $8,868,183 of interest,
including $6,707,183, which was charged to operations and $2,161,000, which was
capitalized.
NOTE 5 -- INCOME TAXES
The provision for income taxes represents Canadian taxes which consist of
the following:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------
1995 1994 1993
-------- -------- --------
<S> <C> <C> <C>
Current
Federal large corporation tax.................... $ 34,625 $ 31,314 $ 45,262
British Columbia capital taxes................... 19,762 17,476 50,769
-------- -------- --------
54,387 48,790 96,031
Deferred........................................... 135,400 178,400 241,400
-------- -------- --------
189,787 227,190 337,431
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.... (49,100) 95,000 --
-------- -------- --------
$188,387 $581,190 $337,431
======== ======== ========
</TABLE>
F-47
<PAGE> 342
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The principal sources of temporary differences resulting in deferred tax
assets and liabilities are as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------
1995 1994
---------- ----------
<S> <C> <C>
Deferred tax asset
Canadian net operating loss carryforwards................. $ (840,900) $ (829,400)
Deferred tax liabilities
Acquisition and development costs of gas deducted for tax
purposes in excess of amounts deducted for financial
reporting purposes..................................... 1,748,700 1,603,200
---------- ----------
Net deferred tax liability........................ $ 907,800 $ 773,800
========== ==========
</TABLE>
The provision for income taxes differs from the Canadian statutory rate
principally due to the following:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------
1995 1994 1993
-------- -------- --------
<S> <C> <C> <C>
Canadian statutory rate............................ 44.62% 44.34% 44.3%
Income taxes based on statutory rate............... $(33,852) $ 82,909 $165,100
Capital taxes, net of deductible portion........... 47,028 36,678 75,587
Non-deductible provincial royalties, net of
resource allowance............................... 95,671 39,836 50,267
Depletion on gas properties with no tax basis...... 44,641 38,420 41,778
Other foreign exchange adjustments................. 36,299 29,347 4,699
-------- -------- --------
$189,787 $227,190 $337,431
======== ======== ========
</TABLE>
As of December 31, 1995, ENCO has non-capital loss carryforwards of
approximately $1,885,000 which may be applied against taxable income of future
periods which expire as follows:
<TABLE>
<S> <C>
1999............................................................. $1,625,000
2000............................................................. $ 260,000
</TABLE>
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 from June 1993 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 $258,000 in 1995,
$253,000 in 1994 and $151,000 in 1993 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.
Accordingly, the performance bonuses earned in 1995 and 1994 are included as a
non-current liability in the consolidated balance sheet. 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.
F-48
<PAGE> 343
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Approximately $2,031,000 in 1995, $1,946,000 in 1994 and $1,260,000 in 1993 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 $19,000 in
1995, $61,000 in 1994 and $6,000 in 1993.
(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 $100,000 in 1995, $101,000 in 1994 and
$96,000 in 1993 was paid under this agreement
(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 in accordance with
the agreement. The Partnership paid ENCO $2.26 per delivered MMBtu through
October 1995 and pays $2.43 per delivered MMBtu through 1996. Prices under the
agreement then escalate at an annual rate of 7.5% until October 31, 2000, and at
4% per annum thereafter. Partnership payments to ENCO under the agreement are
eliminated in consolidation. The agreement expires on the twentieth anniversary
of the date of commercial operation.
The Partnership has a gas supply agreement with 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 agreement. The agreement is expected to terminate on October
31, 1996.
The Partnership and ENCO have a gas management agreement with WGSI. WGSI is
paid a gas management fee for each MMBtu of gas delivered to the Generation
Facility. The gas management fee is adjusted annually based on the British
Columbia Consumer Price Index. The gas management agreement expires October 31,
2008 unless terminated earlier as provided for in the agreement.
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 $2,569,000 in 1995, $2,776,000 in 1994 and $1,347,000 in 1993.
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. As of December 31,
1995 and 1994, the letter of credit had a face amount of $2,500,000 and the
Partnership had a cash deposit of $2,500,000 held in a restricted money market
account as collateral for the letter of credit. As of December 31, 1995 and
1994, $2,500,000 held in a restricted money market account is included in the
current portion of restricted cash and cash equivalents. In January 1996, the
letter of credit was reduced in accordance with its terms to a face amount of
$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.
F-49
<PAGE> 344
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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.
(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 $48,400 in 1995 and 1994, and $45,300
in 1993.
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 $17,700 in 1995, $17,000 in 1994 and $16,000 in 1993.
Future minimum land and office lease commitments as of December 31, 1995
are as follows:
<TABLE>
<CAPTION>
YEAR ENDING
DECEMBER 31, AMOUNT
----------------------------------------------------------------- ----------
<S> <C>
1996............................................................. $ 66,800
1997............................................................. 51,000
1998............................................................. 49,300
1999............................................................. 49,300
2000............................................................. 52,500
Thereafter....................................................... 868,200
----------
$1,137,100
==========
</TABLE>
(h) PROJECT MANAGEMENT SERVICES -- NESCO entered into a project management
agreement with the Partnership for which it received $45,000 per month through
June 1993. Approximately $264,000 was paid to NESCO in 1993, under this
agreement.
(i) CONSTRUCTION MANAGEMENT SERVICES -- Calpine entered into a construction
management agreement with the Partnership for which it received $40,000 per
month through June 1993. Approximately $235,000 was paid to Calpine in 1993,
under this agreement.
(j) 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 made in connection with Loan Conversion (Note 1). 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 $119,000,003 at December 31, 1995. 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-50
<PAGE> 345
SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 8 -- CONTINGENCY
ENCO terminated protracted contract negotiations with two Canadian natural
gas suppliers in January 1995. One of the suppliers notified ENCO it considered
a draft contract to be effective although it had not been executed by ENCO. The
supplier indicated it may pursue legal action if ENCO would not execute the
contract. As of January 19, 1996, no legal action has been served on ENCO.
Management believes if legal action is commenced, it has significant defenses
and believes such action will not result in any material adverse impact to the
Company's financial condition or results of operations.
F-51
<PAGE> 346
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Partners of Calpine Geysers Company, L.P.:
We have audited the accompanying statements of operations and cash flows
for the period from January 1, 1993 to April 18, 1993 of Calpine Geysers
Company, L.P., a Delaware limited partnership. These financial statements are
the responsibility of the Partnership's management. Our responsibility is to
express an opinion on these statements based on our audit.
We conducted our audit 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 audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the results of operations and cash flows of Calpine
Geysers Company, L.P. for the period from January 1, 1993 through April 18, 1993
in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
San Jose, California
March 18, 1994
F-52
<PAGE> 347
CALPINE GEYSERS COMPANY, L.P.
STATEMENT OF OPERATIONS
FOR THE PERIOD FROM JANUARY 1, 1993 TO APRIL 18, 1993
<TABLE>
<S> <C>
Revenue from power contracts.................................................... $20,759,116
-----------
Costs and expenses:
Production royalties.......................................................... 3,150,076
Operating expenses............................................................ 4,893,878
Depreciation and amortization................................................. 5,153,239
General and administrative.................................................... 787,005
-----------
Total costs and expenses.............................................. 13,984,198
-----------
Income from operations................................................ 6,774,918
Other (income) expense
Interest expense.............................................................. 4,794,952
Other income.................................................................. (193,179)
-----------
Net income............................................................ $ 2,173,145
===========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-53
<PAGE> 348
CALPINE GEYSERS COMPANY, L.P.
STATEMENT OF CASH FLOWS
FOR THE PERIOD FROM JANUARY 1, 1993 TO APRIL 18, 1993
<TABLE>
<S> <C>
Cash flows from operating activities:
Net income................................................................... $ 2,173,145
Adjustments to reconcile net income to net cash provided by operating
activities:
Depreciation and amortization............................................. 5,153,239
Amortization of deferred costs............................................ 146,277
Changes in operating assets and liabilities:
Accounts receivable..................................................... 2,157,353
Supplies inventory...................................................... 81,061
Prepaid expenses........................................................ 837,841
Accounts payable and accrued liabilities................................ 2,634,254
Deferred revenue........................................................ 395,100
Payment on note payable................................................. (543,778)
------------
Net cash provided by operating activities............................ 13,034,492
------------
Cash flows from investing activities:
Acquisition of property, plant and equipment................................. (3,401,378)
Increase in restricted cash requirements..................................... (12,862)
------------
Net cash used for investing activities............................... (3,414,240)
------------
Cash flows from financing activities:
Repayment of debt............................................................ (2,200,000)
Partner distributions........................................................ (7,416,018)
------------
Net cash used for financing activities............................... (9,616,018)
------------
Net increase in cash and cash equivalents...................................... 4,234
Cash and cash equivalents at beginning of period............................... 2,700,135
------------
Cash and cash equivalents at end of period..................................... $ 2,704,369
============
Supplementary information:
Cash paid during the period for interest..................................... $ 3,914,710
============
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-54
<PAGE> 349
CALPINE GEYSERS COMPANY, L.P.
NOTES TO FINANCIAL STATEMENTS
FOR THE PERIOD FROM JANUARY 1, 1993 TO APRIL 18, 1993
1. BUSINESS AND FORMATION OF THE PARTNERSHIP
Business
Calpine Geysers Company, L.P. ("CGC"), a Delaware limited partnership, was
formed on April 5, 1990. CGC is the owner of two operating geothermal power
plants and their respective steam fields, and three geothermal steam fields
located in The Geysers area of northern California. Electricity and steam
generated by CGC is sold to two utilities under long-term power sales contracts
(see Note 9).
Formation of the Partnership
CGC was formed by Sonoma Geothermal Partners, L.P. ("SGP"), wholly owned by
Calpine Corporation ("Calpine"), and Freeport-McMoRan Resource Partners, Limited
Partnership ("FMRP") for the purpose of acquiring from FMRP the assets
constituting the geothermal business described above. On July 2, 1990, FMRP
contributed an undivided 15.93 percent interest in the existing assets and
geothermal business and $1,178,567 in cash for financing costs. SGP contributed
$22,165,718 in cash, including financing and closing costs of $2,008,000.
Concurrent with the formation of CGC, an agreement was entered into between
CGC and FMRP to purchase the remaining undivided 84.07 percent interest in the
existing assets and geothermal business for $227.0 million in cash plus the
assumption of the liabilities, not including existing project debt. The amount
was funded by SGP's contribution and a new nonrecourse credit arrangement with a
consortium of banks (see Note 5).
Under the CGC partnership agreement, profits are allocated first to SGP to
the extent necessary to achieve a target return, as defined. Thereafter, profits
are allocated 22.5 percent to SGP and 77.5 percent to FMRP.
Upon liquidation, equity is allocated first to SGP to the extent necessary
to achieve a target return as defined; second, equity is allocated to achieve
the target capital account ratios (22.5 percent to SGP and 77.5 percent to
FMRP); and third, equity is allocated 22.5 percent to SGP and 77.5 percent to
FMRP.
Cash distributions are allocated 99 percent to SGP and 1 percent to FMRP
until the target return is reached. Distributions made during the period from
January 1, 1993 to April 18, 1993 were $7,352,017 to SGP and $64,001 to FMRP.
Acquisition of FMRP Interest in CGC
On April 19, 1993, Calpine purchased all of FMRP's interest in CGC for
$59.8 million, terminating the partnership with FMRP. The purchase price
includes a $23.0 million cash payment by Calpine and a $36.8 million note
payable to FMRP.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Cash and Cash Equivalents
CGC's cash, cash equivalents and restricted cash are primarily held by one
major international financial institution. CGC considers all highly liquid
instruments purchased with an original maturity of three months or less to be
cash equivalents. The carrying amount of these instruments approximates fair
value because of their short maturity.
F-55
<PAGE> 350
CALPINE GEYSERS COMPANY, L.P.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Restricted Cash
CGC is required to maintain cash balances that are restricted by provisions
of its debt agreements and by regulatory agencies. CGC'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, their carrying value
approximates fair value.
Supplies Inventory
Supplies are valued at the lower of cost or market. Cost for large
replacement parts is determined using the specific identification method. For
the remaining supplies, cost is determined using the weighted average cost
method.
Property, Plant and Equipment
CGC uses the full cost method of accounting for costs incurred in
connection with the exploration and development of geothermal properties. All
such costs, including geological and geophysical expenses, costs of drilling
productive, nonproductive and reinjection wells and overhead directly related to
development activities, together with the costs of production equipment, the
related facilities and the operating power plants, are capitalized.
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 the
estimated remaining useful lives of the buildings and roads.
Proceeds from the sale of assets are applied against capitalized costs,
with no gain or loss recognized.
Deferred Costs
Deferred costs consist of financing costs, a commitment fee and Partnership
closing costs. These costs are amortized over the following periods:
<TABLE>
<S> <C>
Financing costs................................................. 15 years
Partnership closing costs....................................... 5 to 7 years
</TABLE>
Revenue Recognition
Revenues from sales of electricity are recognized as service is delivered.
Revenues from sales of steam are calculated considering a future period when
steam will be delivered without receiving corresponding revenue. This free steam
is being recorded at an average rate over future steam production as deferred
revenue.
A recent accounting principle requires companies to recognize revenue on
power sales agreements entered into after May 1992 using the lower of the actual
cash received or the average rate measured on a cumulative basis. CGC's power
sales agreements were entered into prior to May 1992. Had CGC applied this
principle, the revenues CGC recorded for the period from January 1, 1993 to
April 18, 1993 would have been approximately $488,000 less.
Income Taxes
Income taxes are the responsibility of the individual partners; therefore,
there is no provision for Federal and state income taxes in the financial
statements.
F-56
<PAGE> 351
CALPINE GEYSERS COMPANY, L.P.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
3. WORKING CAPITAL LOAN
CGC has a working capital agreement with a bank providing for advances not
to exceed $5.0 million less any outstanding letters of credit. The aggregate
unpaid principal of the working capital loan is payable in full at least once a
year commencing in 1991, with the final payment of principal, interest and fees
due June 30, 1995; interest accrues at the London Interbank Offered Rate (LIBOR)
plus .625 percent over the term of the loan.
4. NOTE PAYABLE
During 1992, CGC entered into a note payable with a financing company for
$543,778. The note bears interest at 3.79 percent annually and was repaid in two
installments in January and April 1993.
5. LONG-TERM DEBT
CGC has a $200.0 million ($176.8 million outstanding at April 18, 1993)
loan agreement with a bank, the components of which are as follows:
Senior term loans: $156.8 million outstanding at April 18, 1993 with
principal and interest payable in quarterly installments at variable
amounts beginning September 30, 1990 and the final payment of principal,
interest and fees due June 30, 2002; interest on $136.8 million is fixed at
9.93 percent with the remainder accruing at LIBOR plus .75 percent to 1.25
percent over the term of the loan; collateralized by all of CGC's assets
and the partners' interest.
Junior term loans: $20.0 million outstanding at April 18, 1993 with
principal and interest payable in quarterly installments at variable
amounts beginning September 30, 2002 and the final payment of principal,
interest and fees due June 30, 2005; interest accrues at LIBOR plus 1.5
percent to 2.75 percent over the term of the loan; the loan is
collateralized by all of CGC's assets and the partners' interest.
The annual principal maturities of the long-term debt outstanding at April
18, 1993 are as follows:
<TABLE>
<S> <C>
1993........................................................... $ 8,800,000
1994........................................................... 16,000,000
1995........................................................... 18,000,000
1996........................................................... 21,000,000
1997........................................................... 22,000,000
Thereafter..................................................... 91,000,000
------------
$176,800,000
============
</TABLE>
The senior and junior term loan agreements contain a number of covenants.
Two of these covenants require that CGC maintain restricted cash balances as
defined in the agreements, and that CGC maintain certain insurance coverages.
During the period from January 1, 1993 to April 18, 1993, CGC did not meet the
insurance covenant and has obtained a waiver for this violation.
The carrying value of the $136.8 million portion of the senior term notes
has an effective rate of 9.93 percent under CGC's interest rate swap agreements
(see Note 6). Based on the borrowing rates currently available to CGC for bank
loans with similar terms and maturities, the fair value of the debt as of April
18, 1993 is approximately $150.2 million.
The carrying value of the remaining $20.0 million of the senior and the
$20.0 million junior term loans approximates the debt's fair market value as the
rates are variable and are based on current LIBOR.
F-57
<PAGE> 352
CALPINE GEYSERS COMPANY, L.P.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
6. INTEREST RATE SWAP AGREEMENTS:
CGC entered into two interest rate swap agreements to minimize the impact
of changes in interest rates by effectively fixing its interest rate at 9.93
percent on a portion of its senior term note. The interest rate swap agreements
mature through December 31, 2000. CGC is exposed to credit loss in the event of
nonperformance by the other parties to the interest rate swap agreements.
7. COMMITMENTS AND CONTINGENCIES
Royalties and Leases
CGC is committed under several geothermal and right of way leases. The
geothermal leases generally provide for royalties based on production revenue,
with reductions for property taxes paid and the right of way leases are based on
flat rates and are not material. Under the terms of certain geothermal land
leases, royalties accrue at rates ranging from 7 percent to 12.5 percent of
electricity, steam and effluent revenue, net of property taxes. Certain
properties also have net profits and overriding royalty interests ranging from
approximately 1.7 percent to 23.5 percent, which are in addition to the land
lease royalties. CGC also has a working interest agreement with a third party
providing for the sharing of approximately 30 percent of drilling and other well
costs, various percentages of other operating costs and 30 percent of revenues
on specified wells of Unit 13 and Unit 16.
Most lease agreements contain clauses providing for minimum lease payments
to leaseholders if production temporarily ceases or if production falls below a
specified level.
Expenses under these agreements for the period from January 1, 1993 to
April 18, 1993 are as follows:
<TABLE>
<S> <C>
Production royalties............................................. $3,150,076
Lease payments................................................... 119,081
</TABLE>
Litigation
CGC is a party to lawsuits and claims arising out of the normal course of
business, principally related to royalty interests on geothermal property sites.
Management believes that the outcome of these claims and lawsuits will not have
a material adverse effect on CGC's financial position and results of operations.
8. RELATED PARTY TRANSACTIONS
The power plants and steam fields of CGC are operated by Calpine Operating
Plant Services, Inc. ("COPS"), wholly owned by Calpine Corporation, under an
Operating and Maintenance Agreement. Under the agreement, COPS is obligated to
perform all operation and maintenance services in connection with the business,
including operation, repair and maintenance of the power plants and steam
fields, arranging for new well drilling, providing administrative and billing
services, and performing technical analyses and contract administration.
For performance of these services, COPS is reimbursed for its direct costs
plus a general and administrative recovery rate of 12 percent for direct labor
costs, 10 percent for specific costs, and 5 percent for capital expenditures up
to $5.0 million per year, then 2 percent for additional capital expenditures. In
addition, the contract also includes an annual operating fee of $1.0 million,
escalating in relation to the Consumer Price Index. During the period from
January 1, 1993 to April 18, 1993, total charges under the Operating and
Maintenance Agreement amounted to approximately $7.1 million, including
approximately $3.7 million for capital expenditures.
F-58
<PAGE> 353
CALPINE GEYSERS COMPANY, L.P.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Calpine also charges CGC directly for expenses in connection with its
duties as general partner, and for technical and administrative services. During
the period from January 1, 1993 to April 18, 1993, charges amounted to
approximately $185,000.
FMRP has a royalty interest in one of the properties in production. During
the period from January 1, 1993 to April 18, 1993, production royalty expense
related to FMRP amounted to approximately $397,000.
9. SIGNIFICANT CUSTOMERS AND SUMMARY OF OPERATIONS:
CGC's revenue is derived primarily from two sources -- Pacific Gas and
Electric ("PG&E") and Sacramento Municipal Utility District ("SMUD"). Revenue
for the period from January 1, 1993 to April 18, 1993 is as follows:
<TABLE>
<S> <C>
PG&E............................................................ $17,323,683
SMUD............................................................ 3,830,533
-----------
21,154,216
Less revenues deferred.......................................... (395,100)
-----------
Total................................................. $20,759,116
===========
</TABLE>
Operating Geothermal Power Plants
Electricity from CGC's two operating geothermal power plants, Bear Canyon
and West Ford Flat, is sold to PG&E under the terms of twenty-year contracts
which began in 1989.
Under the terms of the contracts, CGC is paid for energy delivered based
upon a fixed price which escalates annually for the first ten years of the
contract and upon PG&E's full short-run avoided operating costs for the second
ten years.
CGC also receives capacity payments from PG&E. Under certain circumstances,
if CGC is unable to deliver firm capacity, then CGC may owe PG&E certain minimum
damages, as specified in the contracts.
Geothermal Steam Fields
Steam from CGC's three geothermal steam fields is sold to PG&E and SMUD
under contracts. PG&E is obligated to operate the plants (Unit 13 and Unit 16)
as close to full capacity and as continuously as possible. SMUD is obligated to
make its best effort to continuously accept steam generated by the plant, except
during outages.
Under the terms of the PG&E contract, the price paid for steam is adjusted
annually based upon prices paid by PG&E for fossil fuels (oil and natural gas)
and nuclear fuel. Under the terms of the SMUD contract, the price paid for steam
is adjusted bi-annually based upon inflation and price indices reflecting the
economy and the cost of fuel.
The contracts with both PG&E and SMUD also provide that CGC receive an
additional amount per mwh of net output as compensation for the cost of
disposing of liquid effluents, primarily steam condensate.
In the event the quantity of steam delivered at any of the plants is less
than 50 percent of the units rated capacity during any given month, PG&E or SMUD
is not required to pay for steam delivered during such month until the cost of
the power plants has been completely amortized.
The contracts may be terminated upon written notice under conditions
specified in the contract if further operation of the plants becomes
uneconomical. In the event that the contract is terminated by CGC, and if
requested by either PG&E or SMUD, CGC must assign to PG&E (Unit 13 and Unit 16)
or SMUD (SMUDGEO #1) all rights, title and interest to the wells, lands and
related facilities.
F-59
<PAGE> 354
REPORT OF INDEPENDENT ACCOUNTANTS
To the Shareholder of LFC No. 38 Corp. and Portsmouth Leasing Corporation:
We have audited the accompanying combined balance sheets of LFC No. 38 Corp. and
Portsmouth Leasing Corporation and Subsidiaries as of December 31, 1994 and
1993, and the related combined statements of operations, changes in
shareholder's deficiency and cash flows for the years then ended. These
financial statements are the responsibility of the Companies' management. Our
responsibility is to express an opinion on these 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 audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the combined financial position of LFC No. 38 Corp. and
Portsmouth Leasing Corporation and Subsidiaries as of December 31, 1994 and
1993, and the combined results of their operations and their cash flows for the
years then ended in conformity with generally accepted accounting principles.
As discussed in Note 4 to the financial statements, the Companies changed their
method of accounting for income taxes in 1993.
COOPERS & LYBRAND L.L.P.
2400 Eleven Penn Center
Philadelphia, Pennsylvania
February 3, 1995, except
as to the information presented
in Note 7 for which the date is
March 30, 1995
F-60
<PAGE> 355
LFC NO. 38 CORP. AND PORTSMOUTH LEASING CORPORATION AND SUBSIDIARIES
COMBINED BALANCE SHEETS
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------------
1994 1993
----------- -----------
<S> <C> <C>
ASSETS
Current assets
Cash and equivalents............................................ $ 2,986,606 $ 3,911,692
Accounts receivable............................................. 1,888,467 1,774,335
Other current assets............................................ 74,729 145,754
----------- -----------
Total current assets.................................... 4,949,802 5,831,781
Power production facility, less accumulated depreciation of
$6,086,660 and $5,057,568, respectively......................... 24,228,646 25,239,115
Project development rights, less accumulated amortization of
$1,093,026 and $915,778, respectively........................... 4,287,918 4,465,166
Deferred costs, less accumulated amortization of $1,335,381 and
$1,215,708, respectively........................................ 712,224 831,898
Land.............................................................. 340,938 340,938
----------- -----------
Total assets............................................ $34,519,528 $36,708,898
=========== ===========
LIABILITIES AND SHAREHOLDER'S DEFICIENCY
Current liabilities
Accounts payable and accrued liabilities........................ $ 1,372,360 $ 1,606,528
Accrued interest payable........................................ 136,294 245,135
Notes payable................................................... 1,819,071 1,633,676
Due to affiliates............................................... 224,413 555,185
----------- -----------
Total current liabilities............................... 3,552,138 4,040,524
Notes payable..................................................... 26,767,423 28,553,740
Liability for major maintenance................................... 1,850,728 1,266,518
Deferred income taxes............................................. 9,233,673 8,613,266
----------- -----------
Total liabilities....................................... 41,403,962 42,474,048
----------- -----------
Shareholder's deficiency
Common stock $1 par value, 2,000 shares authorized,
2,000 shares issued.......................................... 2,000 2,000
Capital in excess of par value.................................. 1,279 1,279
Accumulated deficit............................................. (565,743) (1,668,429)
----------- -----------
(562,464) (1,665,150)
Advances to affiliates.......................................... (6,321,970) (4,100,000)
----------- -----------
Total shareholder's deficiency.......................... (6,884,434) (5,765,150)
----------- -----------
Total liabilities and shareholder's deficiency.......... $34,519,528 $36,708,898
=========== ===========
</TABLE>
See Accompanying Notes to Combined Financial Statements
F-61
<PAGE> 356
LFC NO. 38 CORP. AND PORTSMOUTH LEASING CORPORATION AND SUBSIDIARIES
COMBINED STATEMENT OF OPERATIONS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------
1994 1993
----------- -----------
<S> <C> <C>
Revenues
Power sales....................................................... $17,431,700 $18,134,824
Interest income................................................... 234,154 89,318
----------- -----------
17,665,854 18,224,142
----------- -----------
Expenses
Operating costs................................................... 12,702,761 9,271,110
Depreciation and amortization..................................... 1,338,734 1,515,297
Interest expense.................................................. 1,738,152 1,740,675
----------- -----------
15,779,647 12,527,082
----------- -----------
Income before income taxes.......................................... 1,886,207 5,697,060
Income tax provision................................................ 783,521 2,307,233
----------- -----------
Income before cumulative effect of change in accounting principle... 1,102,686 3,389,827
Cumulative effect of change in accounting for income taxes.......... -- (5,108,294)
----------- -----------
Net income (loss)......................................... $ 1,102,686 $(1,718,467)
=========== ===========
</TABLE>
See Accompanying Notes to Combined Financial Statements
F-62
<PAGE> 357
LFC NO. 38 CORP. AND PORTSMOUTH LEASING CORPORATION AND SUBSIDIARIES
COMBINED STATEMENTS OF CHANGES IN SHAREHOLDER'S DEFICIENCY
(FOR THE YEARS ENDED DECEMBER 31, 1994 AND 1993)
<TABLE>
<CAPTION>
RETAINED
CAPITAL IN EARNINGS SHAREHOLDER'S
COMMON EXCESS OF (ACCUMULATED ADVANCES TO EQUITY
STOCK PAR VALUE DEFICIT) AFFILIATES (DEFICIENCY)
------ ---------- ------------ ----------- -------------
<S> <C> <C> <C> <C> <C>
Balance, December 31, 1992............. $2,000 $1,279 $ 50,038 -- $ 53,317
Advance to affiliates.................. -- -- -- $(4,100,000) (4,100,000)
Net loss............................... -- -- (1,718,467) -- (1,718,467)
------ ------ --------- ---------- ----------
Balance, December 31, 1993............. 2,000 1,279 (1,668,429) (4,100,000) (5,765,150)
Advance to affiliates.................. -- -- -- (2,221,970) (2,221,970)
Net income............................. -- -- 1,102,686 -- 1,102,686
------ ------ --------- ---------- ----------
Balance, December 31, 1994............. $2,000 $1,279 $ (565,743) $(6,321,970) $ (6,884,434)
====== ====== ========= ========== ==========
</TABLE>
See Accompanying Notes to Combined Financial Statements
F-63
<PAGE> 358
LFC NO. 38 CORP. AND PORTSMOUTH LEASING CORPORATION AND SUBSIDIARIES
COMBINED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------
1994 1993
----------- -----------
<S> <C> <C>
Cash flows from operating activities
Net income (loss)............................................... $ 1,102,686 $(1,718,467)
Adjustments to reconcile net income (loss) to net cash provided
by operating activities
Depreciation and amortization................................ 1,338,734 1,515,297
Provision for major maintenance.............................. 584,210 710,872
Payments for major maintenance............................... -- (814,244)
Cumulative effect of change in accounting for income taxes... -- 5,108,294
Deferred income taxes........................................ 620,408 2,306,433
Changes in operating assets and liabilities
Accounts receivable........................................ (114,132) 476,265
Due to affiliates.......................................... (330,771) (161,838)
Accounts payable and accrued liabilities................... (234,169) (1,862,005)
Other current assets....................................... 71,025 (20,955)
Accrued interest payable................................... (108,842) (23,990)
----------- -----------
Net cash provided by operating activities....................... 2,929,149 5,515,662
----------- -----------
Cash flows used in investing activities
Investment in power production facility......................... (31,343) (10,433)
----------- -----------
Cash flows used in financing activities
Repayment of financing.......................................... (1,600,922) (1,416,935)
Advances to affiliates.......................................... (2,221,970) (4,100,000)
----------- -----------
Net cash used in financing activities........................... (3,822,892) (5,516,935)
----------- -----------
Net decrease in cash and equivalents.............................. (925,086) (11,706)
Cash and equivalents -- beginning of period....................... 3,911,692 3,923,398
----------- -----------
Cash and equivalents -- end of period............................. $ 2,986,606 $ 3,911,692
=========== ===========
</TABLE>
See Accompanying Notes to Combined Financial Statements
F-64
<PAGE> 359
LFC NO. 38 CORP. AND PORTSMOUTH LEASING CORPORATION AND SUBSIDIARIES
NOTES TO COMBINED FINANCIAL STATEMENTS
NOTE 1 -- THE PARTNERSHIP AND THE PROJECT
LFC No. 38 Corp. (the "Limited Partner"), a Delaware corporation, is the
sole Limited Partner and Greenleaf Unit One Associates, Inc. (the "General
Partner"), a California corporation, is the sole General Partner (collectively
the "Partners") of Greenleaf Unit One Associates, L.P. (the "Partnership"), a
California Limited Partnership. Portsmouth Leasing Corporation ("Portsmouth"), a
Delaware corporation, is the sole owner of the General Partner. Portsmouth and
the Partners are wholly owned subsidiaries of Radnor Energy Partners, L.P.
("L.P."). L.P. is, in turn, a majority-owned subsidiary of LFC Financial Corp
("Financial"). The combined financial statements include the accounts of the
Partners, the Partnership, and Portsmouth (collectively the "Company") after
elimination of all material intercompany balances and transactions.
The Partnership owns and operates a 49.5 megawatt natural gas fired
cogeneration facility located in Yuba City, California (the "Project"). The
facility, which was completed in March 1989, produces electrical power which it
sells to Pacific Gas and Electric Company ("PG&E") pursuant to a power purchase
agreement that provides for electricity and capacity payments over a thirty-year
period. The exhaust gas generated by the Project is used to dry wood chips. The
wood drying facility is operated by Wood Fuel Processing, Inc. ("WFP") pursuant
to a processing facilities agreement. The agreement provides that WFP will pay
certain royalties to the Partnership in the future based on the profitability of
the wood drying operation. Operations and maintenance of the Project is
performed by Stockmar Energy Inc., which does business as LFC Power Systems
Corporation ("Power Systems"), an affiliate. Power Systems is a wholly owned
subsidiary of LFC Energy Corporation ("Energy"), which, in turn, is a
majority-owned subsidiary of Financial.
NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Power Production Facility -- The power production facility, which was
constructed by Power Systems, includes the cogeneration plant (including the
wood drying facility) and the related equipment and is stated at cost.
Depreciation is recorded utilizing the straight-line method over the estimated
useful life of the Project of thirty years. Upon disposition, the cost and
related accumulated depreciation of equipment removed from the accounts and the
resulting gain (loss) is included in gains (losses) on equipment sales for the
period.
Project Development Rights -- The Project development rights include all of
the essential contracts, agreements, permits, licenses and other agreements
which were required to construct and operate the Project, as well as the
preliminary design of the Project, the power purchase agreement, the FERC
certification and other contracts and agreements. These Project development
rights are being amortized by the Partnership over a thirty-year period.
Deferred Costs -- Deferred costs include lender, legal, and other
professional fees incurred in connection with the acquisition and construction
of the Project and pre-operating expenses which were capitalized. Capitalized
fees are amortized over their estimated useful lives and pre-operating expenses
are amortized over sixty months.
Major Maintenance -- Major maintenance costs are accrued ratably over the
scheduled maintenance period and are included in operating costs. Costs
anticipated to be incurred within the next twelve months are classified as a
current liability.
Income Taxes -- Effective January 1, 1993, the Company adopted Statement of
Financial Accounting Standards No. 109 -- "Accounting For Income Taxes"
("SFAS109"). SFAS109 requires the recognition of deferred income tax liabilities
and assets for the future tax consequences of transactions that have been
recognized for financial reporting or income tax purposes and includes a
requirement for adjustment of deferred tax balances for tax rate changes. The
Company joins with L.P. and affiliated companies in the filing of a consolidated
U.S. federal income tax return. The Company's policy is to provide for federal
and state
F-65
<PAGE> 360
LFC NO. 38 CORP. AND PORTSMOUTH LEASING CORPORATION AND SUBSIDIARIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
income taxes on a separate return basis. In addition, the Company has a tax
sharing arrangement with L.P. that provides to the extent that net operating
loss or investment tax credit carryforwards are not utilized by the Company on a
separate return basis, but are utilized in the consolidated tax return of L.P.,
the Company will receive a portion of these tax benefits. These payments will be
classified as capital in excess of par value.
Statements of Cash Flows -- The Company considers all highly liquid
investments with a maturity of three months or less to be cash equivalents for
purposes of the statement of cash flows. Net cash provided by operating
activities includes cash payments for interest of $1,846,993 and $1,764,666 in
1994 and 1993, respectively.
NOTE 3 -- NOTES PAYABLE
Notes payable at December 31, 1994 and 1993 consist of the following:
<TABLE>
<CAPTION>
1994 1993
----------- -----------
<S> <C> <C>
Note payable -- Bank...................................... $25,996,000 $27,507,000
Note payable -- Individuals............................... 2,590,494 2,680,416
----------- -----------
Total........................................... 28,586,494 30,187,416
Less current portion...................................... 1,819,071 1,633,676
----------- -----------
Noncurrent portion........................................ $26,767,423 $28,553,740
=========== ===========
</TABLE>
The Partnership's note payable is payable pursuant to a credit agreement
with the New York branch of Credit Suisse ("Credit Suisse") and is
collateralized by substantially all of the Partnership's assets. The credit
agreement contains certain restrictive covenants including the maintenance of
certain debt service coverage ratios, working capital requirements, and
limitations on distributions. In addition, all cash and equivalents are
maintained in accounts at Credit Suisse. The loan bears interest at variable
rates or fixed rates at the option of the Partnership. The effective interest
rate on the loan was 8.05% at December 31, 1994. The loan is being repaid over
ten years, commencing in 1990, in level quarterly debt service payments on a
fourteen-year amortization schedule with a balloon payment at the end of the
tenth year.
The note payable-individuals is payable pursuant to a sale/purchase
agreement with the former owners of the General Partner. The loan bears interest
at a fixed rate of 8.25%. The loan is scheduled to be repaid in twenty (20)
annual installments plus interest, with each payment being based upon 1.59% of
power sales. If the obligation is repaid prior to maturity, the Company must
continue the payments as defined until the payment period ends, 2010.
The required principal payments by year are as follows:
<TABLE>
<S> <C>
1995....................................................... $ 1,819,071
1996....................................................... 2,016,092
1997....................................................... 2,231,533
1998....................................................... 2,529,127
1999....................................................... 2,794,776
2000....................................................... 16,092,618
Thereafter................................................. 1,103,277
-----------
Total............................................ $28,586,494
===========
</TABLE>
F-66
<PAGE> 361
LFC NO. 38 CORP. AND PORTSMOUTH LEASING CORPORATION AND SUBSIDIARIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 4 -- INCOME TAXES
Effective January 1, 1993, the Company adopted SFAS109, which requires the
liability method of accounting for income taxes. The cumulative effect of the
change in method of accounting for income taxes of $5,108,294 was reported in
the 1993 statement of operations and as an increase in the net deferred tax
liability at January 1, 1993.
The income tax provision is comprised of the following:
<TABLE>
<CAPTION>
1994 1993
-------- ----------
<S> <C> <C>
Current
State...................................................... $ 26,944 $ 800
Federal.................................................... 136,169 --
Deferred
State...................................................... 175,417 529,827
Federal.................................................... 444,991 1,776,606
-------- ----------
Total $783,521 $2,307,233
======== ==========
</TABLE>
The provision for income taxes as a percentage of income before income tax
can be reconciled to the federal statutory rate as follows:
<TABLE>
<CAPTION>
1994 1993
---- ----
<S> <C> <C>
Federal statutory tax rate............................................. 34% 34%
State tax, net of federal benefit...................................... 6% 6%
Other.................................................................. 2% --
-- -
---
Provision for income taxes............................................. 42% 40%
=== ===
</TABLE>
The net deferred tax liability (determined in accordance with SFAS109)
consists of:
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------------
1994 1993
----------- -----------
<S> <C> <C>
Deferred tax liabilities:
Accumulated depreciation................................ $10,872,804 $11,353,409
----------- -----------
Deferred tax assets:
Liability for major maintenance......................... 742,845 508,355
Investment tax credit carryforward...................... 821,862 1,254,862
Net operating loss carryforward......................... 74,424 976,926
----------- -----------
1,639,131 2,740,143
----------- -----------
Net deferred tax liability................................ $ 9,233,673 $ 8,613,266
=========== ===========
</TABLE>
As of December 31, 1994, the Company had, on a separate company basis, a
state net operating loss carryforward of $800,260 which expires in 1996 through
1999 and investment tax credit carryforwards of $821,862 which expires in 2003.
NOTE 5 -- RELATED PARTIES AND OPERATING COSTS
The Partnership incurred operating costs through Power Systems of
$1,976,599 and $1,910,189 in 1994 and 1993, respectively. The Partnership's 1994
and 1993 operating costs include $3,264,328 and $2,680,216, respectively, for
the purchase of natural gas from affiliates. Affiliates also provided gathering,
transportation and fuel management services at a cost of $2,328,028 and $725,000
to the Partnership in 1994 and 1993,
F-67
<PAGE> 362
LFC NO. 38 CORP. AND PORTSMOUTH LEASING CORPORATION AND SUBSIDIARIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
respectively. The Partnership incurred $1,307,649 and $104,114 in 1994 and 1993,
respectively, for management services provided by L.P.
NOTE 6 -- COMMON STOCK
The combined common stock of the Company as of December 31, 1994 and 1993
consists of the following:
<TABLE>
<CAPTION>
CAPITAL
SHARES IN
AUTHORIZED $1 PAR EXCESS OF
AND ISSUED VALUE PAR VALUE
---------- ------ ---------
<S> <C> <C> <C>
LFC No. 38 Corp....................................... 1,000 $1,000 --
Portsmouth Leasing Corporation........................ 1,000 1,000 $ 1,279
----- ------ ------
Total....................................... 2,000 $2,000 $ 1,279
===== ====== ======
</TABLE>
NOTE 7 -- SUBSEQUENT EVENTS
On March 30, 1995, Financial entered into a stock purchase agreement to
sell the stock of the Company to Calpine Corporation. The transaction is
scheduled to close by April 28, 1995. No effect of the proposed sale has been
recognized in the accompanying financial statements.
F-68
<PAGE> 363
REPORT OF INDEPENDENT ACCOUNTANTS
To the Shareholder of LFC No. 60 Corp.:
We have audited the accompanying consolidated balance sheets of LFC No. 60 Corp.
and Subsidiary as of December 31, 1994 and 1993, and the related consolidated
statements of operations, changes in shareholder's deficiency and cash flows for
the years then ended. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of LFC No. 60 Corp.
and Subsidiary as of December 31, 1994 and 1993, and the consolidated results of
their operations and their cash flows for the years then ended in conformity
with generally accepted accounting principles.
As discussed in Note 4 to the financial statements, the Company changed its
method of accounting for income taxes in 1993.
COOPERS & LYBRAND L.L.P.
2400 Eleven Penn Center
Philadelphia, Pennsylvania
February 3, 1995, except
as to the information presented
in Note 6 for which the date is
March 30, 1995
F-69
<PAGE> 364
LFC NO. 60 CORP. AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------------
1994 1993
----------- -----------
<S> <C> <C>
ASSETS
Current assets
Cash and equivalents............................................ $ 2,088,588 $ 2,491,825
Accounts receivable, net of allowance for doubtful accounts of
$200,000 in 1993............................................. 2,076,594 1,967,998
Due from affiliates............................................. 776,253 --
Prepaid assets.................................................. 513,954 266,690
----------- -----------
Total current assets.................................... 5,455,389 4,726,513
Power production facility, less accumulated depreciation of
$5,430,948 and $4,339,447, respectively......................... 26,636,147 27,711,561
Project development rights, less accumulated amortization of
$330,417 and $265,417, respectively............................. 1,619,583 1,684,583
Deferred costs, less accumulated amortization of $1,410,676 and
$1,148,992, respectively........................................ 580,706 842,390
----------- -----------
Total assets............................................ $34,291,825 $34,965,047
=========== ===========
LIABILITIES AND SHAREHOLDER'S DEFICIENCY
Current liabilities
Accounts payable and accrued liabilities........................ $ 1,785,800 $ 882,746
Due to affiliates............................................... -- 634,451
Accrued interest payable........................................ 13,972 131,200
Note payable.................................................... 600,000 600,000
Liability for major maintenance................................. -- 969,996
----------- -----------
Total current liabilities............................... 2,399,772 3,218,393
Note payable...................................................... 31,600,000 32,200,000
Liability for major maintenance................................... 1,737,908 1,273,328
Deferred income taxes............................................. 6,368,319 5,764,303
----------- -----------
Total liabilities....................................... 42,105,999 42,456,024
----------- -----------
Shareholder's deficiency
Common stock $1 par value, authorized, issued and outstanding --
1,000 shares................................................. 1,000 1,000
Capital in excess of par value.................................. 1,199,000 1,199,000
Deficit......................................................... (395,931) (1,290,977)
----------- -----------
804,069 (90,977)
Advances to affiliates.......................................... (8,618,243) (7,400,000)
----------- -----------
Total shareholder's deficiency.......................... (7,814,174) (7,490,977)
----------- -----------
Total liabilities and shareholder's deficiency.......... $34,291,825 $34,965,047
=========== ===========
</TABLE>
See Accompanying Notes to Consolidated Financial Statements
F-70
<PAGE> 365
LFC NO. 60 CORP. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------
1994 1993
----------- -----------
<S> <C> <C>
Revenues
Power sales..................................................... $18,495,832 $19,223,155
Steam sales..................................................... 61,780 62,496
Interest income................................................. 155,715 68,247
----------- -----------
18,713,327 19,353,898
----------- -----------
Expenses
Operating costs................................................. 13,961,525 12,620,397
Depreciation and amortization................................... 1,418,185 1,436,668
Interest expense................................................ 1,773,839 1,702,354
----------- -----------
17,153,549 15,759,419
----------- -----------
Income before income taxes........................................ 1,559,778 3,594,479
Income tax provision.............................................. (664,732) (1,616,815)
----------- -----------
Income before cumulative effect of change in accounting
principle....................................................... 895,046 1,977,664
Cumulative effect of change in accounting for income taxes........ -- (2,773,609)
----------- -----------
Net income (loss)................................................. $ 895,046 $ (795,945)
=========== ===========
</TABLE>
See Accompanying Notes to Consolidated Financial Statements
F-71
<PAGE> 366
LFC NO. 60 CORP. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S DEFICIENCY
(FOR THE YEARS ENDED DECEMBER 31, 1994 AND 1993)
<TABLE>
<CAPTION>
CAPITAL IN
COMMON EXCESS OF ADVANCES TO
STOCK PAR VALUE DEFICIT AFFILIATES TOTAL
------ ---------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Balance December 31, 1992.... $1,000 $1,199,000 $ (495,032) $(3,600,000) $(2,895,032)
Net loss..................... -- -- (795,945) -- (795,945)
Advance to affiliates........ -- -- -- (3,800,000) (3,800,000)
------ ---------- ----------- ----------- -----------
Balance December 31, 1993.... 1,000 1,199,000 (1,290,977) (7,400,000) (7,490,977)
Net income................... -- -- 895,046 -- 895,046
Advance to affiliates........ -- -- -- (1,218,243) (1,218,243)
------ ---------- ----------- ----------- -----------
Balance, December 31, 1994... $1,000 $1,199,000 $ (395,931) $(8,618,243) $(7,814,174)
====== ========= ========== ========== ==========
</TABLE>
See Accompanying Notes to Consolidated Financial Statements
F-72
<PAGE> 367
LFC NO. 60 CORP. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------------
1994 1993
----------- -----------
<S> <C> <C>
Cash flows from operating expenses
Net income (loss)............................................... $ 895,046 $ (795,945)
Adjustments to reconcile net income (loss) to net cash provided
by operating activities
Depreciation and amortization................................ 1,418,185 1,436,668
Provision for major maintenance.............................. 331,134 818,329
Payments for major maintenance............................... (836,550) --
Provision for doubtful accounts.............................. -- 200,000
Cumulative effect of change in accounting principle.......... -- 2,773,609
Deferred income tax provision................................ 604,016 1,364,083
Changes in operating assets and liabilities
Accounts receivable........................................ (108,595) 41,995
Due from affiliates........................................ (1,410,704) (112,443)
Accounts payable and accrued liabilities................... 903,054 (1,184,769)
Prepaid assets............................................. (247,264) (19,510)
Accrued interest payable................................... (117,228) (20,866)
----------- -----------
Net cash provided by operating activities....................... 1,431,094 4,501,151
----------- -----------
Cash flows used in investing activities
Investment in power production facility......................... (16,088) (21,968)
----------- -----------
Cash flows used in financing activities
Repayment of financing.......................................... (600,000) (600,000)
Advances to affiliates.......................................... (1,218,243) (3,800,000)
----------- -----------
Net cash used in financing activities........................... (1,818,243) (4,400,000)
----------- -----------
Net increase (decrease) in cash and equivalents................... (403,237) 79,183
Cash and equivalents -- beginning of period....................... 2,491,825 2,412,642
----------- -----------
Cash and equivalents -- end of period............................. $ 2,088,588 $ 2,491,825
=========== ===========
</TABLE>
See Accompanying Notes to Consolidated Financial Statements
F-73
<PAGE> 368
LFC NO. 60 CORP. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 -- THE COMPANY AND THE PROJECT
LFC No. 60 Corp., a Delaware corporation, is a wholly-owned subsidiary of
Radnor Energy Partners, L.P. ("L.P."). L.P. is, in turn, a majority-owned
subsidiary of LFC Financial Corp ("Financial"). LFC No. 60 Corp. owns 100% of
the Greenleaf Unit Two Associates, Inc. ("GUTA"). The consolidated financial
statements include the accounts of LFC No. 60 Corp. and GUTA (the "Company")
after elimination of all material intercompany balances and transactions.
GUTA is a California corporation which owns and operates a 49.5 megawatt
natural gas fired cogeneration plant located in Yuba City, California (the
"Project"). The facility, which was completed in December 1989, produces
electrical power which it sells to Pacific Gas and Electric Company ("PG&E")
pursuant to a power purchase agreement that provides for electricity and
capacity payments over a thirty year period. The steam produced by the Project
is sold to Sunsweet Growers, Inc. under a long-term steam purchase agreement.
Operations and maintenance of the Project is performed by Stockmar Energy Inc.,
which does business as LFC Power Systems Corporation ("Power Systems"), an
affiliate. Power Systems is a wholly-owned subsidiary of LFC Energy Corporation
("Energy"), which, in turn, is a majority-owned subsidiary of Financial.
NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Power Production Facility -- The power production facility, which was
constructed by Power Systems, includes the cogeneration plant and the related
equipment and is stated at cost. Depreciation is recorded utilizing the
straight-line method over the estimated useful life of the Project of thirty
years. Upon disposition, the cost and related accumulated depreciation of
equipment is removed from the accounts and the resulting gain (loss) is included
in gains (losses) on equipment sales for the period.
Project Development Rights -- The Project development rights include all of
the essential contracts, agreements, permits, licenses and other agreements
which were required to construct and operate the Project as well as the
preliminary design of the Project, the power purchase agreement, the FERC
certification and other contracts and agreements. These Project development
rights are being amortized by the Company over a thirty-year period.
Deferred Costs -- Deferred costs include lender, legal, and other
professional fees incurred in connection with the acquisition and construction
of the Project and pre-operating expenses which were capitalized. Capitalized
fees are amortized over their estimated useful lives and pre-operating expenses
are amortized over sixty months.
Major Maintenance -- Major maintenance costs are accrued ratably over the
scheduled maintenance period and are included in operating costs. Costs
anticipated to be incurred within the next twelve months are classified as a
current liability.
Income Taxes -- Effective January 1, 1993, the Company adopted Statement of
Financial Accounting Standards No. 109 -- "Accounting For Income Taxes" ("SFAS
109"). SFAS109 requires the recognition of deferred income tax liabilities and
assets for the future tax consequences of transactions that have been recognized
for financial reporting or income tax purposes and includes a requirement for
adjustment of deferred tax balances for tax rate changes. The Company joins with
L.P. and affiliated companies in the filing of a consolidated U.S. federal
income tax return. The Company's policy is to provide for federal and state
income taxes on a separate return basis. In addition, the Company has a tax
sharing arrangement with L.P. that provides to the extent that net operating
loss or investment tax credit carryforwards are not utilized by the Company on a
separate return basis, but are utilized in the consolidated tax return of L.P.,
the Company will receive a portion of these tax benefits. These payments will be
classified as capital in excess of par value.
F-74
<PAGE> 369
LFC NO. 60 CORP. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Statements of Cash Flows -- The Company considers all highly liquid
investments purchased with a maturity of three months or less to be cash
equivalents for purposes of the statement of cash flows. Net cash provided by
operating activities includes cash payments for interest of $1,891,067 and
$1,723,220 in 1994 and 1993, respectively.
NOTE 3 -- NOTE PAYABLE
The Company's note payable is payable pursuant to a credit agreement with
the New York branch of Credit Suisse ("Credit Suisse") and is collateralized by
substantially all of the Company's assets. The credit agreement contains certain
restrictive covenants including the maintenance of certain debt service coverage
ratios, working capital requirements, and limitations on distributions. In
addition, all cash and equivalents are maintained in accounts at Credit Suisse.
The note bears interest at variable or fixed rates at the option of the Company.
The effective interest rate on the note was 7.81% at December 31, 1994. The note
is being repaid in quarterly payments through 2005.
The required principal payments by year are as follows:
<TABLE>
<S> <C>
1995....................................................... $ 600,000
1996....................................................... 600,000
1997....................................................... 600,000
1998....................................................... 2,000,000
1999....................................................... 2,500,000
Thereafter................................................. 25,900,000
-----------
Total................................................. $32,200,000
===========
</TABLE>
NOTE 4 -- INCOME TAXES
Effective January 1, 1993, the Company adopted SFAS 109, which requires the
liability method of accounting for income taxes. The cumulative effect of the
change in method of accounting for income taxes of $2,773,609 was reported in
the 1993 statement of operations and as an increase in the net deferred tax
liability at January 1, 1993.
The income tax provision is comprised of the following:
<TABLE>
<CAPTION>
1994 1993
-------- ----------
<S> <C> <C>
Deferred
Federal.................................................... $490,009 $1,293,236
State...................................................... 114,007 70,847
Current -- State............................................. 60,716 252,732
-------- ----------
Total.............................................. $664,732 $1,616,815
======== ==========
</TABLE>
The provision for income taxes as a percentage of income before income
taxes can be reconciled to the federal statutory rate as follows:
<TABLE>
<CAPTION>
1994 1993
---- ----
<S> <C> <C>
Federal statutory tax rate............................................. 34% 34%
State Tax.............................................................. 8% 6%
Other.................................................................. 1% 5%
-- --
Provision for income taxes........................................... 43% 45%
== ==
</TABLE>
F-75
<PAGE> 370
LFC NO. 60 CORP. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The net deferred tax liability (determined in accordance with SFAS109)
consists of:
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------
1994 1993
---------- ----------
<S> <C> <C>
Deferred tax liabilities:
Accumulated depreciation.................................. $9,123,465 $8,509,818
---------- ----------
Deferred tax assets:
Liability for major maintenance........................... 713,324 922,858
Investment tax credit carryforward........................ 1,333,448 1,333,448
Net operating loss carryforward........................... 708,374 418,977
Other..................................................... -- 70,232
---------- ----------
2,755,146 2,745,515
---------- ----------
Net deferred tax liability.................................. $6,368,319 $5,764,303
========== ==========
</TABLE>
As of December 31, 1994, the Company had a tax net operating loss carry
forward determined on a separate company basis of $2,023,928 which expires in
2007 through 2009. As of December 31, 1994, the Company had ITC carryforwards
determined on a separate company basis of $1,333,448 which expire in 2004.
NOTE 5 -- RELATED PARTIES AND OPERATING COSTS
The Company incurred operating costs of $1,610,780 and $2,330,001 through
Power Systems in 1994 and 1993, respectively. The Company's 1994 and 1993
operating costs include $1,088,550 and $1,421,558, respectively, for the
purchase of natural gas from affiliates. Affiliates provided gathering,
transportation and fuel management services at a cost of $2,181,758 and $400,000
in 1994 and 1993, respectively. The Company incurred $1,307,465 and $104,106 in
1994 and 1993, respectively, for management services provided by L.P.
NOTE 6 -- SUBSEQUENT EVENT
On March 30, 1995, Financial entered into a stock purchase agreement to
sell the stock of the Company and certain affiliates to Calpine Corporation. The
transaction is scheduled to close by April 28, 1995. No effect of the proposed
sale has been recognized in the accompanying financial statements.
F-76
<PAGE> 371
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the General Partner of
BAF Energy, A California Limited Partnership:
We have audited the accompanying balance sheets of BAF Energy, A California
Limited Partnership, as of October 31, 1995 and 1994, and the related statements
of income, partners' equity and cash flows for each of the three years ended
October 31, 1995, 1994 and 1993. These financial statements are the
responsibility of the Partnership's management. Our responsibility is to express
an opinion on these 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 audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of BAF Energy, A California
Limited Partnership, as of October 31, 1995 and 1994, and the results of its
operations and its cash flows for each of the three years ended October 31,
1995, 1994 and 1993 in conformity with generally accepted accounting principles.
As explained in Note 1 to the financial statements, effective November 1,
1994, the Company changed its method of accounting for investments.
As discussed in Note 8 to the financial statements, subsequent to October
31, 1995, the Partnership signed a letter agreement with a third party to lease
substantially all of its property, plant and equipment and assign all related
contracts to a third party.
ARTHUR ANDERSEN LLP
San Francisco, California
December 6, 1995
F-77
<PAGE> 372
BAF ENERGY,
A CALIFORNIA LIMITED PARTNERSHIP
BALANCE SHEETS
OCTOBER 31, 1995 AND 1994
<TABLE>
<CAPTION>
1995 1994
------------ ------------
<S> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents..................................... $ 3,757,921 $ 5,363,057
Available for sale securities................................. 1,919,184 --
Restricted available-for-sale securities...................... 7,241,305 12,332,244
Accounts receivable -- trade.................................. 10,916,919 5,277,413
Supplies inventory............................................ 2,153,129 2,060,935
Prepaid insurance............................................. 288,383 251,375
------------ ------------
Total current assets.................................. 26,276,841 25,285,024
------------ ------------
Property, plant and equipment................................... 100,258,434 100,210,960
Accumulated depreciation and amortization..................... (24,387,912) (20,854,389)
------------ ------------
75,870,522 79,356,571
------------ ------------
Total assets.......................................... $102,147,363 $104,641,595
============ ============
LIABILITIES AND PARTNERS' EQUITY
Current liabilities
Accounts payable.............................................. $ 1,598,177 $ 2,824,110
Interest payable.............................................. 1,309,566 1,396,495
Payable to affiliate.......................................... 166,569 615,881
Current portion of long-term liabilities...................... 5,444,386 5,283,785
------------ ------------
Total current liabilities............................. 8,518,698 10,120,271
------------ ------------
Long-term liabilities........................................... 66,804,704 71,157,714
------------ ------------
Commitments and contingencies (Note 6)
Partners' equity:
Contributed equity............................................ 9,901,600 9,901,600
Undistributed earnings........................................ 16,922,361 13,462,010
------------ ------------
Total partners' equity................................ 26,823,961 23,363,610
------------ ------------
Total liabilities and partners' equity................ $102,147,363 $104,641,595
============ ============
</TABLE>
The accompanying notes are an integral part of these statements.
F-78
<PAGE> 373
BAF ENERGY,
A CALIFORNIA LIMITED PARTNERSHIP
STATEMENTS OF INCOME
FOR THE YEARS ENDED OCTOBER 31, 1995, 1994 AND 1993
<TABLE>
<CAPTION>
1995 1994 1993
----------- ----------- -----------
<S> <C> <C> <C>
Operating Revenues.................................. $43,835,619 $47,955,622 $49,738,504
Operating Expenses:
Fuel.............................................. 9,193,490 14,079,684 16,449,118
Depreciation and amortization..................... 3,578,572 3,575,442 3,576,710
Labor, supplies and other......................... 6,614,543 6,959,891 6,343,755
----------- ----------- -----------
Total operating expenses.................. 19,386,605 24,615,017 26,369,583
----------- ----------- -----------
Operating income.......................... 24,449,014 23,340,605 23,368,921
----------- ----------- -----------
Other Income and Expense:
Interest income and other......................... 955,299 477,666 448,961
General and administrative........................ (773,610) (784,401) (653,373)
Interest expense.................................. (8,165,273) (8,654,453) (9,091,695)
----------- ----------- -----------
Total other income and expense............ (7,983,584) (8,961,188) (9,296,107)
----------- ----------- -----------
Partnership Income.................................. $16,465,430 $14,379,417 $14,072,814
=========== =========== ===========
</TABLE>
The accompanying notes are an integral part of these statements.
F-79
<PAGE> 374
BAF ENERGY,
A CALIFORNIA LIMITED PARTNERSHIP
STATEMENTS OF PARTNERS' EQUITY
FOR THE YEARS ENDED OCTOBER 31, 1995, 1994 AND 1993
<TABLE>
<CAPTION>
GENERAL LIMITED UNREALIZED TOTAL
PARTNERS' PARTNERS' UNDISTRIBUTED LOSSES ON PARTNERS'
EQUITY EQUITY EARNINGS SECURITIES EQUITY
--------- ---------- ------------- ----------- ------------
<S> <C> <C> <C> <C> <C>
Balance, October 31, 1992.......... $ 100 $9,901,500 $ 13,509,779 $ -- $ 23,411,379
Net income....................... -- -- 14,072,814 -- 14,072,814
Cash distributions............... -- -- (15,000,000) -- (15,000,000)
---- ---------- ------------ ------- ----
Balance, October 31, 1993.......... 100 9,901,500 12,582,593 -- 22,484,193
Net income....................... -- -- 14,379,417 -- 14,379,417
Cash distributions............... -- -- (13,500,000) -- (13,500,000)
---- ---------- ------------ ------- ----
Balance, October 31, 1994.......... 100 9,901,500 13,462,010 -- 23,363,610
Net income....................... -- -- 16,465,430 -- 16,465,430
Cash distributions............... -- -- (13,000,000) -- (13,000,000)
Change in unrealized losses on
available-for-sale
securities.................... -- -- -- (5,079) (5,079)
---- ---------- ------------ ------- ----
Balance, October 31, 1995.......... $ 100 $9,901,500 $ 16,927,440 $ (5,079) $ 26,823,961
==== ========== ============ ======= ====
</TABLE>
The accompanying notes are an integral part of these statements.
F-80
<PAGE> 375
BAF ENERGY,
A CALIFORNIA LIMITED PARTNERSHIP
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED OCTOBER 31, 1995, 1994 AND 1993
<TABLE>
<CAPTION>
1995 1994 1993
------------ ------------ ------------
<S> <C> <C> <C>
Cash flows from operating activities:
Partnership income............................. $ 16,465,430 $ 14,379,417 $ 14,072,814
Adjustments to reconcile partnership income to
net cash provided from operating
activities --
Depreciation and amortization............. 3,578,572 3,575,442 3,576,710
Realized (gains) losses on sales of
available-for-sale securities, net..... (465) 10,189 (22,701)
Change in operating assets &
liabilities --
Accounts receivable -- trade........... (5,639,506) 7,560,768 (6,403,581)
Supplies inventory..................... (92,194) (301,309) (11,406)
Prepaid insurance...................... (37,008) (69,663) 4,270
Accounts payable....................... (1,225,933) (1,375,739) 1,516,130
Interest payable....................... (86,929) (77,740) (69,540)
Payable to affiliate................... (449,312) 463,194 (1,130,695)
Other, net............................. (45,049) -- --
---------- ---------- ----------
Net cash provided by operating
activities........................ 12,467,606 24,164,559 11,532,001
---------- ---------- ----------
Cash flows from investing activities:
Purchases of available-for-sale securities..... (34,628,300) (25,334,642) (16,319,709)
Proceeds from sales and maturities of
available-for-sale securities............... 37,795,441 20,232,824 20,074,603
Additions to property, plant and equipment,
net......................................... (47,474) (21,066) (131,924)
---------- ---------- ----------
Net cash provided by (used in)
investing activities.............. 3,119,667 (5,122,884) 3,622,970
---------- ---------- ----------
Cash flows from financing activities:
Reductions of long-term liabilities, net....... (4,192,409) (3,587,576) (3,250,397)
Cash distributions to partners................. (13,000,000) (13,500,000) (15,000,000)
---------- ---------- ----------
Net cash used in financing
activities........................ (17,192,409) (17,087,576) (18,250,397)
---------- ---------- ----------
Net (decrease) increase in cash and cash
equivalents.................................... (1,605,136) 1,954,099 (3,095,426)
Cash and cash equivalents, beginning of year..... 5,363,057 3,408,958 6,504,384
---------- ---------- ----------
Cash and cash equivalents, end of year........... $ 3,757,921 $ 5,363,057 $ 3,408,958
========== ========== ==========
Supplemental disclosure of noncash investing and
financing activities
Unrealized holding losses, net, on
available-for-sale securities, recorded as
additions to undistributed earnings......... $ (5,079) $ -- $ --
</TABLE>
The accompanying notes are an integral part of these statements.
F-81
<PAGE> 376
BAF ENERGY,
A CALIFORNIA LIMITED PARTNERSHIP
NOTES TO FINANCIAL STATEMENTS
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Organization
Basic American, Inc. (BAI) formed BAF Energy, A California Limited
Partnership (BAF Energy or the Partnership) on March 25, 1986, for the purpose
of developing, constructing and operating a cogeneration facility. The term of
the Partnership is through December 2020 unless terminated earlier in accordance
with the Partnership Agreement. The facility produces and sells electricity and
steam. On December 6, 1995, the Partnership signed a letter agreement with a
third party to lease substantially all of the Partnership's property, plant and
equipment and to assign all related contracts. The third party lessee will
operate the cogeneration facility through April, 2019 (see Note 8).
BAF Energy, Inc. (BEI) is the general partner of the Partnership and has an
ownership interest of 1 percent. BEI is a wholly owned subsidiary of Basic
Vegetable Products, Inc. (BVP). BVP is a wholly owned subsidiary of BAI. As of
October 31, 1995, BAI also owned approximately 51 percent of the Limited
Partnership units of BAF Energy then outstanding.
Distributions and profit and loss are allocated 99 percent to the limited
partners, based on their proportionate share of limited partnership units, and 1
percent to the general partner.
Reclassifications
Certain reclassifications have been made to the 1994 and 1993 financial
statements to be consistent with the current year presentation.
Cash and Cash Equivalents
For purposes of reporting cash flows, cash and cash equivalents include
cash on deposit with banks, money market funds, and commercial paper. Cash paid
for interest during the years ended October 31, 1995, 1994 and 1993 was
$8,252,202, $8,732,052 and $9,161,241, respectively.
Available-for-Sale Securities
Effective November 1, 1994, the Partnership adopted Statement of Financial
Accounting Standards No. 115, "Accounting for Certain Investments in Debt and
Equity Securities" (SFAS 115). The Partnership has classified its investments as
available-for-sale securities and as restricted available-for-sale securities
and has recorded all securities holdings at fair value. Unrealized gains and
losses are reported as a separate component of partners' equity until realized.
Premiums and discounts are amortized over the life of the related security
as an adjustment to interest income using the effective interest method.
Interest income is recognized when earned. Realized gains and losses on
securities transactions are included in net income and are derived using the
specific identification method for determining the cost of securities sold.
Prior to the November 1, 1994 adoption of SFAS 115, the Partnership's
short-term investments were included in cash and short-term investments and were
valued at the lower of aggregate cost or market. Such securities have been
reclassified as available-for-sale securities to conform with SFAS 115
presentation requirements.
The effect of adopting SFAS 115 was to recognize net unrealized holding
losses of $32,599 as a decrease in partners' equity as of November 1, 1994. At
October 31, 1995, net unrealized holding losses were $5,079.
Restricted securities are required under the term loans described in Note
4.
F-82
<PAGE> 377
BAF ENERGY,
A CALIFORNIA LIMITED PARTNERSHIP
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Property, Plant and Equipment
Property, plant and equipment are stated at cost less accumulated
depreciation and amortization. Depreciation and amortization of property, plant
and equipment are computed on a straight-line method principally over the
following estimated useful lives:
<TABLE>
<CAPTION>
YEARS
--------
<S> <C>
Buildings and improvements.......................................... 30
Machinery and equipment............................................. 5 to 30
</TABLE>
Major Maintenance Accruals
The Partnership accrues for the estimated future costs of major overhauls
and equipment replacement based upon engineering studies.
Income Taxes
Federal and state income tax regulations provide that no income taxes are
levied on a partnership. Instead, each partners' share of partnership profit or
loss is reported on his or her separate income tax return. Accordingly, no
partnership income taxes are provided for in the accompanying financial
statements.
(2) AVAILABLE-FOR-SALE SECURITIES
As of October 31, 1995, the amortized cost and estimated fair values of the
Partnership's investments in tax-exempt municipal securities are summarized as
follows:
<TABLE>
<CAPTION>
RESTRICTED
AVAILABLE- AVAILABLE-
FOR-SALE FOR-SALE
SECURITIES SECURITIES TOTAL
---------- ---------- ----------
<S> <C> <C> <C>
Amortized cost......................... $1,919,184 $7,246,384 $9,165,568
Gross unrealized losses................ -- (5,079) (5,079)
---------- ---------- ----------
Estimated fair value................... $1,919,184 $7,241,305 $9,160,489
========== ========== ==========
</TABLE>
The amortized cost and estimated fair value of tax-exempt municipal
securities by contractual maturity are shown below.
<TABLE>
<CAPTION>
AMORTIZED ESTIMATED
DUE IN FISCAL YEAR ENDING OCTOBER 31, COST FAIR VALUE
---------------------------------------------------- ---------- ----------
<S> <C> <C>
1996................................................ $2,137,292 $2,134,000
1997-2000........................................... 7,028,276 7,026,489
---------- ----------
Total..................................... $9,165,568 $9,160,489
========== ==========
</TABLE>
Proceeds from sales of investments for the year ended October 31, 1995 are
as follow:
<TABLE>
<S> <C>
Gross proceeds.................................................. $26,099,037
Gross gains..................................................... $ 4,404
Gross losses.................................................... $ 3,939
</TABLE>
F-83
<PAGE> 378
BAF ENERGY,
A CALIFORNIA LIMITED PARTNERSHIP
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(3) PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment and accumulated depreciation and amortization
consist of:
<TABLE>
<CAPTION>
1995 1994
------------ ------------
<S> <C> <C>
Cost
Buildings and improvements............................ $ 1,410,873 $ 1,313,304
Machinery and equipment............................... 98,847,561 98,897,656
------------ ------------
100,258,434 100,210,960
Accumulated depreciation and amortization............... (24,387,912) (20,854,389)
------------ ------------
$ 75,870,522 $ 79,356,571
============ ============
</TABLE>
On December 6, 1995, the Partnership signed a letter agreement with a third
party to lease substantially all of the Partnership's property, plant and
equipment (see Note 8).
(4) LONG-TERM LIABILITIES
Long-term liabilities are summarized as follows:
<TABLE>
<CAPTION>
1995 1994
----------- -----------
<S> <C> <C>
Term loan at 10.88%, due in equal installments through
March 2004, non-recourse to the Partnership, secured by
the facility and associated contracts................... $60,514,066 $64,678,085
Term loan at 15.65%, due in equal installments through
March 2004, with recourse to BEI, secured by the
facility and associated contracts....................... 8,137,159 8,575,025
Major maintenance accruals................................ 3,597,865 3,188,389
----------- -----------
72,249,090 76,441,499
Less -- Current maturities................................ 5,444,386 5,283,785
----------- -----------
$66,804,704 $71,157,714
=========== ===========
</TABLE>
Annual Maturities,
Annual maturities of long-term liabilities at October 31, 1995 are
summarized as follows:
<TABLE>
<CAPTION>
YEAR ENDING OCTOBER 31, AMOUNT
---------------------------------------------------------------- -----------
<S> <C>
1996............................................................ $ 5,444,386
1997............................................................ 6,121,107
1998............................................................ 6,716,700
1999............................................................ 7,224,887
2000............................................................ 10,541,918
Thereafter...................................................... 36,200,092
-----------
$72,249,090
===========
</TABLE>
(5) RELATED PARTY TRANSACTIONS
The Partnership Agreement requires that the Partnership pay BEI a monthly
administrative fee. This fee amounted to $146,596, $139,613 and $132,966 for the
years ended October 31, 1995, 1994 and 1993, respectively.
F-84
<PAGE> 379
BAF ENERGY,
A CALIFORNIA LIMITED PARTNERSHIP
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
The Partnership has entered into a ground lease with a remaining term of 23
years with BAI for the land on which the facility is located. The lease includes
options to extend the lease term up to an additional 30 years. Rent was
$146,572, $139,593 and $132,946 for the years ended October 31, 1995, 1994 and
1993, respectively. Rents will escalate at the rate of 5% each year. In fiscal
1996, this lease will be assigned to a third party lessee pursuant to a letter
agreement discussed at Note 8.
The Partnership negotiated a steam sales contract with a remaining term of
23 years with Basic Vegetable Products, LP (BVP, LP). The General Partner of
BVP, LP is BVP. Under the contract, the Partnership supplies steam to BVP, LP's
King City, California food processing plant. Revenues recorded under the
contract totaled $669,341, $840,959 and $1,068,141 in 1995, 1994 and 1993,
respectively. In fiscal 1996, this contract will also be assigned (see Note 8).
(6) COMMITMENTS AND CONTINGENCIES
Facilities
The Partnership executed an Operations and Maintenance (O & M) Agreement
with Bechtel North American Power Corporation (Bechtel) in which Bechtel is
required to operate and maintain the facility for a term of five years from May
1989. The Partnership reimburses Bechtel for all costs incurred in the
performance of the service. O & M expenses paid totaled $3,665,168, $3,884,943
and $4,556,321 in 1995, 1994 and 1993, respectively, including a payment of base
fees of $275,000, $387,456 and $500,000 per year, respectively, and a payment of
earned fees of $380,000, $306,803 and $902,430 per year, respectively. The
agreement also provided for a "high performance" bonus fee dependent on meeting
certain performance standards. In April 1994, the O & M Agreement was
renegotiated and extended through October 1998. The renegotiated terms include
payment of base fees of $275,000 and elimination of the high performance bonus
fee. The bonus paid in 1994 and 1995 totaled $3,107 and $175,327, respectively.
In connection with the anticipated transaction described at Note 8, the
Partnership will sever its O & M Agreement with Bechtel. The severance payment
will be made with funds directly contributed by the third party lessee.
Financing
Calcorp Group, Inc. (CGI), a limited partner, has a put option to sell its
23 percent investment in the Partnership back to the Partnership at fair market
value in certain circumstances. The put is subject to a subordination agreement
with the Partnership's lenders. CGI has entered into a technical support
agreement with the Partnership, wherein CGI is reimbursed for services rendered
based upon time and expenses incurred.
(7) REVENUE RECOGNITION
BEI has an exclusive Power Purchase Agreement with Pacific Gas and Electric
(PG&E) under which PG&E pays capacity payments, as defined in the agreement, and
purchases all available energy, except for amounts sold to BVP, LP (see Note 5).
The Partnership receives substantially all of its capacity payments from PG&E
during May through October, and receives payment for energy sales to PG&E during
May through January. In fiscal 1996, this agreement will be assigned to a third
party lessee pursuant to a letter agreement discussed at Note 8.
(8) SIGNIFICANT LEASE TRANSACTION
On December 6, 1995, BAF Energy signed a letter agreement with a third
party to enter into a 23-year lease of the cogeneration property, plant and
equipment and to assign all related contracts. Under the terms of the lease, the
lessee will assume all rights and responsibilities related to the ground lease
(see Note 5), the BVP, LP steam sales contract (see Note 5), and the PG&E Power
Purchase Agreement (see Note 7). BAF Energy expects to sign the lease in early
1996.
F-85
<PAGE> 380
BAF ENERGY,
A CALIFORNIA LIMITED PARTNERSHIP
CONDENSED BALANCE SHEETS
<TABLE>
<CAPTION>
OCTOBER 31,
1995
JANUARY 31, -------------
1996
-----------
(UNAUDITED)
<S> <C> <C>
ASSETS
Current Assets:
Cash and cash equivalents..................................... $ 2,211,511 $ 3,757,921
Available for sale securities................................. -- 1,919,184
Restricted available-for-sale securities...................... 10,953,152 7,241,305
Accounts receivable -- trade.................................. 2,703,251 10,916,919
Supplies inventory............................................ 2,128,361 2,153,129
Prepaid insurance............................................. 144,633 288,383
------------ ------------
Total current assets.................................. 18,140,908 26,276,841
------------ ------------
Property, Plant and Equipment................................... 100,258,434 100,258,434
Accumulated depreciation and amortization..................... (25,280,413) (24,387,912)
------------ ------------
74,978,021 75,870,522
------------ ------------
$93,118,929 $ 102,147,363
============ ============
LIABILITIES AND PARTNERS' EQUITY
Current Liabilities:
Accounts payable.............................................. $ 811,919 $ 1,598,177
Interest payable.............................................. 3,273,915 1,309,566
Payable to affiliate.......................................... 38,428 166,569
Current portion of long-term liabilities...................... 5,546,361 5,444,386
------------ ------------
Total current liabilities............................. 9,670,623 8,518,698
------------ ------------
Long-Term Liabilities........................................... 66,702,729 66,804,704
------------ ------------
Commitments and Contingencies................................... -- --
Partners' Equity:
Contributed equity............................................ 9,901,600 9,901,600
Undistributed earnings........................................ 6,843,977 16,922,361
------------ ------------
Total partners' equity................................ 16,745,577 26,823,961
------------ ------------
$93,118,929 $ 102,147,363
============ ============
</TABLE>
The accompanying notes are an integral part of these statements.
F-86
<PAGE> 381
BAF ENERGY,
A CALIFORNIA LIMITED PARTNERSHIP
CONDENSED STATEMENTS OF INCOME
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED
JANUARY 31,
---------------------------
1996 1995
----------- -----------
<S> <C> <C>
OPERATING REVENUES................................................ $ 4,957,368 $ 7,941,577
OPERATING EXPENSES:
Fuel............................................................ 1,479,116 3,408,912
Depreciation and amortization................................... 892,500 1,072,028
Labor, supplies and other....................................... 1,066,580 1,431,321
----------- -----------
Total operating expenses................................ 3,438,196 5,912,261
----------- -----------
Operating income...................................... 1,519,172 2,029,316
----------- -----------
OTHER INCOME AND EXPENSE:
Interest income and other....................................... 154,073 130,313
General and administrative...................................... (290,763) (201,340)
Interest expense................................................ (1,965,945) (2,094,761)
----------- -----------
Total other income and expense.......................... (2,102,635) (2,165,788)
----------- -----------
PARTNERSHIP LOSS.................................................. $ (583,463) $ (136,472)
=========== ===========
</TABLE>
The accompanying notes are an integral part of these statements.
F-87
<PAGE> 382
BAF ENERGY,
A CALIFORNIA LIMITED PARTNERSHIP
CONDENSED STATEMENTS OF CASH FLOWS
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED
JANUARY 31,
-----------------------------
1996 1995
------------ ------------
<S> <C> <C>
Net Cash Provided by Operating Activities....................... $ 9,779,417 $ 2,298,789
------------ ------------
Cash Flows from Investing Activities:
Purchases of available-for-sale securities.................... (25,170,795) (12,290,102)
Proceeds from sales and redemptions of available-for-sale
securities................................................. 23,344,968 12,841,335
Additions to property, plant and equipment, net............... -- (20,189)
------------ ------------
Net cash (used in) provided by investing activities... (1,825,827) 531,044
------------ ------------
Cash Flows From Financing Activities:
Increase in long-term liabilities, net........................ -- 307,110
Cash distributions to partners................................ (9,500,000) (8,500,000)
------------ ------------
Net cash used in financing activities................. (9,500,000) (8,192,890)
------------ ------------
Net Decrease in Cash and Cash Equivalents....................... (1,546,410) (5,363,057)
Cash and Cash Equivalents, beginning of period.................. 3,757,921 5,363,057
------------ ------------
Cash and Cash Equivalents, end of period........................ $ 2,211,511 $ --
============ ============
Supplementary Information:
Unrealized holding gains/losses, net, on available-for-sale
securities, recorded as additions to undistributed
earnings................................................... $ 5,079 $ --
Cash paid during the period for interest...................... $ -- $ --
</TABLE>
The accompanying notes are an integral part of these statements.
F-88
<PAGE> 383
BAF ENERGY,
A CALIFORNIA LIMITED PARTNERSHIP
NOTES TO CONDENSED FINANCIAL STATEMENTS
JANUARY 31, 1996
(UNAUDITED)
(1) GENERAL
Organization
BAF Energy, A California Limited Partnership (BAF Energy or the
Partnership) was founded in 1986 and is engaged in the development, construction
and operation of a cogeneration facility. The term of the Partnership is through
December 2020 unless terminated earlier in accordance with the Partnership
Agreement. The facility produces and sells electricity and steam.
BAF Energy, Inc. (BEI) is the general partner of the Partnership and has an
ownership interest of 1 percent. BEI is a wholly owned subsidiary of Basic
Vegetable Products, Inc. (BVP). BVP is a wholly owned subsidiary of Basic
American, Inc. (BAI). As of January 31, 1996, BAI also owned approximately 51
percent of the limited partnership units of BAF Energy then outstanding.
Distributions and profit and loss are allocated 99 percent to the limited
partners, based on their proportionate share of limited partnership units, and 1
percent to the general partner.
Basis of Interim Presentation
The accompanying interim condensed financial statements of the Partnership
have been prepared by the Partnership, without audit by independent public
accountants, pursuant to the rules and regulations of the Securities and
Exchange Commission. In the opinion of management, the condensed consolidated
financial statements include all normal recurring adjustments necessary to
present fairly the information required to be set forth therein. Certain
information and note disclosures normally included in financial statements
prepared in accordance with generally accepted accounting principles have been
condensed or omitted from these statements pursuant to such rules and
regulations and, accordingly, should be read in conjunction with the audited
financial statements of the Partnership for the year ended October 31, 1995.
Consistent with the operating schedule of the cogeneration facility, the
Partnership receives a majority of its operating revenue between May and
September. Therefore, the results of operations for the three months ended
January 31, 1996 and 1995 are not indicative of the results for the entire year.
(2) RELATED PARTY TRANSACTIONS
The Partnership Agreement requires that the Partnership pay BEI a monthly
administrative fee. This fee amounted to $37,558 and $35,770 for the quarters
ended January 31, 1996 and 1995, respectively.
The Partnership has entered into a ground lease with BAI for the land on
which the facility is located. Rent was $37,554 and $35,764 for the quarters
ended January 31, 1996 and 1995, respectively.
The Partnership negotiated a steam sales contract with Basic Vegetable
Products, LP (BVP, LP). The General Partner of BVP, LP is BVP. Under the
contract, the Partnership supplies steam to BVP, LP's food processing plant.
Revenues recorded under the contract totaled $38,333 and $55,788 for the
quarters ended January 31, 1996 and 1995, respectively.
(3) PARTNERS' EQUITY:
The Partnership made distributions of $9,500,000 and $8,500,000 for the
quarters ended January 31, 1996 and 1995, respectively.
F-89
<PAGE> 384
BAF ENERGY,
A CALIFORNIA LIMITED PARTNERSHIP
NOTES TO CONDENSED FINANCIAL STATEMENTS -- (CONTINUED)
JANUARY 31, 1996
(UNAUDITED)
(4) SIGNIFICANT LEASE TRANSACTION:
In April 1996, the Partnership signed an agreement with a third party to
enter into a 23-year lease of the cogeneration property, plant and equipment and
to assign all related contracts. Under the terms of the lease, the lessee will
assume all rights and responsibilities related to the ground lease with BAI (see
Note 2), the BVP, LP steam sales contract (see Note 2) and a Pacific Gas &
Electric (PG&E) Power Purchase Agreement. The ground lease has a remaining term
of 23 years with BAI for the land on which the facility is located. This lease
includes options to extend the lease term up to an additional 30 years. The BVP,
LP steam sales contract has a remaining term of 23 years. The PG&E Power
Purchase Agreement states that PG&E pays capacity payments, as defined in the
agreement, and purchases all available energy, except for amounts sold to BVP,
LP.
F-90
<PAGE> 385
REPORT OF INDEPENDENT AUDITORS
The Shareholder
Gilroy Energy Company
We have audited the accompanying balance sheets of Gilroy Energy Company
(the Company), a wholly owned subsidiary of Gilroy Foods, Inc. which in turn is
a wholly owned subsidiary of McCormick & Company, Inc., as of November 30, 1995
and 1994 and the related statements of income, shareholder's equity, and cash
flows for the years then ended. 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 audit.
We conducted our audit 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 audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Gilroy Energy Company at
November 30, 1995 and 1994 and the results of its operations and its cash flows
for the years then ended in conformity with generally accepted accounting
principles.
ERNST & YOUNG LLP
Baltimore, Maryland
July 18, 1996
F-91
<PAGE> 386
GILROY ENERGY COMPANY
(A WHOLLY OWNED SUBSIDIARY)
BALANCE SHEETS
(DOLLARS IN THOUSANDS)
ASSETS
<TABLE>
<CAPTION>
NOVEMBER 30
---------------------
1995 1994
MAY 31, -------- --------
1996
-----------
(UNAUDITED)
<S> <C> <C> <C>
Current assets:
Accounts receivable..................................... $ 4,428 $ 1,615 $ 1,503
Prepaid expenses........................................ 462 725 776
-------- -------- --------
Total current assets............................ 4,890 2,340 2,279
Property and equipment, at cost:
Buildings............................................... 2,720 2,720 2,720
Machinery and equipment................................. 93,421 93,349 93,098
Furniture and fixtures.................................. 64 64 62
Software................................................ 65 65 58
-------- -------- --------
96,270 96,198 95,938
Less accumulated depreciation and amortization............ 39,202 36,712 31,701
-------- -------- --------
57,068 59,486 64,237
Due from parent and affiliates............................ 64,780 69,422 61,522
-------- -------- --------
Total assets.............................................. $ 126,738 $131,248 $128,038
======== ======== ========
LIABILITIES
Current liabilities:
Bank overdraft.......................................... -- $ 58 $ 618
Accounts payable........................................ $ 1,653 2,678 1,767
Accrued interest........................................ 3,093 3,238 3,363
Other liabilities....................................... 336 993 241
Current portion of long-term debt....................... 2,848 2,468 2,152
-------- -------- --------
Total current liabilities....................... 7,930 9,435 8,141
Long-term debt, due after one year........................ 50,120 52,968 55,436
Other liabilities......................................... 399 49 1,083
-------- -------- --------
50,519 53,017 56,519
Shareholder's equity:
Common stock, no par value:
Authorized shares -- 10,000
Issued and outstanding shares -- 1,000............... 10 10 10
Additional paid-in capital.............................. 16,946 16,946 16,946
Retained earnings....................................... 51,333 51,840 46,422
-------- -------- --------
Total shareholder's equity...................... 68,289 68,796 63,378
-------- -------- --------
Total liabilities and shareholder's equity................ $ 126,738 $131,248 $128,038
======== ======== ========
</TABLE>
See accompanying notes.
F-92
<PAGE> 387
GILROY ENERGY COMPANY
(A WHOLLY OWNED SUBSIDIARY)
STATEMENTS OF INCOME
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
SIX MONTHS ENDED YEARS ENDED
MAY 31, NOVEMBER 30,
---------------- -------------------
1996 1995 1995 1994
------ ------- ------- -------
(UNAUDITED)
<S> <C> <C> <C> <C>
Net revenues:
Electricity revenue................................ $9,306 $11,158 $35,132 $40,037
Steam revenue from Gilroy Foods, Inc............... 185 260 1,089 1,367
------ ------- ------- -------
9,491 11,418 36,221 41,404
Cost of sales........................................ 6,525 8,125 18,825 23,766
------ ------- ------- -------
Gross margin......................................... 2,966 3,293 17,396 17,638
Operating expenses;
Selling, general and administrative................ 720 946 1,888 1,885
------ ------- ------- -------
Operating income..................................... 2,246 2,347 15,508 15,753
Interest expense..................................... 3,093 3,237 6,477 6,731
------ ------- ------- -------
(Loss) Income before income taxes.................... (847) (890) 9,031 9,022
Provision for income tax (benefit) expense........... (340) (356) 3,613 3,622
------ ------- ------- -------
Net (loss) income.................................... $ (507) $ (534) $ 5,418 $ 5,400
====== ======= ======= =======
</TABLE>
See accompanying notes.
F-93
<PAGE> 388
GILROY ENERGY COMPANY
(A WHOLLY OWNED SUBSIDIARY)
STATEMENT OF SHAREHOLDER'S EQUITY
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
COMMON STOCK ADDITIONAL TOTAL
----------------- PAID-IN RETAINED SHAREHOLDER'S
SHARES AMOUNT CAPITAL EARNINGS EQUITY
------ ------ ---------- -------- -------------
<S> <C> <C> <C> <C> <C>
Balance at November 30, 1993............. 1,000 $ 10 $ 16,946 $ 41,022 $57,978
Net income............................... -- -- -- 5,400 5,400
------ ------ ---------- -------- -------------
Balance at November 30, 1994............. 1,000 10 16,946 46,422 63,378
Net income............................... -- -- -- 5,418 5,418
------ ------ ---------- -------- -------------
Balance at November 30, 1995............. 1,000 10 16,946 51,840 68,796
Net (loss) (unaudited)................... -- -- -- (507) (507)
------ ------ ---------- -------- -------------
Balance at May 31, 1996
(unaudited)............................ 1,000 $ 10 $ 16,946 $ 51,333 $68,289
===== ====== ======= ======= ==========
</TABLE>
See accompanying notes.
F-94
<PAGE> 389
GILROY ENERGY COMPANY
(A WHOLLY OWNED SUBSIDIARY)
STATEMENTS OF CASH FLOWS
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
SIX MONTHS ENDED YEARS ENDED
MAY 31, NOVEMBER 30,
------------------- -------------------
1996 1995 1995 1994
------- ------- ------- -------
(UNAUDITED)
<S> <C> <C> <C> <C>
OPERATING ACTIVITIES:
Net income (loss)................................. $ (507) $ (534) $ 5,418 $ 5,400
Adjustments to reconcile net (loss) income to net
cash (used in) provided by operating
activities:
Depreciation and amortization.................. 2,490 2,482 5,011 4,880
Changes in operating assets and liabilities:
Accounts receivable.......................... (2,813) (3,577) (113) 51
Prepaid expenses............................. 263 325 52 49
Accounts payable............................. (1,025) (360) 912 (1,221)
Accrued expenses and other liabilities....... (452) (644) (408) 364
------- ------- ------- -------
Net cash (used in) provided by operating
activities........................................ (2,044) (2,308) 10,872 9,523
------- ------- ------- -------
INVESTING ACTIVITIES:
Due from parent and affiliates...................... 4,642 5,071 (7,900) (4,610)
Purchase of property and equipment.................. (72) (117) (260) (3,376)
------- ------- ------- -------
Net cash provided by (used in) investing
activities........................................ 4,570 4,954 (8,160) (7,986)
------- ------- ------- -------
FINANCING ACTIVITIES:
Principal payments on long-term debt................ (2,468) (2,152) (2,152) (2,152)
------- ------- ------- -------
Net cash (used in) financing activities............. (2,468) (2,152) (2,152) (2,152)
------- ------- ------- -------
Net decrease (increase) in bank overdraft........... 58 494 560 (615)
Bank overdraft at beginning of period............... (58) (618) (618) (3)
------- ------- ------- -------
Bank overdraft at end of period..................... $ -- $ (124) $ (58) $ (618)
======= ======= ======= =======
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Interest paid....................................... $ 3,238 $ 3,359 $ 6,602 $ 6,602
</TABLE>
See accompanying notes.
F-95
<PAGE> 390
GILROY ENERGY COMPANY
(A WHOLLY OWNED SUBSIDIARY)
NOTES TO FINANCIAL STATEMENTS
(DOLLARS IN THOUSANDS)
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization
Gilroy Energy Company (the Company) was incorporated in the State of
California in July 1984. The Company is a wholly owned subsidiary of Gilroy
Foods, Inc. which in turn is a wholly owned subsidiary of McCormick & Company,
Inc. (McCormick). The Company runs a cogeneration facility in Gilroy, California
which uses natural gas and steam turbine engines to generate steam for sale to
Gilroy Foods, Inc. and electricity for sale to Pacific Gas and Electric Company.
Sales to Pacific Gas and Electric Company represented approximately 97% of
total revenues for each of the years ended November 30, 1995 and 1994 and 98%
for the six months ended May 31, 1996 and 1995.
Approximately 80% of the Company's net revenues are recognized during the
months of May through October of each year. As such, the results of operations
for the six month periods ended May 31, 1996 and 1995 are not indicative of the
results of operations that may be realized for the full year.
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and the
disclosure of contingent assets and liabilities at the date of the financial
statements as well as the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Bank Overdrafts
The Company maintains a zero balance bank account. Amounts sufficient to
cover checks presented to the bank are deposited into the account by McCormick &
Company, Inc. The bank overdrafts represent checks that have been written but
have not cleared the bank as of the balance sheet date.
Property and Equipment
Property and equipment are recorded at cost. Depreciation and amortization
are computed using the straight-line method over the estimated useful lives of
the assets, ranging from five to forty years.
In 1995, the Financial Accounting Standards Board released Statement of
Financial Accounting Standards No. 121, "Accounting for Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed of " (FAS 121). FAS 121 requires
recognition of impairment of long-lived assets in the event that the net book
value of such assets exceeds the future undiscounted cash flows attributable to
such assets. The Company will be required to adopt FAS 121 in its 1997 fiscal
year. Management does not believe that the initial adoption of FAS 121 will have
a significant impact on the Company.
Repairs and Maintenance
The cogeneration plant requires a periodic shutdown for major overhauls of
its primary components every several years. The Company's policy is to accrue
the anticipated cost of these overhauls during the operating periods prior to
the scheduled overhaul dates. The amounts and period of accruals for overhaul
costs are revised annually based on management's estimate of time remaining
before the next scheduled overhaul and the estimated cost of the overhaul.
Repairs and maintenance expenditures that are not a part of major overhauls
or do not extend the useful life of the related equipment are charged to expense
when incurred.
F-96
<PAGE> 391
GILROY ENERGY COMPANY
(A WHOLLY OWNED SUBSIDIARY)
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
(DOLLARS IN THOUSANDS)
Due from Parent and Affiliates
The due from parent and affiliates included in the balance sheet represents
a net balance as the result of various transactions between the Company and
Gilroy Foods, Inc. and McCormick & Company, Inc. There are no terms of
settlement, or interest charges associated with the account balance. The balance
is primarily the result of the Company's participation in McCormick's central
cash management program, wherein all the Company's cash receipts are remitted to
McCormick and all cash disbursements are funded by McCormick. Other transactions
include steam sales to Gilroy Foods, Inc., the Company's estimated income tax
payable or receivable resulting from the current and prior years estimated
provisions, and miscellaneous other administrative expenses incurred by Gilroy
Foods, Inc. or McCormick & Company, Inc. on behalf of the Company.
An analysis of transactions in the due from parent and affiliates balance
for the six months ended May 31, 1996 and 1995 (unaudited) and each of the two
years in the period ended November 30, 1995 follows:
<TABLE>
<CAPTION>
SIX MONTHS ENDED YEARS ENDED
MAY 31, NOVEMBER 30,
------------------- -------------------
1996 1995 1995 1994
------- ------- ------- -------
(UNAUDITED)
<S> <C> <C> <C> <C>
Balance in due from parent and affiliates at
beginning of period............................... $69,422 $61,522 $61,522 $56,912
Net cash remitted (from) to Gilroy Foods, Inc. or
McCormick......................................... (4,616) (5,578) 10,671 7,729
Net intercompany sales.............................. 196 275 1,146 1,438
Net intercompany purchases for cost of sales........ (532) (3) (218) (6)
Net intercompany purchases for selling, general and
administrative expenses........................... (30) (121) (87) (929)
Benefit (provision) for income taxes................ 340 356 (3,612) (3,622)
------- ------- ------- -------
Balance in due from parent and affiliated at end of
period............................................ $64,780 $56,451 $69,422 $61,522
======= ======= ======= =======
Average balance during the period................... $66,384 $58,373 $61,811 $56,828
======= ======= ======= =======
</TABLE>
Gilroy Foods, Inc. provides certain administrative services to the Company
including the services of the President of Gilroy Energy Company, Inc.,
accounting, and other administrative services. It is the policy of Gilroy Foods,
Inc. to charge these expenses and all other central operating costs on the basis
of direct usage. In the opinion of management, no other costs of Gilroy Foods,
Inc. should be allocated to the Company.
McCormick provides various administrative services to the Company including
legal assistance and treasury services. McCormick does not charge the Company
for these services. In the opinion of management, the cost of the services
rendered by McCormick in these areas during each of the two years ended November
30, 1995 and 1994 and the six months ended May 31, 1996 and 1995 are nominal.
Concentration of Credit Risk
The Company sells electricity to Pacific Gas and Electric Company under a
long-term contract. All accounts receivable at May 31, 1996 (unaudited) and
November 30, 1995 and 1994 are due from this customer. No collateral is required
for accounts receivable. Management believes that no reserves are required for
potential credit losses at May 31, 1996 and November 30, 1995 and 1994.
F-97
<PAGE> 392
GILROY ENERGY COMPANY
(A WHOLLY OWNED SUBSIDIARY)
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
(DOLLARS IN THOUSANDS)
Sources of Supply
The Company purchases natural gas for the operation of the cogeneration
facility under a supply contract with one supplier. The supply contract requires
the Company to purchase substantially all of its natural gas needs from the
supplier at a price based on the market value determined in accordance with the
contract through July 31, 1997. Management believes that in the event that this
supplier is not able to meet its obligations under the contract, alternative
sources of supply for natural gas are readily available at comparable prices.
2. LONG-TERM DEBT
The Company's outstanding indebtedness is as follows:
<TABLE>
<CAPTION>
NOVEMBER 30,
-------------------
1995 1994
MAY 31, ------- -------
1996
-----------
(UNAUDITED)
<S> <C> <C> <C>
Note payable in annual installments through $52,968 $55,436 $57,588
2006 with interest at 11.68% per annum....
Less current portion........................ 2,848 2,468 2,152
------- ------- -------
$50,120 $52,968 $55,436
======= ======= =======
</TABLE>
The note payable requires the maintenance of a $5,000 maintenance fund and
a $10,000 debt service fund. The note holder has agreed to accept a guarantee of
up to $15,000 by McCormick & Company, Inc. in lieu of establishing these funds.
The terms of the note payable require the Company to comply with certain
nonfinancial covenants. Management believes that the Company was in compliance
with all applicable covenants at November 30, 1995 and 1994. The note payable is
secured by the cogeneration facility.
The note payable agreement provides for the payment of a prepayment penalty
in the event of early retirement. The amount of the prepayment penalty
approximates the present value of the differential between current market
interest rates and the stated rate over the remaining life of the debt as
defined by the agreement.
Aggregate maturities of long-term debt over the next five fiscal years
ending November 30 and thereafter are as follows:
<TABLE>
<S> <C>
1996....................................................... $ 2,468
1997....................................................... 2,848
1998....................................................... 3,101
1999....................................................... 3,481
2000....................................................... 3,797
Thereafter................................................. 39,741
-------
$55,436
=======
</TABLE>
3. INCOME TAXES
The Company is included in the consolidated federal and state income tax
returns of McCormick. McCormick does not have a formal tax sharing arrangement
with its subsidiaries. The income tax provisions included in the statements of
income has been provided under the liability method assuming that Gilroy Energy
Company had prepared separate income tax returns for the years ended November
30, 1995 and 1994 and the six months ended May 31, 1996 and 1995 (unaudited).
Any income taxes receivable or payable as a
F-98
<PAGE> 393
GILROY ENERGY COMPANY
(A WHOLLY OWNED SUBSIDIARY)
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
(DOLLARS IN THOUSANDS)
result of the income tax provisions, including any deferred amounts due or
payable resulting from the current or prior years provisions are included in due
from parent and affiliates.
The (benefit) provision for income taxes is summarized as follows:
<TABLE>
<CAPTION>
SIX MONTHS
ENDED YEARS ENDED
MAY 31, NOVEMBER 30,
--------------- -------------------
1996 1995 1995 1994
----- ----- ------- -------
(UNAUDITED)
<S> <C> <C> <C> <C>
Current:
Federal.............................. $(288) $(303) $ 3,877 $ 4,061
State................................ (52) (53) 1,169 1,225
----- ----- ------- -------
(340) (356) 5,046 5,286
----- ----- ------- -------
Deferred:
Federal.............................. -- -- (1,095) (1,278)
State................................ -- -- (338) (386)
----- ----- ------- -------
-- -- (1,433) (1,664)
----- ----- ------- -------
$(340) $(356) $ 3,613 $ 3,622
===== ===== ======= =======
</TABLE>
The reconciliation between income tax computed at the United States federal
statutory rate and income taxes actually provided follows:
<TABLE>
<CAPTION>
SIX MONTHS ENDED MAY 31, YEARS ENDED NOVEMBER 30,
------------------------------- -------------------------------
1996 1995 1995 1994
------------- ------------- ------------- -------------
AMOUNT % AMOUNT % AMOUNT % AMOUNT %
------ ---- ------ ---- ------ ---- ------ ----
(UNAUDITED)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Tax at federal rate....... $ (288) 34.0% $ (303) 34.0% $3,071 34.0% 3,067 34.0%
State income taxes, net of
federal benefit......... (52) 6.1% (53) 6.0% 542 6.0% 555 6.1%
------ ------ ------
Actual income taxes
(benefit) provided...... $ (340) 40.1% $ (356) 40.0% $3,613 40.0% $3,622 40.1%
====== ====== ======
</TABLE>
The temporary differences that give rise to significant portions of the
deferred tax assets and liabilities that have been netted in due from parent and
affiliates consist of the following:
<TABLE>
<CAPTION>
NOVEMBER 30,
-------------------
1995 1994
------- -------
<S> <C> <C>
Temporary differences resulting in deferred tax assets:
Repairs and maintenance expenditures................... $ 986 $ 1,082
------- -------
Temporary differences resulting in deferred tax
liabilities:
Depreciation........................................... 50,897 54,587
Prepaid expenses....................................... 810 758
Other.................................................. 357 357
------- -------
52,064 55,702
------- -------
$51,078 $54,620
======= =======
</TABLE>
No valuation allowance is provided for deferred tax assets.
F-99
<PAGE> 394
GILROY ENERGY COMPANY
(A WHOLLY OWNED SUBSIDIARY)
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
(DOLLARS IN THOUSANDS)
4. RELATED PARTY TRANSACTIONS
The Company sells substantially all of the steam, which is a byproduct of
the cogeneration process to Gilroy Foods, Inc. During the years ended November
30, 1995 and 1994, the amount of revenue recognized by the Company from steam
sales to Gilroy Foods, Inc. was $1,089 and $1,367, respectively. During the six
months ended May 31, 1996 and 1995, the amount of revenue recognized by the
Company from steam sales to Gilroy Foods, Inc. was $185 and $261, respectively.
Gilroy Foods, Inc. provides certain accounting and administrative services
to Gilroy Energy Company, Inc. A portion of the cost of these services is billed
directly to Gilroy Energy Company, Inc.
The Company leases the land where the cogeneration facility is located
under an operating lease with Gilroy Foods, Inc. The lease agreement runs
through 2018 and provides for minimum annual rental payments with provisions for
the escalation of costs every three years based on the average increase in the
Consumer Price Index. The future minimum lease payments under this lease,
excluding any future increases, are as follows:
<TABLE>
<S> <C>
1996.................................................................................. $ 40
1997.................................................................................. 40
1998.................................................................................. 40
1999.................................................................................. 40
2000.................................................................................. 40
2001 through 2018..................................................................... 715
----
$915
====
</TABLE>
Rent expense recognized under this lease was $38 and $37 in the years ended
November 30, 1995 and 1994, respectively, and $20 and $19 in the six months
ended May 31, 1996 and 1995, respectively.
5. COMMITMENTS AND CONTINGENCIES
The Company has an agreement with the Pacific Gas and Electric Company
(PG&E) to sell all electricity generated by the cogeneration facility to PG&E.
The agreement establishes the methodology used to calculate the purchase price
of the electricity, establishes the operating hours of the cogeneration
facility, and provides for the payment to the Company of additional capacity
payments if certain operating targets as defined are achieved. The current
provisions of this agreement extend through December 31, 1998. Subsequent to
December 31, 1998 and continuing through the expiration of the base agreement on
December 31, 2017, the pricing and operating provisions of the agreement will be
established by negotiation between PG&E and Gilroy Energy Company.
The Company has an agreement with Gilroy Foods, Inc. whereby Gilroy Foods,
Inc. has agreed to purchase substantially all of the steam produced by the
Company. The terms of the agreement, which extends through 2017, provide for the
establishment of the purchase price for steam based on the current cost of
alternative sources of energy available to Gilroy Foods, Inc.
The Company has an operating and maintenance agreement with an outside
party for the daily operation and maintenance of the cogeneration facility. This
agreement, which extends through November 1996, provides for all operating and
routine maintenance of the cogeneration facility at direct costs plus a minimum
annual fee of $100,000. The contract also provides for the payment of bonuses,
as defined, if certain operating targets are met.
F-100
<PAGE> 395
GILROY ENERGY COMPANY
(A WHOLLY OWNED SUBSIDIARY)
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
(DOLLARS IN THOUSANDS)
6. FAIR VALUE
The following methods and assumptions were used by the Company in
estimating fair value disclosures for financial instruments:
Accounts receivable, due from parent and affiliates, bank overdrafts,
current portion of long-term debt, accounts payable, and accrued
liabilities -- The amounts reported in the balance sheet approximate fair value.
Long-term debt. The fair value of long-term debt, based on a discounted
cash flow analysis using current interest rates for debt with similar
characteristics and maturities is as follows:
<TABLE>
<CAPTION>
NOVEMBER 30
---------------------------------------------
1995 1994
FAIR CARRYING FAIR CARRYING
VALUE VALUE VALUE VALUE
------- -------- ------- --------
<S> <C> <C> <C> <C>
Long-term debt............................ $68,100 $ 52,968 $63,000 $ 55,436
</TABLE>
7. SUBSEQUENT EVENT
In May 1996, McCormick & Company, Inc. announced its intention to sell the
assets and liabilities, excluding the due from parent and affiliates, the
current portion of long-term debt and the long-term debt of the Company to
Calpine Corporation. At the time of the closing of the sale, McCormick &
Company, Inc. will assume the due from parent and affiliates and will be
required to retire the current portion of the long-term debt and the long-term
debt. In addition to all remaining assets and liabilities of Gilroy Energy
Company, Calpine Corporation will assume all rights and obligations under the
following agreements to which Gilroy Energy Company is currently a party:
- Long-term contract to sell electricity to Pacific Gas and Electric
Company.
- Natural gas supply contract through July 31, 1997.
- Lease for the land with Gilroy Foods, Inc. upon which the cogeneration
facility is located.
- Steam sale contract with Gilroy Foods, Inc.
Upon closing of the sale, the management contract with the current operator
of the cogeneration facility will be terminated by McCormick & Company, Inc.
It is currently anticipated that the closing date for the sale of the
applicable assets and liabilities of Gilroy Energy Company to Calpine
Corporation will take place in the third quarter of 1996.
F-101
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<PAGE> 399
APPENDIX -- CALPINE GRAPHIC IMAGES
GRAPHIC (Domestic Inside Front Cover)
Upper Photo--Sumas 125 mw Gas-fired Facility
Lower Photo--King City 120 mw Gas-fired Facility
Calpine Logo
GRAPHIC (International Inside Front Cover-Alternate Page A-2)
Photo--Sumas 125 mw Gas-fired Facility
Calpine Logo
GRAPHIC (Inside Back Cover)
Upper Photo--Cerro Prieto 80 mw Geothermal Steam Field
The Power of Innovation
Lower Photo--West Ford Flat 27 mw Geothermal Facility
Calpine Logo
GRAPHIC (page 43)
CALPINE CORPORATION
1 - Calpine Corporation Headquarters
San Jose, California
2 - Calpine Corporation Geothermal Office
Santa Rosa, California
3 - Aidlin 20 mw Geothermal Facility
4 - Agnews 29 mw Cogeneration Facility
5 - Bear Canyon 20 mw Geothermal Facility
6 - Black Hills 80 mw Coal Project
7 - Cerro Prieto 80 mw Steam Fields
8 - Coso 150 mw Geothermal Project
9 - Gilroy 120 mw Cogeneration Facility
10 - Glass Mountain 145 mw Geothermal Project
11 - Greenleaf 1 49.5 mw Cogeneration Facility
12 - Greenleaf 2 49.5 mw Cogeneration Facility
13 - King City 120 mw Cogeneration Facility
14 - Navajo South 1,700 mw Coal Project
15 - Pasadena 240 mw Cogeneration Facility
16 - PG&E Unit 13 Steam Fields
17 - PG&E Unit 16 Steam Fields
18 - SMUDGEO #1 Steam Fields
19 - Sumas 125 mw Cogeneration Facility
20 - Thermal Power Company Steam Fields
21 - Watsonville 28.5 mw Cogeneration Facility
22 - West Ford Flat 27 mw Geothermal Facility
Map of western and southwestern United States indicating:
Corporate Headquarters
Corporate Geothermal Office
Operating Facility
Steam Fields
Future Projects
Graphic (page 40)
Illustration of a Combined Cycle Power Plant
Graphic (page 41)
Illustration of a Geothermal Power Plant
<PAGE> 400
<TABLE>
<C> <S>
- --------------------------------------------- ---------------------------------------------
- --------------------------------------------- ---------------------------------------------
</TABLE>
