CALPINE CORP, 424B4, 1996-10-04

CALPINE CORP
424B4, 1996-10-04
COGENERATION SERVICES & SMALL POWER PRODUCERS

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<PAGE> 1

Filed Pursuant to Rule 424(b)(4)
Registration No. 333-6259

OFFER TO EXCHANGE
all outstanding
10 1/2% SENIOR NOTES DUE 2006
($180,000,000 principal amount outstanding)

for
10 1/2% SENIOR NOTES DUE 2006
of
LOGO
CALPINE CORPORATION
------------------------
THE EXCHANGE OFFER WILL EXPIRE AT 5:00 P.M., NEW YORK CITY TIME, ON
NOVEMBER 5, 1996, UNLESS EXTENDED.

------------------------
CALPINE CORPORATION, A CALIFORNIA CORPORATION ("CALPINE" OR THE "COMPANY"),
HEREBY OFFERS, UPON THE TERMS AND SUBJECT TO THE CONDITIONS SET FORTH IN THIS
PROSPECTUS AND THE ACCOMPANYING LETTER OF TRANSMITTAL (THE "LETTER OF
TRANSMITTAL"), TO EXCHANGE ITS 10 1/2% SENIOR NOTES DUE 2006 (THE "NEW
NOTES"), IN AN OFFERING WHICH HAS BEEN REGISTERED UNDER THE SECURITIES
ACT OF 1933, AS AMENDED (THE "SECURITIES ACT"), PURSUANT TO A
REGISTRATION STATEMENT OF WHICH THIS PROSPECTUS CONSTITUTES A PART,
FOR AN EQUAL PRINCIPAL AMOUNT OF ITS OUTSTANDING 10 1/2% SENIOR
NOTES DUE 2006 (THE "OLD NOTES"), OF WHICH AN AGGREGATE OF
$180,000,000 IN PRINCIPAL AMOUNT IS OUTSTANDING AS OF THE DATE
HEREOF (THE "EXCHANGE OFFER"). THE NEW NOTES AND THE OLD NOTES
ARE SOMETIMES REFERRED TO HEREIN COLLECTIVELY AS THE "SENIOR
NOTES." THE FORM AND TERMS OF THE NEW NOTES WILL BE THE SAME
AS THE FORM AND TERMS OF THE OLD NOTES EXCEPT THAT THE NEW
NOTES WILL NOT BEAR LEGENDS RESTRICTING THE TRANSFER
THEREOF. THE NEW NOTES WILL BE OBLIGATIONS OF THE COMPANY
ENTITLED TO THE BENEFITS OF THE INDENTURE, DATED AS OF
MAY 16, 1996 (THE "INDENTURE"), RELATING TO THE
SENIOR NOTES. SEE "DESCRIPTION OF THE NEW NOTES."
FOLLOWING THE COMPLETION OF THE EXCHANGE OFFER,
NONE OF THE SENIOR NOTES WILL BE ENTITLED TO ANY
RIGHTS UNDER THE REGISTRATION RIGHTS AGREEMENT
DATED AS OF MAY 16, 1996 (THE "REGISTRATION
RIGHTS AGREEMENT"), INCLUDING, BUT NOT
LIMITED TO, THE CONTINGENT INCREASE IN THE
INTEREST RATE PROVIDED FOR PURSUANT
THERETO. SEE "THE EXCHANGE OFFER."

------------------------

INVESTMENT IN THE SENIOR NOTES INVOLVES SIGNIFICANT RISKS DISCUSSED UNDER "RISK
FACTORS" ON PAGE 15 WHICH SHOULD BE CONSIDERED BY PROSPECTIVE INVESTORS.

------------------------
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 ADEQUACY OF THIS PROSPECTUS. ANY
REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.

------------------------

The date of this Prospectus is October 3, 1996.
<PAGE> 2

The Company will accept for exchange any and all Old Notes that are validly
tendered on or prior to 5:00 p.m., New York City time, on the date the Exchange
Offer expires, which will be November 5, 1996 unless the Exchange Offer is
extended (the "Expiration Date"). Tenders of Old Notes may be withdrawn at any
time prior to 5:00 p.m., New York City time, on the Expiration Date. The
Exchange Offer is not conditioned upon any minimum principal amount of Old Notes
being tendered for exchange. The Company has not entered into any arrangement or
understanding with any person to distribute the New Notes to be received in the
Exchange Offer.

The Old Notes initially sold to Qualified Institutional Buyers (as defined
in Rule 144A) in reliance on Rule 144A under the Securities Act ("Rule 144A")
were initially represented by a single, permanent global Note in definitive,
fully registered form, registered in the name of a nominee of The Depositary
Trust Company ("DTC"), which was deposited with Fleet National Bank, the Trustee
under the Indenture (the "Trustee"), as custodian. The Old Notes initially sold
in offshore transactions in reliance on Regulation S under the Securities Act
("Regulation S") were initially represented by a single, temporary global Old
Note, in definitive, fully registered form, registered in the name of a nominee
of DTC for the accounts of Morgan Guaranty Trust Company of New York, Brussels
Office, as operator of the Euroclear System ("Euroclear") and Centrale de
Livraison de Valeurs Mobilieres S.A. ("Cedel"), which was deposited with the
Trustee as custodian. Such temporary global Old Note was exchanged for a single,
permanent global Old Note, which is held by the Trustee, as custodian. The New
Notes exchanged for the Old Notes that are represented by the global Old Notes
will continue to be represented by permanent global Old Notes (collectively, the
"Global Notes," and individually, a "Global Note") in definitive, fully
registered form, registered in the name of a nominee of DTC and deposited with
the Trustee as custodian, unless the beneficial holders thereof request
otherwise. See "Description of the New Notes -- Book Entry; Delivery and Form."
Old Notes may be tendered only in denominations of $1,000 and any integral
multiple thereof.

Interest on the New Notes will be payable semi-annually in arrears on May
15 and November 15 of each year (each an "Interest Payment Date"), commencing on
the first such date following their date of issuance. Interest on the New Notes
will accrue from the last Interest Payment Date on which interest was paid on
the Old Notes that are accepted for exchange or, if no interest has been paid,
from May 16, 1996. Accordingly, interest which has accrued since the last
Interest Payment Date or May 16, 1996 on the Old Notes accepted for exchange
will cease to be payable upon issuance of the New Notes. Untendered Old Notes
that are not exchanged for New Notes pursuant to the Exchange Offer will remain
outstanding and bear interest at a rate of 10 1/2% per annum after the
Expiration Date.

Based on no-action letters issued by the staff of the Securities and
Exchange Commission (the "Commission") to third parties, the Company believes
the New Notes issued pursuant to the Exchange Offer may be offered for resale,
resold and otherwise transferred by a holder thereof (other than (i) a
broker-dealer who acquires such New Notes directly from the Company to resell
pursuant to Rule 144A or any other available exemption under the Securities Act
or (ii) a person that is an affiliate of the Company (within the meaning of Rule
405 under the Securities Act)) without compliance with the registration and
prospectus delivery provisions of the Securities Act, provided that the holder
is acquiring the New Notes in the ordinary course of such holder's business and
is not participating, and has no arrangement or understanding with any person to
participate, in the distribution of the New Notes. Holders of Old Notes wishing
to accept the Exchange Offer must represent to the Company that such conditions
have been met. Each broker-dealer that receives New Notes for its own account
pursuant to the Exchange Offer must acknowledge that it will deliver a
prospectus in connection with any resale of such New Notes. The Letter of
Transmittal states that by so acknowledging and by delivering a prospectus, a
broker-dealer will not be deemed to admit that it is an "underwriter" within the
meaning of the Securities Act. This Prospectus, as it may be amended or
supplemented from time to time, may be used by a broker-dealer in connection
with resales of New Notes received in exchange for Old Notes where such Old
Notes were acquired by such broker-dealer as a result of market-making
activities or other trading activities. The Company has agreed that it will make
this Prospectus available to any broker-dealer for use in connection with any
such resale for a period of 180 days from the date of this Prospectus, or such
shorter period as will terminate when all Old Notes acquired by broker-dealers
for their own accounts as a result of market-making activities or other trading
activities have been exchanged for New Notes and resold by such broker-dealers.
See "Plan of Distribution."

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<PAGE> 3

Prior to the Exchange Offer, there has been no public market for the Senior
Notes. The Company does not intend to list the New Notes on any securities
exchange or to seek approval for quotation through any automated quotation
system. There can be no assurance that an active market for the New Notes will
develop. To the extent that a market for the New Notes develops, the market
value of the New Notes will depend on market conditions (such as yields on
alternative investments) general economic conditions, the Company's financial
condition and other conditions. Such conditions might cause the New Notes, to
the extent that they are actively traded, to trade at a significant discount
from the face value. See "Risk Factors -- Absence of Public Market."

The Company will not receive any proceeds from the Exchange Offer. The
Company has agreed to bear the expenses of the Exchange Offer. No underwriter is
being used in connection with the Exchange Offer.

THE EXCHANGE OFFER IS NOT BEING MADE TO, NOR WILL THE COMPANY ACCEPT
SURRENDERS FOR EXCHANGE FROM, HOLDERS OF OLD NOTES IN ANY JURISDICTION IN WHICH
THE EXCHANGE OFFER OR THE ACCEPTANCE THEREOF WOULD NOT BE IN COMPLIANCE WITH THE
SECURITIES OR BLUE SKY LAWS OF SUCH JURISDICTION.
------------------------

AVAILABLE INFORMATION

The Company has filed with the Commission a Registration Statement on Form
S-4 under the Securities Act with respect to the New Notes 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 New
Notes 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.

3
<PAGE> 4

NO PERSON HAS BEEN AUTHORIZED TO GIVE ANY INFORMATION OR MAKE ANY
REPRESENTATIONS OTHER THAN THOSE CONTAINED IN THIS PROSPECTUS AND THE
ACCOMPANYING LETTER OF TRANSMITTAL, AND, IF GIVEN OR MADE, SUCH INFORMATION OR
REPRESENTATIONS MUST NOT BE RELIED UPON AS HAVING BEEN AUTHORIZED BY THE
COMPANY. NEITHER THIS PROSPECTUS, NOR THE ACCOMPANYING LETTER OF TRANSMITTAL, OR
BOTH TOGETHER, NOR ANY SALE MADE HEREUNDER SHALL UNDER ANY CIRCUMSTANCES CREATE
AN IMPLICATION THAT THERE HAS BEEN NO CHANGE IN THE AFFAIRS OF THE COMPANY SINCE
THE DATE HEREOF. NEITHER THIS PROSPECTUS NOR THE ACCOMPANYING LETTER OF
TRANSMITTAL, OR BOTH TOGETHER, CONSTITUTE AN OFFER TO SELL OR A SOLICITATION OF
AN OFFER TO BUY ANY OF THE SECURITIES OFFERED HEREBY BY ANYONE IN ANY
JURISDICTION IN WHICH SUCH OFFER OR SOLICITATION IS NOT AUTHORIZED OR IN WHICH
THE PERSON MAKING SUCH OFFER OR SOLICITATION IS NOT QUALIFIED TO DO SO OR TO ANY
PERSON TO WHOM IT IS UNLAWFUL TO MAKE SUCH OFFER OR SOLICITATION.

------------------------

TABLE OF CONTENTS

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Summary............................................................................... 5
Risk Factors.......................................................................... 15
Recent Developments................................................................... 24
Use of Proceeds....................................................................... 24
Dividend Policy....................................................................... 24
The Exchange Offer.................................................................... 25
Capitalization........................................................................ 32
Selected Consolidated Financial Data.................................................. 33
Pro Forma Consolidated Financial Data................................................. 35
Management's Discussion and Analysis of Financial Condition and Results of
Operations.......................................................................... 42
Business.............................................................................. 51
Management............................................................................ 83
Certain Transactions.................................................................. 94
Principal Stockholders................................................................ 96
Description of New Notes.............................................................. 97
Description of Certain Other Indebtedness............................................. 125
Transfer Restrictions................................................................. 126
Certain Federal Income Tax Considerations............................................. 127
Plan of Distribution.................................................................. 130
Legal Matters......................................................................... 130
Experts............................................................................... 130
Consolidated Financial Statements..................................................... F-1
</TABLE>

4
<PAGE> 5

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, and (ii) all information in this Prospectus reflects the following
transactions, which were completed on September 13, 1996 in connection with the
Common Stock Offering (as defined herein): (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 authorized 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 $993.2 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 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.

5
<PAGE> 6

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 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 in the future.

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.

6
<PAGE> 7

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
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
(as defined herein), the Company was an indirect wholly owned subsidiary of
Electrowatt Ltd. ("Electrowatt"), a major utility, industrial products and
engineering services company based in Zurich, Switzerland.

The Company 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.

RECENT DEVELOPMENTS

On August 29, 1996, Calpine acquired the Gilroy cogeneration facility (the
"Gilroy Facility"), a 120 megawatt gas-fired cogeneration power plant located in
Gilroy, California, 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 -- Power
Generation Facilities -- Gilroy Facility."

On September 25, 1996, Calpine completed the initial public offering of
18,045,000 shares of its Common Stock (the "Common Stock Offering"). In the
Common Stock Offering, the Company issued and sold 5,477,820 shares of Common
Stock and Electrowatt sold 12,567,180 shares of Common Stock, representing its
entire ownership interest in Calpine. As a result of the Common Stock Offering,
Electrowatt no longer owns any interest in Calpine. The Company received
approximately $82.3 million of net proceeds from the Common Stock Offering.
Approximately $13.0 million of such net proceeds were used to repay outstanding
indebtedness. 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. In connection with the Common Stock Offering,
the Company reincorporated in the State of Delaware, converted the outstanding
Class B Common Stock into Common Stock and eliminated the authorized Class A
Common Stock and Class B Common Stock, completed a 5.194-for-1 stock split of
the Company's Common Stock and converted the Company's outstanding Preferred
Stock into shares of Common Stock (collectively, the "Reincorporation").

RISK FACTORS

See "Risk Factors" for a discussion of certain risks that should be
considered in conjunction with an investment in the Senior Notes.

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<PAGE> 8

SUMMARY OF THE TERMS OF THE EXCHANGE OFFER

The Exchange Offer......... The Company is offering to exchange $1,000 in
principal amount (and any integral multiple
thereof) of New Notes for each $1,000 in principal
amount (and any integral multiple thereof) of Old
Notes that are validly tendered pursuant to the
Exchange Offer. The Company will issue the New
Notes promptly after the Expiration Date. As of the
date of this Prospectus, $180,000,000 in aggregate
principal amount of Old Notes are outstanding. The
Company has not entered into any arrangement or
understanding with any person to distribute the New
Notes to be received in the Exchange Offer.

Resale..................... The Company believes that the New Notes issued
pursuant to the Exchange Offer generally will be
freely transferable by the holders thereof without
registration or any prospectus delivery requirement
under the Securities Act, except that a "dealer" or
any of the Company's "affiliates," as such terms
are defined under the Securities Act, that
exchanges Old Notes held for its own account may be
required to deliver copies of this Prospectus in
connection with any resale of the New Notes issued
in exchange for such Old Notes. See "The Exchange
Offer -- General" and "Plan of Distribution."

Expiration Date............ The Exchange Offer will expire at 5:00 p.m., New
York City time, on November 5, 1996, unless
extended, in which case the term Expiration Date
means the latest date and time to which the
Exchange Offer is extended. The Company will accept
for exchange any and all Old Notes that are validly
tendered in the Exchange Offer prior to 5:00 p.m.,
New York City time, on the Expiration Date.

Accrued Interest on the New
Notes and the Old
Notes.................... Each New Note will bear interest from the last
Interest Payment Date on which interest was paid on
the Old Notes, or, if interest has not yet been
paid on the Old Notes, from May 16, 1996, the date
of issuance. Such interest will be paid with the
first interest payment on the New Notes.
Accordingly, interest, which has accrued since the
last Interest Payment Date or May 16, 1996, on the
Old Notes accepted for exchange will cease to be
payable upon issuance of the New Notes. Untendered
Old Notes that are not exchanged for New Notes
pursuant to the Exchange Offer will bear interest
at a rate of 10 1/2% per annum after the Expiration
Date.

Termination................ The Company may terminate the Exchange Offer if it
determines that its ability to proceed with the
Exchange Offer could be materially impaired due to
any legal or governmental action, any new law,
statute, rule or regulation or any interpretation
by the staff of the Commission of any existing law,
statute, rule or regulation. Holders of Old Notes
will have certain rights against the Company under
the Registration Rights Agreement should the
Company fail to consummate the Exchange Offer. See
"The Exchange Offer -- Termination." No federal or
state regulatory requirements must be complied with
or approvals obtained in connection with the
Exchange Offer, other than applicable requirements
under federal and state securities laws.

Procedures for Tendering
Old Notes.................. Each holder of Old Notes wishing to accept the
Exchange Offer must complete, sign and date the
Letter of Transmittal, or a facsimile thereof,

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<PAGE> 9

in accordance with the instructions contained
herein and therein, and mail or otherwise deliver
such Letter of Transmittal, or such facsimile,
together with such Old Notes and any other required
documentation to Fleet National Bank, as Exchange
Agent (the "Exchange Agent"), at the address set
forth herein and therein, or effect a tender of Old
Notes pursuant to the procedure for book-entry
transfer as provided for herein. By executing the
Letter of Transmittal, each holder will represent
to the Company that, among other things, the New
Notes acquired pursuant to the Exchange Offer are
being obtained in the ordinary course of business
of the person receiving such New Notes, whether or
not such person is the holder, that neither the
holder nor any such other person has an arrangement
or understanding with any person to participate in
the distribution of such New Notes and, except as
otherwise disclosed in writing to the Company, that
neither the holder nor any such other person is an
"affiliate," as defined in Rule 405 under the
Securities Act, of the Company.

Special Procedures for
Beneficial Owners.......... Any beneficial owner whose Old Notes are registered
in the name of a broker, dealer, commercial bank,
trust company or other nominee and who wishes to
tender such Old Notes in the Exchange Offer should
contact such registered holder promptly and
instruct such registered holder to tender on such
beneficial owner's behalf. If such beneficial owner
wishes to tender on such owner's own behalf, such
owner must, prior to completing and executing the
Letter of Transmittal and delivering such owner's
Old Notes, either make appropriate arrangements to
register ownership of the Old Notes in such owner's
name or obtain a properly completed bond power from
the registered holder. The transfer of record
ownership may take considerable time and may not be
able to be completed prior to the Expiration Date.

Guaranteed Delivery
Procedures............... Holders of Old Notes who wish to tender their Old
Notes and whose Old Notes are not immediately
available or who cannot deliver their Old Notes,
the Letter of Transmittal or any other documents
required by the Letter of Transmittal to the
Exchange Agent prior to the Expiration Date must
tender their Old Notes according to the guaranteed
delivery procedures set forth in "The Exchange
Offer -- Guaranteed Delivery Procedures."

Withdrawal Rights.......... Tenders of Old Notes may be withdrawn at any time
prior to 5:00 p.m., New York City time, on the
Expiration Date.

Acceptance of Old Notes and
Delivery of New Notes.... Subject to certain conditions (as summarized above
in "Termination" and described more fully in "The
Exchange Offer -- Termination"), the Company will
accept for exchange any and all Old Notes that are
validly tendered in the Exchange Offer prior to
5:00 p.m., New York City time, on the Expiration
Date. The New Notes issued pursuant to the Exchange
Offer will be delivered promptly following the
Expiration Date. See "The Exchange
Offer -- General."

Certain Federal Income Tax
Considerations........... The exchange pursuant to the Exchange Offer will
generally not be a taxable event for federal income
tax purposes. For a discussion of certain

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<PAGE> 10

federal income tax considerations relating to the
exchange of the Old Notes for the New Notes, see
"Certain Federal Income Tax Considerations."

Exchange Agent............. The Trustee is also the Exchange Agent. The mailing
address of the Exchange Agent and address for
deliveries by overnight courier is: Fleet National
Bank, Corporate Trust Operations, 777 Main Street,
Lower Level, CTMO 0224, Hartford, Connecticut
06115, Attention: Patricia Williams. Hand
deliveries should be made to Fleet National Bank,
Corporate Trust Operations, 777 Main Street, Lower
Level, Hartford, Connecticut 06115, Attention:
Patricia Williams. For information with respect to
the Exchange Offer, the telephone number for the
Exchange Agent is (860) 986-2910 and the facsimile
number for the Exchange Agent is (860) 986-7908.

Use of Proceeds............ There will be no cash proceeds payable to the
Company from the issuance of the New Notes pursuant
to the Exchange Offer. Of the approximately $174.6
million of net proceeds received by the Company
from the sale of the Old Notes, approximately
$155.7 million was used to repay outstanding
indebtedness of the Company and one of its
subsidiaries and approximately $18.9 million was
used for general corporate purposes. See "Use of
Proceeds."

10
<PAGE> 11

SUMMARY OF THE TERMS OF THE NEW NOTES

The Exchange Offer applies to an aggregate principal amount of $180,000,000
of the Old Notes. The form and terms of the New Notes will be the same as the
form and terms of the Old Notes except that the New Notes will not bear legends
restricting the transfer thereof. The New Notes will be obligations of the
Company entitled to the benefits of the Indenture. See "Description of the New
Notes."

<TABLE>
<S> <C>
Notes Offered........................ $180,000,000 aggregate principal amount of 10 1/2%
Senior Notes Due 2006 (the "New Notes").
Maturity............................. May 15, 2006.
Interest............................. Payable semi-annually at the rate of 10 1/2% per
annum, in cash, on May 15 and November 15, commencing
on the first Interest Payment Date following the
consummation of the Exchange Offer.
Optional Redemption by the Company... The New Notes will be redeemable at the option of the
Company on or after May 15, 2001 at the redemption
prices set forth herein, plus accrued interest. In
addition, up to $63.0 million aggregate principal
amount of New Notes will be redeemable from the
proceeds of one or more Public Equity Offerings (as
defined herein) following which there is a Public
Market (as defined herein), in each case at the option
of the Company, in whole or in part, at the redemption
prices set forth herein, plus accrued interest. See
"Description of New Notes -- Optional Redemption."
Ranking.............................. The New Notes will be senior unsecured obligations of
the Company and will rank pari passu in right of
payment with all other existing and future Senior
Indebtedness (as defined herein) of the Company and
senior in right of payment to all Subordinated
Indebtedness (as defined herein) of the Company, if
any, issued in the future. The New Notes will be
effectively subordinated to all liabilities of the
Company's subsidiaries, including trade payables. See
"Risk Factors -- High Leverage," "Risk
Factors -- Risks Related to Holding Company Structure"
and "Description of New Notes -- Ranking."
Negative Covenants................... The Indenture (as defined herein) will limit, among
other things, (i) the incurrence of additional debt by
the Company and its subsidiaries, (ii) the payment of
dividends on and redemptions of capital stock by the
Company and its subsidiaries, (iii) the use of
proceeds from the sale of assets and subsidiary stock,
(iv) transactions with affiliates, (v) the creation of
liens and (vi) sale leaseback transactions. The
Indenture will also restrict the Company's ability to
consolidate or merge with or into, or to transfer all
or substantially all of its assets to, another person.
However, these limitations are subject to a number of
important qualifications and exceptions. See
"Description of New Notes -- Covenants."
Change of Control.................... Upon a Change of Control Triggering Event (as defined
herein), the Company will be required to make an offer
to purchase the New Notes then outstanding at a
purchase price equal to 101% of the principal amount
thereof, plus accrued interest. See "Risk
Factors -- High Leverage," "Risk Factors -- Control by
Electrowatt" and "Description of New
Notes -- Covenants -- Change of Control."
</TABLE>

11
<PAGE> 12
<TABLE>
<S> <C>
Registration Requirements............ Pursuant to the Registration Rights Agreement, the
Company is obligated to consummate the Exchange Offer
or cause resales of the Old Notes to be registered
under the Securities Act, and, if one of such events
does not occur prior to 180 days after May 16, 1996,
the rate of interest on the Old Notes will permanently
increase by one-half of one percent per annum. Any Old
Notes remaining outstanding following a consummation
of the Exchange Offer will be treated together with
the New Notes as one series for purposes of the
Indenture. Holders of Senior Notes who do not
participate in the Exchange Offer may thereafter hold
a less liquid security. See "Description of New
Notes -- Registration Rights."
</TABLE>

12
<PAGE> 13

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 IN THOUSANDS)
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 AND
RATIOS:
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
EBITDA to
Consolidated
Interest
Expense(5)... 2.55x 4.73x 2.98x 2.23x 2.11x 1.99x 1.67x 2.08x 1.55x
Total debt to
EBITDA..... 5.87x 3.70x 6.24x 6.23x 5.87x 5.06x -- -- --
Ratio of
earnings to
fixed
charges(6)... 2.28x 3.41x 2.09x 1.52x 1.46x 1.39x 1.14x 1.22x --
Deficiency of
earnings to
fixed
charges.... -- -- -- -- -- -- -- -- $ 1,623
SELECTED
OPERATING
INFORMATION(7):
Power plants:
Electricity
revenue(8):
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(9)... 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 DECEMBER 31, AS OF JUNE 30, 1996
---------------------------------------------------- ------------------------------
1991 1992 1993 1994 1995 ACTUAL PRO FORMA(2)
-------- -------- -------- -------- -------- ------------ ---------------
(IN THOUSANDS)
<S> <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 $ 98,307
Property, plant and equipment, net...... 351 424 251,070 335,453 447,751 530,203 657,724
Total assets............................ 41,245 55,370 302,256 421,372 554,531 792,812 993,237
Total liabilities....................... 34,624 44,865 288,827 402,723 529,304 713,156 831,321
Stockholder's equity.................... 6,621 10,505 13,429 18,649 25,227 79,656 161,916
(See footnotes on next page)
</TABLE>

13
<PAGE> 14

- ------------

(1) The pro forma information presented under statement of operations data and
other financial data and ratios 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 Old Notes and the application of the net proceeds therefrom as
described under "Use of Proceeds." The pro forma information presented
under selected operating information 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 and
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 Old Notes and the application
of the net proceeds therefrom as described under "Use of Proceeds" as if
such transactions had occurred on January 1, 1996. The pro forma
information presented under balance sheet data gives effect to the Gilroy
Transaction and the Common Stock Offering as if such transactions 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 in connection with
the Common Stock Offering.

(4) EBITDA is defined as income from operations plus depreciation, capitalized
interest, other income, non-cash charges and cash received from investments
in power projects, reduced by the income from unconsolidated investments in
power projects. See "Description of New Notes -- Certain Definitions."
EBITDA is presented not as a measure of operating results but rather as a
measure of the Company's ability to service debt. EBITDA should not be
construed as an alternative either (i) to income from operations
(determined in accordance with generally accepted accounting principles) or
(ii) to cash flows from operating activities (determined in accordance with
generally accepted accounting principles).

(5) Consolidated Interest Expense is defined as total interest expense plus
one-third of all operating lease obligations, capitalized interest,
dividends paid in respect of preferred stock and cash contributions to any
employee stock ownership plan used to pay interest on loans incurred to
purchase capital stock of the Company. See "Description of New
Notes -- Certain Definitions." The pro forma EBITDA to Consolidated
Interest Expense ratio presented gives effect to the sale of the Old Notes
and the application of the net proceeds therefrom as if such transaction
had occurred on January 1, 1995. For purposes of the "Limitation on
Incurrence of Indebtedness" covenant under the Indenture, such ratio was
calculated as if such transaction had occurred on April 1, 1995 and did not
give effect to the portion of the Old Notes incurred pursuant to
refinancing and other permitted exceptions thereto. Under such method of
calculation, such ratio would have been 2.02x for the twelve-month period
ended March 31, 1996.

(6) Earnings are defined as income before provision for taxes, extraordinary
item and cumulative effect of changes in accounting principle plus cash
received from investments in power projects and fixed charges reduced by
the equity in income from investments in power projects and capitalized
interest. Fixed charges consist of interest expense, capitalized interest,
amortization of debt issuance costs and the portion of rental expenses
representative of the interest expense component.

(7) For an explanation of such selected operating information, see
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Selected Operating Information."

(8) 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.

(9) Average energy price per kilowatt hour represents energy revenue divided by
kilowatt hours produced.

------------------------

This Prospectus contains forward-looking statements which involve risks and
uncertainties. The Company's actual results may differ significantly from the
results discussed in the forward-looking statements. Factors that might cause
such a difference include, but are not limited to, those discussed in "Risk
Factors."

14
<PAGE> 15

RISK FACTORS

Prospective purchasers of the New Notes should carefully consider the
factors set forth below, as well as the other information contained in this
Prospectus, in evaluating an investment in the New Notes.

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 and the Common Stock
Offering, the Company's total consolidated indebtedness would have been $615.8
million, its total consolidated assets would have been $993.2 million and its
stockholder's equity would have been $161.9 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 to be dated as of May 16, 1996 (the "Indenture") relating to
the Senior Notes and the Indenture dated as of February 17, 1994 (the "9 1/4%
Indenture") relating to the Company's 9 1/4% Senior Notes Due 2004 (the "9 1/4%
Senior Notes") (collectively, the "Indentures") 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 a Change of Control Triggering Event
(as defined herein), to make an offer to purchase the Senior Notes and the
9 1/4% Senior Notes. There can be no assurance that the Company will have the
financial resources necessary to purchase the 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. See
"-- Control by Electrowatt," "Description of New Notes" and "Description of
Certain Other Indebtedness."

The Company believes that, based on current levels of operations and
anticipated growth, cash flow from operations, together with other available
sources of funds, including borrowings under the Company's existing borrowing
arrangements, will be adequate to make required payments of principal and
interest on the Company's debt, including the Senior Notes and 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 "-- Risks Related to Holding Company Structure,"
"-- Possible Unavailability of Project Financing," "-- Control by Electrowatt,"
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and "Certain Transactions."

RISKS RELATED TO HOLDING COMPANY STRUCTURE

The Senior Notes will be exclusively the obligations of Calpine and not of
any of its subsidiaries or other affiliates. Because the operations of the
Company are conducted primarily by its subsidiaries and other affiliates, the
Company's cash flow and its ability to service its indebtedness, including its
ability to pay the

15
<PAGE> 16

interest on and principal of the Senior Notes, are almost entirely dependent
upon the earnings of its subsidiaries and other affiliates and the distribution
of those earnings to the Company. The non-recourse debt agreements of certain of
the Company's subsidiaries and other affiliates generally restrict their ability
to pay dividends, make distributions or otherwise transfer funds to the Company.
The restrictions in such agreements generally require that, prior to the payment
of dividends, distributions or other transfers, the subsidiary or other
affiliate proposing to make the distribution must provide for the payment of
other obligations, including operating expenses, debt service and reserves.
Calpine's subsidiaries and other affiliates are separate and distinct legal
entities and have no obligation, contingent or otherwise, to pay any amounts due
on the Senior Notes or to make any funds available therefor, whether by
dividends, loans or other payments, and do not guarantee the payment of interest
on or principal of the Senior Notes. Any right of Calpine to receive any assets
of any of its subsidiaries or other affiliates upon any liquidation or
reorganization of Calpine (and the consequent right of the holders of the Senior
Notes to participate in the distribution of, or to realize proceeds from, those
assets) will be effectively subordinated to the claims of any such subsidiaries'
or other affiliates' creditors (including trade creditors and holders of debt
issued by such subsidiaries or affiliates). After giving pro forma effect to the
Gilroy Transaction, as of June 30, 1996, approximately $324.2 million of
indebtedness of certain of the Company's subsidiaries would be effectively
senior to the Senior Notes, substantially all of which represents non-recourse
project financing secured by the assets of such subsidiaries.

While the Indentures impose limitations on the ability of the Company and
its subsidiaries to incur additional indebtedness, the Indentures do not limit
the amount of non-recourse debt that the Company's subsidiaries may incur to
finance new facilities. See "Description of New
Notes -- Covenants -- Limitations on Incurrence of Indebtedness."

POSSIBLE UNAVAILABILITY OF FINANCING

Each power generation facility acquired or developed by the Company will
require substantial capital investment. The Company's ability to arrange
financing and the cost of such financing are dependent upon numerous factors,
including general economic and capital market conditions, conditions in energy
markets, regulatory developments, credit availability from banks or other
lenders, investor confidence in the industry and the Company, the continued
success of the Company's current facilities, and provisions of tax and
securities laws that are conducive to raising capital. There can be no assurance
that financing for new facilities will be available to the Company on acceptable
terms in the future. In addition, there can be no assurance that all required
governmental permits and approvals for the Company's new or acquired facilities
will be obtained, that the Company will be able to obtain favorable power sales
agreements and adequate financing, or that the Company will be successful in the
development of power generation facilities in the future. Historically, the
Company has been successful in obtaining debt financing for its facilities and
has relied on Electrowatt, currently the Company's sole stockholder, to provide
funding for a substantial portion of its facility equity commitments. Over the
past few years, the Company has maintained a $50.0 million credit facility with
Credit Suisse (the "Credit Suisse Credit Facility"), which was arranged for the
Company by Electrowatt. In connection with the Common Stock Offering,
Electrowatt sold all of its shares of Common Stock of the Company and, as a
result, the Company will no longer be able to rely on Electrowatt for financing.
Upon the completion of the Common Stock Offering, the Credit Suisse Credit
Facility was terminated.

On September 25, 1996, the Company entered into a $50.0 million three-year
revolving credit facility with The Bank of Nova Scotia (the "Bank of Nova Scotia
Credit Facility"). The Bank of Nova Scotia Credit Facility contains certain
restrictions that significantly limit or prohibit, among other things, the
ability of the Company or its subsidiaries to incur indebtedness, make
prepayments of certain indebtedness, pay dividends, make investments, engage in
transactions with affiliates, create liens, sell assets and engage in mergers
and consolidations. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Liquidity and Capital Resources."

The Company's power generation facilities have been financed using a
variety of leveraged financing structures, primarily consisting of non-recourse
debt and lease obligations. As of 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

16
<PAGE> 17

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 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

17
<PAGE> 18

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 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 low gas prices and a high degree of
precipitation during the period, which resulted in higher levels of energy
generation by hydroelectric power facilities that supply electricity. 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."

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POWER PROJECT DEVELOPMENT AND ACQUISITION RISKS

The development of power generation facilities is subject to substantial
risks. In connection with the development of a power generation facility, the
Company must generally obtain power and/or steam sales agreements, governmental
permits and approvals, fuel supply and transportation agreements, sufficient
equity capital and debt financing, electrical transmission agreements, site
agreements and construction contracts, and there can be no assurance that the
Company will be successful in doing so. In addition, project development is
subject to certain environmental, engineering and construction risks relating to
cost-overruns, delays and performance. Although the Company may attempt to
minimize the financial risks in the development of a project by securing a
favorable long-term power sales agreement, entering into power marketing
transactions, obtaining all required governmental permits and approvals and
arranging adequate financing prior to the commencement of construction, the
development of a power project may require the Company to expend significant
sums for preliminary engineering, permitting and legal and other expenses before
it can be determined whether a project is feasible, economically attractive or
financeable. If the Company were unable to complete the development of a
facility, it would generally not be able to recover its investment in such a
facility.

The process for obtaining initial environmental, siting and other
governmental permits and approvals is complicated and lengthy, often taking more
than one year, and is subject to significant uncertainties. As a result of
competition, it may be difficult to obtain a power sales agreement for a
proposed project, and the prices offered in new power sales agreements for both
electric capacity and energy may be less than the prices in prior agreements.

The Company has grown substantially in recent years as a result of
acquisitions of interests in power generation facilities and steam fields such
as the Transactions. The Company believes that although the domestic power
industry is undergoing consolidation and that significant acquisition
opportunities are available, the Company is likely to confront significant
competition for acquisition opportunities. In addition, there can be no
assurance that the Company will continue to identify attractive acquisition
opportunities at favorable prices or, to the extent that any opportunities are
identified, that the Company will be able to consummate such acquisitions.

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.

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<PAGE> 20

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 and/or steam sales agreements. In
addition, although insurance is maintained to protect against certain of these
operating risks, the proceeds of such insurance may not be adequate to cover
lost revenues or increased expenses, and, as a result, the entity owning such
power generation facility or steam field may be unable to service principal and
interest payments under its financing obligations and may operate at a loss. A
default under such a financing obligation could result in the Company losing its
interest in such power generation facility or steam field. See "-- Possible
Unavailability of Project 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 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

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<PAGE> 21

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 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."

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<PAGE> 22

Currently, Congress is considering proposed legislation that would amend
PURPA by eliminating the requirement that utilities purchase electricity from
QFs at avoided costs. The Company does not know whether such legislation will be
passed or what form it may take. The Company believes that if any such
legislation is passed, it would apply to new projects. As a result, although
such legislation may adversely affect the Company's ability to develop new
projects, the Company believes it would not affect the Company's existing QFs.
There can be no assurance, however, that any legislation passed would not
adversely impact the Company's existing projects.

Many states are implementing or considering regulatory initiatives designed
to increase competition in the domestic power generation industry. In a December
20, 1995 policy decision, the CPUC outlined a new market structure that would
provide for a competitive power generation industry and direct access to
generation for all consumers within five years. As part of its policy decision,
the CPUC indicated that power sales agreements of existing QFs would be honored.
The Company cannot predict the final form or timing of the proposed
restructuring and the impact, if any, that such restructuring would have on the
Company's existing business or results of operations.

SEISMIC DISTURBANCES

Areas in which the Company operates and is developing many of its
geothermal and gas-fired projects are subject to frequent low-level seismic
disturbances, and more significant seismic disturbances are possible. While the
Company's existing power generation facilities are built to withstand relatively
significant levels of seismic disturbances, and the Company believes it
maintains adequate insurance protection, there can be no assurance that
earthquake, property damage or business interruption insurance will be adequate
to cover all potential losses sustained in the event of serious seismic
disturbances or that such insurance will continue to be available to the Company
on commercially reasonable terms.

AVAILABILITY OF NATURAL GAS

To date, the Company's fuel acquisition strategy has included various
combinations of Company-owned gas reserves, gas prepayment contracts and short-,
medium- and long-term supply contracts. In its gas supply arrangements, the
Company attempts to match the fuel cost with the fuel component included in the
facility's power sales agreements, in order to minimize a project's exposure to
fuel price risk. The Company believes that there will be adequate supplies of
natural gas available at reasonable prices for each of its facilities when
current gas supply agreements expire. There can be no assurance, however, that
gas supplies will be available for the full term of the facilities' power sales
agreements, or that gas prices will not increase significantly. If gas is not
available, or if gas prices increase above the fuel component of the facilities'
power sales agreements, there could be a material adverse impact on the
Company's net revenues.

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."

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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."

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. See "Management's Discussion and Anaysis of Financial
Condition and Results of Operations -- Quarterly Results of Operations and
Seasonality."

ABSENCE OF PUBLIC MARKET

There has previously been no public market for the Senior Notes. The
Company does not intend to list the New Notes on any securities exchange or to
seek approval for quotation through any automated quotation system. There can be
no assurance that an active trading market will develop or be sustained in the
New Notes. To the extent that a market for the New Notes does develop, the
market value of the New Notes will depend on market conditions (such as yields
on alternative investments), general economic conditions, the Company's
financial condition and other conditions. Such conditions might cause the New
Notes, to the extent they are actively traded, to trade at a significant
discount from face value.

CONSEQUENCES OF FAILURE TO EXCHANGE

Untendered Old Notes that are not exchanged for New Notes pursuant to the
Exchange Offer will remain subject to the existing restrictions on transfer of
such Old Notes. Additionally, holders of any Old Notes not tendered in the
Exchange Offer will not have any rights under the Registration Rights Agreement
to cause the Company to register the Old Notes, and the interest rate on the Old
Notes will remain at its initial rate of 10 1/2% per annum.

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<PAGE> 24

RECENT DEVELOPMENTS

On August 29, 1996, Calpine acquired the Gilroy Facility, a 120 megawatt
gas-fired cogeneration facility located in Gilroy, California, 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 -- Power Generation Facilities -- Gilroy Facility."

On September 25, 1996, Calpine completed the initial public offering of
18,045,000 shares of its Common Stock (the "Common Stock Offering"). In the
Common Stock Offering, the Company issued and sold 5,477,820 shares of Common
Stock and Electrowatt sold 12,567,180 shares of Common Stock, representing its
entire ownership interest in Calpine. As a result of the Common Stock Offering,
Electrowatt no longer owns any interest in Calpine. The Company received
approximately $82.3 million of net proceeds from the Common Stock Offering.
Approximately $13.0 million of such net proceeds was used to repay outstanding
indebtedness. 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. In connection with the Common Stock Offering,
the Company reincorporated in the State of Delaware, converted the outstanding
Class B Common Stock into Common Stock and eliminated the authorized Class A
Common Stock and Class B Common Stock, completed a 5.194-for-1 stock split of
the Company's Common Stock and converted the Company's outstanding Preferred
Stock into shares of Common Stock (collectively, the "Reincorporation").

USE OF PROCEEDS

The Company will not receive any cash proceeds from the issuance of the New
Notes offered hereby. In consideration for issuing the New Notes as contemplated
in this Prospectus, the Company will receive in exchange Old Notes in like
principal amount, the terms of which are identical to the New Notes. The Old
Notes surrendered in exchange for New Notes will be retired and canceled and
cannot be reissued. Accordingly, issuance of the New Notes will not result in
any increase in the indebtedness of the Company.

The net proceeds received by the Company from the sale of the Old Notes
(after the deduction of placement agent fees and other expenses of such sale)
were approximately $174.6 million. The Company used the net proceeds as follows:
(i) $57.0 million to repay in full The Bank of Nova Scotia loan to Calpine
Thermal Company, a wholly owned subsidiary of the Company (the "$57 Million Bank
of Nova Scotia Loan"), (ii) $45.0 million to repay in full The Bank of Nova
Scotia loan to the Company (the "$45 Million Bank of Nova Scotia Loan"), (iii)
approximately $53.7 million to repay revolving loans outstanding under the
Credit Suisse Credit Facility and (iv) approximately $18.9 million for general
corporate purposes. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Liquidity and Capital Resources."

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 limited under the
Indentures and under the Bank of Nova Scotia Credit Facility. See "Description
of New Notes -- Certain Covenants -- Limitation on Restricted Payments" and
"Description of Certain Other Indebtedness -- 9 1/4% Senior Notes Due 2004."
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 (including the Indentures) and such other factors as
the Board of Directors may deem relevant.

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<PAGE> 25

THE EXCHANGE OFFER

GENERAL

In connection with the sale of the Old Notes, the Company entered into the
Registration Rights Agreement, which requires the Company to file with the
Commission a registration statement (the "Exchange Offer Registration
Statement") under the Securities Act with respect to an issue of senior notes of
the Company with terms identical to the Old Notes (except with respect to
restrictions on transfer) and to use its best efforts to cause such registration
statement to become effective under the Securities Act and, upon the
effectiveness of such registration statement, to offer to the holders of the Old
Notes the opportunity, for a period of 30 days from the date the notice of the
Exchange Offer is mailed to holders of the Old Notes, to exchange their Old
Notes for a like principal amount of New Notes. The Exchange Offer is being made
pursuant to the Registration Rights Agreement to satisfy the Company's
obligations thereunder. The Company has not entered into any arrangement or
understanding with any person to distribute the New Notes to be received in the
Exchange Offer.

Under existing interpretations of the staff of the Commission, the New
Notes would, in general, be freely transferable after the Exchange Offer without
further registration under the Securities Act by holders thereof (other than (i)
a broker-dealer who acquires such New Notes directly from the Company to resell
pursuant to Rule 144A or any other available exemption under the Securities Act
or (ii) a person that is an affiliate of the Company within the meaning of Rule
405 under the Securities Act), without compliance with the registration and
prospectus delivery provisions of the Securities Act, provided that such New
Notes are acquired in the ordinary course of such holders' business and such
holders have no arrangements with any person to participate in the distribution
of such New Notes. Eligible holders wishing to accept the Exchange Offer must
represent to the Company that such conditions have been met. Each broker-dealer
that receives New Notes for its own account pursuant to the Exchange Offer must
acknowledge that it will deliver a prospectus in connection with any resale of
such New Notes.

In the event that applicable interpretations of the staff of the Commission
would not permit the Company to effect the Exchange Offer or, if for any other
reason the Exchange Offer is not consummated on or prior to November 12, 1996,
the Company has agreed to use its best efforts to cause to become effective a
shelf registration statement (the "Shelf Registration Statement") with respect
to the resale of the Old Notes and to keep the Shelf Registration Statement
effective until three years after the date of the initial sale of the Old Notes
or until all the Old Notes covered by the Shelf Registration Statement have been
sold pursuant to such Shelf Registration Statement.

TERMS OF THE EXCHANGE OFFER

Each holder of Old Notes who wishes to exchange Old Notes for New Notes in
the Exchange Offer will be required to make certain representations, including
that (i) it is neither an affiliate of the Company nor a broker-dealer tendering
Old Notes acquired directly from the Company for its own account, (ii) any New
Notes to be received by it were acquired in the ordinary course of its business
and (iii) at the time of commencement of the Exchange Offer, it has no
arrangement with any person to participate in the distribution (within the
meaning of the Securities Act) of the New Notes. In addition, in connection with
any resales of New Notes, any broker-dealer (a "Participating Broker-Dealer")
who acquired Old Notes for its own account as a result of market-making
activities or other trading activities must deliver a prospectus meeting the
requirements of the Securities Act in connection with any resale of the New
Notes. The Commission has taken the position that Participating Broker-Dealers
may fulfill their prospectus delivery requirements with respect to the New Notes
(other than a resale of an unsold allotment from the original sales of Old
Notes) with the prospectus contained in the Exchange Offer Registration
Statement. Under the Registration Rights Agreement, the Company is required to
allow Participating Broker-Dealers (and other persons, if any, subject to
similar prospectus delivery requirements) to use the prospectus contained in the
Exchange Offer Registration Statement in connection with the resale of such New
Notes, provided, however, the Company shall not be required to amend or
supplement such prospectus for a period exceeding 180 days after the
consummation of the Exchange Offer. The Company has also agreed that in the
event that either the Exchange Offer is not consummated or a Shelf Registration
Statement is not declared effective on or prior to

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<PAGE> 26

November 12, 1996, the interest rate borne by the Old Notes will be increased by
one-half of one percent per annum until the earlier of the consummation of the
Exchange Offer or the effectiveness of the Shelf Registration Statement, as the
case may be.

In the event an exchange offer is consummated on or before November 12,
1996, the Company will not be required to file a Shelf Registration Statement to
register any outstanding Old Notes, and the interest rate on such Old Notes will
remain at its initial level of 10 1/2% per annum. The Exchange Offer shall be
deemed to have been consummated upon the Company's having exchanged, pursuant to
the Exchange Offer, New Notes for all Old Notes that have been properly tendered
and not withdrawn by the Expiration Date. In such event, holders of Old Notes
not participating in the Exchange Offer who are seeking liquidity in their
investment would have to rely on exemptions to registration requirements under
the securities laws, including the Securities Act.

Upon the terms and subject to the conditions set forth in this Prospectus
and in the accompanying Letter of Transmittal, the Company will accept all Old
Notes validly tendered prior to 5:00 p.m., New York City time, on the Expiration
Date. The Company will issue $1,000 in principal amount of New Notes (and any
integral multiple thereof) in exchange for an equal principal amount of
outstanding Old Notes tendered and accepted in the Exchange Offer. Holders may
tender some or all of their Old Notes pursuant to the Exchange Offer in any
denomination of $1,000 or in integral multiples thereof.

Based on no-action letters issued by the staff of the Commission to third
parties, the Company believes that the New Notes issued pursuant to the Exchange
Offer in exchange for Old Notes may be offered for resale, resold and otherwise
transferred by holders thereof (other than any such holder that is an
"affiliate" of the Company within the meaning of Rule 405 under the Securities
Act) without compliance with the registration and prospectus delivery
requirements of the Securities Act, provided that such New Notes are acquired in
the ordinary course of such holders' business and such holders have no
arrangement with any person to participate in the distribution of such New
Notes. Any holder of Old Notes who tenders in the Exchange Offer for the purpose
of participating in a distribution of the New Notes cannot rely on such
interpretation by the staff of the Commission and must comply with the
registration and prospectus delivery requirements of the Securities Act in
connection with any resale transaction. Each broker-dealer that receives New
Notes for its own account in exchange for Old Notes, where such Old Notes were
acquired by such broker-dealer as a result of market-making activities or other
trading activities, must acknowledge that it will deliver a prospectus in
connection with any resale of such New Notes.

The form and terms of the New Notes will be the same as the form and terms
of the Old Notes except that the New Notes will not bear legends restricting the
transfer thereof. The New Notes will evidence the same debt as the Old Notes.
The New Notes will be issued under and entitled to the benefits of the Note
Indenture.

As of the date of this Prospectus, $180,000,000 aggregate principal amount
of the Old Notes are outstanding and there are two registered holders thereof.
In connection with the issuance of the Old Notes, the Company arranged for the
Old Notes to be eligible for trading in the Private Offering, Resale and Trading
through Automated Linkages (PORTAL) Market, the National Association of
Securities Dealers' screen based, automated market trading of securities
eligible for resale under Rule 144A and to be issued and transferable in
book-entry form through the facilities of DTC. The New Notes will also be
issuable and transferable in book-entry form through DTC.

This Prospectus, together with the accompanying Letter of Transmittal, is
being sent to all registered holders as of October 2, 1996 (the "Record Date").

The Company shall be deemed to have accepted validly tendered Old Notes
when, as and if the Company has given oral or written notice thereof to the
Exchange Agent. See "Exchange Agent." The Exchange Agent will act as agent for
the tendering holders of Old Notes for the purpose of receiving New Notes from
the Company and delivering New Notes to such holders.

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<PAGE> 27

If any tendered Old Notes are not accepted for exchange because of an
invalid tender or the occurrence of certain other events set forth herein,
certificates for any such unaccepted Old Notes will be returned, without
expense, to the tendering holder thereof as promptly as practicable after the
Expiration Date.

Holders of Old Notes who tender in the Exchange Offer will not be required
to pay brokerage commissions or fees or, subject to the instructions in the
Letter of Transmittal, transfer taxes with respect to the exchange of Old Notes
pursuant to the Exchange Offer. The Company will pay all charges and expenses,
other than certain applicable taxes, in connection with the Exchange Offer. See
"Fees and Expenses."

Holders of Old Notes do not have any appraisal or dissenters' rights under
the California Corporations Code or the Note Indenture in connection with the
Exchange Offer. The Company intends to conduct the Exchange Offer in accordance
with the provisions of the Registration Rights Agreement and the applicable
requirements of the Exchange Act and the rules and regulations of the Commission
thereunder. Old Notes that are not tendered for exchange in the Exchange Offer
will remain outstanding and continue to accrue interest, but will not be
entitled to any rights or benefits under the Registration Rights Agreement.

EXPIRATION DATE; EXTENSIONS; AMENDMENTS

The term "Expiration Date" shall mean 5:00 p.m. New York City time, on
November 5, 1996 unless the Company, in its sole discretion, extends the
Exchange Offer, in which case the term "Expiration Date" shall mean the latest
date to which the Exchange Offer is extended.

In order to extend the Expiration Date, the Company will notify the
Exchange Agent of any extension by oral or written notice and will mail to the
record holders of Old Notes an announcement thereof, each prior to 9:00 a.m.,
New York City time, on the next business day after the previously scheduled
Expiration Date. Such announcement may state that the Company is extending the
Exchange Offer for a specified period of time.

The Company reserves the right (i) to delay acceptance of any Old Notes, to
extend the Exchange Offer or to terminate the Exchange Offer and to refuse to
accept Old Notes not previously accepted, if any of the conditions set forth
herein under "Termination" shall have occurred and shall not have been waived by
the Company (if permitted to be waived by the Company), by giving oral or
written notice of such delay, extension or termination to the Exchange Agent,
and (ii) to amend the terms of the Exchange Offer in any manner deemed by it to
be advantageous to the holders of the Old Notes. Any such delay in acceptance,
extension, termination or amendment will be followed as promptly as practicable
by oral or written notice thereof. If the Exchange Offer is amended in a manner
determined by the Company to constitute a material change, the Company will
promptly disclose such amendment in a manner reasonably calculated to inform the
holders of the Old Notes of such amendment.

Without limiting the manner in which the Company may choose to make public
announcements of any delay in acceptance, extension, termination or amendment of
the Exchange Offer, the Company shall have no obligation to publish, advertise,
or otherwise communicate any such public announcement, other than by making a
timely release to the Dow Jones News Service.

INTEREST ON THE NEW NOTES

The New Notes will bear interest from the last Interest Payment Date on
which interest was paid on the Old Notes, or if interest has not yet been paid
on the Old Notes, from May 16, 1996. Such interest will be paid with the first
interest payment on the New Notes. Interest on the Old Notes accepted for
exchange will cease to accrue upon issuance of the New Notes.

The New Notes will bear interest at a rate of 10 1/2% per annum. Interest
on the New Notes will be payable semi-annually, in arrears, on each Interest
Payment Date following the consummation of the Exchange Offer. Untendered Old
Notes that are not exchanged for New Notes pursuant to the Exchange Offer will
bear interest at a rate of 10 1/2% per annum after the Expiration Date.

27
<PAGE> 28

PROCEDURES FOR TENDERING

To tender in the Exchange Offer, a holder must complete, sign and date the
Letter of Transmittal, or a facsimile thereof, have the signatures thereon
guaranteed if required by the Letter of Transmittal, and mail or otherwise
deliver such Letter of Transmittal or such facsimile, together with the Old
Notes (unless the book-entry transfer procedures described below are used) and
any other required documents, to the Exchange Agent for receipt prior to 5:00
p.m., New York City time, on the Expiration Date.

Any financial institution that is a participant in DTC's Book-Entry
Transfer Facility system may make book-entry delivery of the Old Notes by
causing DTC to transfer such Old Notes into the Exchange Agent's account in
accordance with DTC's procedure for such transfer.

The tender by a holder of Old Notes will constitute an agreement between
such holder and the Company in accordance with the terms and subject to the
conditions set forth herein and in the Letter of Transmittal.

Delivery of all documents must be made to the Exchange Agent at its address
set forth herein. Holders may also request that their respective brokers,
dealers, commercial banks, trust companies or nominees effect such tender for
such holders.

The method of delivery of Old Notes and the Letter of Transmittal and all
other required documents to the Exchange Agent is at the election and risk of
the holders. Instead of delivery by mail, it is recommended that holders use an
overnight or hand delivery service. In all cases, sufficient time should be
allowed to assure timely delivery. No Letter of Transmittal should be sent to
the Company.

Only a holder of Old Notes may tender such Old Notes in the Exchange Offer.
The term "holder" with respect to the Exchange Offer means any person in whose
name Old Notes are registered on the books of the Company or any other person
who has obtained a properly completed bond power from the registered holder or
any person whose Old Notes are held of record by DTC who desires to deliver such
Old Notes by book-entry transfer at DTC.

Any beneficial holder whose Old Notes are registered in the name of such
holder's broker, dealer, commercial bank, trust company or other nominee and who
wishes to tender should contact such registered holder promptly and instruct
such registered holder to tender on such holder's behalf. If such beneficial
holder wishes to tender on such holder's own behalf, such beneficial holder
must, prior to completing and executing the Letter of Transmittal and delivering
such holder's Old Notes, either make appropriate arrangements to register
ownership of the Old Notes in such holder's name or obtain a properly completed
bond power from the registered holder. The transfer of record ownership may take
considerable time.

Signatures on a Letter of Transmittal or a notice of withdrawal, as the
case may be, must be guaranteed by a member firm of a registered national
securities exchange or of the National Association of Securities Dealers, Inc.,
a commercial bank or trust company having an office or correspondent in the
United States or an "eligible guarantor institution" within the meaning of Rule
17Ad-15 under the Exchange Act (an "Eligible Institution") that is a participant
in a recognized medallion signature guarantee program unless the Old Notes
tendered pursuant thereto are tendered (i) by a registered holder who has not
completed the box entitled "Special Issuance Instructions" or "Special Delivery
Instructions" on the Letter of Transmittal or (ii) for the account of an
Eligible Institution.

If the Letter of Transmittal is signed by a person other than the
registered holder of any Old Notes listed therein, such Old Notes must be
endorsed or accompanied by appropriate bond powers which authorize such person
to tender the Old Notes on behalf of the registered holder, in either case
signed as the name of the registered holder or holders appears on the Old Notes.

28
<PAGE> 29

If the Letter of Transmittal or any Old Notes or bond powers are signed by
trustees, executors, administrators, guardians, attorneys-in-fact, officers of
corporations or others acting in a fiduciary or representative capacity, such
persons should so indicate when signing, and unless waived by the Company,
submit evidence satisfactory to the Company of their authority to so act with
the Letter of Transmittal.

All questions as to the validity, form, eligibility (including time of
receipt), acceptance and withdrawal of the tendered Old Notes will be determined
by the Company in its sole discretion, which determination will be final and
binding. The Company reserves the absolute right to reject any and all Old Notes
not properly tendered or any Old Notes the Company's acceptance of which would,
in the opinion of counsel for the Company, be unlawful. The Company also
reserves the absolute right to waive any irregularities or conditions of tender
as to particular Old Notes. The Company's interpretation of the terms and
conditions of the Exchange Offer (including the instructions in the Letter of
Transmittal) will be final and binding on all parties. Unless waived, any
defects or irregularities in connection with tenders of Old Notes must be cured
within such time as the Company shall determine. Neither the Company, the
Exchange Agent nor any other person shall be under any duty to give notification
of defects or irregularities with respect to tenders of Old Notes nor shall any
of them incur any liability for failure to give such notification. Tenders of
Old Notes will not be deemed to have been made until such irregularities have
been cured or waived. Any Old Notes received by the Exchange Agent that are not
properly tendered and as to which the defects or irregularities have not been
cured or waived will be returned without cost by the Exchange Agent to the
tendering holder of such Old Notes unless otherwise provided in the Letter of
Transmittal as soon as practicable following the Expiration Date.

In addition, the Company reserves the right in its sole discretion to (a)
purchase or make offers for any Old Notes that remain outstanding subsequent to
the Expiration Date, or, as set forth under "Termination," to terminate the
Exchange Offer and (b) to the extent permitted by applicable law, purchase Old
Notes in the open market, in privately negotiated transactions or otherwise. The
terms of any such purchases or offers may differ from the terms of the Exchange
Offer.

GUARANTEED DELIVERY PROCEDURES

Holders who wish to tender their Old Notes and (i) whose Old Notes are not
immediately available, or (ii) who cannot deliver their Old Notes, the Letter of
Transmittal or any other required documents to the Exchange Agent prior to the
Expiration Date, or if such holder cannot complete the procedure for book-entry
transfer on a timely basis, may effect a tender if:

(a) the tender is made through an Eligible Institution;

(b) prior to the Expiration Date, the Exchange Agent receives from
such Eligible Institution a properly completed and duly executed Notice of
Guaranteed Delivery (by facsimile transmission, mail or hand delivery)
setting forth the name and address of the holder of the Old Notes, the
certificate number or numbers of such Old Notes and the principal amount of
Old Notes tendered, stating that the tender is being made thereby, and
guaranteeing that, within three business days after the Expiration Date,
the Letter of Transmittal (or facsimile thereof), together with the
certificate(s) representing the Old Notes (unless the book-entry transfer
procedures are to be used) to be tendered in proper form for transfer and
any other documents required by the Letter of Transmittal, will be
deposited by the Eligible Institution with the Exchange Agent; and

(c) such properly completed and executed Letter of Transmittal (or
facsimile thereof), together with the certificate(s) representing all
tendered Old Notes in proper form for transfer (or confirmation of a
book-entry transfer into the Exchange Agent's account at DTC of Old Notes
delivered electronically) and all other documents required by the Letter of
Transmittal are received by the Exchange Agent within three business days
after the Expiration Date.

Upon request to the Exchange Agent, a Notice of Guaranteed Delivery will be
sent to holders who wish to tender their Old Notes according to the guaranteed
delivery procedures set forth above.

29
<PAGE> 30

WITHDRAWAL OF TENDERS

Except as otherwise provided herein, tenders of Old Notes may be withdrawn
at any time prior to 5:00 p.m., New York City time, on the Expiration Date.

To withdraw a tender of Old Notes in the Exchange Offer, a written or
facsimile transmission notice of withdrawal must be received by the Exchange
Agent at its address set forth herein prior to 5:00 p.m., New York City time, on
the Expiration Date. Any such notice of withdrawal must (i) specify the name of
the person having deposited the Old Notes to be withdrawn (the "Depositor"),
(ii) identify the Old Notes to be withdrawn (including the certificate number or
numbers and principal amount of such Old Notes), (iii) be signed by the
Depositor in the same manner as the original signature on the Letter of
Transmittal by which such Old Notes were tendered (including any required
signature guarantees) or be accompanied by documents of transfer sufficient to
permit the Trustee with respect to the Old Notes to register the transfer of
such Old Notes into the name of the Depositor withdrawing the tender and (iv)
specify the name in which any such Old Notes are to be registered, if different
from that of the Depositor. All questions as to the validity, form and
eligibility (including time of receipt) of such withdrawal notices will be
determined by the Company, whose determination shall be final and binding on all
parties. Any Old Notes so withdrawn will be deemed not to have been validly
tendered for purposes of the Exchange Offer, and no New Notes will be issued
with respect thereto unless the Old Notes so withdrawn are validly retendered.
Any Old Notes that have been tendered but which are not accepted for exchange
will be returned to the holder thereof without cost to such holder as soon as
practicable after withdrawal, rejection of tender or termination of the Exchange
Offer. Properly withdrawn Old Notes may be retendered by following one of the
procedures described above under "Procedures for Tendering" at any time prior to
the Expiration Date.

TERMINATION

Notwithstanding any other term of the Exchange Offer, the Company will not
be required to accept for exchange, or exchange New Notes for any Old Notes not
theretofore accepted for exchange, and may terminate or amend the Exchange Offer
as provided herein before the acceptance of such Old Notes if: (i) any action or
proceeding is instituted or threatened in any court or by or before any
governmental agency with respect to the Exchange Offer, which, in the Company's
judgment, might materially impair the Company's ability to proceed with the
Exchange Offer or (ii) any law, statute, rule or regulation is proposed, adopted
or enacted, or any existing law, statute, rule or regulation is interpreted by
the staff of the Commission in a manner, which, in the Company's judgment, might
materially impair the Company's ability to proceed with the Exchange Offer.

If the Company determines that it may terminate the Exchange Offer, as set
forth above, the Company may (i) refuse to accept any Old Notes and return any
Old Notes that have been tendered to the holders thereof, (ii) extend the
Exchange Offer and retain all Old Notes tendered prior to the expiration of the
Exchange Offer, subject to the rights of such holders of tendered Old Notes to
withdraw their tendered Old Notes, or (iii) waive such termination event with
respect to the Exchange Offer and accept all properly tendered Old Notes that
have not been withdrawn. If such waiver constitutes a material change in the
Exchange Offer, the Company will disclose such change by means of a supplement
to this Prospectus that will be distributed to each registered holder of Old
Notes, and the Company will extend the Exchange Offer for a period of five to
ten business days, depending upon the significance of the waiver and the manner
of disclosure to the registered holders of the Old Notes, if the Exchange Offer
would otherwise expire during such period.

30
<PAGE> 31

EXCHANGE AGENT

Fleet National Bank has been appointed as Exchange Agent for the Exchange
Offer. Questions and requests for assistance and requests for additional copies
of this Prospectus or of the Letter of Transmittal should be directed to the
Exchange Agent addressed as follows:

<TABLE>
<S> <C>
By Hand: By Mail or Overnight Courier:
Fleet National Bank Fleet National Bank
Corporate Trust Operations Corporate Trust Operations
777 Main Street, Lower Level 777 Main Street, Lower Level
Hartford, Connecticut 06115 CTMO 0224
Attention: Patricia Williams Hartford, Connecticut 06115
Attention: Patricia Williams
Facsimile Transmission: (860) 986-7908
</TABLE>

FEES AND EXPENSES

The expenses of soliciting tenders pursuant to the Exchange Offer will be
borne by the Company. The principal solicitation for tenders pursuant to the
Exchange Offer is being made by mail. Additional solicitations may be made by
officers and regular employees of the Company and its affiliates in person, by
telegraph or by telephone.

The Company will not make any payments to brokers, dealers or other persons
soliciting acceptances of the Exchange Offer. The Company, however, will pay the
Exchange Agent reasonable customary fees for its services and will reimburse the
Exchange Agent for its reasonable out-of-pocket expenses in connection
therewith. The Company may also pay brokerage houses and other custodians,
nominees and fiduciaries the reasonable out-of-pocket expenses incurred by them
in forwarding copies of this Prospectus, Letters of Transmittal and related
documents to the beneficial owners of the Old Notes and in handling or
forwarding tenders for exchange.

The expenses to be incurred in connection with the Exchange Offer,
including fees and expenses of the Exchange Agent and Trustee and accounting and
legal fees, will be paid by the Company.

The Company will pay all transfer taxes, if any, applicable to the exchange
of Old Notes pursuant to the Exchange Offer. If, however, certificates
representing New Notes or Old Notes not tendered or accepted for exchange are to
be delivered to, or are to be registered or issued in the name of, any person
other than the registered holder of the Old Notes tendered, or if tendered Old
Notes are registered in the name of any person other than the person signing the
Letter of Transmittal, or if a transfer tax is imposed for any reason other than
the exchange of Old Notes pursuant to the Exchange Offer, then the amount of any
such transfer taxes (whether imposed on the registered holder or any other
persons) will be payable by the tendering holder. If satisfactory evidence of
payment of such taxes or exemption therefrom is not submitted with the Letter of
Transmittal, the amount of such transfer taxes will be billed directly to such
tendering holder.

ACCOUNTING TREATMENT

The New Notes will be recorded at the same carrying value as the Old Notes,
which is face value, as reflected in the Company's accounting records on the
date of the exchange. Accordingly, no gain or loss for accounting purposes will
be recognized by the Company upon the consummation of the Exchange Offer. The
expenses of the Exchange Offer will be amortized by the Company over the term of
the New Notes under generally accepted accounting principles.

31
<PAGE> 32

CAPITALIZATION

The following table sets forth, as of June 30, 1996 (i) the actual
consolidated capitalization of the Company; and (ii) the pro forma consolidated
capitalization of the Company after giving effect to the Gilroy Transaction and
the Common Stock Offering. 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>
JUNE 30, 1996
------------------------
ACTUAL PRO FORMA
-------- -----------
(IN THOUSANDS)
<S> <C> <C>
Short-term debt:
Current portion of non-recourse project financing.................. $ 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
Notes payable...................................................... 6,598 6,598
Senior notes....................................................... 285,000 285,000
-------- -----------
Total long-term debt............................................ 472,572 588,572
-------- -----------
Shareholder's equity:
Preferred Stock, $.001 par value: 5,000,000 shares authorized and
outstanding; pro forma, 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, 100,000,000 shares
authorized, 18,045,000 shares outstanding(1).................... 10 18
Additional paid-in capital......................................... 56,209 138,466
Retained earnings.................................................. 23,463 23,463
Cumulative translation adjustment.................................. (31) (31)
-------- -----------
Total shareholder's equity...................................... 79,656 161,916
-------- -----------
Total capitalization.......................................... $552,228 $ 750,488
======== =========
</TABLE>

- ------------

(1) Does not include 2,392,026 shares of Common Stock subject to 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."

32
<PAGE> 33

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>
(IN THOUSANDS)
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 50,532 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
---- ----
---- ----
(See footnotes on next page)
</TABLE>

33
<PAGE> 34

<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
"Executive Compensation -- 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 gave effect
to the issuance of Common Stock upon the conversion of the Company's
Preferred Stock in the Reincorporation.

(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. See "Description of New Notes -- Certain Definitions."
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).

(6) Earnings are defined as income before provision for taxes, extraordinary
item and cumulative effect of change in accounting principle plus cash
received from investments in power projects and fixed charges reduced by the
equity in income from investments in power projects and capitalized
interest. Fixed charges consist of interest expense, capitalized interest,
amortization of debt issuance costs and the portion of rental expenses
representative of the interest expense component.

34
<PAGE> 35

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, (iii)
the sale of the Old Notes and the application of the net proceeds therefrom as
described under "Use of Proceeds," and (iv) the Common Stock Offering, 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, (iii) the sale of the Old Notes and the application of the net
proceeds therefrom as described under "Use of Proceeds" and (iv) the Common
Stock Offering, 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 and the Common Stock Offering and the application of the net
proceeds therefrom, as if such transactions had occurred on June 30, 1996.

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.

35
<PAGE> 36

PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1995
------------------------------------------------------------------------------------
PRO FORMA FOR THE
TRANSACTIONS, THE
ADJUSTMENTS FOR THE PRO FORMA FOR THE ADJUSTMENTS PREFERRED STOCK
TRANSACTIONS AND TRANSACTIONS AND FOR THE INVESTMENT AND
THE PREFERRED STOCK THE PREFERRED SALE OF THE THE SALE OF THE
ACTUAL INVESTMENT(1) STOCK INVESTMENT OLD NOTES OLD NOTES
-------- ------------------- ----------------- ----------- -----------------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenue:
Electricity and steam sales......... $127,799 $ 89,349 $ 217,148 -- $ 217,148
Service contract revenue............ 7,153 250 7,403 -- 7,403
Income (loss) from unconsolidated
investments in power projects..... (2,854) -- (2,854) -- (2,854)
Interest income on loans to power
projects.......................... -- 2,564 2,564 -- 2,564
-------- -------- -------- ----------- --------
Total revenue..................... 132,098 92,163 224,261 -- 224,261
-------- -------- -------- ----------- --------
Cost of revenue:
Plant operating expenses............ 33,162 37,369 70,531 -- 70,531
Depreciation and amortization....... 26,264 15,838 42,102 -- 42,102
Operating lease expense............. 1,542 11,703 13,245 -- 13,245
Service contract expense............ 5,846 -- 5,846 -- 5,846
Production royalties................ 10,574 -- 10,574 -- 10,574
-------- -------- -------- ----------- --------
Total cost of revenue............. 77,388 64,910 142,298 -- 142,298
-------- -------- -------- ----------- --------
Gross profit.......................... 54,710 27,253 81,963 -- 81,963
Project development expenses.......... 3,087 -- 3,087 -- 3,087
General and administrative expenses... 8,937 -- 8,937 -- 8,937
-------- -------- -------- ----------- --------
Income from operations............ 42,686 27,253 69,939 -- 69,939
Interest expense...................... 32,154 16,193 48,347 $ 9,176(2) 57,523
Other income, net..................... (1,895) (7,263) (9,158) -- (9,158)
-------- -------- -------- ----------- --------
Income before provision for income
taxes............................. 12,427 18,323 30,750 (9,176) 21,574
Provision for income taxes............ 5,049 7,443 12,492 (3,728) 8,764
-------- -------- -------- ----------- --------
Net income...................... $ 7,378 $ 10,880 $ 18,258 $ (5,448) $ 12,810
======== ================= ================ =========== ================
Net income per share............ $ 0.52 $ 0.91
======== ================
OTHER FINANCIAL DATA AND RATIOS:
Depreciation and amortization....... $ 26,896 $ 42,734 $ 42,734
EBITDA.............................. $ 69,515 $ 123,770 $ 123,770
EBITDA to Consolidated Interest
Expense........................... 2.11x 2.34x 1.99x
Total debt to EBITDA................ 5.87x 4.70x 5.06x
Ratio of earnings to fixed
charges........................... 1.46x 1.63x 1.39x
</TABLE>

See Notes to Pro Forma Consolidated Statements of Operations

36
<PAGE> 37

PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS

<TABLE>
<CAPTION>
SIX MONTHS ENDED JUNE 30, 1996
-------------------------------------------------------------------------------------
PRO FORMA FOR THE
KING CITY
ADJUSTMENTS ADJUSTMENTS ADJUSTMENTS TRANSACTION, THE
FOR THE FOR THE FOR THE GILROY TRANSACTION
KING CITY GILROY SALE OF THE AND THE SALE OF THE
ACTUAL TRANSACTION(3)(5) TRANSACTION(4)(5) OLD NOTES OLD NOTES
------- ----------------- ----------------- ----------- ---------------------
(DOLLARS IN THOUSANDS)
<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 AND RATIOS:
Depreciation and amortization....... $15,757 $21,302
EBITDA.............................. $41,345 $46,993
EBITDA to Consolidated Interest
Expense........................... 2.08x 1.55x
Total debt to EBITDA................ -- --
Ratio of earnings to fixed
charges........................... 1.22x --
Deficiency of earnings to fixed
charges........................... -- $ 1,623
</TABLE>

See Notes to Pro Forma Consolidated Statements of Operations

37
<PAGE> 38

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 (loss) 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 (loss) 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 (loss)...................... $(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 Old Notes and
$540,000 of amortization expense for the costs associated with the sale of
the Old Notes, reduced by $4.4 million of actual interest expense in 1995 as
a result of the repayment of the $57 Million Bank of Nova Scotia Loan to
Calpine Thermal Company, a wholly-owned subsidiary of the Company, $3.4
million of interest expense as a result of the

38
<PAGE> 39

repayment of the $45 Million Bank of Nova Scotia Loan to the Company
(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 Old Notes and
$201,000 of amortization expense for the costs associated with the sale of
the Old 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%).

39
<PAGE> 40

PRO FORMA CONSOLIDATED BALANCE SHEET

<TABLE>
<CAPTION>
AS OF JUNE 30, 1996
-----------------------------------------------------
PRO FORMA
FOR THE
GILROY
ADJUSTMENTS ADJUSTMENTS TRANSACTION
FOR THE FOR THE AND THE
GILROY COMMON STOCK COMMON STOCK
ACTUAL TRANSACTION OFFERING OFFERING
-------- ------------ ------------ ------------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
ASSETS
Current assets:
Cash and cash equivalents........................ $ 38,403 $(22,356)(1) $ 82,260(7) $ 98,307
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) 82,260 173,648
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 $ 82,260 $993,237
========= ============= ============= ===============
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.................................. 5 -- $ (5)(8) --
Common stock..................................... 10 -- 8 18
Additional paid-in capital....................... 56,209 -- 82,257 138,466
Retained earnings................................ 23,463 -- -- 23,463
Cumulative translation adjustment................ (31) -- -- (31)
-------- ------------ ------------ ------------
Total stockholder's equity..................... 79,656 -- 82,260 161,916
-------- ------------ ------------ ------------
Total liabilities and stockholder's equity..... $792,812 $118,165 $ 82,260 $993,237
========= ============= ============= ===============
</TABLE>

See Notes to Pro Forma Consolidated Balance Sheet

40
<PAGE> 41

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 the 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.

(7) Represents the 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.

(8) Reflects the conversion of the Company's outstanding Preferred Stock into
Common Stock in connection with the Common Stock Offering.

41
<PAGE> 42

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 $993.2 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 $108.3
million 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
Gilroy Facility, a 120 megawatt gas-fired cogeneration facility, for a purchase
price of $125.0 million plus certain contingent consideration, which the Company
currently estimates will amount to approximately $24.1 million. 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 and steam 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

42
<PAGE> 43

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 Greenleaf 1 and 2 Facilities and the Watsonville Facility since
their acquisitions on April 21, 1995 and

43
<PAGE> 44

June 29, 1995, respectively, and the King City Facility since the effective date
of the lease on May 2, 1996. The information set forth under steam fields
consists of the results for the PG&E Unit 13 and Unit 16 Steam Fields, the
SMUDGEO #1 Steam Fields and, for 1994 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."

- ------------

(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 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

44
<PAGE> 45

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
Old Notes.

Provision for income taxes. The effective rate for the income tax
provisions 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

45
<PAGE> 46

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

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<PAGE> 47

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.

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,

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<PAGE> 48

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 1996 1995
-------- -------- -------- -------- ---------
(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 Old Notes, of
which a portion of the net proceeds was used to refinance current indebtedness
and to repay the $57 Million Bank of 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 Old 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 Old Notes in short-term
marketable securities. The increase in working capital was also due to the
proceeds from

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<PAGE> 49

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, $18.0 million for 1999, $18.0 million for 2000 and $100.2
million thereafter.

On September 25, 1996, the Company entered into a $50.0 million three-year
revolving credit facility with The Bank of Nova Scotia (the "Bank of Nova Scotia
Credit Facility"). The Bank of Nova Scotia Credit Facility replaced the
Company's $50.0 million Credit Suisse Credit Facility, which was terminated in
connection with the Common Stock Offering. Borrowings under the Bank of Nova
Scotia Credit Facility bear interest at either LIBOR or at The Bank of Nova
Scotia base rate plus a mutually-agreed margin. As of September 25, 1996, the
Company had no borrowings outstanding under the Bank of Nova Scotia Credit
Facility.

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
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 Credit Facility will
contain certain restrictions that will significantly limit or prohibit, among
other things, the ability of the Company of its subsidiaries to incur
indebtedness, make payments of certain indebtedness, pay dividends, make
investments, engage in transactions with affiliates, create liens, sell assets
and engage in mergers and consolidations.

The Company has a $1.2 million working capital line with a commercial
lender that may be used to fund short-term working capital commitments and
letters of credit. At 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. See "Business -- Description of Facilities -- Power Generation
Facilities -- Gilroy Facility."

On September 25, 1996, the Company completed the Common Stock Offering and
received approximately $82.3 million of net proceeds therefrom. The Company used
approximately $13.0 million of the net proceeds to repay the outstanding balance
on the Credit Suisse Credit Facility. 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. See "Recent
Developments."

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

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<PAGE> 50

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 Old Notes) and $50.0 million of proceeds from the
Preferred Stock Investment by Electrowatt. See "Use of Proceeds,"
"Business -- Description of Facilities -- Power Generation Facilities -- King
City Facility" and "Description of Capital Stock -- Preferred Stock."

The Company believes that it will have sufficient liquidity from cash on
hand, 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 has 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> 51

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 $993.2 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 generation facilities, as well as marketing
power and energy services to utilities and other end users.

THE MARKET

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 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> 52

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 in the future.

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.

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
investments in these projects will effectively position it for future expansion
in Southeast Asia and Latin America.

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<PAGE> 53

POWER GENERATION TECHNOLOGIES

NATURAL GAS-FIRED

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. 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 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

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<PAGE> 54

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> 55

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 a 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 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

55
<PAGE> 56

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."

56
<PAGE> 57

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."

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

57
<PAGE> 58

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 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

58
<PAGE> 59

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 Old 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%.

59
<PAGE> 60

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.

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<PAGE> 61

Gilroy Facility

On August 29, 1996, the Company acquired the Gilroy cogeneration facility
(the "Gilroy Facility"), a 120 megawatt gas-fired facility 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.

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<PAGE> 62

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
a 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, Chevron, 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:

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 1 Facility during hydro-spill periods, or during periods of
negative avoided costs. During 1995, the Greenleaf 1 Facility

62
<PAGE> 63

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:

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.

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<PAGE> 64

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:

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.

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<PAGE> 65

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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<PAGE> 66

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
October 15, 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> 67

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> 68

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>

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> 69

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.

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> 70

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> 71

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> 72

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 on 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 profit 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

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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.

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.

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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
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."

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 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,

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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 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.

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<PAGE> 81

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 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

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<PAGE> 82

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 October 11, 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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<PAGE> 83

MANAGEMENT

BOARD OF DIRECTORS AND EXECUTIVE OFFICERS

The following table sets forth certain information with respect to each
person who is a Director or an executive officer of the Company.

<TABLE>
<CAPTION>
NAME AGE POSITION
------------------------------------------ ---- ---------------------------------------------
<S> <C> <C>
Peter Cartwright.......................... 66 Chairman of the Board, President and Chief
Executive Officer
Ann B. Curtis............................. 45 Senior Vice President and Director
George J. Stathakis....................... 66 Director
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 Director and
executive officer of the Company. Upon completion of the Common Stock Offering,
Mr. Pierre Krafft, Mr. Hans-Peter Aebi and Mr. Rudolf Boesch each of whom were
Directors of the Company representing Electrowatt, resigned from the Board of
Directors of the Company and Ms. Curtis and Mr. Stathakis were appointed to fill
two of the vacancies. Accordingly, the Board of Directors is currently comprised
of Mr. Cartwright, Ms. Curtis and Mr. Stathakis, and Mr. Cartwright serves as
the 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 became Chairman of the Board of Directors of the Company on September
19, 1996. 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 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.

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 became a Director of the Company on September 19, 1996. 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.

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<PAGE> 84

George J. Stathakis has been a Senior Advisor to the Company since 1994 and
became a Director of the Company on September 19, 1996. 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.

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

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<PAGE> 85

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.

All Directors currently hold office until the next annual meeting of
shareholders or until their successors have been elected and qualified.
Executive officers are appointed by the Board of Directors and serve at the
discretion of the Board. There are no family relationships among any of the
Directors or executive officers of the Company.

CLASSIFIED BOARD OF DIRECTORS

The Company's By-Laws 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. The Company's Board of
Directors is 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.

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<PAGE> 86

COMMITTEES OF THE BOARD OF DIRECTORS

The Board of Directors has established an Audit Committee and a
Compensation Committee. The Audit Committee reviews 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 administers 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. Mr. Stathakis currently
serves as the sole Director on the Audit Committee and the Compensation
Committee. 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

Prior to the Common Stock Offering, Directors have not received any
compensation or other services as members of the Board of Directors. Following
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 are eligible to
participate in the Company's 1996 Stock Incentive Plan. See "-- 1996 Stock
Incentive Plan."

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 Officer 1993 220,055 176,000 -- 7,722
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.

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<PAGE> 87

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.

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 under the Company's Stock Option Program 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.

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<PAGE> 88

OPTION GRANTS IN LAST FISCAL YEAR

<TABLE>
<CAPTION>
INDIVIDUAL GRANTS(1)
----------------------------------------------------------------- POTENTIAL REALIZABLE
PERCENTAGE OF VALUE AT ASSUMED
TOTAL OPTIONS ANNUAL RATES OF STOCK
GRANTED TO PRICE APPRECIATION
OPTIONS EMPLOYEES FOR OPTION TERM
GRANTED IN FISCAL EXERCISE EXPIRATION ---------------------
NAME (NO. OF SHARES)(2) YEAR(3) PRICE PER 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 86,050 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 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. Novola, an option for
20,775 shares; Mr. Walter, an option for 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"

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<PAGE> 89

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.

AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR
AND FISCAL 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 $16.00 per share, which was the initial public offering
price of the shares sold in the Common Stock Offering.

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 completion of the
Common Stock Offering, the Company established a Compensation Committee of the
Board of Directors. No member of the Compensation Committee of the Board of
Directors of the Company serves 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 subsequently 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 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.

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<PAGE> 90

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 then 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 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 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 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

90
<PAGE> 91

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 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 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

91
<PAGE> 92

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 began on September 19, 1996 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.

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.

92
<PAGE> 93

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
attorney's 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.

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<PAGE> 94

CERTAIN TRANSACTIONS

CS Holding, a Swiss corporation, holds approximately 44.9% of the
outstanding shares of Electrowatt, which, prior to the Common Stock Offering,
held all of the outstanding capital stock of the Company. CS Holding also holds
(i) approximately 100% of the outstanding shares of Credit Suisse and (ii)
approximately 69.3% of the outstanding common stock of CS First Boston, Inc.,
which holds all of the outstanding common stock of CS First Boston Corporation.
CS First Boston Corporation was one of the underwriters of the Company's 9 1/4%
Senior Notes issued in February 1994 and was one of the placement agents in the
sale of the Old Notes. CS First Boston was also an underwriter in the Common
Stock Offering.

In January 1990, O.L.S. Energy-Agnews entered into a credit agreement with
Credit Suisse providing for a $28 million loan to finance the construction of
the Agnews 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 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 Old 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 restored to $50.0 million. Upon
completion of the Common Stock Offering, the Credit Suisse Credit Facility was
terminated.

In January 1992, Sumas and its wholly owned subsidiary, ENCO, entered into
loan agreements with Prudential and Credit Suisse providing for a $120.0 million
loan to finance the construction of the Sumas Facility and acquisition of
associated gas reserves. See "Business -- Description of Facilities -- Power
Generation Facilities -- Sumas Cogeneration 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
completion of the Common Stock Offering, the management services agreement was
terminated.

In 1995, the Company paid $106,000 to Electrowatt pursuant to a guarantee
fee agreement whereby Electrowatt agreed to guarantee the payment when due of
any and all indebtedness of the Company to Credit Suisse in accordance with the
terms and conditions of the Credit Suisse Credit Facility. Under the guarantee
fee agreement, the Company 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 completion of the Common Stock Offering, the
guarantee fee agreement was terminated.

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<PAGE> 95

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.

95
<PAGE> 96

PRINCIPAL STOCKHOLDERS

The following table sets forth certain information known to the Company
regarding beneficial ownership of the Company's Common Stock as of September 25,
1996 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 of the Company, (iii) each executive officer of the Company listed
in the Summary Compensation Table and (iv) all executive officers and Directors
of the Company as a group.

<TABLE>
<CAPTION>
NAME AND ADDRESS NUMBER OF SHARES PERCENTAGE OF SHARES
OF BENEFICIAL OWNER BENEFICIALLY OWNED(1) BENEFICIALLY OWNED(1)
- --------------------------------------------------------- --------------------- ---------------------
<S> <C> <C>
Ohio Public Employee Retirement Board.................... 1,600,000 8.9%
277 East Town Street
Columbus, OH 43215
Dreyfus Fund............................................. 1,200,000 6.7%
200 Park Avenue
New York, NY 10166
State Street Research & Management Company............... 1,100,000 6.1%
One Financial Center
31st Floor
Boston, MA 02111-2690
Lazard Freres Asset Management........................... 1,000,000 5.5%
30 Rockefeller Center
58th Floor
New York, NY 10020
Wellington Management Company............................ 1,000,000 5.5%
75 State Street
Boston, MA 02109
Peter Cartwright......................................... 686,763(2) 3.7%
Ann B. Curtis............................................ 167,581(2) *
George Stathakis......................................... 10,000(2) *
Lynn A. Kerby............................................ 84,666(2) *
Ron A. Walter............................................ 117,928(2) *
Alicia N. Noyola......................................... 34,513(2) *
Robert D. Kelly.......................................... 53,328(2) *
All executive officers and directors as a group (12 1,343,816(2) 6.9%
persons)...............................................
</TABLE>

- ------------

* Less than one percent

(1) Beneficial ownership is determined in accordance with the rules of the SEC
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. Except as indicated by
footnote, and 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) 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 September 25, 1996.

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<PAGE> 97

DESCRIPTION OF NEW NOTES

GENERAL

The New Notes are to be issued under an Indenture (the "Indenture") to be
dated as of May 16, 1996, among the Company and Fleet National Bank, as trustee
(the "Trustee"), in exchange for the Old Notes. No New Notes are currently
outstanding. The terms of the New Notes will include those stated in the
Indenture and those made part of the Indenture by reference to the Trust
Indenture Act of 1939, as amended (the "Trust Indenture Act"). The New Notes
will be subject to all such terms, and holders of Senior Notes are referred to
the Indenture and the Trust Indenture Act for a statement of such terms. A copy
of the proposed form of the Indenture is available upon request made to the
Company.

The following summary of certain provisions of the Indenture does not
purport to be complete and is subject to, and is qualified in its entirety by
reference to, all the provisions of the Indenture, including the definitions of
certain terms therein.

The Company has no sinking fund or mandatory redemption obligations with
respect to the Senior Notes.

The Company is subject to the informational reporting requirements of
Sections 13 and 15(d) under the Exchange Act and, in accordance therewith, will
file certain reports and other information with the Commission. See "Additional
Information." In addition, if Sections 13 and 15(d) cease to apply to the
Company, the Company will covenant in the Indenture to file such reports and
information with the Trustee and the Commission, and mail such reports and
information to holders of the Senior Notes at their registered addresses, for so
long as any Senior Notes remain outstanding.

The Company conducts substantially all of its operations through its
subsidiaries. Creditors of its subsidiaries, including trade creditors, would
have a claim on the subsidiaries' assets that would be prior to the claims of
the holders of the Senior Notes. See "Risk Factors -- Risks Related to Holding
Company Structure."

TERMS OF THE SENIOR NOTES

The Old Notes were issued under the Indenture. The Senior Notes are
obligations of the Company and not of Electrowatt or any other person. The
Senior Notes will mature on May 15, 2006. The Senior Notes are limited to
$180,000,000 in aggregate principal amount and are issued in fully registered
form in denominations of $1,000 and any amount which is an integral amount
multiple of $1,000 in excess thereof.

Interest at the annual rate of 10 1/2% is payable semi-annually on May 15
and November 15 of each year while the Senior Notes are outstanding, commencing
on November 15, 1996 (each, an "Interest Payment Date"), to holders of record at
the close of business on the preceding May 1 and November 1, respectively, and
unless other arrangements are made, will be paid by check mailed to such holders
at their registered addresses, as shown on the Senior Note register. Interest
will be computed on the basis of a year of twelve months of 30 days each.
Interest began to accrue on May 16, 1996. The interest rate on the Senior Notes
will be permanently increased by one-half of one percent per annum if the
Exchange Offer is not consummated, or a registration statement with respect to
the resale of the Senior Notes is not declared effective, by the 180th calendar
day following the initial sale of the Old Notes. See "-- Registration Rights."

Payments of principal of, and premium (if any) on the Senior Notes will be
made against presentation of the Senior Notes at or after the due date for such
payments, at an office maintained by the Trustee for such purpose at Shawmut
Trust Company of New York, 14 Wall Street, 8th Floor, Window 2, New York, New
York 10005, and the Senior Notes may be presented for registration of transfer
and exchange without service charge, at such office during normal business hours
on any day on which banks in the Borough of Manhattan, in the City of New York,
are open for business.

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<PAGE> 98

OPTIONAL REDEMPTION

Except as set forth in the following paragraph, the Company may not redeem
the Senior Notes prior to May 15, 2001. On and after such date, the Company may
redeem the Senior Notes at any time as a whole, or from time to time in part, at
the following redemption prices (expressed in percentages of principal amount),
plus accrued interest to the redemption date, if redeemed during the 12-month
period beginning May 15:

<TABLE>
<CAPTION>
REDEMPTION
YEAR PRICE
------------------------------------------------------ ----------
<S> <C>
2001.................................................. 105.250%
2002.................................................. 102.625%
2003 and thereafter................................... 100.000%
</TABLE>

The Company may redeem up to $63.0 million principal amount of Senior Notes
with the proceeds of one or more Public Equity Offerings following which there
is a Public Market, at any time as a whole or from time to time in part, at a
redemption price (expressed as a percentage of principal amount), plus accrued
interest to the redemption date, of 110.50% if redeemed at any time prior to May
15, 1999.

SELECTION FOR REDEMPTION

In the case of any partial redemption, selection of the Senior Notes for
redemption will be made by the Trustee on a pro rata basis, by lot or by such
other method that complies with applicable legal and securities exchange
requirements, if any, and that the Trustee in its sole discretion shall deem to
be fair and appropriate; provided, however, that no Senior Note of $1,000 in
original principal amount or less shall be redeemed in part. If any Senior Note
is to be redeemed in part only, the notice of redemption relating to such Senior
Note shall state the portion of the principal amount thereof to be redeemed. A
Senior Note in principal amount equal to the unredeemed portion thereof will be
issued in the name of the holder thereof upon cancellation of the original
Senior Note.

RANKING

The Indebtedness evidenced by the Senior Notes constitutes Senior
Indebtedness of the Company and will rank pari passu in right of payment with
all existing and future Senior Indebtedness of the Company, including, without
limitation, all obligations under the Bank Credit Agreement (as defined herein),
the Working Capital Credit Agreement (as defined herein) and the 9 1/4% Senior
Notes. At June 30, 1996, on a pro forma basis after giving effect to the Gilroy
Transaction, the Company would have had outstanding approximately $285.0 million
of Senior Indebtedness. The Company conducts substantially all of its operations
through its subsidiaries. Creditors of its subsidiaries, including trade
creditors, would have a claim on the subsidiaries' assets that would be prior to
the claims of the holders of the Senior Notes. As of June 30, 1996, on a pro
forma basis after giving effect to the Gilroy Transaction, the Company's
subsidiaries would have $324.2 million of debt (excluding trade debt)
outstanding. See "Risk Factors -- Risks Related to Holding Company Structure."

CERTAIN DEFINITIONS

Set forth below is a summary of certain defined terms used in the
Indentures.

"Acquired Indebtedness" means Indebtedness of a Person existing at the time
at which such Person became a Subsidiary and not incurred in connection with, or
in contemplation of, such Person becoming a Subsidiary. Acquired Indebtedness
shall be deemed to be Incurred on the date the acquired Person becomes a
Subsidiary.

"Additional Assets" means (i) any property or assets related to the Line of
Business which will be owned and used by the Company or a Restricted Subsidiary;
(ii) the Capital Stock of a Person that becomes a Restricted Subsidiary as a
result of the acquisition of such Capital Stock by the Company or another

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Restricted Subsidiary or (iii) Capital Stock constituting a minority interest in
any Person that at such time is a Restricted Subsidiary.

"Affiliate" of any specified Person means any other Person, directly or
indirectly, controlling or controlled by or under direct or indirect common
control with such specified Person. For the purposes of this definition,
"control" when used with respect to any Person means the power to direct the
management and policies of such Person, directly or indirectly, whether through
the ownership of voting securities, by contract or otherwise; and the terms
"controlling" and "controlled" have meanings correlative to the foregoing. For
purposes of the provisions described under "-- Covenants -- Transactions with
Affiliates" and "-- Sales of Assets" only, "Affiliate" shall also mean any
beneficial owner of 5% or more of the total Voting Shares (on a Fully Diluted
Basis) of the Company or of rights or warrants to purchase such stock (whether
or not currently exercisable) and any Person who would be an Affiliate of any
such beneficial owner pursuant to the first sentence hereof. For purposes of the
provision described under "-- Covenants -- Limitation on Restricted Payments"
only, "Affiliate" shall also mean any Person of which the Company owns 5% or
more of any class of Capital Stock or rights to acquire 5% or more or any class
of Capital Stock and any Person who would be an Affiliate of any such Person
pursuant to the first sentence hereof.

"Asset Sale" means any sale, transfer or other disposition (including by
way of merger, consolidation or sale leaseback transactions, but excluding
(except as provided for in the provisions described in the last paragraph under
"-- Covenants -- Sales of Assets") those permitted by the provisions described
under "-- Covenants -- Merger and Consolidation" and "-- Covenants -- Limitation
on Sale/Leaseback Transactions") in one or a series of transactions by the
Company or any Restricted Subsidiary to any Person other than the Company or any
Wholly Owned Subsidiary, of (i) all or any of the Capital Stock of the Company
or any Restricted Subsidiary, (ii) all or substantially all of the assets of any
operating unit, Facility, division or line of business of the Company or any
Restricted Subsidiary or (iii) any other property or assets or rights to acquire
property or assets of the Company or any Restricted Subsidiary outside of the
ordinary course of business of the Company or such Restricted Subsidiary.

"Attributable Debt" in respect of a Sale/Leaseback Transaction means, as at
the time of determination, the present value (discounted at the interest rate
borne by the Senior Notes, compounded annually) of the total obligations of the
lessee for rental payments during the remaining term of the lease included in
such Sale/Leaseback Transaction (including any period for which such lease has
been extended).

"Average Life" means, as of the date of determination, with respect to any
Indebtedness or Preferred Stock, the quotient obtained by dividing (i) the sum
of the products of (A) the numbers of years from the date of determination to
the dates of each successive scheduled principal payment of such Indebtedness or
scheduled redemption or similar payment with respect to such Indebtedness or
Preferred Stock multiplied by (B) the amount of such payment by (ii) the sum of
all such payments.

"Bank Credit Agreement" means the Promissory Grid Note, dated as of April
21, 1995, between the Company and Credit Suisse, New York Branch, as amended,
refinanced, renewed or extended from time to time.

"Board of Directors" means the Board of Directors of the Company or any
authorized committee thereof.

"Business Day" means each day which is not a Legal Holiday.

"Capital Stock" means any and all shares, interests, participations or
other equivalents (however designated) of capital stock of a corporation or any
and all equivalent ownership interests in a Person (other than a corporation).

"Capitalized Lease" means, as applied to any Person, any lease of any
property (whether real, personal or mixed) of which the discounted present value
of the rental obligations of such Person as lessee, in conformity with GAAP, is
required to be capitalized on the balance sheet of such Person; the Stated
Maturity thereof shall be the date of the last payment of rent or any other
amount due under such lease prior to the first date upon which such lease may be
terminated by the lessee without payment of a penalty; and "Capitalized Lease
Obligations" means the rental obligations, as aforesaid, under such lease.

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"Change of Control" means the occurrence of any of the following events:
(i) any "person" (as such term is used in Sections 13(d) and 14(d) of the
Exchange Act), other than Parent or an underwriter engaged in a firm commitment
underwriting on behalf of the Company, is or becomes the beneficial owner (as
such term is used in Rules 13d-3 and 13d-5 under the Exchange Act, except that
for purposes of this clause (i) a person shall be deemed to have beneficial
ownership of all shares that such person has the right to acquire, whether such
right is exercisable immediately or only after the passage of time), directly or
indirectly, of more than (x) at any time prior to the occurrence of a Public
Market, a greater percentage of the total Voting Shares of the Company than is
held by Parent and its Affiliates, and (y) at any time after the occurrence of a
Public Market, 40% of the total Voting Shares of the Company provided that such
ownership is greater than the total Voting Shares held by Parent and its
Affiliates; (ii) during any period of two consecutive years, individuals who at
the beginning of such period constituted the Board of Directors (together with
any new directors whose election by the Board of Directors or whose nomination
for election by the stockholders was approved by a vote of 66 2/3% of the
directors of the Company then still in office who were either directors at the
beginning of such period or whose election or nomination for election was
previously so approved) cease for any reason to constitute a majority of the
Board of Directors then in office; (iii) all or substantially all of the
Company's and its Restricted Subsidiaries' assets are sold, leased, exchanged or
otherwise transferred to any Person or group of Persons acting in concert; or
(iv) the Company is liquidated or dissolved or adopts a plan of liquidation.

"Change of Control Triggering Event" means (A) if a Rating Agency maintains
a rating of the Senior Notes at the time a Change of Control occurs, the
occurrence of a Change of Control and the occurrence of a Rating Decline or (B)
if no Rating Agency maintains a rating of the Senior Notes at the time a Change
of Control occurs, the occurrence of a Change of Control.

"Code" means the Internal Revenue Code of 1986, as amended.

"Company" means the party named as such in the Indenture until a successor
replaces it pursuant to the terms and conditions of the Indenture and thereafter
means the successor.

"Consolidated Coverage Ratio" as of any date of determination means the
ratio of (i) the aggregate amount of EBITDA for the period of the most recent
four consecutive fiscal quarters to (ii) the Consolidated Interest Expense
(excluding interest capitalized in connection with the construction of a new
Facility which interest is capitalized during the construction of such Facility)
for such four fiscal quarters; provided, however, that if the Company or any
Restricted Subsidiary has Incurred any Indebtedness since the beginning of such
period that remains outstanding or if the transaction giving rise to the need to
calculate the Consolidated Coverage Ratio is an Incurrence of Indebtedness, or
both, both EBITDA and Consolidated Interest Expense for such period shall be
calculated after giving effect on a pro forma basis to (x) such new Indebtedness
as if such Indebtedness had been Incurred on the first day of such period and
(y) the repayment, redemption, repurchase, defeasance or discharge of any
Indebtedness repaid, redeemed, repurchased, defeased or discharged with the
proceeds of such new Indebtedness as if such repayment, redemption, repurchase,
defeasance or discharge had been made on the first day of such period; provided,
further, that if within the period during which EBITDA or Consolidated Interest
Expense is measured, the Company or any of its Restricted Subsidiaries shall
have made any Asset Sales, (x) the EBITDA for such period shall be reduced by an
amount equal to the EBITDA (if positive) directly attributable to the assets or
Capital Stock which are the subject of such Asset Sales for such period, or
increased by an amount equal to the EBITDA (if negative), directly attributable
thereto for such period and (y) the Consolidated Interest Expense for such
period shall be reduced by an amount equal to the Consolidated Interest Expense
directly attributable to any Indebtedness for which neither Company nor any
Restricted Subsidiary shall continue to be liable as a result of any such Asset
Sale or repaid, redeemed, defeased, discharged or otherwise retired in
connection with or with the proceeds of the assets or Capital Stock which are
the subject of such Asset Sales for such period; and provided, further, that if
the Company or any Restricted Subsidiary shall have made any acquisition of
assets or Capital Stock (occurring by merger or otherwise) since the beginning
of such period (including any acquisition of assets or Capital Stock occurring
in connection with a transaction causing a calculation to be made hereunder) the
EBITDA and Consolidated Interest Expense for such period shall be calculated,
after giving pro forma effect thereto (and without regard to clause (iv) of the
proviso to the definition of "Consolidated Net Income"), as if such acquisition
of assets or Capital Stock took place on the first day of such period. For all
purposes of this

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definition, if the date of determination occurs prior to the completion of the
first four full fiscal quarters following the Issue Date, then "EBITDA" and
"Consolidated Interest Expense" shall be calculated after giving effect on a pro
forma basis to the Offering as if the Offering occurred on the first day of the
four full fiscal quarters that were completed preceding such date of
determination.

"Consolidated Current Liabilities," as of the date of determination, means
the aggregate amount of liabilities of the Company and its Consolidated
Restricted Subsidiaries which may properly be classified as current liabilities
(including taxes accrued as estimated), after eliminating (i) all inter-company
items between the Company and any Consolidated Subsidiary and (ii) all current
maturities of long-term Indebtedness, all as determined in accordance with GAAP.

"Consolidated Income Tax Expense" means, for any period, as applied to the
Company, the provision for local, state, federal or foreign income taxes on a
Consolidated basis for such period determined in accordance with GAAP.

"Consolidated Interest Expense" means, for any period, as applied to the
Company, the sum of (a) the total interest expense of the Company and its
Consolidated Restricted Subsidiaries for such period as determined in accordance
with GAAP, including, without limitation, (i) amortization of debt issuance
costs or of original issue discount on any Indebtedness and the interest portion
of any deferred payment obligation, calculated in accordance with the effective
interest method of accounting, (ii) accrued interest, (iii) noncash interest
payments, (iv) commissions, discounts and other fees and charges owed with
respect to letters of credit and bankers' acceptance financing, (v) interest
actually paid by the Company or any such Subsidiary under any guarantee of
Indebtedness or other obligation of any other Person and (vi) net costs
associated with Interest Rate Agreements (including amortization of discounts)
and Currency Agreements, plus (b) all but the principal component of rentals in
respect of Capitalized Lease Obligations paid, accrued, or scheduled to be paid
or accrued by the Company or its Consolidated Restricted Subsidiaries, plus (c)
one-third of all Operating Lease Obligations paid, accrued and/or scheduled to
be paid by the Company and its Consolidated Restricted Subsidiaries, plus (d)
capitalized interest, plus (e) dividends paid in respect of Preferred Stock of
the Company or any Restricted Subsidiary held by Persons other than the Company
or a Wholly Owned Subsidiary, plus (f) cash contributions to any employee stock
ownership plan to the extent such contributions are used by such employee stock
ownership plan to pay interest or fees to any person (other than the Company or
a Restricted Subsidiary) in connection with loans incurred by such employee
stock ownership plan to purchase Capital Stock of the Company.

"Consolidated Net Income (Loss)" means, for any period, as applied to the
Company, the Consolidated net income (loss) of the Company and its Consolidated
Restricted Subsidiaries for such period, determined in accordance with GAAP,
adjusted by excluding (without duplication), to the extent included in such net
income (loss), the following: (i) all extraordinary gains or losses; (ii) any
net income of any Person if such Person is not a Domestic Subsidiary, except
that (A) the Company's equity in the net income of any such Person for such
period shall be included in Consolidated Net Income (Loss) up to the aggregate
amount of cash actually distributed by such Person during such period to the
Company or a Restricted Subsidiary as a dividend or other distribution and (B)
the equity of the Company or a Restricted Subsidiary in a net loss of any such
Person for such period shall be included in determining Consolidated Net Income
(Loss); (iii) the net income of any Restricted Subsidiary to the extent that the
declaration or payment of dividends or similar distributions by such Restricted
Subsidiary of such income is not at the time thereof permitted, directly or
indirectly, by operation of the terms of its charter or bylaws or any agreement,
instrument, judgment, decree, order, statute, rule or governmental regulation
applicable to such Restricted Subsidiary or its stockholders; (iv) any net
income (or loss) of any Person combined with the Company or any of its
Restricted Subsidiaries on a "pooling of interests" basis attributable to any
period prior to the date of such combination; (v) any gain (but not loss)
realized upon the sale or other disposition of any property, plant or equipment
of the Company or its Restricted Subsidiaries (including pursuant to any
sale-and-leaseback arrangement) which is not sold or otherwise disposed of in
the ordinary course of business and any gain (but not loss) realized upon the
sale or other disposition by the Company or any Restricted Subsidiary of any
Capital Stock of any Person, provided that losses shall be included on an
after-tax basis; and (vi) the cumulative effect of a change in accounting
principles; and further adjusted by subtracting from such net income the tax
liability of any parent of the

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Company to the extent of payments made to such parent by the Company pursuant to
any tax sharing agreement or other arrangement for such period.

"Consolidated Net Tangible Assets" means, as of any date of determination,
as applied to the Company, the total amount of assets (less accumulated
depreciation or amortization, allowances for doubtful receivables, other
applicable reserves and other properly deductible items) which would appear on a
Consolidated balance sheet of the Company and its Consolidated Restricted
Subsidiaries, determined on a Consolidated basis in accordance with GAAP, and
after giving effect to purchase accounting and after deducting therefrom, to the
extent otherwise included, the amounts of: (i) Consolidated Current Liabilities;
(ii) minority interests in Consolidated Subsidiaries held by Persons other than
the Company or a Restricted Subsidiary; (iii) excess of cost over fair value of
assets of businesses acquired, as determined in good faith by the Board of
Directors; (iv) any revaluation or other write-up in value of assets subsequent
to December 31, 1993 as a result of a change in the method of valuation in
accordance with GAAP; (v) unamortized debt discount and expenses and other
unamortized deferred charges, goodwill, patents, trademarks, service marks,
trade names, copyrights, licenses, organization or developmental expenses and
other intangible items; (vi) treasury stock; and (vii) any cash set apart and
held in a sinking or other analogous fund established for the purpose of
redemption or other retirement of Capital Stock to the extent such obligation is
not reflected in Consolidated Current Liabilities.

"Consolidated Net Worth" means, at any date of determination, as applied to
the Company, stockholders' equity as set forth on the most recently available
Consolidated balance sheet of the Company and its Consolidated Restricted
Subsidiaries (which shall be as of a date no more than 60 days prior to the date
of such computation), less any amounts attributable to Redeemable Stock or
Exchangeable Stock, the cost of treasury stock and the principal amount of any
promissory notes receivable from the sale of Capital Stock of the Company or any
Subsidiary.

"Consolidation" means, with respect to any Person, the consolidation of
accounts of such Person and each of its subsidiaries if and to the extent the
accounts of such Person and such subsidiaries are consolidated in accordance
with GAAP. The term "Consolidated" shall have a correlative meaning.

"Controlled Non-Subsidiary Investment" means any Investment of the type
specified in clause (iv) of the first sentence under
"-- Covenants -- Limitations on Restricted Payments" which is made by the
Company or its Restricted Subsidiaries in an Affiliate other than a Subsidiary;
provided that (i) at the time such Investment is made, no Default or Event of
Default shall have occurred and be continuing (or would result therefrom); (ii)
after giving effect to the Investment and to the Incurrence of any Indebtedness
in connection therewith on a pro forma basis, the Consolidated Coverage Ratio is
at least 1.75:1; (iii) after giving effect to the Investment, the aggregate
Investment made by the Company and its Subsidiaries in Controlled Non-Subsidiary
Investments does not exceed $100,000,000; (iv) the Person in which the
Investment is made is engaged only in the business described under
"-- Covenants -- Limitation on Changes in the Nature of Business" including
Unrelated Businesses to the extent permitted under "-- Covenants -- Limitations
on Changes in the Nature of the Business"; (v) the Company, directly or through
its Restricted Subsidiaries is entitled to (A) in the case of an Investment in
Capital Stock, receive dividends or other distributions on its Investment at the
same time as or prior to, and on a basis pro rata with, any other holder or
holders of Capital Stock of such Person and (B) in the case of an Investment
other than in Capital Stock, receive interest thereon at a rate per annum not
less than the rate on the Senior Notes and, on the liquidation or dissolution of
such Person, receive repayment of the principal thereof prior to the payment of
any dividends or distributions on Capital Stock of such Person; (vi) the Company
directly or through its Restricted Subsidiaries, either (x) controls, under an
operating and management agreement or otherwise, the day to day management and
operation of such Person and any Facility of the Person in which the Investment
is made or (y) has significant influence over the management and operation of
such Person and any Facility of such Person in all material respects
(significant influence to include the right to control or veto any material act
or decision) in connection with such management or operation; and (vii) any
encumbrances or restrictions on the ability of the Person in which the
Investment is made to make the payments, distributions, losses, advances or
transfers referred to in clauses (i) through (iii) under
"-- Covenants -- Limitations on Payment Restrictions Affecting Subsidiaries" in
the written opinion of the President or Chief Financial Officer of the Company
(x) is required

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in order to obtain necessary financing, (y) is customary for such financings and
(z) applies only to the assets of or revenues of the Person in whom the
Investment is made.

"Currency Agreement" means any foreign exchange contract, currency swap
agreement or other similar agreement or arrangement designed to protect the
Company or any Restricted Subsidiary against fluctuations in currency values to
or under which the Company or any Restricted Subsidiary is a party or a
beneficiary on the Issue Date or becomes a party or beneficiary thereafter.

"Default" means any event which is, or after notice or passage of time or
both would be, an Event of Default.

"defaulted interest" means any interest on any Senior Note which is
payable, but is not punctually paid or duly provided for on any Interest Payment
Date.

"Domestic Subsidiary" means a Restricted Subsidiary that is not a Foreign
Subsidiary.

"EBITDA" means, for any period, as applied to the Company, the sum of
Consolidated Net Income (Loss) (but without giving effect to adjustments,
accruals, deductions or entries resulting from purchase accounting,
extraordinary losses or gains and any gains or losses from any Asset Sales),
plus the following to the extent included in calculating Consolidated Net Income
(Loss): (a) Consolidated Income Tax Expense, (b) Consolidated Interest Expense,
(c) depreciation expense, (d) amortization expense and (e) all other non-cash
items reducing Consolidated Net Income, less all non-cash items increasing
Consolidated Net Income, in each case for such period; provided that, if the
Company has any Subsidiary that is not a Wholly Owned Subsidiary, EBITDA shall
be reduced (to the extent not otherwise reduced by GAAP) by an amount equal to
(A) the consolidated net income (loss) of such Subsidiary (to the extent
included in Consolidated Net Income (Loss)) multiplied by (B) the quotient of
(1) the number of shares of outstanding common stock of such Subsidiary not
owned on the last day of such period by the Company or any Wholly Owned
Subsidiary of the Company divided by (2) the total number of shares of
outstanding common stock of such Subsidiary on the last day of such period.

"Exchangeable Stock" means any Capital Stock which by its terms is
exchangeable or convertible at the option of any Person other than the Company
into another security (other than Capital Stock of the Company which is neither
Exchangeable Stock nor Redeemable Stock).

"Existing Agreements" means the Management Services Agreement, dated
January 1, 1992 between the Company and Parent, and the Guarantee Fee Agreement,
dated January 1, 1992 between the Company and Parent, in each case as in effect
on the date of the Indenture.

"Facility" means a power generation facility or energy producing facility,
including any related steam fields or gas reserves.

"Foreign Asset Sale" means an Asset Sale in respect of the Capital Stock or
assets of a Foreign Subsidiary or a Restricted Subsidiary of the type described
in Section 936 of the Code to the extent that the proceeds of such Asset Sale
are received by a Person subject in respect of such proceeds to the tax laws of
a jurisdiction other than the United States of America or any State thereof or
the District of Columbia.

"Foreign Subsidiary" means a Restricted Subsidiary that is incorporated in
a jurisdiction other than the United States of America or a State thereof or the
District of Columbia.

"Fully Diluted Basis" means after giving effect to the exercise of any
outstanding options, warrants or rights to purchase Voting Shares and the
conversion or exchange of any securities convertible into or exchangeable for
Voting Shares.

"GAAP" means generally accepted accounting principles in the United States
of America as in effect and, to the extent optional, adopted by the Company on
the Issue Date, consistently applied, including, without limitation, those set
forth in the opinions and pronouncements of the Accounting Principles Board of
the American Institute of Certified Public Accountants and statements and
pronouncements of the Financial Accounting Standards Board.

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"guarantee" means, as applied to any obligation, contingent or otherwise,
of any Person, (i) a guarantee, direct or indirect, in any manner, of any part
or all of such obligation (other than by endorsement of negotiable instruments
for collection in the ordinary course of business) and (ii) an agreement, direct
or indirect, contingent or otherwise, the practical effect of which is to insure
in any way the payment or performance (or payment of damages in the event of
nonperformance) of any part or all of such obligation, including the payment of
amounts drawn down under letters of credit.

"Holder" or "Securityholder" means the Person in whose name a Senior Note
is registered on the Registrar's books.

"Incur" means, as applied to any obligation, to create, incur, issue,
assume, guarantee or in any other manner become liable with respect to,
contingently or otherwise, such obligation, and "Incurred," "Incurrence" and
"Incurring" shall each have a correlative meaning; provided, however, that any
Indebtedness or Capital Stock of a Person existing at the time such Person
becomes (after the Issue Date) a Subsidiary (whether by merger, consolidation,
acquisition or otherwise) shall be deemed to be Incurred by such Subsidiary at
the time it becomes a Subsidiary; and provided, further, that any amendment,
modification or waiver of any provision of any document pursuant to which
Indebtedness was previously Incurred shall not be deemed to be an Incurrence of
Indebtedness as long as (i) such amendment, modification or waiver does not (A)
increase the principal or premium thereof or interest rate thereon, (B) change
to an earlier date the Stated Maturity thereof or the date of any scheduled or
required principal payment thereon or the time or circumstances under which such
Indebtedness may or shall be redeemed, (C) if such Indebtedness is contractually
subordinated in right of payment to the Securities, modify or affect, in any
manner adverse to the Holders, such subordination, (D) if the Company is the
obligor thereon, provide that a Restricted Subsidiary shall be an obligor, (E)
if such Indebtedness is Non-Recourse Debt, cause such Indebtedness to no longer
constitute Non-Recourse Debt or (F) violate, or cause the Indebtedness to
violate, the provisions described under "-- Covenants -- Limitation on Payment
Restrictions Affecting Subsidiaries" and "-- Limitation on Liens" and (ii) such
Indebtedness would, after giving effect to such amendment, modification or
waiver as if it were an Incurrence, comply with clause (i) of the first proviso
to the definition of "Refinancing Indebtedness."

"Indebtedness" of any Person means, without duplication, (i) the principal
of and premium (if any such premium is then due and owing) in respect of (A)
indebtedness of such Person for money borrowed and (B) indebtedness evidenced by
notes, debentures, bonds or other similar instruments for the payment of which
such Person is responsible or liable; (ii) all Capitalized Lease Obligations of
such Person; (iii) all obligations of such Person Incurred as the deferred
purchase price of property, all conditional sale obligations of such Person and
all obligations of such Person under any title retention agreement; (iv) all
obligations of such Person for the reimbursement of any obligor on any letter of
credit, banker's acceptance or similar credit transaction (other than
obligations with respect to letters of credit securing obligations (other than
obligations described in (i) through (iii) above) entered into in the ordinary
course of business of such Person to the extent such letters of credit are not
drawn upon or, if and to the extent drawn upon, such drawing is reimbursed no
later than the tenth Business Day following receipt by such Person of a demand
for reimbursement following payment on the letter of credit); (v) Redeemable
Stock of such Person and, in the case of any Subsidiary, any other Preferred
Stock, in either case valued at, in the case of Redeemable Stock, the greater of
its voluntary or involuntary maximum fixed repurchase price exclusive of accrued
and unpaid dividends or, in the case of Preferred Stock that is not Redeemable
Stock, its liquidation preference exclusive of accrued and unpaid dividends;
(vi) contractual obligations to repurchase goods sold or distributed; (vii) all
obligations of such Person in respect of Interest Rate Agreements and Currency
Agreements; (viii) all obligations of the type referred to in clauses (i)
through (vii) of other Persons and all dividends of other Persons for the
payment of which, in either case, such Person is responsible or liable, directly
or indirectly, as obligor, guarantor or otherwise, including by means of any
guarantee; and (ix) all obligations of the type referred to in clauses (i)
through (viii) of other Persons secured by any Lien on any property or asset of
such Person (whether or not such obligation is assumed by such Person), the
amount of such obligation being deemed to be the lesser of the value of such
property or assets or the amount of the obligation so secured; provided,
however, that Indebtedness shall not include trade accounts payable arising in
the ordinary course of

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business. For purposes hereof, the "maximum fixed repurchase price" of any
Redeemable Stock which does not have a fixed repurchase price shall be
calculated in accordance with the terms of such Redeemable Stock as if such
Redeemable Stock were purchased on any date on which Indebtedness shall be
required to be determined pursuant to the Indenture, and if such price is based
upon, or measured by, the fair market value of such Redeemable Stock, such fair
market value to be determined in good faith by the Board of Directors. The
amount of Indebtedness of any Person at any date shall be, with respect to
unconditional obligations, the outstanding balance at such date of all such
obligations as described above and, with respect to any contingent obligations
(other than pursuant to clause (vi) above, which shall be included to the extent
reflected on the balance sheet of such Person in accordance with GAAP) at such
date, the maximum liability determined by such Person's board of directors, in
good faith, as, in light of the facts and circumstances existing at the time,
reasonably likely to be Incurred upon the occurrence of the contingency giving
rise to such obligation.

"Interest Payment Date" means the stated maturity of an installment of
interest on the Senior Notes.

"Interest Rate Agreement" means any interest rate protection agreement,
interest rate future agreement, interest rate option agreement, interest rate
swap agreement, interest rate cap agreement, interest rate collar agreement,
interest rate hedge agreement or other similar agreement or arrangement designed
to protect against fluctuations in interest rates to or under which the Company
or any of its Restricted Subsidiaries is a party or beneficiary on the Issue
Date or becomes a party or beneficiary thereunder.

"Investment" means, with respect to any Person, any direct or indirect
advance, loan or other extension of credit or capital contribution to (by means
of any transfer of cash or other property to others or any payment for property
or services for the account or use of others), or any other investment in any
other Person, or any purchase or acquisition by such Person of any Capital
Stock, bonds, notes, debentures or other securities or assets issued or owned by
any other Person (whether by merger, consolidation, amalgamation, sale of assets
or otherwise). For purposes of the definition of "Unrestricted Subsidiary" and
the provisions set forth under "-- Covenants -- Limitation on Restricted
Payments", (i) "Investment" shall include the portion (proportionate to the
Company's equity interest in such Subsidiary) of the fair market value of the
net assets of any Restricted Subsidiary at the time that such Restricted
Subsidiary is designated an Unrestricted Subsidiary and shall exclude the fair
market value of the net assets of any Unrestricted Subsidiary at the time that
such Unrestricted Subsidiary is designated a Restricted Subsidiary and (ii) any
property transferred to or from an Unrestricted Subsidiary shall be valued at
its fair market value at the time of such transfer, in each case as determined
by the Board of Directors in good faith. For purposes of determining the
aggregate amount of Investments in Controlled Non-Subsidiary Investments, the
amount of such Investments shall be reduced by an amount equal to the net
payments of interest on Indebtedness, dividends, repayments of interest on
Indebtedness, dividends, repayments of loans or advances, or other transfers of
assets, in each case to the Company or any Restricted Subsidiary from any Person
in whom a Controlled Non-Subsidiary Investment has been made, not to exceed in
the case of any Controlled Non-Subsidiary Investment the amount of Investments
previously made by the Company or any Restricted Subsidiary in such Person.

"Investment Grade" means, with respect to the Senior Notes, a rating of
Baa3 or higher by Moody's together with a rating of BBB- or higher by S&P,
provided that neither of such entities shall have announced or informed the
Company that it is reviewing the rating of the Senior Notes in light of
downgrading the rating thereof.

"Issue Date" means the date on which the Senior Notes are originally issued
under the Indenture.

"Lien" means any mortgage, lien, pledge, charge, or other security interest
or encumbrance of any kind (including any conditional sale or other title
retention agreement and any lease in the nature thereof).

"Line of Business" means the ownership, acquisition, development,
construction, improvement and operation of Facilities.

"Moody's" means Moody's Investors Service, Inc. and its successors.

"Net Available Cash" means, with respect to any Asset Sale, the cash or
cash equivalent payments received by the Company or a Subsidiary in connection
with such Asset Sale (including any cash received by

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way of deferred payment of principal pursuant to a note or installment
receivable or otherwise, but only as or when received and also including the
proceeds of other property received when converted to cash or cash equivalents)
net of the sum of, without duplication, (i) all reasonable legal, title and
recording tax expenses, reasonable commissions, and other reasonable fees and
expenses incurred directly relating to such Asset Sale, (ii) all local, state,
federal and foreign taxes required to be paid or accrued as a liability by the
Company or any of its Restricted Subsidiaries as a consequence of such Asset
Sale, (iii) payments made to repay Indebtedness which is secured by any assets
subject to such Asset Sale in accordance with the terms of any Lien upon or
other security agreement of any kind with respect to such assets, or which must
by its terms, or by applicable law, be repaid out of the proceeds from such
Asset Sale and (iv) all distributions required by any contract entered into
other than in contemplation of such Asset Sale to be paid to any holder of a
minority equity interest in such Restricted Subsidiary as a result of such Asset
Sale, so long as such distributions do not exceed such minority holder's pro
rata portion (based on such minority holder's proportionate equity interest) of
the cash or cash equivalent payments described above, net of the amounts set
forth in clauses (i)-(iii) above.

"Net Cash Proceeds" means, with respect to any issuance or sale of Capital
Stock by any Person, the cash proceeds to such Person of such issuance or sale
net of attorneys' fees, accountants' fees, underwriters' or placement agents'
fees, discounts or commissions and brokerage, consultancy and other fees
actually incurred by such Person in connection with such issuance or sale and
net of taxes paid or payable by such Person as a result thereof.

"Non-Convertible Capital Stock" means, with respect to any corporation, any
Capital Stock of such corporation which is not convertible into another security
other than non-convertible common stock of such corporation; provided, however,
that Non-Convertible Capital Stock shall not include any Redeemable Stock or
Exchangeable Stock.

"Non-Recourse Debt" means Indebtedness of the Company or any Restricted
Subsidiary that is Incurred to acquire, construct or develop a Facility provided
that such Indebtedness is without recourse to the Company or any Restricted
Subsidiary or to any assets of the Company or any such Restricted Subsidiary
other than such Facility and the income from and proceeds of such Facility.

"Offering" means the public offering and sale of the Senior Notes.

"Officers' Certificate" means a certificate signed by two officers, one of
whom must be the President, the Treasurer or a Vice President of the Company.
Each Officers' Certificate (other than certificates provided pursuant to TIA
Section 314(a)(4)) shall include the statements provided for in TIA Section
314(e).

"Operating Lease Obligations" means any obligation of the Company and its
Restricted Subsidiaries on a Consolidated basis incurred or assumed under or in
connection with any lease of real or personal property which, in accordance with
GAAP, is not required to be classified and accounted for as a capital lease.

"Opinion of Counsel" means a written opinion from legal counsel who is
acceptable to the Trustee. The counsel, if so acceptable, may be an employee of
or counsel to the Company or the Trustee. Each such Opinion of Counsel shall
include the statements provided for in TIA Section 314(e).

"Parent" means Electrowatt Ltd, a Swiss corporation, and any subsidiary
thereof holding Voting Shares of the Company.

"Person" means any individual, corporation, partnership, joint venture,
association, joint-stock company, trust, unincorporated organization, government
or any agency or political subdivision thereof or any other entity.

"Preferred Stock", as applied to the Capital Stock of any corporation,
means Capital Stock of any class or classes (however designated) which is
preferred as to the payment of dividends, or as to the distribution of assets
upon any voluntary or involuntary liquidation or dissolution of such
corporation, over shares of Capital Stock of any other class of such
corporation.

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"principal" of a Senior Note means the principal of the Senior Note plus,
if applicable, the premium on the Senior Note.

"Public Equity Offering" means an underwritten primary public offering of
equity securities of the Company pursuant to an effective registration statement
under the Securities Act.

"Public Market" shall be deemed to have occurred if (x) a Public Equity
Offering has been consummated and (y) at least 25% (for purposes of the
definition of "Change of Control") or 15% (for purposes of the provisions
described under "-- Optional Redemption") of the total issued and outstanding
common stock of the Company has been distributed by means of an effective
registration statement under the Securities Act or sales pursuant to Rule 144
under the Securities Act.

"PUHCA" means the Public Utility Holding Company Act of 1935, as amended.

"PURPA" means the Public Utility Regulatory Policies Act of 1978, as
amended.

"Rating Agencies" is defined to mean S&P and Moody's.

"Rating Category" is defined to mean (i) with respect to S&P, any of the
following categories: AAA, AA, A, BBB, BB, B, CCC, CC, C and D (or equivalent
successor categories) and (ii) with respect to Moody's, any of the following
categories: Aaa, Aa, A, Baa, Ba, B, Caa, Ca, C and D (or equivalent successor
categories). In determining whether the rating of the Senior Notes has decreased
by one or more gradations, gradations within Rating Categories (+ and - for S&P;
1, 2 and 3 for Moody's) shall be taken into account (e.g., with respect to S&P,
a decline in a rating from BB+ to BB, as well as from BB- to B+, will constitute
a decrease of one gradation).

"Rating Decline" is defined to mean the occurrence of (i) or (ii) below on,
or within 90 days after, the earliest of (A) the Company having become aware
that a Change of Control has occurred, (B) the date of public notice of the
occurrence of a Change of Control or (C) the date of public notice of the
intention by Parent or the Company to approve, recommend or enter into, any
transaction which, if consummated, would result in a Change of Control (which
period shall be extended so long as the rating of the Senior Notes is under
publicly announced consideration or possible downgrade by either of the Rating
Agencies), (i) a decrease of the rating of the Senior Notes by either Rating
Agency by one or more rating gradations or (ii) the Company shall fail to
promptly advise the Rating Agencies, in writing, of such occurrence or any
subsequent material developments or shall fail to use its best efforts to
obtain, from at least one Rating Agency, a written, publicly announced
affirmation of its rating of the Senior Notes, stating that it is not
downgrading, and is not considering downgrading, the Senior Notes.

"Redeemable Stock" means any class or series of Capital Stock of any Person
that (a) by its terms, by the terms of any security into which it is convertible
or exchangeable or otherwise is, or upon the happening of an event or passage of
time would be, required to be redeemed (in whole or in part) on or prior to the
first anniversary of the Stated Maturity of the Senior Notes, (b) is redeemable
at the option of the holder thereof at any time on or prior to the first
anniversary of the Stated Maturity of the Senior Notes (other than on a Change
of Control or Asset Sale, provided that such Change of Control or Asset Sale
shall not yet have occurred) or (c) is convertible into or exchangeable for
Capital Stock referred to in clause (a) or clause (b) above or debt securities
at any time prior to the first anniversary of the Stated Maturity of the Senior
Notes.

"Refinancing Indebtedness" means Indebtedness that refunds, refinances,
replaces, renews, repays or extends (including pursuant to any defeasance or
discharge mechanism) (collectively, "refinances," and "refinanced" shall have a
correlative meaning) any Indebtedness of the Company or a Restricted Subsidiary
existing on the Issue Date or Incurred in compliance with the Indenture
(including Indebtedness of the Company that refinances Indebtedness of any
Restricted Subsidiary and Indebtedness of any Restricted Subsidiary that
refinances Indebtedness of another Restricted Subsidiary) including Indebtedness
that refinances Refinancing Indebtedness; provided, however, that (i) if the
Indebtedness being refinanced is contractually subordinated in right of payment
to the Senior Notes, the Refinancing Indebtedness shall be contractually
subordinated in right of payment to the Senior Notes to at least the same extent
as the

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Indebtedness being refinanced, (ii) if the Indebtedness being refinanced is
Non-Recourse Debt, such Refinancing Indebtedness shall be Non-Recourse Debt,
(iii) the Refinancing Indebtedness is scheduled to mature either (a) no earlier
than the Indebtedness being refinanced or (b) after the Stated Maturity of the
Senior Notes, (iv) the Refinancing Indebtedness has an Average Life at the time
such Refinancing Indebtedness is Incurred that is equal to or greater than the
Average Life of the Indebtedness being refinanced and (v) such Refinancing
Indebtedness is in an aggregate principal amount (or if issued with original
issue discount, an aggregate issue price) that is equal to or less than the
aggregate principal amount (or if issued with original issue discount, the
aggregate accreted value) then outstanding (plus fees and expenses, including
any premium, swap breakage and defeasance costs) under the Indebtedness being
refinanced; and provided, further, that Refinancing Indebtedness shall not
include (x) Indebtedness of a Subsidiary of the Company that refinances
Indebtedness of the Company or (y) Indebtedness of the Company or a Restricted
Subsidiary that refinances Indebtedness of an Unrestricted Subsidiary.

"Related Assets" means electric power plants that, on the Issue Date,
produce electricity solely by utilizing steam from steam fields owned and
operated by a Restricted Subsidiary that is a Wholly Owned Subsidiary on the
Issue Date.

"Related Asset Indebtedness" means Non-Recourse Debt of a Restricted
Subsidiary that is a Wholly Owned Subsidiary on the Issue Date, the proceeds of
which are used by such Restricted Subsidiary to finance the acquisition of
Related Assets by such Restricted Subsidiary; provided, however, that (i) such
Related Asset Indebtedness is Incurred contemporaneously with a Refinancing of
all of the Non-Recourse Debt of such Restricted Subsidiary then outstanding and
(ii) the principal amount of such Related Asset Indebtedness shall not exceed
the purchase price of the Related Assets plus reasonable out-of-pocket
transaction costs and expenses of the Company and its Restricted Subsidiaries
required to acquire, or finance the acquisition of, such Related Assets.

"Restricted Subsidiary" means any Subsidiary of the Company that is not
designated an Unrestricted Subsidiary by the Board of Directors.

"S&P" means Standard and Poor's Corporation and its successors.

"Sale/Leaseback Transaction" means an arrangement relating to property now
owned or hereafter acquired whereby the Company or a Subsidiary transfers such
property to a Person and leases it back from such Person, other than leases for
a term of not more than 36 months or between the Company and a Wholly Owned
Subsidiary or between Wholly Owned Subsidiaries.

"Senior Indebtedness" means (i) all obligations consisting of the principal
of and premium, if any, and accrued and unpaid interest (including interest
accruing on or after the filing of any petition in bankruptcy or for
reorganization relating to the Company whether or not post-filing interest is
allowed in such proceeding), whether existing on the Issue Date or thereafter
Incurred, in respect of (A) Indebtedness of the Company for money borrowed and
(B) Indebtedness evidenced by notes, debentures, bonds or other similar
instruments for the payment of which the Company is responsible or liable; (ii)
all Capitalized Lease Obligations of the Company; (iii) all obligations of the
Company (A) for the reimbursement of any obligor on any letter of credit,
banker's acceptance or similar credit transaction, (B) under Interest Rate
Agreements and Currency Agreements entered into in respect of any obligations
described in clauses (i) and (ii) or (C) issued or assumed as the deferred
purchase price of property, and all conditional sale obligations of the Company
and all obligations of the Company under any title retention agreement; (iv) all
guarantees of the Company with respect to obligations of other persons of the
type referred to in clauses (ii) and (iii) and with respect to the payment of
dividends of other Persons; and (v) all obligations of the Company consisting of
modifications, renewals, extensions, replacements and refundings of any
obligations described in clauses (i), (ii), (iii) or (iv); unless, in the
instrument creating or evidencing the same or pursuant to which the same is
outstanding, it is provided that such obligations are subordinated in right of
payment to the Senior Notes, or any other Indebtedness or obligation of the
Company; provided, however, that Senior Indebtedness shall not be deemed to
include (1) any obligation of the Company to any Subsidiary, (2) any liability
for Federal, state, local or other taxes or (3) any accounts payable or other
liability to trade creditors arising in the ordinary course of business
(including guarantees thereof or instruments evidencing such liabilities).

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"Significant Subsidiary" means any Subsidiary (other than an Unrestricted
Subsidiary) that would be a "Significant Subsidiary" of the Company within the
meaning of Rule 1-02 under Regulations S-X promulgated by the SEC.

"Stated Maturity" means, with respect to any security, the date specified
in such security as the fixed date on which the principal of such security is
due and payable, including pursuant to any mandatory redemption provision (but
excluding any provision providing for the repurchase of such security at the
option of the holder thereof upon the happening of any contingency).

"Subordinated Indebtedness" means any Indebtedness of the Company (whether
outstanding on the Issue Date or thereafter Incurred) which is contractually
subordinated or junior in right of payment to the Senior Notes or any other
Indebtedness of the Company.

"Subsidiary" means, as applied to any Person, any corporation, limited or
general partnership, trust, association or other business entity of which an
aggregate of at least a majority of the outstanding Voting Shares or an
equivalent controlling interest therein, of such Person is, at the time,
directly or indirectly, owned by such Person and/or one or more Subsidiaries of
such Person.

"Unrelated Business" means any business other than the Line of Business.

"Unrestricted Subsidiary" means (i) any Subsidiary that at the time of
determination shall be designated an Unrestricted Subsidiary by the Board of
Directors in the manner provided below and (ii) any subsidiary of an
Unrestricted Subsidiary. The Board of Directors may designate any Subsidiary
(including any newly acquired or newly formed Subsidiary) to be an Unrestricted
Subsidiary unless such Subsidiary owns any Capital Stock of, or owns or holds
any Lien on any property of, the Company or any other Subsidiary that is not a
Subsidiary of the Subsidiary to be so designated; provided, that either (A) the
Subsidiary to be so designated has total assets of $1,000 or less or (B) if such
Subsidiary has assets greater than $1,000, that such designation would be
permitted pursuant to the provisions under "Covenants -- Limitation on
Restricted Payments". The Board of Directors may designate any Unrestricted
Subsidiary to be a Restricted Subsidiary of the Company; provided, however, that
immediately after giving effect to such designation (x) the Company could Incur
$1.00 of additional Indebtedness pursuant to the first paragraph of
"Covenants -- Limitation on Incurrence of Indebtedness" and (y) no Default or
Event of Default shall have occurred and be continuing. Any such designation by
the Board of Directors shall be evidenced to the Trustee by promptly filing with
the Trustee a copy of the board resolution giving effect to such designation and
an Officers' Certificate certifying that such designation complied with the
foregoing provisions; provided, however, that the failure to so file such
resolution and/or Officers' Certificate with the Trustee shall not impair or
affect the validity of such designation.

"U.S. Government Obligations" means securities that are (i) direct
obligations of the United States of America for the payment of which its full
faith and credit is pledged or (ii) obligations of a Person controlled or
supervised by and acting as an agency or instrumentality of the United States of
America the payment of which is unconditionally guaranteed as a full faith and
credit obligation by the United States of America, which, in either case under
clauses (i) or (ii) are not callable or redeemable before the maturity thereof.

"Voting Shares", with respect to any corporation, means the Capital Stock
having the general voting power under ordinary circumstances to elect at least a
majority of the board of directors (irrespective of whether or not at the time
stock of any other class or classes shall have or might have voting power by
reason of the happening of any contingency).

"Wholly Owned Subsidiary" means a Subsidiary (other than an Unrestricted
Subsidiary) all the Capital Stock of which (other than directors' qualifying
shares) is owned by the Company or another Wholly Owned Subsidiary.

"Working Capital Credit Agreement" means the Line of Credit Note, dated as
of June 4, 1993, between the Company and The Bank of California, N.A. as
amended, refinanced, renewed or extended from time to time.

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COVENANTS

The Indenture contains covenants including, among others, the following:

Limitation on Restricted Payments. Under the terms of the Indenture, so
long as any of the Senior Notes are outstanding, the Company shall not, and
shall not permit any Restricted Subsidiary to, directly or indirectly, (i)
declare or pay any dividend on or make any distribution or similar payment of
any sort in respect of its Capital Stock (including any payment in connection
with any merger or consolidation involving the Company) to the direct or
indirect holders of its Capital Stock (other than dividends or distributions
payable solely in its Non-Convertible Capital Stock or rights to acquire its
Non-Convertible Capital Stock and dividends or distributions payable solely to
the Company or a Restricted Subsidiary and other than pro rata dividends paid by
a Subsidiary with respect to a series or class of its Capital Stock the majority
of which is held by the Company or a Wholly Owned Subsidiary that is not a
Foreign Subsidiary), (ii) purchase, redeem, defease or otherwise acquire or
retire for value any Capital Stock of the Company or of any direct or indirect
parent of the Company, or, with respect to the Company, exercise any option to
exchange any Capital Stock that by its terms is exchangeable solely at the
option of the Company (other than into Capital Stock of the Company which is
neither Exchangeable Stock nor Redeemable Stock), (iii) purchase, repurchase,
redeem, defease or otherwise acquire or retire for value, prior to scheduled
maturity or scheduled repayment thereof or scheduled sinking fund payment
thereon, any Subordinated Indebtedness (other than the purchase, repurchase or
other acquisition of Subordinated Indebtedness purchased in anticipation of
satisfying a sinking fund obligation, principal installment or final maturity,
in each case due within one year of the date of acquisition) or (iv) make any
Investment, other than a Controlled Non-Subsidiary Investment, or a payment
described in clause (vi) of the second sentence under
"-- Covenants -- Transactions with Affiliates," in any Unrestricted Subsidiary
or any Affiliate of the Company other than a Restricted Subsidiary or a Person
which will become a Restricted Subsidiary as a result of any such Investment
(each such payment described in clauses (i)-(iv) of this paragraph, a
"Restricted Payment"), unless at the time of and after giving effect to the
proposed Restricted Payment: (1) no Default or Event of Default shall have
occurred and be continuing (or would result therefrom); (2) the Company would be
permitted to Incur an additional $1 of Indebtedness pursuant to the provisions
described in the first paragraph under "-- Limitation on Incurrence of
Indebtedness," and (3) the aggregate amount of all such Restricted Payments
subsequent to the Issue Date shall not exceed the sum of (A) 50% of aggregate
Consolidated Net Income accrued during the period (treated as one accounting
period) from January 1, 1994 to the end of the most recent fiscal quarter for
which financial statements are available (or if such Consolidated Net Income is
a deficit, minus 100% of such deficit), and minus 100% of the amount of any
write-downs, write-offs, other negative reevaluations and other negative
extraordinary charges not otherwise reflected in Consolidated Net Income during
such period; (B) if the Senior Notes are Investment Grade immediately following
the Restricted Payment in connection with which this calculation is made, an
additional 25% of Consolidated Net Income for any period of one or more
consecutive completed fiscal quarters ending with the last fiscal quarter
completed prior to the date of such Restricted Payment during which the Senior
Notes were Investment Grade for the entire period; (C) the aggregate Net Cash
Proceeds received by the Company after January 1, 1994 from the sale of Capital
Stock (other than Redeemable Stock or Exchangeable Stock) of the Company to any
person other than the Company, any of its Subsidiaries or an employee stock
ownership plan; (D) the amount by which the principal amount of, and any accrued
interest on, Indebtedness of the Company or its Restricted Subsidiaries is
reduced on the Company's Consolidated balance sheet upon the conversion or
exchange (other than by a Subsidiary) subsequent to the Issue Date of any
Indebtedness of the Company or any Restricted Subsidiary converted or exchanged
for Capital Stock (other than Redeemable Stock or Exchangeable Stock) of the
Company (less the amount of any cash, or the value of any other property,
distributed by the Company or any Restricted Subsidiary upon such conversion or
exchange); (E) an amount equal to the net reduction in Investments in
Unrestricted Subsidiaries resulting from payments of interest on Indebtedness,
dividends, repayments of loans or advances, or other transfers of assets, in
each case to the Company or any Restricted Subsidiary from Unrestricted
Subsidiaries, or from redesignations of Unrestricted Subsidiaries as Restricted
Subsidiaries (valued in each case as provided in the definition of
"Investments"), not to exceed in the case of any Unrestricted Subsidiary the
amount of Investments previously made by the Company or any Restricted
Subsidiary in such Unrestricted Subsidiary; and (F) $5 million.

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The failure to satisfy the conditions set forth in clauses (2) and (3) of
the first paragraph under "-- Limitation on Restricted Payments" shall not
prohibit any of the following as long as the condition set forth in clause (1)
of such paragraph is satisfied (except as set forth below): (i) dividends paid
within 60 days after the date of declaration thereof if at such date of
declaration such dividend would have complied with the provisions described in
the first paragraph under "-- Limitation on Restricted Payments"; provided,
however, that following the occurrence of Public Market, notwithstanding clause
(1) of the immediately preceding paragraph, the occurrence or existence of a
Default at the time of payment shall not prohibit the payment of such dividends;
(ii) any purchase, redemption, defeasance, or other acquisition or retirement
for value of Capital Stock or Subordinated Indebtedness of the Company made by
exchange for, or out of the proceeds of the substantially concurrent sale of,
Capital Stock of the Company (other than Redeemable Stock or Exchangeable Stock
and other than stock issued or sold to a Subsidiary or to an employee stock
ownership plan), provided, however, that notwithstanding clause (1) of the first
paragraph under "-- Limitation on Restricted Payments", the occurrence or
existence of a Default or Event of Default shall not prohibit, for purposes of
this Section, the making of such purchase, redemption, defeasance or other
acquisition or retirement, and provided, further, such purchase, redemption,
defeasance or other acquisition or retirement shall not be included in the
calculation of Restricted Payments made for purposes of clause (3) of the first
paragraph under "-- Limitation on Restricted Payments," and provided, further,
that the Net Cash Proceeds from such sale shall be excluded from sub-clause (C)
of clause (3) of the first paragraph under "-- Limitation on Restricted
Payments"; (iii) any purchase, redemption, defeasance or other acquisition or
retirement for value of Subordinated Indebtedness of the Company made by
exchange for, or out of the proceeds of the substantially concurrent Incurrence
of for cash (other than to a Subsidiary), new Indebtedness of the Company,
provided, however, that (A) such new Indebtedness shall be contractually
subordinated in right of payment to the Securities at least to the same extent
as the Indebtedness being so redeemed, repurchased, defeased, acquired or
retired, (B) if the Indebtedness being purchased, redeemed, defeased or acquired
or retired for value is Non-Recourse Debt, such new Indebtedness shall be
Non-Recourse Debt, (C) such new Indebtedness has a Stated Maturity either (1) no
earlier than the Stated Maturity of the Indebtedness redeemed, repurchased,
defeased, acquired or retired or (2) after the Stated Maturity of the Senior
Notes and (D) such Indebtedness has an Average Life equal to or greater than the
Average Life of the Indebtedness redeemed, repurchased, defeased, acquired or
retired, and provided, further, that such purchase, redemption, defeasance or
other acquisition or retirement shall not be included in the calculation of
Restricted Payments made for purposes of clause (3) of the first paragraph under
"-- Limitation on Restricted Payments"; (iv) any purchase, redemption,
defeasance or other acquisition or retirement for value of Subordinated
Indebtedness upon a Change of Control or an Asset Sale to the extent required by
the indenture or other agreement pursuant to which such Subordinated
Indebtedness was issued, but only if the Company (A) in the case of a Change of
Control, has made an offer to repurchase the Senior Notes as described under
"-- Covenants -- Change of Control" or (B) in the case of an Asset Sale, has
applied the Net Available Cash from such Asset Sale in accordance with the
provisions described under "-- Covenants -- Sales of Assets"; and (v) dividends
paid to Parent in any fiscal year not in excess of the lesser of (A) the sum of
(1) $300,000 plus (2) 10% of the Company's paid-in capital paid by Parent and
(B) $1,050,000.

Limitation on Incurrence of Indebtedness. Under the terms of the
Indenture, the Company shall not, and shall not permit any Restricted Subsidiary
to, directly or indirectly, Incur any Indebtedness, except that the Company may
Incur Indebtedness if, after giving effect thereto, the Consolidated Coverage
Ratio would be greater than 2:1.

The foregoing provision will not limit the ability of the Company or any
Restricted Subsidiary to Incur the following Indebtedness: (i) Refinancing
Indebtedness (except with respect to Indebtedness referred to in clause (ii),
(iii) or (iv) below); (ii) in addition to any Indebtedness otherwise permitted
to be Incurred hereunder, Indebtedness of the Company at any one time
outstanding in an aggregate principal amount not to exceed $5,000,000 and
provided that the proceeds of such Indebtedness shall not be used for the
purpose of making any Restricted Payments described in clause (i) or (ii) under
"-- Limitation on Restricted Payments"; (iii) Indebtedness of the Company which
is owed to and held by a Wholly Owned Subsidiary and Indebtedness of a Wholly
Owned Subsidiary which is owed to and held by the Company or a Wholly Owned
Subsidiary; provided, however, that any subsequent issuance or transfer of any
Capital Stock which results in

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any such Wholly Owned Subsidiary ceasing to be a Wholly Owned Subsidiary or any
transfer of such Indebtedness (other than to the Company or a Wholly Owned
Subsidiary) shall be deemed, in each case, to constitute the Incurrence of such
Indebtedness by the Company or by a Wholly Owned Subsidiary, as the case may be;
(iv) Indebtedness of the Company under the Bank Credit Agreement which, when
taken together with the aggregate amount of Indebtedness Incurred pursuant to
clause (viii) of this paragraph, is not in excess of $50,000,000, and
Indebtedness of the Company under the Working Capital Credit Agreement not in
excess of $5,000,000; (v) Acquired Indebtedness; provided, however, that the
Company would have been able to Incur such Indebtedness at the time of the
Incurrence thereof pursuant to the immediately preceding paragraph; (vi)
Indebtedness of the Company or a Restricted Subsidiary outstanding on the Issue
Date (other than Indebtedness referred to in clause (iv) above and Indebtedness
being repaid or retired with the proceeds of the Offering); (vii) Non-Recourse
Debt of a Restricted Subsidiary (other than a Restricted Subsidiary existing on
the Issue Date), the proceeds of which are used to acquire, develop, improve or
construct a new Facility of such Restricted Subsidiary; (viii) guarantees by the
Company of Indebtedness of Restricted Subsidiaries which, but for such
guarantees, would be permitted to be Incurred pursuant to clause (vii) of this
paragraph, provided that the aggregate principal amount of Indebtedness Incurred
pursuant to this clause (viii), when taken together with outstanding
Indebtedness Incurred under the Bank Credit Agreement pursuant to clause (iv) of
this paragraph, is not in excess of $50,000,000; and (ix) Related Asset
Indebtedness, provided that at the time of the Incurrence thereof, giving pro
forma effect to the Incurrence thereof, Moody's and S&P shall have affirmed
their respective ratings of the Senior Notes in effect prior to the Incurrence
of such Related Asset Indebtedness.

Notwithstanding the provisions of this covenant described in the first two
paragraphs above, the Indenture provides that the Company shall not Incur any
Indebtedness if the proceeds thereof are used, directly or indirectly, to repay,
prepay, redeem, defease, retire, refund or refinance any Subordinated
Indebtedness unless such repayment, prepayment, redemption, defeasance,
retirement, refunding or refinancing is not prohibited under "-- Limitation on
Restricted Payments" or unless such Indebtedness shall be contractually
subordinated to the Senior Notes at least to the same extent as such
Subordinated Indebtedness.

Limitation on Payment Restrictions Affecting Subsidiaries. Under the terms
of the Indenture, the Company shall not, and shall not permit any Subsidiary to,
create or otherwise cause or permit to exist or become effective any consensual
encumbrance or restriction on the ability of any Restricted Subsidiary to (i)
pay dividends to or make any other distributions on its Capital Stock, or pay
any Indebtedness or other obligations owed to the Company or any other
Restricted Subsidiary, (ii) make any Investments in the Company or any other
Restricted Subsidiary or (iii) transfer any of its property or assets to the
Company or any other Restricted Subsidiary; provided, however, that the
foregoing shall not apply to (a) any encumbrance or restriction existing
pursuant to the Indenture or any other agreement or instrument as in effect or
entered into on the Issue Date; (b) any encumbrance or restriction with respect
to a Subsidiary pursuant to an agreement relating to any Acquired Indebtedness;
provided, however, that such encumbrance or restriction was not Incurred in
connection with or in contemplation of such Subsidiary becoming a Subsidiary;
(c) any encumbrance or restriction pursuant to an agreement effecting a
refinancing of Indebtedness referred to in clause (a) or (b) above or contained
in any amendment or modification with respect to such Indebtedness; provided,
however, that the encumbrances and restrictions contained in any such agreement,
amendment or modification are no less favorable in any material respect with
respect to the matters referred to in clauses (i), (ii) and (iii) above than the
encumbrances and restrictions with respect to the Indebtedness being refinanced,
amended or modified; (d) in the case of clause (iii) above, customary
non-assignment provisions of (A) any leases governing a leasehold interest, (B)
any supply, license or other agreement entered into in the ordinary course of
business of the Company or any Subsidiary or (C) any security agreement relating
to a Lien permitted by Section 3.7(l), that, in the reasonable determination of
the President or Chief Financial Officer of the Company (x) is required in order
to obtain such financing and (v) is customary for such financings; (e) any
restrictions with respect to a Subsidiary imposed pursuant to an agreement
entered into for the sale or disposition of all or substantially all of the
Capital Stock or assets of such Subsidiary pending the closing of such sale or
disposition; (f) any encumbrance imposed pursuant to the terms of Indebtedness
incurred pursuant to clause (vii) of the proviso to the covenant described under
"-- Limitation on Incurrence of Indebtedness" above, provided that such
encumbrance in the written opinion of the President or Chief

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Financial Officer of the Company, (x) is required in order to obtain such
financing, (y) is customary for such financings and (z) applies only to the
assets of or revenues of the applicable Facility or (g) any encumbrance or
restriction existing by reason of applicable law.

Limitation on Sale/Leaseback Transactions. Under the terms of the
Indenture, the Company shall not, and shall not permit any Restricted Subsidiary
to, enter into any Sale/Leaseback Transaction unless (i) the Company or such
Subsidiary would be entitled to create a Lien on such property securing
Indebtedness in an amount equal to the Attributable Debt with respect to such
transaction without equally and ratably securing the Securities pursuant to the
covenant entitled "Limitation on Liens" or (ii) the net proceeds of such sale
are at least equal to the fair value (as determined by the Board of Directors)
of such property and the Company or such Subsidiary shall apply or cause to be
applied an amount in cash equal to the net proceeds of such sale to the
retirement, within 30 days of the effective date of any such arrangement, of
Senior Indebtedness or Indebtedness of a Restricted Subsidiary; provided,
however, that in addition to the transactions permitted pursuant to the
foregoing clauses (i) and (ii), the Company or any Restricted Subsidiary may
enter into a Sale/Leaseback Transaction as long as the sum of (x) the
Attributable Debt with respect to such Sale/Leaseback Transaction and all other
Sale/Leaseback Transactions entered into pursuant to this proviso, plus (y) the
amount of outstanding Indebtedness secured by Liens Incurred pursuant to the
final proviso to the covenant described under "-- Limitation on Liens" below,
does not exceed 10% of Consolidated Net Tangible Assets as determined based on
the consolidated balance sheet of the Company as of the end of the most recent
fiscal quarter for which financial statements are available; and provided,
further, that a Restricted Subsidiary that is not a Restricted Subsidiary on the
Issue Date may enter into a Sale/Leaseback Transaction with respect to property
owned by such Restricted Subsidiary, the proceeds of which are used to acquire,
develop, construct, or repay (within 365 days of the commencement of commercial
operation of such Facility) Indebtedness Incurred to acquire, develop or
construct, a new Facility of such Restricted Subsidiary, as long as neither the
Company nor any other Restricted Subsidiary shall have any obligation or
liability in connection therewith.

Limitation on Liens. Under the terms of the Indenture, the Company shall
not, and shall not permit any Restricted Subsidiary to, directly or indirectly,
incur or permit to exist any Lien of any nature whatsoever on any of its
properties (including, without limitation, Capital Stock), whether owned at the
date of such Indenture or thereafter acquired, other than (a) pledges or
deposits made by such Person under workers' compensation, unemployment insurance
laws or similar legislation, or good faith deposits in connection with bids,
tenders, contracts (other than for payment of Indebtedness) or leases to which
such Person is a party, or deposits to secure statutory or regulatory
obligations of such Person or deposits of cash of United States Government bonds
to secure surety, appeal or performance bonds to which such Person is a party,
or deposits as security for contested taxes or import duties or for the payment
of rent, in each case Incurred in the ordinary course of business; (b) Liens
imposed by law such as carriers', warehousemen's and mechanics' Liens, in each
case, arising in the ordinary course of business and with respect to amounts not
yet due or being contested in good faith by appropriate legal proceedings
promptly instituted and diligently conducted and for which a reserve or other
appropriate provision, if any, as shall be required in conformity with GAAP
shall have been made; or other Liens arising out of judgments or awards against
such Person with respect to which such Person shall then be diligently
prosecuting appeal or other proceedings for review; (c) Liens for property taxes
not yet subject to penalties for non-payment or which are being contested in
good faith and by appropriate legal proceedings promptly instituted and
diligently conducted and for which a reserve or other appropriate provision, if
any, as shall be required in conformity with GAAP shall have been made; (d)
Liens in favor of issuers or surety bonds or letters of credit issued pursuant
to the request of and for the account of such Person in the ordinary course of
its business; provided, however, that such letters of credit may not constitute
Indebtedness; (e) minor survey exceptions, minor encumbrances, easements or
reservations of, or rights of others for, rights of way, sewers, electric lines,
telegraph and telephone lines and other similar purposes, or zoning or other
restrictions as to the use of real properties or liens incidental to the conduct
of the business of such Person or to the ownership of its properties which were
not Incurred in connection with Indebtedness or other extensions of credit and
which do not in the aggregate materially adversely affect the value of said
properties or materially impair their use in the operation of the business of
such Person; (f) Liens securing Indebtedness Incurred to finance the
construction or purchase of, or repairs, improvements or additions to,

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property; provided, however, that the Lien may not extend to any other property
owned by the Company or any Restricted Subsidiary at the time the Lien is
incurred, and the Indebtedness secured by the Lien may not be issued more than
270 days after the later of the acquisition, completion of construction, repair,
improvement, addition or commencement of full operation of the property subject
to the Lien; (g) Liens existing on the Issue Date (other than Liens relating to
Indebtedness or other obligations being repaid or liens that are otherwise
extinguished with the proceeds of the Offering); (h) Liens on property or shares
of stock of a Person at the time such Person becomes a Subsidiary; provided,
however, that any such lien may not extend to any other property owned by the
Company or any Restricted Subsidiary; (i) Liens on property at the time the
Company or a Subsidiary acquires the property, including any acquisition by
means of a merger or consolidation with or into the Company or a Subsidiary;
provided, however, that such Liens are not incurred in connection with, or in
contemplation of, such merger or consolidation; and provided, further, that the
Lien may not extend to any other property owned by the Company or any Restricted
Subsidiary; (j) Liens securing Indebtedness or other obligations of a Subsidiary
owing to the Company or a Wholly Owned Subsidiary; (k) Liens incurred by a
Person other than the Company or any Subsidiary on assets that are the subject
of a Capitalized Lease Obligation to which the Company or a Subsidiary is a
party; provided, however, that any such Lien may not secure Indebtedness of the
Company or any Subsidiary (except by virtue of clause (ix) of the definition of
"Indebtedness") and may not extend to any other property owned by the Company or
any Restricted Subsidiary; (l) Liens Incurred by a Restricted Subsidiary on its
assets to secure Non-Recourse Debt Incurred pursuant to clause (vii) of the
second paragraph under "-- Limitation on Incurrence of Indebtedness" above,
provided that such Lien (A) is incurred at the time of the initial Incurrence of
such Indebtedness and (b) does not extend to any assets or property of the
Company or any other Restricted Subsidiary; (m) Liens not in respect of
Indebtedness arising from Uniform Commercial Code financing statements for
informational purposes with respect to leases Incurred in the ordinary course of
business and not otherwise prohibited by this Indenture; (n) Liens not in
respect of Indebtedness consisting of the interest of the lessor under any lease
Incurred in the ordinary course of business and not otherwise prohibited by this
Indenture; (o) Liens which constitute banker's liens, rights of set-off or
similar rights and remedies as to deposit accounts or other funds maintained
with any bank or other financial institution, whether arising by operation of
law or pursuant to contract; (p) Liens to secure any refinancing, refunding,
extension, renewal or replacement (or successive refinancings, refundings,
extensions, renewals or replacements) as a whole, or in part, of any
Indebtedness secured by any Lien referred to in the foregoing clauses (f), (g),
(h) and (i), provided, however, that (x) such new Lien shall be limited to all
or part of the same property that secured the original Lien (plus improvements
on such property) and (y) the Indebtedness secured by such Lien at such time is
not increased (other than by an amount necessary to pay fees and expenses,
including premiums, related to the refinancing, refunding, extension, renewal or
replacement of such Indebtedness); and (q) Liens by which the Senior Notes are
secured equally and ratably with other Indebtedness of the Company pursuant to
the provisions described under "-- Covenants -- Limitations on Liens", without
effectively providing that the Senior Notes shall be secured equally and ratably
with (or prior to) the obligations so secured for so long as such obligations
are so secured; provided, however, that the Company may incur other Liens to
secure Indebtedness as long as the sum of (x) the amount of outstanding
Indebtedness secured by Liens incurred pursuant to this proviso plus (y) the
Attributable Debt with respect to all outstanding leases in connection with
Sale/Leaseback Transactions entered into pursuant to the proviso under
"-- Limitation on Sale/Leaseback Transactions," does not exceed 10% of
Consolidated Net Tangible Assets as determined with respect to the Company as of
the end of the most recent fiscal quarter for which financial statements are
available.

Change of Control. Under the terms of the Indenture, in the event of a
Change of Control Triggering Event, the Company shall make an offer to purchase
(the "Change of Control Offer") the Senior Notes then outstanding at a purchase
price equal to 101% of the principal amount (excluding any premium) thereof plus
accrued and unpaid interest to the Change of Control Purchase Date (as defined
below) on the terms set forth in this provision. The date on which the Company
shall purchase the Senior Notes pursuant to this provision (the "Change of
Control Purchase Date") shall be no earlier than 30 days, nor later than 60
days, after the notice referred to below is mailed, unless a longer period shall
be required by law. The Company shall notify

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the Trustee in writing promptly after the occurrence of any Change of Control
Triggering Event of the Company's obligation to offer to purchase all of the
Senior Notes.

Notice of a Change of Control Offer shall be mailed by the Company to the
Holders of the Senior Notes at their last registered address (with a copy to the
Trustee and the Paying Agent) within thirty (30) days after a Change in Control
Triggering Event has occurred. The Change of Control Offer shall remain open
from the time of mailing until a date not more than five (5) Business Days
before the Change of Control Purchase Date. The notice shall contain all
instructions and materials necessary to enable such Holders to tender (in whole
or in part) the Senior Notes pursuant to the Change of Control Offer. The
notice, which shall govern the terms of the Change of Control Offer, shall
state: (a) that the Change of Control Offer is being made pursuant to the
Indenture; (b) the purchase price and the Change of Control Purchase Date; (c)
that any Senior Note not surrendered or accepted for payment will continue to
accrue interest; (d) that any Senior Note accepted for payment pursuant to the
Change of Control Offer shall cease to accrue interest after the Change of
Control Purchase Date; (e) that any Holder electing to have a Senior Note
purchased (in whole or in part) pursuant to a Change of Control Offer will be
required to surrender the Senior Note, with the form entitled "Option of Holder
to Elect Purchase" on the reverse of the Senior Note completed, to the Paying
Agent at the address specified in the notice (or otherwise make effective
delivery of the Senior Note pursuant to book-entry procedures and the related
rules of the applicable depositories) at least five (5) Business Days before the
Change of Control Purchase Date; and (f) that any Holder will be entitled to
withdraw his or her election if the Paying Agent receives, not later than three
(3) Business Days prior to the Change of Control Purchase Date, a telegram,
telex, facsimile transmission or letter setting forth the name of the Holder,
the principal amount of the Senior Note the Holder delivered for purchase and a
statement that such Holder is withdrawing his or her election to have the Senior
Note purchased.

On the Change of Control Purchase Date, the Company shall (i) accept for
payment the Senior Notes, or portions thereof, surrendered and properly tendered
and not withdrawn, pursuant to the Change of Control Offer, (ii) deposit with
the Paying Agent, no later than 11:00 a.m. eastern standard time, money, in
immediately available funds, sufficient to pay the purchase price of all the
Senior Notes or portions thereof so accepted and (iii) deliver to the Trustee,
no later than 11:00 a.m. eastern standard time, the Senior Notes so accepted
together with an Officers' Certificate stating that such Senior Notes have been
accepted for payment by the Company. The Paying Agent shall promptly mail or
deliver to Holders of Senior Notes so accepted payment in an amount equal to the
purchase price. Holders whose Securities are purchased only in part will be
issued new Senior Notes equal in principal amount to the unpurchased portion of
the Senior Notes surrendered.

Transactions with Affiliates. Under the terms of the Indenture, the
Company shall not, and shall not permit any Restricted Subsidiary to, directly
or indirectly, enter into, permit to exist, renew or extend any transaction or
series of transactions (including, without limitation, the sale, purchase,
exchange or lease of any assets or property or the rendering of any services)
with any Affiliate of the Company unless (i) the terms of such transaction or
series of transactions are (A) no less favorable to the Company or such
Restricted Subsidiary, as the case may be, than would be obtainable in a
comparable transaction or series of related transactions in arm's-length
dealings with an unrelated third party and (B) set forth in writing, if such
transaction or series of transactions involve aggregate payments or
consideration in excess of $1,000,000, and (ii) with respect to a transaction or
series of transactions involving the sale, purchase, lease or exchange of
property or assets having a value in excess of $5,000,000, such transaction or
series of transactions has been approved by a majority of the disinterested
members of the Board of Directors or, if there are no disinterested members of
the Board of Directors, the Board of Directors of the Company shall have
received a written opinion of a nationally recognized investment banking firm
stating that such transaction or series of transactions is fair to the Company
or such Restricted Subsidiary from a financial point of view. The foregoing
provisions do not prohibit (i) the payment of reasonable fees to directors of
the Company and its subsidiaries who are not employees of the Company or its
subsidiaries; (ii) any transaction between the Company and a Wholly Owned
Subsidiary or between Wholly Owned Subsidiaries otherwise permitted by the terms
of the Indenture; (iii) the payment of any Restricted Payment which is expressly
permitted to be paid pursuant to the second paragraph under
"-- Covenants -- Limitation on Restricted Payments"; (iv) any issuance of

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securities or other reasonable payments, awards or grants, in cash or otherwise,
pursuant to, or the funding of, employment arrangements approved by the Board of
Directors; (v) the grant of stock options or similar rights to employees and
directors of the Company pursuant to plans approved by the Board of Directors;
(vi) loans or advances to employees in the ordinary course of business; (vii)
any repurchase, redemption or other retirement of Capital Stock of the Company
held by employees of the Company or any of its Subsidiaries upon death,
disability or termination of employment at a price not in excess of the fair
market value thereof approved by the Board of Directors; (viii) any transaction
between or among the Company and any Subsidiary in the ordinary course of
business and consistent with past practices of the Company and its Subsidiaries;
(ix) payments pursuant to Existing Agreements and payments of principal,
interest and commitment fees under the Bank Credit Agreement; and (x) any
agreement to do any of the foregoing. Any transaction which has been determined,
in the written opinion of an independent nationally recognized investment
banking firm, to be fair, from a financial point of view, to the Company or the
applicable Restricted Subsidiary shall be deemed to be in compliance with this
provision.

Sales of Assets. Under the terms of the Indenture, neither the Company nor
any Restricted Subsidiary shall consummate any Asset Sale unless (i) the Company
or such Restricted Subsidiary receives consideration at the time of such Asset
Sale at least equal to the fair market value, as determined in good faith by the
Board of Directors, of the shares or assets subject to such Asset Sale, (ii) at
least 60% of the consideration thereof received by the Company or such
Restricted Subsidiary is in the form of cash or cash equivalents which are
promptly converted into cash by the Person receiving such payment and (iii) an
amount equal to 100% of the Net Available Cash is applied by the Company (or
such Subsidiary, as the case may be) as set forth herein. Under the terms of the
Indenture, the Company shall not permit any Unrestricted Subsidiary to make any
Asset Sale unless such Unrestricted Subsidiary receives consideration at the
time of such Asset Sale at least equal to the fair market value of the shares or
assets so disposed of as determined in good faith by the Board of Directors.

Under the terms of the Indenture, within 365 days (such period being the
"Application Period") following the consummation of an Asset Sale, the Company
or such Restricted Subsidiary shall apply the Net Available Cash from such Asset
Sale as follows: (i) first, to the extent the Company or such Restricted
Subsidiary elects, to reinvest in Additional Assets (including by means of an
investment in Additional Assets by a Restricted Subsidiary with Net Available
Cash received by the Company or another Restricted Subsidiary); (ii) second, to
the extent of the balance of such Net Available Cash after application in
accordance with clause (i), and to the extent the Company or such Restricted
Subsidiary elects (or is required by the terms of any Senior Indebtedness or any
Indebtedness of such Restricted Subsidiary), to prepay, repay or purchase Senior
Indebtedness (other than Senior Notes) or Indebtedness (other than any Preferred
Stock) of a Restricted Subsidiary (in each case other than Indebtedness owed to
the Company or an Affiliate of the Company); (iii) third, to the extent of the
balance of such Net Available Cash after application in accordance with clauses
(i) and (ii), and to the extent the Company or such Restricted Subsidiary
elects, to purchase Senior Notes; and (iv) fourth, to the extent of the balance
of such Net Available Cash after application in accordance with clauses (i),
(ii) and (iii), to make an offer to purchase the Senior Notes at not less than
their principal amount plus accrued interest (if any) pursuant to and subject to
the conditions set forth in the Indenture; provided, however, that in connection
with any prepayment, repayment or purchase of Indebtedness pursuant to clause
(ii), (iii) or (iv) above, the Company or such Restricted Subsidiary shall
retire such Indebtedness and cause the related loan commitment (if any) to be
permanently reduced in an amount equal to the principal amount so prepaid,
repaid or purchased. To the extent that any Net Available Cash from any Asset
Sale remains after the application of such Net Available Cash in accordance with
this paragraph, the Company or such Restricted Subsidiary may utilize such
remaining Net Available Cash in any manner not otherwise prohibited by the
Indenture.

To the extent that any or all of the Net Available Cash of any Foreign
Asset Sale is prohibited or delayed by applicable local law from being
repatriated to the United States, the portion of such Net Available Cash so
affected shall not be required to be applied at the time provided above, but may
be retained by the applicable Restricted Subsidiary so long, but only so long,
as the applicable local law will not permit repatriation to the United States
(the Company hereby agreeing to promptly take or cause the applicable Restricted
Subsidiary

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to promptly take all actions required by the applicable local law to permit such
repatriation). Once such repatriation of any of such affected Net Available Cash
is permitted under the applicable local law, such repatriation shall be
immediately effected and such repatriated Net Available Cash will be applied in
the manner set forth in this provision as if such Asset Sale had occurred on the
date of such repatriation.

Notwithstanding the foregoing, to the extent that the Board of Directors
determines, in good faith, that repatriation of any or all of the Net Available
Cash of any Foreign Asset Sale would have a material adverse tax consequence to
the Company, the Net Available Cash so affected may be retained outside of the
United States by the applicable Restricted Subsidiary for so long as such
material adverse tax consequence would continue.

Under the Indenture, the Company shall not be required to make an offer to
purchase the Senior Notes if the Net Available Cash available from an Asset Sale
(after application of the proceeds as provided in clauses (i) and (ii) of the
second paragraph above) is less than $1,000,000 for any particular Asset Sale
(which lesser amounts shall not be carried forward for purposes of determining
whether an offer is required with respect to the Net Available Cash from any
subsequent Asset Sale).

Notwithstanding the foregoing, this provision shall not apply to, or
prevent any sale of assets, property, or Capital Stock of Subsidiaries to the
extent that the fair market value (as determined in good faith by the Board of
Directors) of such asset, property or Capital Stock, together with the fair
market value of all other assets, property, or Capital Stock of Subsidiaries
sold, transferred or otherwise disposed of in Asset Sales during the twelve
month period preceding the date of such sale, does not exceed 5% of Consolidated
Net Tangible Assets as determined as of the end of the most recent fiscal
quarter for which financial statements are available (it being understood that
this provision shall only apply with respect to the fair market value of such
asset, property or Capital Stock in excess of 5% of consolidated Net Tangible
Assets), and no violation of this provision shall be deemed to have occurred as
a consequence thereof.

In the event of the transfer of substantially all (but not all) of the
property and assets of the Company as an entirety to a Person in a transaction
permitted under the covenant described under "-- Merger and Consolidation," the
Successor Corporation shall be deemed to have sold the properties and assets of
the Company not so transferred for purposes of this covenant, and shall comply
with the provisions of this covenant with respect to such deemed sale as if it
were an Asset Sale.

Limitation on the Issuance of Capital Stock and the Incurrence of
Indebtedness of Restricted Subsidiaries. Pursuant to the terms of the
Indenture, the Company shall not permit any Restricted Subsidiary, directly or
indirectly, to issue or sell, and shall not permit any Person other than the
Company or a Wholly Owned Subsidiary to own (except to the extent that any such
Person may own on the Issue Date), any shares of such Restricted Subsidiary's
Capital Stock (including options, warrants or other rights to purchase shares of
Capital Stock) except, to the extent otherwise permitted by the Indenture, (i)
to the Company or another Restricted Subsidiary that is a Wholly Owned
Subsidiary of the Company, or (ii) if, immediately after giving effect to such
issuance and sale, such Restricted Subsidiary would no longer constitute a
Restricted Subsidiary for purposes of the Indenture; provided, however, that a
Restricted Subsidiary that has an interest in a Facility may sell shares of
Non-Convertible Stock that is not Preferred Stock if, after giving effect to
such sale, the Company or a Wholly Owned Subsidiary continues to hold at least a
majority of each class of Capital Stock of such Restricted Subsidiary. The
Company shall not permit any Restricted Subsidiary, directly or indirectly, to
Incur Indebtedness other than pursuant to the second paragraph under
"-- Limitation on Incurrence of Indebtedness."

Limitation on Changes in the Nature of the Business. The Indenture
provides that the Company and its Subsidiaries shall engage only in the business
of acquiring, constructing, managing, developing, improving, owning and
operating Facilities, as well as any other activities reasonably related to the
foregoing activities (including acquiring and holding reserves), including but
not limited to investing in Facilities; provided that up to 10% of the Company's
Consolidated total assets may be used in Unrelated Businesses without
constituting a violation of this covenant. In addition, the Company will, and
will cause its Subsidiaries, to conduct their respective businesses in a manner
so as to maintain the exemption of the Company and its Subsidiaries from
treatment as a public utility holding company under PUHCA or an electric utility
or public

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utility under any federal, state or local law; provided, however, to the extent
that any such law is amended following the Issue Date in such a manner that
would (absent application of this proviso) make compliance with this paragraph
result in a material adverse effect on the Company's results of operations or
financial condition, then the Company shall not be required to comply with this
paragraph, but only to the extent of actions or failures to act that would
(absent application of this proviso) constitute violations of this Covenant
solely as a result of such amendment.

Limitation on Subsidiary Investments. The Indenture provides that the
Company will not permit any Subsidiary with an interest in a Facility to make
any investment in or merge with any other person with an interest in a power
generation facility or, except in connection with the acquisition of Related
Assets by such Subsidiary, in an Unrelated Business.

Merger and Consolidation. Under the terms of each of the Indentures, the
Company shall not, in a single transaction or through a series of related
transactions, consolidate with or merge with or into any other corporation or
sell, assign, convey, transfer or lease or otherwise dispose of all or
substantially all of its properties and assets as an entirety to any Person or
group of affiliated Persons unless: (i) either (A) the Company shall be the
continuing Person, or (B) the Person (if other than the Company) formed by such
consolidation or into which the Company is merged or to which the properties and
assets of the Company as an entirety are transferred (the "Successor
Corporation") shall be a corporation organized and existing under the laws of
the United States or any State thereof or the District of Columbia and shall
expressly assume, by an indenture supplemental to the Indenture, executed and
delivered to the Trustee, in form and substance reasonably satisfactory to the
Trustee, all the obligations of the Company under the Indenture and the Senior
Notes; (ii) immediately before and immediately after giving effect to such
transaction on a pro forma basis (and treating any Indebtedness which becomes an
obligation of the Company (or the Successor Corporation if the Company is not
the continuing obligor under the Indenture) or any Restricted Subsidiary as a
result of such transaction as having been Incurred by such Person at the time of
such transaction), no Default shall have occurred and be continuing; (iii) the
Company shall have delivered, or caused to be delivered, to the Trustee an
Officers' Certificate and, as to legal matters, an Opinion of Counsel, each in
form and substance reasonably satisfactory to the Trustee, each stating that
such consolidation, merger or transfer and such supplemental indenture comply
with the Indenture and that all conditions precedent herein provided for
relating to such transaction have been complied with; (iv) immediately after
giving effect to such transaction on a pro forma basis (and treating any
Indebtedness which becomes an obligation of the Company (or the Successor
Corporation if the Company is not the continuing obligor under the Indenture) or
a Restricted Subsidiary in connection with or as a result of such transaction as
having been Incurred by such Person at the time of such transaction), the
Company (or the Successor Corporation if the Company is not the continuing
obligor under the Indenture) shall have a Consolidated Net Worth in an amount
which is not less than the Consolidated Net Worth of the Company immediately
prior to such transaction; and (v) immediately after giving effect to such
transaction on a pro forma basis (and treating any Indebtedness which becomes an
obligation of the Company (or the Successor Corporation if the Company is not
the continuing obligor under the Indenture) or a Restricted Subsidiary in
connection with or as a result of such transaction as having been Incurred by
such Person at the time of such transaction), the Consolidated Coverage Ratio of
the Company (or the Successor Corporation if the Company is not the continuing
obligor under the Indenture) is at least 1.10:1, or, if less, equal to the
Consolidated Coverage Ratio of the Company immediately prior to such
transaction; provided that, if the Consolidated Coverage Ratio of the Company
before giving effect to such transaction is within the range set forth in column
(A) below, then the pro forma Consolidated Coverage Ratio of the Company (or the
Successor Corporation if the Company is not the continuing obligor under the
Indenture) shall be at least equal to the lesser of (1) the ratio determined by
multiplying the percentage set

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forth in column (B) below by the Consolidated Coverage Ratio of the Company
prior to such transaction and (2) the ratio set forth in column (C) below:

Notwithstanding the foregoing clauses (ii), (iv) and (v), any Restricted
Subsidiary (other than a Subsidiary having an interest in a Facility) may
consolidate with, merge into or transfer all or part of its properties and
assets to the Company or any Wholly Owned Subsidiary or Wholly Owned
Subsidiaries (other than a Subsidiary or Subsidiaries which have an interest in
a Facility) and no violation of this provision will be deemed to have occurred
as a consequence thereof, as long as the requirements of clauses (i) and (iii)
are satisfied in connection therewith.

Upon any such assumption by the Successor Corporation, except in the case
of a lease, the Successor Corporation shall succeed to and be substituted for
the Company under the Indenture and the Senior Notes and the Company shall
thereupon be released from all obligations under the Indenture and under the
Senior Notes and the Company as the predecessor corporation may thereupon or at
any time thereafter be dissolved, wound up or liquidated. The Successor
Corporation thereupon may cause to be signed, and may issue either in its own
name or in the name of the Company, all or any of the Senior Notes issuable
under the Indenture which theretofore shall not have been signed by the Company
and delivered to the Trustee; and, upon the order of the Successor Corporation
instead of the Company and subject to all the terms, conditions and limitations
prescribed in the Indenture, the Trustee shall authenticate and shall deliver
any Senior Notes which the Successor Corporation thereafter shall cause to be
signed and delivered to the Trustee for that purpose. All the Senior Notes so
issued shall in all respects have the same legal rank and benefit under the
Indenture as the Senior Notes theretofore or thereafter issued in accordance
with the terms of the Indenture as though all such Senior Notes had been issued
at the date of the execution of the Indenture.

In the case of any such consolidation, merger or transfer, such changes in
form (but not in substance) may be made in the Senior Notes thereafter to be
issued as may be appropriate.

EVENTS OF DEFAULT

"Events of Default" are defined in the Indenture as (a) default for 30 days
in payment of any interest installment due and payable on the Senior Notes, (b)
default in payment of the principal when due on any Senior Note, or failure to
redeem or purchase Senior Notes when required pursuant to the Indenture or the
Senior Notes, (c) default in performance of any other covenants or agreements in
the Indenture or in the Senior Notes for 30 days after written notice to the
Company by the Trustee or to the Company and the Trustee by the holders of at
least 25% in principal amount of the Senior Notes then outstanding, (d) there
shall have occurred either (i) a default by the Company or any Subsidiary under
any instrument or instruments under which there is or may be secured or
evidenced any Indebtedness of the Company or any Subsidiary of the Company
(other than the Senior Notes) having an outstanding principal amount of
$2,000,000 (or its foreign currency equivalent) or more individually or
$5,000,000 (or its foreign currency equivalent) or more in the aggregate that
has caused the holders thereof to declare such Indebtedness to be due and
payable prior to its Stated Maturity or (ii) a default by the Company or any
Subsidiary in the payment when due of any portion of the principal under any
such instrument, and such unpaid portion exceeds $2,000,000 (or its foreign
currency equivalent) individually or $5,000,000 (or its foreign currency
equivalent) in the aggregate and is not paid, or such default is not cured or
waived, within any grace period applicable thereto, unless such Indebtedness is
discharged within 20 days of the Company or a Restricted Subsidiary becoming
aware of such default; provided, however, that the foregoing shall not apply to
any default on Non-Recourse Indebtedness; (e) any final judgment or order (not
covered by insurance) for the payment of money shall be rendered against the
Company or any Significant Subsidiary in an amount in excess of $2,000,000 (or

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its foreign currency equivalent) individually or $5,000,000 (or its foreign
currency equivalent) in the aggregate for all such final judgments or orders
against all such Persons (treating any deductibles, self-insurance or retention
as not so covered) and shall not be discharged, and there shall be any period of
30 consecutive days following entry of the final judgment or order in excess of
$2,000,000 (or its foreign currency equivalent) individually or that causes the
aggregate amount for all such final judgments or orders outstanding against all
such Persons to exceed $5,000,000 (or its foreign currency equivalent) during
which a stay of enforcement of such final judgment or order, by reason of a
pending appeal or otherwise, shall not be in effect; and (f) certain events of
bankruptcy, insolvency and reorganization of the Company.

If any Event of Default (other than an Event of Default described in clause
(f) with respect to the Company) occurs and is continuing, the Indenture
provides that the Trustee by notice to the Company, or the Holders of at least
25% in principal amount of the Senior Notes by notice to the Company and the
Trustee, may declare the principal amount of the Senior Notes and any accrued
and unpaid interest to be due and payable immediately. If an Event of Default
described in clause (f) with respect to the Company occurs, the principal of and
interest on all the Senior Notes shall ipso facto become and be immediately due
and payable without any declaration or other act on the part of the Trustee or
any Holders of Senior Notes. The Holders of a majority in principal amount of
the Senior Notes by notice to the Trustee may rescind any such declaration and
its consequences if the rescission would not conflict with any judgment or
decree and if all existing Events of Default have been cured or waived other
than the non-payment of principal of or interest on the Senior Notes which shall
have become due by such declaration.

The Company must file annually with the Trustee a certificate describing
any Default by the Company in the performance of any conditions or covenants
that has occurred under the Indenture and its status. The Company must give the
Trustee written notice within 30 days of any Default under the Indenture that
could mature into an Event of Default described in clause (c), (d), (e) or (f)
of the second preceding paragraph.

The Trustee is entitled, subject to the duty of the Trustee during a
Default to act with the required standard of care, to be indemnified before
proceeding to exercise any right or power under the Indenture at the direction
of the Holders of the Senior Notes or which requires the Trustee to expend or
risk its own funds or otherwise incur any financial liability. The Indenture
also provides that the Holders of a majority in principal amount of the Senior
Notes issued under the Indenture may direct the time, method and place of
conducting any proceeding for any remedy available to the Trustee or exercising
any trust or power conferred on the Trustee; however, the Trustee may refuse to
follow any such direction that conflicts with law or the Indenture, is unduly
prejudicial to the rights of other Holders of the Senior Notes, or would involve
the Trustee in personal liability.

The Indenture provides that while the Trustee generally must mail notice of
a Default or Event of Default to the holders of the Senior Notes within 90 days
of occurrence, the Trustee may withhold notice to the Holders of the Senior
Notes of any Default or Event of Default (except in payment on the Senior Notes)
if the Trustee in good faith determines that the withholding of such notice is
in the interest of the Holders of the Senior Notes.

MODIFICATION OF THE INDENTURE

Under the terms of the Indenture, the Company and the Trustee may, with the
consent of the Holders of a majority in principal amount of the outstanding
Senior Notes amend or supplement the Indenture or the Senior Notes except that
no amendment or supplement may, without the consent of each affected Holder, (i)
reduce the principal of or change the Stated Maturity of any Senior Note, (ii)
reduce the rate of or change the time of payment of interest on any Senior Note,
(iii) change the currency of payment of the Senior Notes, (iv) reduce the
premium payable upon the redemption of any Senior Note, or change the time at
which any such Senior Note may or shall be redeemed, (v) reduce the amount of
Senior Notes, the holders of which must consent to an amendment or supplement or
(vi) change the provisions of the Indenture relating to waiver of past defaults,
rights of Holders of the Senior Notes to receive payments or the provisions
relating to amendments of the Indenture that require the consent of Holders of
each affected Senior Note.

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ACTIONS BY NOTEHOLDERS

Under the terms of the Indenture, a Holder of Senior Notes may not pursue
any remedy with respect to the Indenture or the Senior Notes (except actions for
payment of overdue principal or interest), unless (i) the Holder has given
notice to the Trustee of a continuing Event of Default, (ii) Holders of at least
25% in principal amount of the Senior Notes have made a written request to the
Trustee to pursue such remedy, (iii) such Holder or Holders have offered the
Trustee security or indemnity reasonably satisfactory to it against any loss,
liability or expense, (iv) the Trustee has not complied with such request within
60 days of such request and offer and (v) the Holders of a majority in principal
amount of the Senior Notes have not given the Trustee an inconsistent direction
during such 60-day period.

DEFEASANCE, DISCHARGE AND TERMINATION

Defeasance and Discharge. The Indenture provides that the Company will be
discharged from any and all obligations in respect of the Senior Notes, and the
provisions of the Indenture will no longer be in effect with respect to such
Senior Notes (except for, among other matters, certain obligations to register
the transfer or exchange of such Senior Notes, to replace stolen, lost or
mutilated Senior Notes, to maintain paying agencies and to hold monies for
payment in trust, and the rights of holders to receive payments of principal and
interest thereon), on the 123rd day after the date of the deposit with the
Trustee, in trust, of money or U.S. Government Obligations that, through the
payment of interest and principal in respect thereof in accordance with their
terms, will provide money, or a combination thereof, in an amount sufficient to
pay the principal of and interest on such Senior Notes, when due in accordance
with the terms of the Indenture and such Senior Notes. Such a trust may only be
established if, among other things, (i) the Company has delivered to the Trustee
either (a) an Opinion of Counsel (who may not be employed by the Company) to the
effect that Holders will not recognize income, gain or loss for federal income
tax purposes as a result of such deposit, defeasance and discharge and will be
subject to federal income tax on the same amount and in the same manner and at
the same times as would have been the case if such deposit, defeasance and
discharge had not occurred, which Opinion of Counsel must refer to and be based
upon a ruling of the Internal Revenue Service or a change in applicable federal
income tax law occurring after the date of the Indenture or (b) a ruling of the
Internal Revenue Service to such effect and (ii) no Default under the Indenture
shall have occurred and be continuing on the date of such deposit or during the
period ending on the 123rd day after such date of deposit and such deposit shall
not result in or constitute a Default or result in a breach or violation of, or
constitute a default under, any other agreement or instrument to which the
Company is a party or by which the Company is bound.

Defeasance of Certain Covenants and Certain Events of Default. The
Indenture further provides that the provisions of the Indenture will no longer
be in effect with respect to the provisions described in clauses (iv) (v) under
"-- Merger and Consolidation" and all the covenants described herein under
"-- Covenants," clause (c) under "-- Events of Default" with respect to such
covenants and clauses (iv) and (v) under "-- Merger and Consolidation," and
clauses (d) and (e) under "-- Events of Default" shall be deemed not to be
Events of Default under the Indenture, and the provisions described herein under
"-- Ranking" shall not apply, upon the deposit with the Trustee, in trust, of
money or U.S. Government Obligations that through the payment of interest and
principal in respect thereof in accordance with their terms will provide money
in an amount sufficient to pay the principal of and interest on the Senior Notes
issued thereunder when due in accordance with the terms of the Indenture. Such a
trust may only be established if, among other things, the provisions described
in clause (ii) of the immediately preceding paragraph have been satisfied and
the Company has delivered to the Trustee an Opinion of Counsel (who may not be
an employee of the Company) to the effect that the Holders will not recognize
income, gain or loss for federal income tax purposes as a result of such deposit
and defeasance of certain covenants and Events of Default and will be subject to
federal income tax on the same amount and in the same manner and at the same
times as would have been the case if such deposit and defeasance had not
occurred.

Defeasance and Certain Other Events of Default. In the event the Company
exercises its option to omit compliance with certain covenants and provisions of
the Indenture with respect to the Senior Notes, as described in the immediately
preceding paragraph and such Senior Notes are declared due and payable

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because of the occurrence of an Event of Default that remains applicable, the
amount of money or U.S. Government Obligations on deposit with the Trustee will
be sufficient to pay principal of and interest on Senior Notes on the respective
dates on which such amounts are due but may not be sufficient to pay amounts due
on such Senior Notes, at the time of the acceleration resulting from such Event
of Default. However, the Company shall remain liable for such payments.

Termination of Company's Obligations in Certain Circumstances. The
Indenture further provides that the Company will be discharged from any and all
obligations in respect of the Senior Notes and the provisions of such Indenture
will no longer be in effect with respect to the Senior Notes (except to the
extent provided under "-- Defeasance and Discharge") if such Senior Notes mature
within one year or all of them are to be called for redemption within one year
under arrangements satisfactory to the Trustee for giving the notice of
redemption, and the Company deposits with the Trustee, in trust, money or U.S.
Government Obligations that, through the payment of interest and principal in
respect thereof in accordance with their terms, will provide money in an amount
sufficient to pay the principal of, premium, if any, and accrued interest on
such Senior Notes when due in accordance with the terms of the Indenture and
such Senior Notes. Such a trust may only be established if, among other things,
(i) no Default under the Indenture shall have occurred and be continuing on the
date of such deposit, (ii) such deposit will not result in or constitute a
Default or result in a breach or violation of, or constitute a Default under,
any other agreement or instrument to which the Company is a party or by which it
is bound and (iii) the Company has delivered to the Trustee an Opinion of
Counsel stating that such conditions have been complied with. Pursuant to this
provision, the Company is not required to deliver an Opinion of Counsel to the
effect that Holders will not recognize income, gain or loss for U.S. federal
income tax purposes as a result of such deposit and termination, and there is no
assurance that Holders would not recognize income, gain or loss for U.S. federal
income tax purposes as a result thereof or that Holders would be subject to U.S.
federal income tax on the same amount and in the same manner and at the same
times as would have been the case if such deposit and termination had not
occurred.

UNCLAIMED MONEY

Under the terms of the Indenture, subject to any applicable abandoned
property law, the Trustee will pay to the Company upon request any money held by
it for the payment of principal or interest that remains unclaimed for two
years. After payment to the Company, Holders of Senior Notes entitled to such
money must look to the Company for payment as general creditors.

CONCERNING THE TRUSTEE AND PAYING AGENT

Fleet National Bank acts as Trustee under the Indenture and will initially
be Paying Agent and Registrar for the Senior Notes. The Company may have in the
future other relationships with such bank. Notices to the Trustee, Paying Agent
and Registrar under the Indenture should be directed to Fleet National Bank, 777
Main Street, Hartford, Connecticut 06115, Attention: Corporate Trust Department.

GOVERNING LAW

Under the terms of the Indenture, the laws of the State of New York govern
the Indenture and the Senior Notes.

BOOK ENTRY; DELIVERY AND FORM

The Old Notes were and the New Notes will be issued in fully registered
form without interest coupons. No Senior Notes will be issuable in bearer form.
Old Notes sold in reliance on Rule 144A are represented by a single, permanent
global Note in definitive, fully registered form without interest coupons (the
"Restricted Global Note"), which was deposited with the Trustee as custodian for
DTC and registered in the name of a nominee of DTC.

Old Notes sold in offshore transactions in reliance on Regulation S were
originally represented by a single, permanent global Note, in definitive, fully
registered form without interest coupons (the "Regulation S Global Note"), which
was deposited with the Trustee as custodian for DTC and registered in the name
of a

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nominee of DTC for the accounts of Euroclear and Cedel. Old Notes originally
purchased by or transferred to Institutional Accredited Investors who were not
qualified institutional buyers ("Non-Global Purchasers") were issued in
registered form without coupons ("Certificated Notes").

THE GLOBAL NOTES

The Regulation S Global Note and the Restricted Global Note (each a "Global
Note" and together the "Global Notes") will be credited by DTC or its custodian
on its internal system the respective principal amount of the individual
beneficial interests represented by such Global Note to the accounts of persons
who have accounts with such depositary. Ownership of beneficial interests in a
Global Note will be limited to persons who have accounts with DTC
("participants") or persons who hold interests through participants. Ownership
of beneficial interests in the Global Note will be shown on, and the transfer of
that ownership will be effected only through, records maintained by DTC or its
nominee (with respect to interests of participants) and the records of
participants (with respect to interests of persons other than participants).
Qualified Institutional Buyers may hold their interests in the Global Note
directly through DTC if they are participants in such system, or indirectly
through organizations which are participants in such system.

Investors may hold their interests in the Regulation S Global Note directly
through Cedel or Euroclear, if they are participants in such system, or
indirectly through organizations that are participants in such systems.
Beginning 40 days after the later of the commencement of this Offering and the
closing date (but not earlier), investors may also hold such interests through
organizations other than Cedel or Euroclear that are participants in the DTC
system. Cedel and Euroclear will hold interests in the Regulation S Global Note
on behalf of their participants through DTC.

So long as DTC, or its nominee, is the registered owner or holder of a
Global Note, DTC or such nominee, as the case may be, will be considered the
sole owner or holder of the Senior Notes represented by such Global Note for all
purposes under the Indenture and the Senior Notes. No beneficial owner of an
interest in a Global Note will be able to transfer that interest except in
accordance with DTC's applicable procedures, in addition to those provided for
under the Indenture and, if applicable, those of Euroclear and Cedel.

Payments of the principal of, and interest on, the Global Notes will be
made to DTC or its nominee, as the case may be, as the registered owner thereof.
Neither the Company, the Trustee nor any Paying Agent will have any
responsibility or liability for any aspect of the records relating to or
payments made on account of beneficial ownership interests in the Global Notes
or for maintaining, supervising or reviewing any records relating to such
beneficiary ownership interests.

The Company expects that DTC or its nominee, upon receipt of any payment of
principal or interest in respect of a Global Note will credit participants'
accounts with payments in amounts proportionate to their respective beneficial
interests in the principal amount of such Global Note as shown on the records of
DTC or its nominee. The Company also expects that payments by participants to
owners of beneficial interests in such Global Note held through such
participants will be governed by standing instructions and customary practices,
as is now the case with securities held for the accounts of customers registered
in the names of nominees for such customers. Such payments will be the
responsibility of such participants.

Transfers between participants in DTC will be effected in the ordinary way
in accordance with DTC rules and will be settled in same-day funds. If a holder
requires physical delivery of a Certificated Note for any reason, including to
sell Senior Notes to persons in states which require such delivery of such
Senior Notes or to pledge such Senior Notes, such holder must transfer its
interest in the Global Note in accordance with the normal procedures of DTC and
the procedures set forth in the Indenture. Transfers between participants in
Euroclear and Cedel will be effected in the ordinary way in accordance with
their respective rules and operating procedures.

DTC has advised the Company that it will take any action permitted to be
taken by a holder of Senior Notes (including the presentation of Senior Notes
for exchange as described below) only at the direction of one or more
participants to whose account the DTC interests in the Global Notes is credited
and only in

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respect of such portion of the aggregate principal amount of Senior Notes as to
which such participant or participants has or have given such direction.
However, if there is an Event of Default under the Senior Notes, DTC will
exchange the Global Notes for Certificated Notes which it will distribute to its
participants and which, if representing interests in the Restricted Global Note,
will be legended as set forth under the heading "Transfer Restrictions."

DTC has advised the Company as follows: DTC is a limited purpose trust
company organized under the laws of the State of New York, a "banking
organization" within the meaning of New York Banking Law, a member of the
Federal Reserve System, a "clearing corporation" within the meaning of the
Uniform Commercial Code and a "Clearing Agency" registered pursuant to the
provisions of Section 17A of the Securities Exchange Act of 1934. DTC was
created to hold securities for its participants and facilitate the clearance and
settlement of securities transactions between participants through electronic
book-entry changes in accounts of its participants, thereby eliminating the need
for physical movement of certificates. Participants include securities brokers
and dealers, banks, trust companies and clearing corporations and certain other
organizations. Indirect access to the DTC system is available to others such as
banks, brokers, dealers and trust companies that clear through or maintain a
custodial relationship with a participant, either directly or indirectly
("indirect participants").

Although DTC, Euroclear and Cedel have agreed to the foregoing procedures
in order to facilitate transfers of interest in the Global Notes among
participants of DTC, Euroclear and Cedel, they are under no obligation to
perform or continue to perform such procedures, and such procedures may be
discontinued at any time. Neither the Company nor the Trustee will have any
responsibility for the performance by DTC, Euroclear or Cedel or their
respective participants or indirect participants of their respective obligations
under the rules and procedures governing their operations.

CERTIFICATED NOTES

If DTC is at any time unwilling or unable to continue as a depositary for
the Global Notes and a successor depositary is not appointed by the Company
within 90 days, the Company will issue Certificated Notes in exchange for the
Global Notes which, in the case of Senior Notes issued in exchange for the
Restricted Global Note, will bear the legend referred to under the heading
"Transfer Restrictions."

SAME-DAY SETTLEMENT

Settlement by purchasers of the Senior Notes will be made in immediately
available funds. All payments by the Company to DTC of principal and interest
will be made in immediately available funds.

So long as any Senior Notes or Exchange Notes are represented by Global
Notes registered in the name of DTC or its nominee, such Senior Notes or
Exchange Notes will trade in DTC's Same-Day Funds Settlement system, and
secondary market trading activity in such Senior Notes or Exchange Notes will
therefore be required by DTC to settle in immediately available funds.

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DESCRIPTION OF CERTAIN OTHER INDEBTEDNESS

9 1/4% SENIOR NOTES DUE 2004

On February 17, 1994, the Company issued $105.0 million aggregate principal
amount of 9 1/4% Senior Notes in an underwritten public offering. The 9 1/4%
Senior Notes are senior unsecured obligations of the Company and will rank pari
passu with the Senior Notes.

The 9 1/4% Senior Notes bear interest at a rate of 9 1/4% per annum payable
semi-annually on February l and August l of each year and mature on February 1,
2004. The 9 1/4% Senior Notes are redeemable at the option of the Company, in
whole or in part, at any time after February 1, 1999 at the various redemption
prices set forth in the 9 1/4% Senior Note Indenture, plus accrued interest to
the date of redemption. In addition, prior to February 1, 1997, up to $36.75
million of 9 1/4% Senior Notes may be redeemed at 109.25% of the principal
amount thereof, plus accrued interest, with the net proceeds of one or more
public equity offerings by the Company.

Upon a Change of Control Triggering Event (as defined in the 9 1/4%
Indenture), each holder of 9 1/4% Senior Notes will have the right to require
the Company to repurchase such 9 1/4% Senior Notes at 101% of the principal
amount thereof plus accrued and unpaid interest to the repurchase date. The
Credit Suisse Credit Facility limits the Company's ability to redeem the 9 1/4%
Senior Notes.

Similar to the Indenture governing the Senior Notes (and subject to similar
qualifications), the 9 1/4% Indenture contains certain covenants that, among
other things, limits (i) the incurrence of additional debt by the Company and
its subsidiaries, (ii) the payment of dividends on and redemptions of capital
stock by the Company and its subsidiaries, (iii) the use of proceeds from the
sale of assets and subsidiary stock, (iv) transactions with affiliates, (v) the
incurrence of liens, (vi) sale and leaseback transactions and (vii)
consolidations, mergers and certain transfers of assets.

The foregoing summary describes certain provisions of the 9 1/4% Indenture
and the 9 1/4% Senior Notes, a copy of each of which is available upon request
made to the Company. The foregoing summary does not purport to be complete and
is subject to and is qualified in its entirety by reference to the 9 1/4%
Indenture and the form of 9 1/4% Senior Notes.

OTHER

See "Description of Facilities" and "Management's Discussion and Analysis
of Results of Operations and Financial Condition" for a description of other
indebtedness of the Company, including the Credit Suisse Credit Facility.

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TRANSFER RESTRICTIONS

Unless and until an Old Note is exchanged for a New Note pursuant to the
Exchange Offer, it will bear the following legend on the face thereof.

THIS NOTE HAS NOT BEEN REGISTERED UNDER THE U.S. SECURITIES ACT OF 1933,
AS AMENDED (THE "SECURITIES ACT"), AND, ACCORDINGLY, MAY NOT BE OFFERED
OR SOLD WITHIN THE UNITED STATES OR TO, OR FOR THE ACCOUNT OR BENEFIT
OF, U.S. PERSONS EXCEPT AS SET FORTH IN THE FOLLOWING SENTENCE. BY ITS
ACQUISITION HEREOF, THE HOLDER (1) REPRESENTS THAT (A) IT IS A
"QUALIFIED INSTITUTIONAL BUYER" (AS DEFINED IN RULE 144A UNDER THE
SECURITIES ACT) OR (B) IT IS AN INSTITUTIONAL "ACCREDITED INVESTOR" (AS
DEFINED IN RULE 501(a)(1), (2), (3) OR (7) OF REGULATION D UNDER THE
SECURITIES ACT) (AN "INSTITUTIONAL ACCREDITED INVESTOR") OR (C) IT IS
NOT A U.S. PERSON AND IS ACQUIRING THIS NOTE IN AN OFFSHORE TRANSACTION
IN COMPLIANCE WITH REGULATION S UNDER THE SECURITIES ACT, (2) AGREES
THAT IT WILL NOT, WITHIN THREE YEARS AFTER THE LATER OF THE ORIGINAL
ISSUANCE OF THIS NOTE OR THE LAST DATE ON WHICH THIS NOTE WAS HELD BY AN
AFFILIATE OF THE COMPANY, RESELL OR OTHERWISE TRANSFER THIS NOTE EXCEPT
(A) TO THE COMPANY OR ANY SUBSIDIARY THEREOF, (B) INSIDE THE UNITED
STATES TO A QUALIFIED INSTITUTIONAL BUYER IN COMPLIANCE WITH RULE 144A
UNDER THE SECURITIES ACT, (C) INSIDE THE UNITED STATES TO AN
INSTITUTIONAL ACCREDITED INVESTOR THAT, PRIOR TO SUCH TRANSFER,
FURNISHES TO THE TRUSTEE A SIGNED LETTER CONTAINING CERTAIN
REPRESENTATIONS AND AGREEMENTS RELATING TO THE RESTRICTIONS ON TRANSFER
OF THIS NOTE (THE FORM OF WHICH LETTER CAN BE OBTAINED FROM THE TRUSTEE)
AND, IF SUCH TRANSFER IS IN RESPECT OF AN AGGREGATE PRINCIPAL AMOUNT OF
NOTES AT THE TIME OF TRANSFER OF LESS THAN $250,000, AN OPINION OF
COUNSEL ACCEPTABLE TO THE COMPANY THAT SUCH TRANSFER IS IN COMPLIANCE
WITH THE SECURITIES ACT, (D) OUTSIDE THE UNITED STATES IN AN OFFSHORE
TRANSACTION IN COMPLIANCE WITH RULE 904 UNDER THE SECURITIES ACT, (E)
PURSUANT TO THE EXEMPTION FROM REGISTRATION PROVIDED BY RULE 144 UNDER
THE SECURITIES ACT (IF AVAILABLE) OR (F) PURSUANT TO AN EFFECTIVE
REGISTRATION STATEMENT UNDER THE SECURITIES ACT AND (3) AGREES THAT IT
WILL DELIVER TO EACH PERSON TO WHOM THIS NOTE IS TRANSFERRED A NOTICE
SUBSTANTIALLY TO THE EFFECT OF THIS LEGEND. IN CONNECTION WITH ANY
TRANSFER OF THIS NOTE WITHIN THREE YEARS AFTER THE LATER OF THE ORIGINAL
ISSUANCE OF THE NOTE OR THE LAST DATE ON WHICH THIS NOTE WAS HELD BY AN
AFFILIATE OF THE COMPANY, THE HOLDER MUST CHECK THE APPROPRIATE BOX SET
FORTH ON THE REVERSE HEREOF RELATING TO THE MANNER OF SUCH TRANSFER AND
SUBMIT THIS NOTE TO THE TRUSTEE. IF THE PROPOSED TRANSFEREE IS AN
INSTITUTIONAL ACCREDITED INVESTOR, THE HOLDER MUST, PRIOR TO SUCH
TRANSFER, FURNISH TO THE TRUSTEE AND THE COMPANY SUCH CERTIFICATIONS,
LEGAL OPINIONS OR OTHER INFORMATION AS EITHER OF THEM MAY REASONABLY
REQUIRE TO CONFIRM THAT SUCH TRANSFER IS BEING MADE PURSUANT TO AN
EXEMPTION FROM, OR IN A TRANSACTION NOT SUBJECT TO, THE REGISTRATION
REQUIREMENTS OF THE SECURITIES ACT. AS USED HEREIN, THE TERMS "OFFSHORE
TRANSACTION", "UNITED STATES" AND "U.S. PERSON" HAVE THE MEANINGS GIVEN
TO THEM BY REGULATION S UNDER THE SECURITIES ACT. THE NOTE INDENTURE
CONTAINS A PROVISION REQUIRING THE TRUSTEE TO REFUSE TO REGISTER ANY
TRANSFER OF THIS NOTE IN VIOLATION OF THE FOREGOING RESTRICTIONS.

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<PAGE> 127

The New Notes will not contain such restrictive legend or be otherwise
subject to restrictions on their transfer, except each Global Note shall bear
the following legend on the face thereof:

UNLESS THIS NOTE IS PRESENTED BY AN AUTHORIZED REPRESENTATIVE OF
THE DEPOSITORY TRUST COMPANY, A NEW YORK CORPORATION ("DTC"), TO THE
COMPANY OR ITS AGENT FOR REGISTRATION OF TRANSFER, EXCHANGE OR PAYMENT,
AND ANY NOTE ISSUED IS REGISTERED IN THE NAME OF CEDE & CO. OR IN SUCH
OTHER NAME AS IS REQUESTED BY AN AUTHORIZED REPRESENTATIVE OF DTC (AND
ANY PAYMENT IS MADE TO CEDE & CO. OR TO SUCH OTHER ENTITY AS IS
REQUESTED BY AN AUTHORIZED REPRESENTATIVE OF DTC), ANY TRANSFER, PLEDGE
OR OTHER USE HEREOF FOR VALUE OR OTHERWISE BY OR TO ANY PERSON IS
WRONGFUL INASMUCH AS THE REGISTERED OWNER HEREOF, CEDE & CO., HAS AN
INTEREST HEREIN.

TRANSFERS OF THIS NOTE SHALL BE LIMITED TO TRANSFERS IN WHOLE, BUT
NOT IN PART, TO NOMINEES OF CEDE & CO. OR TO A SUCCESSOR THEREOF OR SUCH
SUCCESSOR'S NOMINEE AND TRANSFERS OF PORTIONS OF THIS NOTE SHALL BE
LIMITED TO TRANSFERS MADE IN ACCORDANCE WITH THE RESTRICTIONS SET FORTH
IN SECTION 2.08 OF THE INDENTURE.

CERTAIN FEDERAL INCOME TAX CONSIDERATIONS

The discussion set forth in this summary is based on the provisions of the
Internal Revenue Code of 1986, as amended (the "Code"), final, temporary and
proposed Treasury regulations thereunder ("Treasury Regulations"), and
administrative and judicial interpretations thereof, all as in effect on the
date hereof and all of which are subject to change (possibly on a retroactive
basis). Legislative, judicial or administrative changes or interpretations may
be forthcoming that could affect the tax consequences to holders of Senior
Notes.

This summary is for general information only and does not purport to
address all of the federal income tax consequences that may be applicable to a
holder of Senior Notes. The tax treatment of a holder of Senior Notes may vary
depending on its particular situation. For example, certain holders, including
individual retirement and other tax-deferred accounts, insurance companies,
tax-exempt organizations, financial institutions, broker-dealers, foreign
corporations and individuals who are not citizens or residents of the United
States, may be subject to special rules not discussed below. In addition, this
discussion addresses the tax consequences to the initial holders of the Senior
Notes and not the tax consequences to subsequent transfers of the Senior Notes.

EACH HOLDER SHOULD CONSULT ITS OWN TAX ADVISOR WITH RESPECT TO THE FEDERAL
INCOME TAX CONSEQUENCES SET FORTH BELOW AND ANY OTHER FEDERAL, STATE, LOCAL OR
FOREIGN TAX CONSEQUENCES OF EXCHANGING OLD NOTES FOR NEW NOTES AND OF HOLDING
AND DISPOSING OF THE NEW NOTES.

EXCHANGE OFFER

Under Section 1001 of the Code modifications in debt instruments may in
certain cases be deemed to constitute a taxable exchange of the existing debt
instrument for a new debt instrument. The Internal Revenue Service (the "IRS")
has issued Regulations providing rules for determining when a modification of a
debt instrument constitutes a taxable exchange. It is not clear whether or not
the exchange of Old Notes for New Notes (the "Exchange") pursuant to the
Exchange Offer will be treated as an "exchange" for federal income tax purposes.
Because the terms of the New Notes do not appear to significantly modify the
terms of the Old Notes, under Treasury Regulations Section 1.1001-3 each New
Note should be viewed as a continuation of the corresponding Old Note, the
issuance of the New Note should be disregarded, and a holder exchanging an Old
Note for a New Note (as well as a non-exchanging holder) should not recognize
any gain or loss as a result of the Exchange (or the Exchange Offer).

127
<PAGE> 128

Even if the IRS were to treat the Exchange of Old Notes for New Notes as an
"exchange" for federal income tax purposes, the Exchange should nevertheless
constitute a "recapitalization" for federal income tax purposes. Holders
exchanging Old Notes pursuant to such a recapitalization should not recognize
any gain or loss upon the Exchange. In such event, if the New Notes are "traded
on an established securities market" (as defined for purposes of Section
1273(b)(3) of the Code), the New Notes may be issued with original issue
discount ("OID") equal to any excess of the stated redemption price at maturity
of the New Notes over the fair market value of the New Notes on the day of the
Exchange. Such OID would be included in the gross income of the holders of the
New Notes as described below. However, in the case of a holder whose tax basis
for an Old Note exceeds the fair market value (on the day of the Exchange) of
the New Notes received in exchange therefor, such OID may be reduced or
eliminated by amortization deductions attributable to such excess. If the New
Notes are deemed not to be "traded on an established securities market," the
issue price of the New Notes in a deemed "exchange" should be the New Notes'
stated redemption price at maturity, which should result in no OID with respect
to the New Notes. Although the Company cannot predict whether an active public
market for the New Notes will develop, the Company believes the New Notes will
be deemed to be "traded on an established securities market" for federal income
tax purposes.

STATED INTEREST

A holder of a New Note will be required to report as income for federal
income tax purposes interest earned on a New Note in accordance with the
holder's method of tax accounting. A holder of a New Note using the accrual
method of accounting for tax purposes is, as a general rule, required to include
interest in ordinary income as such interest accrues, while a cash basis holder
must include interest income when cash payments are received (or made available
for receipt) by such holder.

ORIGINAL ISSUE DISCOUNT

As explained under the section entitled "Certain Federal Income Tax
Considerations -- Exchange Offer," if the Exchange of the Old Notes for the New
Notes is treated as an "exchange" for federal income tax purposes, and the New
Notes are "traded on an established securities market" (as defined for purposes
of Section 1273(b)(3) of the Code), the New Notes may be issued with OID equal
to the excess of the stated redemption price at maturity of the New Notes over
the fair market value of the New Notes on the day of the Exchange. The following
summary is a general discussion of the federal income tax consequences of the
ownership of the New Notes if they are deemed to be issued with OID. The summary
is based upon Treasury Regulations issued by the IRS (the "OID Regulations").

If the New Notes are issued with OID within the meaning of Sections 1272
and 1273 of the Code and the OID Regulations, holders of the New Notes generally
will be required to include such OID in gross income as it accrues in advance of
the receipt of the cash attributable to such income. The total amount of OID
with respect to each New Note will be any excess of its "stated redemption price
at maturity" over its "issue price"; provided that a New Note will not be deemed
to have OID if such excess is less than 1/4 of 1% of the New Note's stated
redemption price at maturity multiplied by the number of complete years to its
maturity from its issue date. The "issue price" of a New Note will be equal to
its fair market value when issued. The "stated redemption price at maturity" of
a New Note is the sum of all payments provided by the New Note other than
"qualified stated interest" payments. The term "qualified stated interest"
generally means stated interest that is unconditionally payable in cash or
property (other than debt instruments of the issuer) at least annually at a
single fixed rate.

A holder of a New Note must include OID in income for federal income tax
purposes as it accrues under a "constant yield method" in advance of receipt of
cash payments attributable to such income, regardless of such holder's method of
accounting for tax purposes. In general, the amount of OID included in income by
the initial holder of a New Note is the sum of the "daily portion" of OID with
respect to such New Note for each day during the taxable year on which such
holder held such New Note. The "daily portion" of OID on any New Note is
determined by allocating to each day in any "accrual period" a ratable portion
of the OID allocable to that accrual period. The "accrual period" with respect
to the New Notes is the six-month period

128
<PAGE> 129

(or shorter period from the date of original issue of the New Note) which ends
on May 15 or November 15 in each calendar year.

Under the "constant yield method," the amount of OID allocable to each
accrual period is equal to the product of the New Note's "adjusted issue price"
at the beginning of such accrual period and its "yield to maturity" (determined
on the basis of compounding at the close of each accrual period). The "adjusted
issue price" of a New Note at the beginning of the first accrual period is the
issue price. Thereafter, the adjusted issue price of a New Note is the sum of
the issue price of the New Note plus the amount of OID allocable to all prior
periods, minus any prior payments on the New Note other than payments of
"qualified stated interest." The "yield to maturity" or "yield" of a New Note is
the discount rate that, when used in computing the present value of all
principal and interest payments to be made under the New Note, produces an
amount equal to the issue price of the New Note. The yield must be constant over
the term of the New Note.

The Company is required to furnish certain information to the IRS and will
furnish annually to record holders of the New Notes information with respect to
the OID, if any, accruing during the calendar year (as well as interest paid
during that year). The Company intends to take the position that the Exchange
does not constitute an exchange for federal income tax purposes and that there
is no OID with respect to the New Notes.

SALE, EXCHANGE, OR REDEMPTION OF A NOTE

Upon the sale, exchange (other than pursuant to the Exchange as discussed
above), or redemption of a Senior Note, a holder will recognize taxable gain or
loss equal to the difference between (i) the amount of cash and the fair market
value of property received (other than amounts received attributable to interest
not previously taken into account, which amount will be treated as interest
received), and (ii) the holder's adjusted tax basis in the Senior Note. A
holder's adjusted tax basis in a Senior Note generally will equal the cost of
the Senior Note to the holder, increased by the amount of any OID previously
included in income by the holder with respect to the Senior Note and reduced by
any payments previously received by the holder with respect to the Senior Note,
other than qualified stated interest payments, and by any premium amortization
deductions previously claimed by the holder. Provided the Senior Note is a
capital asset in the hands of the holder and has been held for more than one
year, any gain or loss recognized by the holder will generally be a long-term
capital gain or loss.

BACKUP WITHHOLDING

Under the backup withholding rules, a holder of a Senior Note may be
subject to a backup withholding at the rate of 31% on interest paid on the
Senior Note or on any other cash payment with respect to the sale or redemption
of the Senior Note, unless (i) such holder is a corporation or comes under
certain other exempt categories and when required demonstrates this fact or (ii)
such holder provides a correct taxpayer identification number, certifies as to
no loss of exemption from backup withholding, and otherwise complies with
applicable requirements of the backup withholding rules in the Treasury
Regulations. Prospective holders of the Senior Notes (who have not previously
furnished a Form W-9 with respect to the Old Notes) will be required to complete
a Form W-9 in order to provide the required information to the Company. A holder
of a Senior Note who does not provide the Company with the holder's correct
taxpayer identification number may be subject to penalties imposed by the IRS.

The Company will report to the holders of the Senior Notes and to the IRS
the amount of any "reportable payments" for each calendar year and the amount of
tax withheld, if any, with respect to payments on the Senior Notes.

Any amounts withheld under the backup withholding rules will be allowed as
a refund or a credit against the holder's federal income tax liability, provided
that the required information is furnished to the IRS.

129
<PAGE> 130

THE FOREGOING DISCUSSION OF CERTAIN FEDERAL INCOME TAX CONSEQUENCES IS FOR
GENERAL INFORMATION ONLY AND IS NOT TAX ADVICE. ACCORDINGLY, EACH HOLDER SHOULD
CONSULT ITS OWN TAX ADVISOR WITH RESPECT TO THE TAX CONSEQUENCES OF THE
EXCHANGE, OWNERSHIP, AND DISPOSITION OF THE SENIOR NOTES (INCLUDING THE
APPLICABILITY AND EFFECT OF STATE, LOCAL, FOREIGN, AND OTHER TAX LAWS).

PLAN OF DISTRIBUTION

Each broker-dealer that receives New Notes for its own account pursuant to
the Exchange Offer must acknowledge that it will deliver a prospectus in
connection with any resale of such New Notes. This Prospectus, as it may be
amended or supplemented from time to time, may be used by a broker-dealer in
connection with resales of New Notes received in exchange for Old Notes where
such Old Notes were acquired as a result of market-making activities or other
trading activities. The Company has agreed that it will make this Prospectus, as
amended or supplemented, available to any broker-dealer for use in connection
with any such resale for a period of 180 days from the date of this Prospectus,
or such shorter period as will terminate when all Old Notes acquired by
broker-dealers for their own accounts as a result of market-making activities or
other trading activities have been exchanged for New Notes and resold by such
broker-dealers.

The Company will not receive any proceeds from any sale of New Notes by
broker-dealers. New Notes received by broker-dealers for their own accounts
pursuant to the Exchange Offer may be sold from time to time in one or more
transactions in the over-the-counter market or, in negotiated transactions or a
combination of such methods of resale, at market prices prevailing at the time
of resale, at prices related to such prevailing market prices or negotiated
prices. Any such resale may be made directly to purchasers or to or through
brokers or dealers who may receive compensation in the form of commissions or
concessions from any such broker-dealer and/or the purchasers of any such New
Notes. Any broker-dealer that resells New Notes that were received by it for its
own account pursuant to the Exchange Offer and any broker or dealer that
participates in a distribution of such New Notes may be deemed to be an
"Underwriter" within the meaning of the Securities Act and any profit on any
such resale of New Notes and any commissions or concessions received by any such
persons may be deemed to be underwriting compensation under the Securities Act.
The Letter of Transmittal states that by acknowledging that it will deliver and
by delivering a prospectus, a broker-dealer will not be deemed to admit that it
is an "underwriter" within the meaning of the Securities Act.

For a period of 180 days from the date of this Prospectus, or such shorter
period as will terminate when all Old Notes acquired by broker-dealers for their
own accounts as a result of market-making activities or other trading activities
have been exchanged for New Notes and resold by such broker-dealers, the Company
will promptly send additional copies of this Prospectus and any amendment or
supplement to this Prospectus to any broker-dealer that requests such documents
in the Letter of Transmittal. The Company has agreed to indemnify such
broker-dealers against certain liabilities, including liabilities under the
Securities Act.

LEGAL MATTERS

The validity of the New Notes will be passed upon for the Company by
Brobeck, Phleger & Harrison LLP, San Francisco, California.

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

130
<PAGE> 131

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, 1996, appearing in this Prospectus and
Registration Statement have been audited by Ernst & Young L.L.P. 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.

131
<PAGE> 132

(THIS PAGE INTENTIONALLY LEFT BLANK)
<PAGE> 133

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 Shareholder'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-29
Condensed Consolidated Statements of Operations for the Six Months Ended June 30, 1996
and 1995 (unaudited)................................................................ F-30
Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 1996
and 1995 (unaudited)................................................................ F-31
Notes to Condensed Consolidated Financial Statements for the Six Months Ended June 30,
1996 and 1995 (unaudited)........................................................... F-32
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
Report of Independent Public Accountants.............................................. F-37
Consolidated Balance Sheets, December 31, 1995 and 1994............................... F-38
Consolidated Statement of Operations for the Years Ended December 31, 1995, 1994 and
1993................................................................................ F-39
Consolidated Statement of Changes in Partners' Deficit for the Years Ended December
31, 1995, 1994 and 1993............................................................. F-40
Consolidated Statement of Cash Flows for the Years Ended December 31, 1995, 1994 and
1993................................................................................ F-41
Notes to Consolidated Financial Statements for the Years Ended December 31, 1995, 1994
and 1993............................................................................ F-42
CALPINE GEYSERS COMPANY, L.P.
Report of Independent Public Accountants.............................................. F-51
Statement of Operations for the Period from January 1, 1993 to April 18, 1993......... F-52
Statement of Cash Flows for the Period from January 1, 1993 to April 18, 1993......... F-53
Notes to Financial Statements for the Period from January 1, 1993 to April 18, 1993... F-54
LFC NO. 38 CORP. AND PORTSMOUTH LEASING CORPORATION AND SUBSIDIARIES
Report of Independent Public Accountants.............................................. F-59
Combined Balance Sheets, December 31, 1994 and 1993................................... F-60
Combined Statement of Operations for the Years Ended December 31, 1994 and 1993....... F-61
Combined Statements of Changes in Shareholder's Deficiency for the Years Ended
December 31, 1994 and 1993.......................................................... F-62
Combined Statements of Cash Flows for the Years Ended December 31, 1994 and 1993...... F-63
Notes to Combined Financial Statements for the Years Ended December 31, 1994 and
1993................................................................................ F-64
LFC NO. 60 CORP. AND SUBSIDIARY
Report of Independent Public Accountants.............................................. F-68
Consolidated Balance Sheets, December 31, 1994 and 1993............................... F-69
Consolidated Statements of Operations for the Years Ended December 31, 1994 and
1993................................................................................ F-70
Consolidated Statements of Changes in Shareholder's Deficiency for the Years Ended
December 31, 1994 and 1993.......................................................... F-71
Consolidated Statements of Cash Flows for the Years Ended December 31, 1994 and
1993................................................................................ F-72
Notes to Consolidated Financial Statements for the Years Ended December 31, 1994 and
1993................................................................................ F-73
</TABLE>

F-1
<PAGE> 134

<TABLE>
<CAPTION>
PAGE
----
<S> <C>
BAF ENERGY, A CALIFORNIA LIMITED PARTNERSHIP
Report of Independent Public Accountants.............................................. F-76
Balance Sheets, October 31, 1995 and 1994............................................. F-77
Statements of Income for the Years Ended October 31, 1995, 1994 and 1993.............. F-78
Statements of Partners' Equity for the Years Ended October 31, 1995, 1994 and 1993.... F-79
Statements of Cash Flows for the Years Ended October 31, 1995, 1994 and 1993.......... F-80
Notes to Financial Statements for the Years Ended October 31, 1995, 1994 and 1993..... F-81
Condensed Balance Sheets as of January 31, 1996 (unaudited) and October 31, 1995...... F-85
Condensed Statements of Income for the Three Months Ended January 31, 1996 and 1995
(unaudited)......................................................................... F-86
Condensed Statements of Cash Flows for the Three Months Ended January 31, 1996 and
1995 (unaudited).................................................................... F-87
Notes to Condensed Financial Statements as of January 31, 1996........................ F-88
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> 135

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 matters
discussed in Note 26, as to which the
date is
September 13, 1996)

F-3
<PAGE> 136

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 1995 AND 1994
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE INFORMATION)

<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 SHAREHOLDER'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)
Shareholder'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 shareholder's equity............................................ 25,227 18,649
-------- --------
Total liabilities and shareholder's equity............................ $554,531 $421,372
======== ========
</TABLE>

The accompanying notes are an integral part of these consolidated financial
statements.

F-4
<PAGE> 137

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
======== ======= =======
Weighted averages shares outstanding....................... 2,214 2,177 2,164
As adjusted earnings per share assuming conversion of
preferred stock:
As adjusted weighted average shares outstanding.......... 14,151
========
Net income per share............................. $ 0.52
========
</TABLE>

The accompanying notes are an integral part of these consolidated financial
statements.

F-5
<PAGE> 138

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDER'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....................... 2,000 $ 20 $6,204 $ 4,281 $ -- $10,505
Dividend ($0.40 per share)..................... -- -- -- (800 ) -- (800)
Net income..................................... -- -- -- 3,754 -- 3,754
Cumulative translation adjustment.............. -- -- -- -- (31) (31)
----- --- ------ ------- ---- -------
Balance, December 31, 1993....................... 2,000 20 6,204 7,235 (31) 13,428
Dividend ($0.40 per share)..................... -- -- -- (800 ) -- (800)
Net income..................................... -- -- -- 6,021 -- 6,021
----- --- ------ ------- ---- -------
Balance, December 31, 1994....................... 2,000 20 6,204 12,456 (31) 18,649
Dividend ($0.40 per share)..................... -- -- -- (800 ) -- (800)
Net income..................................... -- -- -- 7,378 -- 7,378
----- --- ------ ------- ---- -------
Balance, December 31, 1995....................... 2,000 $ 20 $6,204 $19,034 $(31) $25,227
===== === ====== ======= ==== =======
</TABLE>

The accompanying notes are an integral part of these consolidated financial
statements.

F-6
<PAGE> 139

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> 140

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 May 1992. Had the Company applied this
principle, the revenues of the Company recorded for the years

F-8
<PAGE> 141

CALPINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 computed using the straight-line method over their
estimated useful lives. It is reasonably possible that the

F-9
<PAGE> 142

CALPINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 Company's initial public
offering (using the as-if-converted method). If the offering contemplated by the

F-10
<PAGE> 143

CALPINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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> 144

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> 145

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> 146

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......................................... $ 2.20 $ 5.38
</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> 147

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> 148

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> 149

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> 150

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> 151

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> 152

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 SHAREHOLDER

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> 153

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> 154

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> 155

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> 156

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

The Company has Class A and Class B common stock. Each class of common
stock fully participates in any dividends declared. Although Class A
shareholders are precluded from receiving stock dividends of Class B common
stock, Class B shares are convertible into Class A shares on a share-for-share
basis at the option of the holder. Each share of Class A common stock is
entitled to one vote per share, and each share of Class B common stock is
entitled to ten votes per share.

As of December 31, 1995, no shares of Class A common stock were
outstanding, and 2,000,000 shares of Class B common stock were outstanding. All
of the Class B shares are held by Electrowatt.

F-24
<PAGE> 157

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 500,000 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.......................... 180,000 $ 2.60 December 31, 2002
April 1, 1993.............................. 34,500 $ 9.62 April 1, 2003
October 1, 1994............................ 57,000 $23.74 October 1, 2004
January 1, 1995............................ 80,550 $25.48 January 1, 2005
June 16, 1995.............................. 5,000 $25.48 June 16, 2005
-------
357,050
=======
</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 234,375. 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> 158

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.

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

F-26
<PAGE> 159

CALPINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

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

F-27
<PAGE> 160

CALPINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.

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-28
<PAGE> 161

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 DECEMBER 31,
(NOTE 12) 1995
JUNE 30, -------------------- ------------
1996
--------
(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-29
<PAGE> 162

CALPINE CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS)
(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:
As adjusted weighted average shares outstanding.................... 14,400
========
Net income per share....................................... $ 0.31
========
</TABLE>

The accompanying notes are an integral part of these condensed consolidated
financial statements.

F-30
<PAGE> 163

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-31
<PAGE> 164

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-32
<PAGE> 165

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-33
<PAGE> 166

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-34
<PAGE> 167

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 discussed in Note
8 below and a $45.0 million loan from The Bank of Nova Scotia which bears
interest at 7.5% and matures upon the earlier of the issuance of the Senior
Notes Due 2006 (see Note 9) or August 23, 1996. The Company expects to repay the
short-term borrowings from a portion of the net proceeds of the Senior Notes Due
2006 to be issued in May 1996.

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 a mutually agreed margin, for a total interest rate of approximately 6.05%
as of March 31, 1996. 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-35
<PAGE> 168

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.

12. SUBSEQUENT EVENT

F-36
<PAGE> 169

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-37
<PAGE> 170

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-38
<PAGE> 171

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-39
<PAGE> 172

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-40
<PAGE> 173

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-41
<PAGE> 174

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-42
<PAGE> 175

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-43
<PAGE> 176

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-44
<PAGE> 177

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-45
<PAGE> 178

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-46
<PAGE> 179

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:

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-47
<PAGE> 180

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-48
<PAGE> 181

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-49
<PAGE> 182

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-50
<PAGE> 183

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-51
<PAGE> 184

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-52
<PAGE> 185

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-53
<PAGE> 186

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-54
<PAGE> 187

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-55
<PAGE> 188

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-56
<PAGE> 189

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-57
<PAGE> 190

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-58
<PAGE> 191

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.

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-59
<PAGE> 192

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-60
<PAGE> 193

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-61
<PAGE> 194

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-62
<PAGE> 195

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-63
<PAGE> 196

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.

F-64
<PAGE> 197

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-65
<PAGE> 198

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-66
<PAGE> 199

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-67
<PAGE> 200

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.

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-68
<PAGE> 201

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-69
<PAGE> 202

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-70
<PAGE> 203

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-71
<PAGE> 204

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-72
<PAGE> 205

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.

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-73
<PAGE> 206

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-74
<PAGE> 207

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-75
<PAGE> 208

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.

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-76
<PAGE> 209

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-77
<PAGE> 210

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-78
<PAGE> 211

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-79
<PAGE> 212

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-80
<PAGE> 213

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-81
<PAGE> 214

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-82
<PAGE> 215

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-83
<PAGE> 216

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-84
<PAGE> 217

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-85
<PAGE> 218

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-86
<PAGE> 219

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-87
<PAGE> 220

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-88
<PAGE> 221

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-89
<PAGE> 222

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.

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-90
<PAGE> 223

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-91
<PAGE> 224

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-92
<PAGE> 225

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-93
<PAGE> 226

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-94
<PAGE> 227

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-95
<PAGE> 228

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-96
<PAGE> 229

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-97
<PAGE> 230

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-98
<PAGE> 231

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-99
<PAGE> 232

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-100
<PAGE> 233

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