CALPINE CORP, 424B4, 1999-10-29

CALPINE CORP
424B4, 1999-10-29
COGENERATION SERVICES & SMALL POWER PRODUCERS

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<PAGE> 1
Filed Pursuant to Rule 424(b)(4)
Registration No. 333-87427

7,200,000 Shares

LOGO
CALPINE CORPORATION

Common Stock
------------------

Our common stock is listed on The New York Stock Exchange under the symbol
"CPN." On October 27, 1999, the last sale price of the common stock was
$46.3125.

The underwriters have an option to purchase a maximum of 1,080,000
additional shares to cover over-allotments of shares.

Concurrently with this offering, we are offering $240.0 million of
convertible preferred securities of a subsidiary trust by means of a separate
prospectus. The underwriters of the convertible trust preferred securities
offering have an option to purchase a maximum of $36.0 million of convertible
preferred securities to cover over-allotments. This offering and the convertible
trust preferred securities offering are not contingent on each other.

INVESTING IN OUR COMMON STOCK INVOLVES RISKS. SEE "RISK FACTORS" ON PAGE 9.

<TABLE>
<CAPTION>
UNDERWRITING PROCEEDS TO
PRICE TO DISCOUNTS AND CALPINE
PUBLIC COMMISSIONS CORPORATION
------------------- ------------------- -------------------
<S> <C> <C> <C>
Per Share.................. $46.3125 $1.72 $44.5925
Total...................... $333,450,000 $12,384,000 $321,066,000
</TABLE>

Delivery of the shares of common stock will be made on or about November 2,
1999.

Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved of these securities or determined if this
prospectus is truthful or complete. Any representation to the contrary is a
criminal offense.

CREDIT SUISSE FIRST BOSTON
CIBC WORLD MARKETS
DONALDSON, LUFKIN & JENRETTE

GOLDMAN, SACHS & CO.
SALOMON SMITH BARNEY
GERARD KLAUER MATTISON & CO.

The date of this prospectus is October 27, 1999.
<PAGE> 2

[Depiction of Delta Energy Center.]

"Delta Energy Center, a proposed 880 megawatt gas-fired facility located in
Pittsburg, California."

[Depiction of Pasadena Power Plant.]

"Pasadena Power Plant, a 240 megawatt gas-fired facility located in Pasadena,
Texas."
<PAGE> 3

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

TABLE OF CONTENTS

<TABLE>
<CAPTION>
Page
----
<S> <C>
PROSPECTUS SUMMARY.................. 1
RISK FACTORS........................ 9
WHERE YOU CAN FIND MORE
INFORMATION....................... 18
FORWARD-LOOKING STATEMENTS.......... 19
USE OF PROCEEDS..................... 20
PRICE RANGE OF COMMON STOCK......... 21
DIVIDEND POLICY..................... 21
CAPITALIZATION...................... 22
SELECTED CONSOLIDATED FINANCIAL
DATA.............................. 23
PRO FORMA CONSOLIDATED FINANCIAL
DATA.............................. 25
</TABLE>

<TABLE>
<CAPTION>
Page
----
<S> <C>
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS..................... 27
BUSINESS............................ 43
MANAGEMENT.......................... 70
PRINCIPAL STOCKHOLDERS.............. 73
DESCRIPTION OF CAPITAL STOCK........ 75
UNDERWRITING........................ 77
NOTICE TO CANADIAN RESIDENTS........ 79
LEGAL MATTERS....................... 80
EXPERTS............................. 80
</TABLE>

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

YOU SHOULD RELY ONLY ON THE INFORMATION CONTAINED IN THIS DOCUMENT OR TO
WHICH WE HAVE REFERRED YOU. WE HAVE NOT AUTHORIZED ANYONE TO PROVIDE YOU WITH
INFORMATION THAT IS DIFFERENT. THIS DOCUMENT MAY ONLY BE USED WHERE IT IS LEGAL
TO SELL THESE SECURITIES. THE INFORMATION CONTAINED IN THIS DOCUMENT MAY ONLY BE
ACCURATE ON THE DATE OF THIS DOCUMENT.

i
<PAGE> 4

PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus.
This summary is not complete and does not contain all of the information that
you should consider before investing in the common stock. You should carefully
read the entire prospectus, including the risk factors, the financial statements
and the documents incorporated by reference into it. The terms "Calpine," "our
company," "our" and "we," as used in this prospectus, refer to Calpine
Corporation and its consolidated subsidiaries.

All information in this prospectus reflects the 2 for 1 stock split
effective on October 7, 1999.

THE COMPANY

Calpine is a leading independent power company engaged in the development,
acquisition, ownership and operation of power generation facilities and the sale
of electricity predominantly in the United States. We have experienced
significant growth in all aspects of our business over the last five years.
Currently, we own interests in 38 power plants having an aggregate capacity of
3,694 megawatts and have a transaction pending in which we will acquire 80% of
Cogeneration Corporation of America, which owns interests in 6 power plants with
an aggregate capacity of 579 megawatts. We also have 8 gas-fired projects and
one project expansion under construction having an aggregate capacity of 4,485
megawatts and have announced plans to develop 6 gas-fired power plants with a
total capacity of 3,930 megawatts. Upon completion of pending acquisitions and
projects under construction, we will have interests in 52 power plants located
in 14 states having an aggregate capacity of 8,758 megawatts, of which we will
have a net interest in 7,381 megawatts. This represents significant growth from
the 342 megawatts of capacity we had at the end of 1993. Of this total
generating capacity, 90% will be attributable to gas-fired facilities and 10%
will be attributable to geothermal facilities.

As a result of our expansion program, our revenues, cash flow, earnings and
assets have grown significantly over the last five years, as shown in the table
below.

<TABLE>
<CAPTION>
COMPOUND ANNUAL
1993 1998 GROWTH RATE
-------- ---------- ---------------
(DOLLARS IN MILLIONS)
<S> <C> <C> <C>
Total Revenue....................... $ 69.9 $ 555.9 51%
EBITDA.............................. 42.4 255.3 43%
Net Income.......................... 3.8 45.7 64%
Total Assets........................ 302.3 1,728.9 42%
</TABLE>

Since our inception in 1984, we have developed substantial expertise in all
aspects of the development, acquisition and operation of power generation
facilities. We believe that the vertical integration of our extensive
engineering, construction management, operations, fuel management and financing
capabilities provides us with a competitive advantage to successfully implement
our acquisition and development program and has contributed to our significant
growth over the past five years.
1
<PAGE> 5

THE MARKET

The power industry represents the third largest industry in the United
States, with an estimated end-user market of over $250 billion of electricity
sales in 1998 produced by an aggregate base of power generation facilities with
a capacity of approximately 750,000 megawatts. In response to increasing
customer demand for access to low-cost electricity and enhanced services, new
regulatory initiatives have been and are continuing to be adopted at both the
state and federal level to increase competition in the domestic power generation
industry. The power generation industry historically has been largely
characterized by electric utility monopolies producing electricity from old,
inefficient, high-cost generating facilities selling to a captive customer base.
Industry trends and regulatory initiatives have transformed the existing market
into a more competitive market where end users purchase electricity from a
variety of suppliers, including non-utility generators, power marketers, public
utilities and others.

There is a significant need for additional power generating capacity
throughout the United States, both to satisfy increasing demand, as well as to
replace old and inefficient generating facilities. Due to environmental and
economic considerations, we believe this new capacity will be provided
predominantly by gas-fired facilities. We believe that these market trends will
create substantial opportunities for efficient, low-cost power producers that
can produce and sell energy to customers at competitive rates.

In addition, as a result of a variety of factors, including deregulation of
the power generation market, utilities, independent power producers and
industrial companies are disposing of power generation facilities. To date,
numerous utilities have sold or announced their intentions to sell their power
generation facilities and have focused their resources on the transmission and
distribution business segments. Many independent producers operating a limited
number of power plants are also seeking to dispose of their plants in response
to competitive pressures, and industrial companies are selling their power
plants to redeploy capital in their core businesses.

STRATEGY

Our strategy is to continue our rapid growth by capitalizing on the
significant opportunities in the power market, primarily through our active
development and acquisition programs. In pursuing our proven growth strategy, we
utilize our extensive management and technical expertise to implement a fully
integrated approach to the acquisition, development and operation of power
generation facilities. This approach uses our expertise in design, engineering,
procurement, finance, construction management, fuel and resource acquisition,
operations and power marketing, which we believe provides us with a competitive
advantage. The key elements of our strategy are as follows:

RECENT DEVELOPMENTS

Project Development and Construction. In May 1999, we completed a 35
megawatt expansion of our Clear Lake Power Plant to 412 megawatts, and the 169
megawatt Dighton Power Plant commenced commercial operations in August 1999.

We currently have nine projects under construction representing 4,485
additional megawatts. Of these new projects, we are currently expanding our
Pasadena facility by 545 megawatts to 785 megawatts and we have eight new power
plants under construction, including the Tiverton Power Plant in Rhode Island;
the Rumford Power Plant in Maine; the Westbrook Power Plant in Maine; the Sutter
Power Plant in California; the Los Medanos Power Plant in California; the South
Point Power Plant in Arizona; and the Magic Valley Power Plant in Texas; and the
Lost Pines 1 Power Plant in Texas. We have also announced plans to develop six
additional power generation facilities, totaling 3,930 megawatts, in California,
Texas, Arizona and Pennsylvania.

In July 1999, we announced an agreement with Credit Suisse First Boston,
New York branch and The Bank of Nova Scotia, as lead arrangers, for a $1.0
billion revolving construction loan facility. The credit facility will be
utilized to finance the construction of our development program. We expect to
finalize the documentation relating to this facility in the fourth quarter of
1999.

In August 1999, we announced the purchase of 18 F-class combustion turbines
from Siemens Westinghouse Power Corporation that will be capable of producing
4,900 megawatts of electricity in a combined-cycle configuration. Beginning in
2002, Siemens will deliver six turbines per year through 2004. Combined with our
existing turbine orders we have 69 turbines under contract, option, letter of
intent or other commitment capable of producing 17,745 megawatts.

Acquisitions. In March 1999, we completed the acquisition of Unocal
Corporation's Geysers geothermal steam fields in northern California for
approximately $102.1 million. The steam fields fuel our 12 Sonoma County power
plants, totaling 544 megawatts, purchased from Pacific Gas and Electric Company
in May 1999.

In May 1999 we completed the acquisition from Pacific Gas and Electric
Company of 14 geothermal power plants at The Geysers in northern California,
with a combined capacity of approximately 700 megawatts, for $212.8 million.
With the acquisition, we now own interests in and operate 18 geothermal power
plants that generate more than 800 megawatts of electricity, and we are the
nation's largest geothermal and green power producer. The combination of our
existing geothermal steam and power plant assets, the acquisition of the Sonoma
steam fields from Unocal, and the 14 power plants from Pacific Gas and Electric
Company allows us to fully integrate the steam and power plant operations at The
Geysers into one efficient, unified system to maximize the renewable natural
resource, lower overall production costs and extend the life of The Geysers.

In August 1999, we completed the acquisition of an additional 50% of the
Aidlin Power Plant from Edison Mission Energy (5%) and General Electric Capital
Corporation (45%) for a total purchase price of $7.2 million. We now own 55% of
the 20 megawatt Aidlin Geothermal Power Plant.
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<PAGE> 7

In August 1999, we announced an agreement with Cogeneration Corporation of
America Inc. ("CGCA") to acquire 80% of its common stock for $25.00 per share or
approximately $145.0 million. NRG Energy, Inc., a wholly owned subsidiary of
Northern States Power, will own the remaining 20%. The transaction is subject to
the approval of CGCA shareholders and we expect to consummate the acquisition by
year-end 1999. CGCA currently owns interests in six natural gas-fired power
plants, totaling 579 megawatts. The plants are located in Pennsylvania, New
Jersey, Illinois and Oklahoma.

In October 1999, we completed the acquisition of Sheridan Energy, Inc., a
natural gas exploration and production company, through a $41.0 million cash
tender offer. We purchased the outstanding shares of Sheridan Energy's common
stock for $5.50 per share. In addition, we redeemed $11.5 million of outstanding
preferred stock of Sheridan Energy. Sheridan Energy's oil and gas properties,
including 148 billion cubic feet equivalent of proven reserves, are located in
northern California and the Gulf Coast region, where we are developing low-cost
natural gas supplies and proprietary pipeline systems to support our
strategically-located natural gas-fired power plants.

In October 1999, we completed the acquisition of the Calistoga geothermal
power plant from FPL Energy and Caithness Corporation for approximately $78.0
million. Located in The Geysers region of northern California, Calistoga is a 67
megawatt facility which provides electricity to Pacific Gas and Electric Company
under a long term contract.

Enhancement of Existing Power Plants. In July 1999, we announced a
renegotiation of our Gilroy power sales agreement with Pacific Gas and Electric
Company. The amendment provides for the termination of the remaining 18 years of
the long-term contract in exchange for a fixed long-term payment schedule. The
amended agreement is subject to approval by the California Public Utilities
Commission, whose decision we expect to receive in the fourth quarter of 1999.
We will continue to sell the output from the Gilroy Power Plant through October
2002 to Pacific Gas and Electric Company and thereafter we will market the
output in the California wholesale power market.

Third Quarter 1999 Earnings. On October 22, 1999, we announced earnings
for the three and nine months ended September 30, 1999.

Net income was $42.9 million for the quarter ended September 30, 1999,
representing an 86% increase compared to net income of $23.1 million for the
third quarter in 1998. Diluted earnings per share after accounting for the
recently completed two-for-one stock split rose 37% to $0.74 per share for the
quarter, from $0.54 per share for the same period in 1998. Revenue for the
quarter increased 42% from $186.2 million a year ago to $263.6 million. Earnings
before interest, tax, depreciation and amortization increased 28% to $119.1
million for the quarter compared to $93.4 million a year ago.

For the nine months ended September 30, 1999, net income was $64.3 million,
an increase of 103% compared to $31.6 million for the same period in 1998.
Diluted earnings per share rose 61% to $1.21 per share, compared to $0.75 per
share for the nine months of 1998. Revenue for the nine months was $600.2
million, a 57% increase from $382.9 million a year ago. Earnings before
interest, tax, depreciation and amortization for the nine months rose 43% to
$268.2 million, form $187.0 million in 1998. Total assets as of September 30,
1999, were $2.7 billion, up 59% from $1.7 billion at December 31, 1998.

Financial results for the three and nine months ended September 30, 1999
benefited primarily from the acquisition of 14 geothermal power plants totaling
approximately 700 megawatts from Pacific Gas and Electric Company, completed in
May 1999. For certain of
4
<PAGE> 8

these facilities, revenue includes amounts received under a Reliability Must Run
contract with the California Independent System Operator, which is awaiting
final Federal Energy Regulatory Commission approval.

OUR PRINCIPAL EXECUTIVE OFFICES

Our principal executive offices are located at 50 West San Fernando Street,
San Jose, California 95113. Our telephone number is (408) 995-5115, and our
internet website address is www.calpine.com. The contents of our website are not
part of this prospectus.
5
<PAGE> 9

THE OFFERING

Common stock offered by
Calpine......................... 7,200,000 shares(1)

Common stock to be outstanding
after the offering............ 61,769,788 shares(1)(2)

Convertible preferred
offering........................ Concurrently with the common stock offering,
our subsidiary trust is offering (by a
separate prospectus) $240.0 million of
convertible preferred securities. The
underwriters of the convertible trust
preferred securities offering have an option
to purchase a maximum of $36.0 million of
convertible preferred securities to cover
over-allotments.

Use of proceeds................. We expect to use a substantial portion of
the net proceeds from the offerings to
finance power projects under development and
construction. In addition, we expect to use
$145.0 million of the net proceeds of this
offering to complete the acquisition of 80%
of CGCA. The remaining net proceeds, if any,
will be used for working capital and general
corporate purposes.

New York Stock Exchange
symbol.......................... CPN

- -------------------------
(1) Excludes the 1,080,000 shares that may be issued pursuant to the
underwriters' over-allotment option.

(2) Based on 54,569,788 shares outstanding as of October 27, 1999. Does not
include 7,684,824 shares of common stock subject to issuance upon exercise
of options previously granted and outstanding as of August 31, 1999, under
our 1996 Stock Incentive Plan.
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<PAGE> 10

SUMMARY CONSOLIDATED HISTORICAL FINANCIAL AND OPERATING INFORMATION

The following table sets forth a summary of our consolidated historical
financial and operating information for the periods indicated. Our summary
consolidated historical financial information was derived from our consolidated
financial statements. The information presented below should be read in
conjunction with "Selected Consolidated Financial Data" and our consolidated
financial statements and the related notes, incorporated by reference in this
prospectus.

<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
------------------------------------------------------------ -----------------------
1994 1995 1996 1997 1998 1998 1999
-------- ---------- ---------- ---------- ---------- ---------- ----------
(IN THOUSANDS, EXCEPT PER SHARE DATA) (UNAUDITED)
<S> <C> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Total revenue.................. $ 94,762 $ 132,098 $ 214,554 $ 276,321 $ 555,948 $ 196,742 $ 336,590
Cost of revenue................ 52,845 77,388 129,200 153,308 375,327 136,125 238,170
Gross profit................... 41,917 54,710 85,354 123,013 180,621 60,617 98,420
Project development expenses... 1,784 3,087 3,867 7,537 7,165 3,119 4,248
General and administrative
expenses..................... 7,323 8,937 14,696 18,289 26,780 11,043 20,964
Income from operations......... 31,772 42,686 66,791 97,187 146,676 46,455 73,208
Interest expense............... 23,886 32,154 45,294 61,466 86,726 40,790 47,171
Other (income) expense......... (1,988) (1,895) (6,259) (17,438) (13,423) (6,599) (11,068)
Extraordinary charge net of tax
benefit of $--, $--, $--,
$--, $441, $207 and $793..... -- -- -- -- 641 302 1,150
Net income..................... $ 6,021 $ 7,378 $ 18,692 $ 34,699 $ 45,678 $ 8,569 $ 21,410
Diluted earnings per common
share:
Weighted average shares of
common stock outstanding... 21,842 21,913 29,758 42,032 42,328 42,100 50,469
Income before extraordinary
charge..................... $ 0.28 $ 0.34 $ 0.63 $ 0.83 $ 1.10 $ 0.21 $ 0.45
Extraordinary charge......... $ -- $ -- $ -- $ -- $ (0.02) $ (0.01) $ (0.02)
Net income................... $ 0.28 $ 0.34 $ 0.63 $ 0.83 $ 1.08 $ 0.20 $ 0.43

OTHER FINANCIAL DATA AND RATIOS:
Depreciation and
amortization................. $ 21,580 $ 26,896 $ 40,551 $ 48,935 $ 82,913 $ 32,104 $ 45,449
EBITDA(1)...................... $ 53,707 $ 69,515 $ 117,379 $ 172,616 $ 255,306 $ 93,374 $ 151,927
EBITDA to Consolidated Interest
Expense(2)................... 2.23x 2.11x 2.41x 2.60x 2.74x 2.16x 2.92x
Total debt to EBITDA........... 6.23x 5.87x 5.12x 4.96x 4.20x -- --
Ratio of earnings to fixed
charges(3)................... 1.52x 1.46x 1.45x 1.64x 1.68x 1.11x 1.43x

SELECTED OPERATING INFORMATION:
Power plants:
Electricity revenue(4):
Energy..................... $ 45,912 $ 54,886 $ 93,851 $ 110,879 $ 252,178 $ 93,735 $ 177,305
Capacity................... $ 7,967 $ 30,485 $ 65,064 $ 84,296 $ 193,535 $ 67,103 $ 106,155
Megawatt hours produced...... 447,177 1,033,566 1,985,404 2,158,008 9,864,080 2,217,659 5,516,805
Average energy price per
kilowatt hour(5)........... 10.267c 5.310c 4.727c 5.138c 2.557c 4.227c 3.214c
</TABLE>

Footnotes appear on the next page.
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<PAGE> 11

<TABLE>
<CAPTION>
AS OF DECEMBER 31, AS OF
------------------------------------------------------------ JUNE 30,
1994 1995 1996 1997 1998 1999
-------- ---------- ---------- ---------- ---------- -----------
(DOLLARS IN THOUSANDS) (UNAUDITED)
<S> <C> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Cash and cash
equivalents........... $ 22,527 $ 21,810 $ 95,970 $ 48,513 $ 96,532 $ 320,287
Total assets............ 421,372 554,531 1,031,397 1,380,915 1,728,946 2,549,750
Short-term debt......... 27,300 85,885 37,492 112,966 5,450 --
Long-term line of
credit................ -- 19,851 -- -- -- --
Long-term non-recourse
debt.................. 196,806 190,642 278,640 182,893 114,190 79,210
Notes payable........... 5,296 6,348 -- -- -- --
Senior notes............ 105,000 105,000 285,000 560,000 951,750 1,551,750
Total debt.............. 334,402 407,726 601,132 855,859 1,071,390 1,630,960
Stockholders' equity.... 18,649 25,227 203,127 239,956 286,966 514,127
</TABLE>

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

(1) EBITDA is defined as income from operations plus depreciation, capitalized
interest, other income, non-cash charges and cash received from investments
in power projects, reduced by the income from unconsolidated investments in
power projects. EBITDA is presented not as a measure of operating results
but rather as a measure of our ability to service debt. EBITDA should not be
construed as an alternative either (a) to income from operations (determined
in accordance with generally accepted accounting principles) or (b) to cash
flows from operating activities (determined in accordance with generally
accepted accounting principles).

(2) For purposes of calculating the EBITDA to Consolidated Interest Expense
ratio, Consolidated Interest Expense is defined as total interest expense
plus one-third of all operating lease obligations, 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 our capital stock.

(3) 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.

(4) Electricity revenue is comprised of fixed capacity payments, which are not
related to production volume, and variable energy payments, which are
related to production volume.

(5) The average energy price per kilowatt hour represents energy revenue divided
by the megawatt hours produced.
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<PAGE> 12

RISK FACTORS

You should carefully consider the risks described below before making an
investment decision. The risks and uncertainties described below are not the
only ones facing our company. Additional risks and uncertainties not presently
known to us or that we currently deem immaterial may also impair our business
operations.

Each of the following factors could have a material adverse effect on our
business, financial condition or results of operations, causing the trading
price of our common stock to decline and the loss of all or part of your
investment.

WE HAVE SUBSTANTIAL INDEBTEDNESS THAT WE MAY BE UNABLE TO SERVICE AND THAT
RESTRICTS OUR ACTIVITIES

We have substantial debt that we incurred to finance the acquisition and
development of power generation facilities. As of June 30, 1999, our total
consolidated indebtedness was $1.6 billion, our total consolidated assets were
$2.5 billion and our stockholders' equity was $514.1 million. On June 30, 1999,
on an as adjusted basis after giving effect to the sale of common stock and
convertible preferred securities in the offerings and the application of the
proceeds from the offerings, our total consolidated indebtedness would have been
approximately $1.6 billion, our total consolidated assets would have been
approximately $3.1 billion and our as adjusted cash balances would have been
approximately $873.8 million. Whether we will be able to meet our debt service
obligations and to repay our outstanding indebtedness will be dependent
primarily upon the performance of our power generation facilities.

This high level of indebtedness has important consequences, including:

- limiting our ability to borrow additional amounts for working capital,
capital expenditures, debt service requirements, execution of our growth
strategy, or other purposes,

- limiting our ability to use operating cash flow in other areas of our
business because we must dedicate a substantial portion of these funds to
service the debt,

- increasing our vulnerability to general adverse economic and industry
conditions, and

- limiting our ability to capitalize on business opportunities and to react
to competitive pressures and adverse changes in government regulation.

The operating and financial restrictions and covenants in our existing debt
agreements, including the indentures relating to our $1.5 billion aggregate
principle amount of senior notes and our $100.0 million revolving credit
facility, contain restrictive covenants. Among other things, these restrictions
limit or prohibit our ability to:

- incur indebtedness,

- make prepayments of indebtedness in whole or in part,

- pay dividends,

- make investments,

- engage in transactions with affiliates,

- create liens,

- sell assets, and

- acquire facilities or other businesses.

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<PAGE> 13

Also, if our management or ownership changes, the indentures governing our
senior notes may require us to make an offer to purchase our senior notes. We
cannot assure you that we will have the financial resources necessary to
purchase our senior notes in this event.

We believe that our cash flow from operations, together with other
available sources of funds, including borrowings under our existing borrowing
arrangements, will be adequate to pay principal and interest on our senior notes
and other debt and to enable us to comply with the terms of our indentures and
other debt agreements. If we are unable to comply with the terms of our
indentures and other debt agreements and fail to generate sufficient cash flow
from operations in the future, we may be required to refinance all or a portion
of our senior notes and other debt or to obtain additional financing. However,
we may be unable to refinance or obtain additional financing because of our high
levels of debt and the debt incurrence restrictions under our indentures and
other debt agreements. If cash flow is insufficient and refinancing or
additional financing is unavailable, we may be forced to default on our senior
notes and other debt obligations. In the event of a default under the terms of
any of our indebtedness, the debt holders may accelerate the maturity of our
obligations, which could cause defaults under our other obligations.

OUR ABILITY TO REPAY OUR DEBT DEPENDS UPON THE PERFORMANCE OF OUR SUBSIDIARIES

Almost all of our operations are conducted through our subsidiaries and
other affiliates. As a result, we depend almost entirely upon their earnings and
cash flow to service our indebtedness, including our ability to pay the interest
on and principal of our senior notes. The non-recourse project financing
agreements of certain of our subsidiaries and other affiliates generally
restrict their ability to pay dividends, make distributions or otherwise
transfer funds to us prior to the payment of other obligations, including
operating expenses, debt service and reserves.

Our subsidiaries and other affiliates are separate and distinct legal
entities and have no obligation to pay any amounts due on our senior notes, and
do not guarantee the payment of interest on or principal of these notes. The
right of our senior note holders to receive any assets of any of our
subsidiaries or other affiliates upon our liquidation or reorganization will be
subordinated to the claims of any subsidiaries' or other affiliates' creditors
(including trade creditors and holders of debt issued by our subsidiaries or
affiliates). As of June 30, 1999, our subsidiaries had $79.2 million of
non-recourse project financing. We intend to utilize non-recourse project
financing in the future that will be effectively senior to our senior notes.

While the indentures impose limitations on our ability and the ability of
our subsidiaries to incur additional indebtedness, the indentures do not limit
the amount of non-recourse project financing that our subsidiaries may incur to
finance the acquisition and development of new power generation facilities.

10
<PAGE> 14

WE MAY BE UNABLE TO SECURE ADDITIONAL FINANCING IN THE FUTURE

Each power generation facility that we acquire or develop will require
substantial capital investment. Our ability to arrange financing and the cost of
the financing are dependent upon numerous factors. These factors include:

- 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 in us,

- the continued success of our current power generation facilities, and

- provisions of tax and securities laws that are conducive to raising
capital.

Financing for new facilities may not be available to us on acceptable terms in
the future.

We have financed our existing power generation facilities using a variety
of leveraged financing structures, primarily consisting of non-recourse project
financing and lease obligations. As of June 30, 1999, we had approximately $1.6
billion of total consolidated indebtedness, $79.2 million of which represented
non-recourse project financing. Each non-recourse project financing and lease
obligation is structured to be fully paid out of cash flow provided by the
facility or facilities. In the event of a default under a financing agreement
which we do not cure, the lenders or lessors would generally have rights to the
facility and any related assets. In the event of foreclosure after a default, we
might not retain any interest in the facility. While we intend to utilize
non-recourse or lease financing when appropriate, market conditions and other
factors may prevent similar financing for future facilities. We do not believe
the existence of non-recourse or lease financing will significantly affect our
ability to continue to borrow funds in the future in order to finance new
facilities. However, it is possible that we may be unable to obtain the
financing required to develop our power generation facilities on terms
satisfactory to us.

We have from time to time guaranteed certain obligations of our
subsidiaries and other affiliates. Our lenders or lessors may also require us to
guarantee the indebtedness for future facilities. This would render our general
corporate funds vulnerable in the event of a default by the facility or related
subsidiary. Additionally, our indentures may restrict our ability to guarantee
future debt, which could adversely affect our ability to fund new facilities.
Our indentures do not limit the ability of our subsidiaries to incur
non-recourse or lease financing for investment in new facilities.

REVENUE UNDER SOME OF OUR POWER SALES AGREEMENTS MAY BE REDUCED SIGNIFICANTLY
UPON THEIR EXPIRATION OR TERMINATION

Most of the electricity we generate from our existing portfolio is sold
under long-term power sales agreements that expire at various times. When the
terms of each of these power sales agreements expire, it is possible that the
price paid to us for the generation of electricity may be reduced significantly,
which would substantially reduce our revenue under such agreements. The fixed
price periods in some of our long-term power sales agreements have recently
expired, and the electricity under those agreements is now sold at

11
<PAGE> 15

a fluctuating market price. For example, the price for electricity for two of
our power plants, the Bear Canyon (20 megawatts) and West Ford Flat (27
megawatts) power plants, was approximately 13.83 cents per kilowatt hour under
the fixed price periods that recently expired for these facilities, and is now
set at the energy clearing price, which averaged 2.66 cents per kilowatt hour
during 1998. As a result, our energy revenue under these power sales agreements
has been materially reduced. We expect the decline in energy revenues will be
partially mitigated by decreased royalties and planned operating cost reductions
at these facilities. In addition, we will continue our strategy of offsetting
these reductions through our acquisition and development program.

OUR POWER PROJECT DEVELOPMENT AND ACQUISITION ACTIVITIES MAY NOT BE SUCCESSFUL

The development of power generation facilities is subject to substantial
risks. In connection with the development of a power generation facility, we
must generally obtain:

- necessary power generation equipment,

- governmental permits and approvals,

- fuel supply and transportation agreements,

- sufficient equity capital and debt financing,

- electrical transmission agreements, and

- site agreements and construction contracts.

We may be unsuccessful in accomplishing any of these matters or in doing so on a
timely basis. In addition, project development is subject to various
environmental, engineering and construction risks relating to cost-overruns,
delays and performance. Although we may attempt to minimize the financial risks
in the development of a project by securing a favorable power sales agreement,
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 us to expend significant sums for preliminary engineering,
permitting and legal and other expenses before we can determine whether a
project is feasible, economically attractive or financeable. If we were unable
to complete the development of a facility, we would generally not be able to
recover our investment in the project. 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. We cannot assure you that we will be successful in
the development of power generation facilities in the future.

We have grown substantially in recent years as a result of acquisitions of
interests in power generation facilities and steam fields. We believe that
although the domestic power industry is undergoing consolidation and that
significant acquisition opportunities are available, we are likely to confront
significant competition for acquisition opportunities. In addition, we may be
unable to continue to identify attractive acquisition opportunities at favorable
prices or, to the extent that any opportunities are identified, we may be unable
to complete the acquisitions.

12
<PAGE> 16

OUR PROJECTS UNDER CONSTRUCTION MAY NOT COMMENCE OPERATION AS SCHEDULED

The commencement of operation of a newly constructed power generation
facility 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 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. The insurance, warranties or performance guarantees, however, may not be
adequate to cover lost revenues or increased expenses. 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 losing our interest in a power generation facility.

In addition, power sales agreements entered into with a utility early in
the development phase of a project may enable the utility to terminate the
agreement, or to retain security posted as liquidated damages, if a project
fails to achieve commercial operation or certain operating levels by specified
dates or fails to make specified payments. In the event a termination right is
exercised, the default provisions in a financing agreement may be triggered
(rendering such debt immediately due and payable). As a result, the project may
be rendered insolvent and we may lose our interest in the project.

OUR POWER GENERATION FACILITIES MAY NOT OPERATE AS PLANNED

Upon completion of our pending acquisitions and projects currently under
construction, we will operate 42 of the 52 power plants in which we will have an
interest. The continued operation of power generation facilities 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. Although from time to time our
power generation facilities have experienced equipment breakdowns or failures,
these breakdowns or failures have not had a significant effect on the operation
of the facilities or on our results of operations. As of June 30, 1999, our gas-
fired and geothermal power generation facilities have operated at an average
availability of approximately 96% and 99%, respectively. Although our facilities
contain various redundancies and back-up mechanisms, a breakdown or failure may
prevent the affected facility from performing under applicable power sales
agreements. In addition, although insurance is maintained to protect against
operating risks, the proceeds of insurance may not be adequate to cover lost
revenues or increased expenses. As a result, we could be unable to service
principal and interest payments under our financing obligations which could
result in losing our interest in the power generation facility.

13
<PAGE> 17

OUR GEOTHERMAL ENERGY RESERVES MAY BE INADEQUATE FOR OUR OPERATIONS

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,

- operating expenses relating to the extraction of fluids,

- price levels relating to the extraction of fluids, and

- capital expenditure requirements relating primarily to the drilling of
new wells.

In connection with each geothermal power plant, we estimate the
productivity of the geothermal resource and the expected decline in
productivity. The productivity of a geothermal resource may decline more than
anticipated, resulting in insufficient reserves being available for sustained
generation of the electrical power capacity desired. An incorrect estimate by us
or an unexpected decline in productivity could lower our results of operations.

Geothermal reservoirs are highly complex. 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 ours. 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 we have
extensive experience in the operation and development of geothermal energy
resources and in preparing such estimates, we cannot assure you that we will be
able to successfully manage the development and operation of our geothermal
reservoirs or that we will accurately estimate the quantity or productivity of
our steam reserves.

WE DEPEND ON OUR ELECTRICITY AND THERMAL ENERGY CUSTOMERS

Each of our power generation facilities currently relies on one or more
power sales agreements with one or more utility or other customers for all or
substantially all of such facility's revenue. In addition, the sales of
electricity to two utility customers during 1998 comprised approximately 64% of
our total revenue during that year. The loss of any one power sales agreement
with any of these customers could have a negative effect on our results of
operations. In addition, any material failure by any customer to fulfill its
obligations under a power sales agreement could have a negative effect on the
cash flow available to us and on our results of operations.

14
<PAGE> 18

WE ARE SUBJECT TO COMPLEX GOVERNMENT REGULATION WHICH COULD ADVERSELY AFFECT OUR
OPERATIONS

Our 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 we believe that we have obtained the requisite approvals for our existing
operations and that our business is operated in accordance with applicable laws,
we remain subject to a varied and complex body of laws and regulations that both
public officials and private individuals may seek to enforce. Existing laws and
regulations may be revised or new laws and regulations may become applicable to
us that may have a negative effect on our business and results of operations. We
may be unable to obtain all necessary licenses, permits, approvals and
certificates for proposed projects, and completed facilities may not 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. Intricate and changing environmental and other
regulatory requirements may necessitate substantial expenditures to obtain
permits. If a project is unable to function as planned due to changing
requirements or local opposition, it may create expensive delays or significant
loss of value in a project.

Our operations are potentially subject to the provisions of various energy
laws and regulations, including the Public Utility Regulatory Policies Act of
1978, as amended ("PURPA"), the Public Utility Holding Company Act of 1955, as
amended ("PUHCA"), and state and local regulations. PUHCA provides for the
extensive regulation of public utility holding companies and their subsidiaries.
PURPA provides to qualifying facilities ("QFs") (as defined under PURPA) and
owners of QFs certain exemptions from certain federal and state regulations,
including rate and financial regulations.

Under present federal law, we are not subject to regulation as a holding
company under PUHCA, and will not be subject to such regulation as long as the
plants in which we have an interest (1) qualify as QFs, (2) are subject to
another exemption or waiver or (3) qualify as exempt wholesale generators
("EWG") under the Energy Policy Act of 1992. In order to be a QF, a facility
must be not more than 50% owned by an electric utility company or electric
utility holding company. In addition, a QF that is a cogeneration facility, such
as the plants in which we currently have interests, must produce electricity as
well as thermal energy for use in an industrial or commercial process in
specified minimum proportions. The QF also must meet certain minimum energy
efficiency standards. Generally, any geothermal power facility which produces up
to 80 megawatts of electricity and meets PURPA ownership requirements is
considered a QF.

If any of the plants in which we have an interest lose their QF status or
if amendments to PURPA are enacted that substantially reduce the benefits
currently afforded QFs, we could become a public utility holding company, which
could subject us to significant federal, state and local regulation, including
rate regulation. If we become a holding company, which could be deemed to occur
prospectively or retroactively to the date that any of our plants loses its QF
status, all our other power plants could 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
particular power purchase 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

15
<PAGE> 19

of some or all contract revenues or otherwise impair the value of a project. If
a power purchaser were to cease taking and paying for electricity or seek 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. Such events could adversely affect our ability to service our
indebtedness, including our senior notes. See "Business -- Government
Regulation -- Federal Energy Regulation."

Currently, Congress is considering proposed legislation that would amend
PURPA by eliminating the requirement that utilities purchase electricity from
QFs at prices based on avoided costs of energy. We do not know whether this
legislation will be passed or, if passed, what form it may take. We cannot
provide assurance that any legislation passed would not adversely affect our
existing domestic projects.

In addition, many states are implementing or considering regulatory
initiatives designed to increase competition in the domestic power generation
industry and increase access to electric utilities' transmission and
distribution systems for independent power producers and electricity consumers.
In particular, the state of California has restructured its electric industry by
providing for a phased-in competitive power generation industry, with a power
pool and an independent system operator, and for direct access to generation for
all power purchasers outside the power exchange under certain circumstances.
Although existing QF power sales contracts are to be honored under such
restructuring, and all of our California operating projects are QFs, until the
new system is fully implemented, it is impossible to predict what impact, if
any, it may have on the operations of those projects.

WE MAY BE UNABLE TO OBTAIN AN ADEQUATE SUPPLY OF NATURAL GAS IN THE FUTURE

To date, our fuel acquisition strategy has included various combinations of
our own gas reserves, gas prepayment contracts and short-, medium- and long-term
supply contracts. In our gas supply arrangements, we attempt 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. We believe that
there will be adequate supplies of natural gas available at reasonable prices
for each of our facilities when current gas supply agreements expire. However,
gas supplies may not be available for the full term of the facilities' power
sales agreements, and gas prices may 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 negative impact on our results of
operations.

COMPETITION COULD ADVERSELY AFFECT OUR PERFORMANCE

The power generation industry is characterized by intense competition. We
encounter competition from utilities, industrial companies and other power
producers. In recent years, there has been increasing competition in an effort
to obtain power sales agreements. This competition has contributed to a
reduction in electricity prices. In addition, many states have implemented or
are considering regulatory initiatives designed to increase competition in the
domestic power industry. This competition has put pressure on electric utilities
to lower their costs, including the cost of purchased electricity.

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<PAGE> 20

OUR INTERNATIONAL INVESTMENTS MAY FACE UNCERTAINTIES

We have one investment in geothermal steam fields located in Mexico and may
pursue additional international investments. International investments are
subject to unique risks and uncertainties relating to the political, social and
economic structures of the countries in which we invest. 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.

WE DEPEND ON OUR SENIOR MANAGEMENT

Our success is largely dependent on the skills, experience and efforts of
our senior management. The loss of the services of one or more members of our
senior management could have a negative effect on our business, financial
results and future growth.

SEISMIC DISTURBANCES COULD DAMAGE OUR PROJECTS

Areas where we operate and are developing many of our geothermal and
gas-fired projects are subject to frequent low-level seismic disturbances. More
significant seismic disturbances are possible. Our existing power generation
facilities are built to withstand relatively significant levels of seismic
disturbances, and we believe we maintain adequate insurance protection. However,
earthquake, property damage or business interruption insurance may be inadequate
to cover all potential losses sustained in the event of serious seismic
disturbances. Additionally, insurance may not continue to be available to us on
commercially reasonable terms.

OUR RESULTS ARE SUBJECT TO QUARTERLY AND SEASONAL FLUCTUATIONS

Our 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:

- the timing and size of acquisitions,

- the completion of development projects, and

- variations in levels of production.

Additionally, because we receive the majority of capacity payments under
some of our power sales agreements during the months of May through October, our
revenues and results of operations are, to some extent, seasonal.

THE PRICE OF OUR COMMON STOCK IS VOLATILE

The market price for our common stock has been volatile in the past, and
several factors could cause the price to fluctuate substantially in the future.
These factors include:

- announcements of developments related to our business,

- fluctuations in our results of operations,

- sales of substantial amounts of our securities into the marketplace,

17
<PAGE> 21

- general conditions in our industry or the worldwide economy,

- an outbreak of war or hostilities,

- a shortfall in revenues or earnings compared to securities analysts'
expectations,

- changes in analysts' recommendations or projections, and

- announcements of new acquisitions or development projects by us.

The market price of our common stock may fluctuate significantly in the
future, and these fluctuations may be unrelated to our performance. General
market price declines or market volatility in the future could adversely affect
the price of our common stock, and the current market price may not be
indicative of future market prices.

WE COULD BE ADVERSELY AFFECTED IF OUR COMPUTER SYSTEMS ARE NOT YEAR 2000
COMPLIANT

The "Year 2000 problem" refers to the fact that some computer hardware,
software and embedded systems were designed to read and store dates using only
the last two digits of the year.

We are coordinating our efforts to address the impact of Year 2000 on our
business through an analysis of four separate technology domains:

- corporate applications, which include core business systems,

- non-information technology, which includes all operating and control
systems,

- end-user computing systems (that is, systems that are not considered core
business systems but may contain date calculations), and

- business partner and vendor systems.

We currently expect to complete our Year 2000 efforts with respect to
critical systems by November of 1999. This schedule and our cost estimates may
be affected by, among other things, the availability of Year 2000 personnel, the
readiness of third parties, the timing for testing our embedded systems, the
availability of vendor resources to complete embedded system assessments and
produce required component upgrades and our ability to implement appropriate
contingency plans.

We produce revenues by selling power we produce to customers. We depend on
transmission and distribution facilities that are owned and operated by
investor-owned utilities to deliver power to our customers. If either our
customers or the providers of transmission and distribution facilities
experience significant disruptions as a result of the Year 2000 problem, our
ability to sell and deliver power may be hindered, which could result in a loss
of revenue.

The cost or consequences of a materially incomplete or untimely resolution
of the Year 2000 problem could adversely affect our future operations, financial
results or our financial condition.

WHERE YOU CAN FIND MORE INFORMATION

We file annual, quarterly and special reports, proxy statements and other
information with the Securities and Exchange Commission. You may read and copy
any document we file at the public reference facilities of the SEC located at
450 Fifth Street N.W., Washington D.C. 20549. You may obtain information on the
operation of the SEC's public

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<PAGE> 22

reference facilities by calling the SEC at 1-800-SEC-0330. You can also access
copies of such material electronically on the SEC's home page on the World Wide
Web at http://www.sec.gov.

This prospectus is part of a registration statement (Registration No.
333-87427) we filed with the SEC. The SEC permits us to "incorporate by
reference" the information we file with them, which means that we can disclose
important information to you by referring you to those documents. The
information incorporated by reference is considered to be part of this
prospectus, and information that we file with the SEC after the date of this
prospectus will automatically update and supersede this information. We
incorporate by reference our Annual Report on Form 10-K as amended for the year
ended December 31, 1998, our Quarterly Reports on Form 10-Q for the periods
ended March 31, 1999 and June 30, 1999, our Current Report on Form 8-K dated May
7, 1999, our Current Report on Form 8-K dated October 11, 1999, and our Current
Report on Form 8-K dated October 22, 1999, each filed by us with the SEC. We
also incorporate by reference any future filings made with the SEC under
Sections 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934, as
amended, until we sell all of the shares of common stock and convertible
preferred securities being registered or until this offering is otherwise
terminated.

If you request a copy of any or all of the documents incorporated by
reference, then we will send to you the copies you requested at no charge.
However, we will not send exhibits to such documents, unless such exhibits are
specifically incorporated by reference in such documents. You should direct
requests for such copies to Investor Relations, Calpine Corporation, 50 West San
Fernando Street, San Jose, California 95113. Our telephone number is (408)
995-5115.

FORWARD-LOOKING STATEMENTS

Some of the statements in this prospectus and incorporated by reference are
forward-looking statements. These statements involve known and unknown risks,
uncertainties, and other factors that may cause our or our industry's actual
results, levels of activity, performance, or achievements to be materially
different from any future results, levels of activity, performance, or
achievements expressed or implied by such forward-looking statements. Such
factors include, among other things, those listed under "Risk Factors" and
elsewhere in this prospectus.

In some cases, you can identify forward-looking statements by terminology
such as "may," "will," "should," "expects," "plans," "anticipates," "believes,"
"estimates," "predicts," "potential," or "continue" or the negative of such
terms or other comparable terminology.

Although we believe that the expectations reflected in the forward-looking
statements are reasonable, we cannot guarantee future results, levels of
activity, performance, or achievements. Moreover, neither we nor any other
person assumes responsibility for the accuracy and completeness of such
statements. We are under no duty to update any of the forward-looking statements
after the date of this prospectus to conform such statements to actual results.

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<PAGE> 23

USE OF PROCEEDS

The aggregate net proceeds to us from the sale of the 7,200,000 shares of
common stock offered by us in the offering (after deducting underwriting
discounts and commissions and estimated offering expenses) will be approximately
$320.3 million ($368.4 million if the underwriters' over-allotment option in the
common stock offering is exercised in full), assuming an offering price of
$46.3125 per share. We expect to use a substantial portion of the net proceeds
from this offering to finance power projects under development and construction.
In addition, we expect to use $145.0 million of the net proceeds to complete the
acquisition of 80% of CGCA. The remaining net proceeds, if any, will be used for
working capital and general corporate purposes. See "Business -- Project
Development and Acquisitions." Pending such uses, we expect to invest the net
proceeds in short-term, interest-bearing securities.

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<PAGE> 24

PRICE RANGE OF COMMON STOCK

Our common stock is traded on the New York Stock Exchange under the symbol
"CPN." Public trading of the common stock commenced on September 20, 1996. Prior
to that, there was no public market for the common stock. The following table
sets forth, for the periods indicated, the high and low sale price per share of
the common stock on the New York Stock Exchange. The information in the
following table reflects the 2 for 1 stock split effective on October 7, 1999.

<TABLE>
<CAPTION>
HIGH LOW
------- -------
<S> <C> <C>
1997
First Quarter.............................................. $11.375 $ 8.563
Second Quarter............................................. 10.438 7.875
Third Quarter.............................................. 11.469 8.250
Fourth Quarter............................................. 10.625 6.188

1998
First Quarter.............................................. $ 9.250 $ 6.375
Second Quarter............................................. 10.625 8.625
Third Quarter.............................................. 10.750 8.563
Fourth Quarter............................................. 13.813 8.906

1999
First Quarter.............................................. $18.688 $12.625
Second Quarter............................................. 29.500 17.563
Third Quarter.............................................. 47.875 27.406
Fourth Quarter (through October 27, 1999).................. 53.250 42.531
</TABLE>

As of October 27, 1999, there were approximately 87 holders of record of
our common stock. On October 27, 1999, the last sale price reported on the New
York Stock Exchange for our common stock was $46.3125 per share.

DIVIDEND POLICY

We do not anticipate paying any cash dividends on our common stock in the
foreseeable future because we intend to retain our earnings to finance the
expansion of our business and for general corporate purposes. In addition, our
ability to pay cash dividends is restricted under our indentures and our other
debt agreements. Future cash dividends, if any, will be at the discretion of our
board of directors and will depend upon, among other things, our future
operations and earnings, capital requirements, general financial condition,
contractual restrictions and such other factors as the board of directors may
deem relevant.

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<PAGE> 25

CAPITALIZATION

The following table sets forth, as of June 30, 1999 (1) the actual
consolidated capitalization of the Company; and (2) the consolidated
capitalization of our Company as adjusted for the sale of the shares of our
common stock and convertible preferred securities in the offerings. This table
should be read in conjunction with the consolidated financial statements and
related notes thereto incorporated by reference in this prospectus.

<TABLE>
<CAPTION>
JUNE 30, 1999
-------------------------
ACTUAL AS ADJUSTED
---------- -----------
UNAUDITED
(DOLLARS IN THOUSANDS,
EXCEPT SHARE AMOUNTS)
<S> <C> <C>
CASH:
Cash and cash equivalents........................... $ 320,287 $ 873,777
========== ==========

LONG-TERM DEBT:
Non-recourse project financing, net of current
portion.......................................... $ 79,210 $ 79,210
Senior notes........................................ 1,551,750 1,551,750
---------- ----------
Total long-term debt........................ 1,630,960 1,630,960
---------- ----------
Company-obligated convertible preferred securities of
a subsidiary trust(1)............................... -- 233,224
---------- ----------

STOCKHOLDERS' EQUITY:
Preferred stock, $0.001 par value:
10,000,000 shares authorized; no shares
outstanding, actual and as adjusted.............. -- --
Common stock, $0.001 par value:
100,000,000 shares authorized; 54,348,294 shares
outstanding, actual; and 61,548,294 shares
outstanding, as adjusted(2)(3)(4)................ 54 62
Additional paid-in capital.......................... 374,591 694,849
Retained earnings................................... 139,482 139,482
---------- ----------
Total stockholders' equity.................. 514,127 834,393
---------- ----------
Total capitalization..................... $2,145,087 $2,698,577
========== ==========
</TABLE>

- -------------------------
(1) Proceeds are recorded net of unamortized issuance costs of $6,776.
(2) Excludes the 1,080,000 shares that may be issued upon exercise of the
underwriters' over-allotment option.
(3) Does not include 7,051,428 shares of common stock subject to issuance upon
exercise of options previously granted and outstanding as of June 30, 1999
under our 1996 Stock Incentive Plan.
(4) Reflects 2 for 1 stock split effective on October 7, 1999.

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<PAGE> 26

SELECTED CONSOLIDATED FINANCIAL DATA

The consolidated financial data set forth below for the five years ended
and as of December 31, 1998 have been derived from the audited consolidated
financial statements of our company. The consolidated financial data for the six
months ended and as of June 30, 1998 and June 30, 1999 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, 1999 should not be
considered 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
incorporated by reference in this prospectus.

<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
--------------------------------------------------- -------------------
1994 1995 1996 1997 1998 1998 1999
------- -------- -------- -------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) (UNAUDITED)
<S> <C> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenue:
Electricity and steam sales........ $90,295 $127,799 $199,464 $237,277 $507,897 $178,798 $304,322
Service contract revenue from
related parties.................. 7,221 7,153 6,455 10,177 20,249 8,529 13,238
Income (loss) from unconsolidated
investments in power projects.... (2,754) (2,854) 6,537 15,819 25,240 6,853 18,321
Interest income on loans to power
projects......................... -- -- 2,098 13,048 2,562 2,562 709
------- -------- -------- -------- -------- -------- --------
Total revenue................ 94,762 132,098 214,554 276,321 555,948 196,742 336,590
Cost of revenue...................... 52,845 77,388 129,200 153,308 375,327 136,125 238,170
------- -------- -------- -------- -------- -------- --------
Gross profit......................... 41,917 54,710 85,354 123,013 180,621 60,617 98,420
Project development expenses......... 1,784 3,087 3,867 7,537 7,165 3,119 4,248
General and administrative
expenses........................... 7,323 8,937 14,696 18,289 26,780 11,043 20,964
Provision for write-off of project
development costs.................. 1,038 -- -- -- -- -- --
------- -------- -------- -------- -------- -------- --------
Income from operations............... 31,772 42,686 66,791 97,187 146,676 46,455 73,208
Interest expense..................... 23,886 32,154 45,294 61,466 86,726 40,790 47,171
Other (income) expense............... (1,988) (1,895) (6,259) (17,438) (13,423) (6,599) (11,068)
------- -------- -------- -------- -------- -------- --------
Income before provision for income
taxes............................ 9,874 12,427 27,756 53,159 73,373 12,264 37,105
Provision for income taxes........... 3,853 5,049 9,064 18,460 27,054 3,393 14,545
------- -------- -------- -------- -------- -------- --------
Income before extraordinary
charge........................... 6,021 7,378 18,692 34,699 46,319 8,871 22,560
Extraordinary charge for retirement
of debt, net of tax benefit of $--,
$--, $--, $--, $441, $207 and
$793............................... -- -- -- -- 641 302 1,150
------- -------- -------- -------- -------- -------- --------
Net income......................... $ 6,021 $ 7,378 $ 18,692 $ 34,699 $ 45,678 $ 8,569 $ 21,410
======= ======== ======== ======== ======== ======== ========
Basic earnings per common share:
Weighted average shares of common
stock outstanding................ 20,776 20,776 25,805 39,892 40,242 40,112 47,518
Income before extraordinary
charge........................... $ 0.29 $ 0.36 $ 0.72 $ 0.87 $ 1.15 $ 0.22 $ 0.47
Extraordinary charge............... $ -- $ -- $ -- $ -- $ (0.02) $ (0.01) $ (0.02)
Net income......................... $ 0.29 $ 0.36 $ 0.72 $ 0.87 $ 1.13 $ 0.21 $ 0.45
Diluted earnings per common share:
Weighted average shares of common
stock outstanding................ 21,842 21,913 29,758 42,032 42,328 42,100 50,469
Income before extraordinary
charge........................... $ 0.28 $ 0.34 $ 0.63 $ 0.83 $ 1.10 $ 0.21 $ 0.45
Extraordinary charge............... $ -- $ -- $ -- $ -- $ (0.02) $ (0.01) $ (0.02)
Net income......................... $ 0.28 $ 0.34 $ 0.63 $ 0.83 $ 1.08 $ 0.20 $ 0.43
</TABLE>

23
<PAGE> 27

<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
---------------------------------------------------------- -----------------------
1994 1995 1996 1997 1998 1998 1999
-------- -------- ---------- ---------- ---------- ---------- ----------
(IN THOUSANDS, EXCEPT RATIOS) (UNAUDITED)
<S> <C> <C> <C> <C> <C> <C> <C>
OTHER FINANCIAL DATA AND
RATIOS:
Depreciation and
amortization.............. $ 21,580 $ 26,896 $ 40,551 $ 48,935 $ 82,913 $ 32,104 $ 45,449
EBITDA(1)................... $ 53,707 $ 69,515 $ 117,379 $ 172,616 $ 255,306 $ 93,374 $ 151,927
EBITDA to Consolidated
Interest Expense(2)....... 2.23x 2.11x 2.41x 2.60x 2.74x 2.16x 2.92x
Total debt to EBITDA........ 6.23x 5.87x 5.12x 4.96x 4.20x -- --
Ratio of earnings to fixed
charges(3)................ 1.52x 1.46x 1.45x 1.64x 1.68x 1.11x 1.43x
</TABLE>

<TABLE>
<CAPTION>
AS OF DECEMBER 31,
---------------------------------------------------------- AS OF
1994 1995 1996 1997 1998 JUNE 30, 1999
-------- -------- ---------- ---------- ---------- -------------
(IN THOUSANDS) (UNAUDITED)
<S> <C> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Cash and cash equivalents............ $ 22,527 $ 21,810 $ 95,970 $ 48,513 $ 96,532 $ 320,287
Property, plant and equipment, net... 335,453 447,751 648,208 736,339 1,094,303 1,568,882
Investments in power projects........ 11,114 8,218 13,936 222,542 221,509 234,584
Notes receivable..................... 16,882 25,785 36,143 117,357 10,899 16,202
Total assets......................... 421,372 554,531 1,031,397 1,380,915 1,728,946 2,549,750
Short-term debt...................... 27,300 85,885 37,492 112,966 5,450 --
Long-term line of credit............. -- 19,851 -- -- -- --
Non-recourse debt.................... 196,806 190,642 278,640 182,893 114,190 79,210
Notes payable........................ 5,296 6,348 -- -- -- --
Senior notes......................... 105,000 105,000 285,000 560,000 951,750 1,551,750
Total debt........................... 334,402 407,726 601,132 855,859 1,071,390 1,630,960
Stockholders' equity................. 18,649 25,227 203,127 239,956 286,966 514,127
</TABLE>

- -------------------------
(1) EBITDA is defined as income from operations plus depreciation, capitalized
interest, other income, non-cash charges and cash received from investments
in power projects, reduced by the income from unconsolidated investments in
power projects. EBITDA is presented here not as a measure of operating
results but rather as a measure of our ability to service debt. EBITDA
should not be construed as an alternative either (a) to income from
operations (determined in accordance with generally accepted accounting
principles) or (b) to cash flows from operating activities (determined in
accordance with generally accepted accounting principles).

(3) 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.

24
<PAGE> 28

PRO FORMA CONSOLIDATED FINANCIAL DATA

The following unaudited pro forma consolidated statement of operations for
the year ended December 31, 1998 gives effect to the following transactions as
if such transactions had occurred on January 1, 1998: (1) our acquisition of the
remaining 55% interest in the Bethpage Power Plant on February 5, 1998 (the
"Bethpage Transaction"); (2) our acquisition of the remaining 50% interest in
the Texas City Power Plant and the Clear Lake Power Plant on April 1, 1998 (the
"Texas City/Clear Lake Transaction"); (3) our sale of $300 million of 7 7/8%
Senior Notes Due 2008 on March 31, 1998, and the application of the net proceeds
therefrom; and (4) our sale of $100 million of 7 7/8% Senior Notes Due 2008 on
July 24, 1998 and the application of the net proceeds therefrom (the Bethpage
Transaction, the Texas City/Clear Lake Transaction, the sale of $300 million of
7 7/8% Senior Notes Due 2008 and the sale of $100 million of 7 7/8% Senior Notes
Due 2008 being collectively referred to as the "Transactions").

The pro forma consolidated financial data and Management's Discussion and
Analysis of Financial Condition and Results of Operations should be read in
conjunction with the consolidated financial statements and related notes thereto
incorporated by reference 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
our results of operations would actually have been had such transactions in fact
occurred at such dates, or to project our results of operations for any future
period. In the opinion of management, all adjustments necessary to present
fairly such pro forma consolidated financial data have been made.

25
<PAGE> 29

PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS

<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1998
-------------------------------------------------
ADJUSTMENTS PRO FORMA
FOR THE FOR THE
ACTUAL TRANSACTIONS TRANSACTIONS
--------- ---------------- ------------------
(IN THOUSANDS, EXCEPT RATIOS AND PER SHARE DATA)
<S> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenue:
Electricity and steam sales..................... $507,897 $ 74,163 $582,060
Service contract revenue from related parties... 20,249 (1,613) 18,636
Income from unconsolidated investments in power
projects...................................... 25,240 (1,765) 23,475
Interest income on loans to power projects...... 2,562 (2,520) 42
-------- --------- --------
Total revenue............................ 555,948 68,265 624,213
-------- --------- --------
Cost of revenue:
Plant operating expenses........................ 256,079 48,764 304,843
Depreciation.................................... 73,988 7,612 81,600
Production royalties............................ 10,714 -- 10,714
Operating lease expenses........................ 17,129 (1,277) 15,852
Service contract expenses....................... 17,417 -- 17,417
-------- --------- --------
Total cost of revenue.................... 375,327 55,099 430,426
-------- --------- --------
Gross profit...................................... 180,621 13,166 193,787
Project development expenses...................... 7,165 -- 7,165
General and administrative expenses............... 26,780 (27) 26,753
-------- --------- --------
Income from operations.......................... 146,676 13,193 159,869
Interest expense.................................. 86,726 8,302 95,028
Interest income................................... (12,348) -- (12,348)
Other (income) expense............................ (1,075) (146) (1,221)
-------- --------- --------
Income before provision for income taxes........ 73,373 5,037 78,410
Provision for income taxes........................ 27,054 1,689 28,743
-------- --------- --------
Income before extraordinary charge................ 46,319 3,348 49,667
Extraordinary charge for retirement of debt, net
of tax benefit of $441, $-- and $441............ 641 -- 641
-------- --------- --------
Net income.................................... $ 45,678 $ 3,348 $ 49,026
======== ========= ========
Basic earnings per common share:
Weighted average shares of common stock
outstanding................................... 40,242 40,242
Income before extraordinary charge.............. $ 1.15 $ 1.24
Extraordinary charge............................ $ (0.02) $ (0.02)
Net income...................................... $ 1.13 $ 1.22
Diluted earnings per common share:
Weighted average shares of common stock
outstanding................................... 42,328 42,328
Income before extraordinary charge.............. $ 1.10 $ 1.18
Extraordinary charge............................ $ (0.02) $ (0.02)
Net income...................................... $ 1.08 $ 1.16
OTHER OPERATING DATA AND RATIOS:
Depreciation and amortization................... $ 82,913 $ 90,525
EBITDA.......................................... $255,306 $278,091
EBITDA to Consolidated Interest Expense......... 2.74x 2.74x
Total debt to EBITDA............................ 4.20x 3.85x
Ratio of earnings to fixed charges.............. 1.68x 1.69x
</TABLE>

26
<PAGE> 30

MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OVERVIEW

Calpine is engaged in the development, acquisition, ownership and operation
of power generation facilities and the sale of electricity and steam principally
in the United States. At October 27, 1999, we had interests in 38 power plants
predominantly in the United States, having an aggregate capacity of 3,694
megawatts.

On February 5, 1998, we acquired the remaining 55% interest in, and assumed
operations and maintenance of, the Bethpage Power Plant. We purchased the
remaining interests for approximately $5.0 million. Additionally, on March 31,
1998 we repaid all outstanding project debt of $37.4 million related to the
Bethpage Power Plant.

On March 31, 1998, we completed the acquisition of the remaining 50%
interest in the Texas Cogeneration Company ("TCC"), which is the owner of the
Texas City and Clear Lake Power Plants. We paid $52.8 million in cash and agreed
to make certain contingent purchase payments that could approximate 2.2% of
project revenue beginning in the year 2000, increasing to 2.9% in 2002. As part
of this acquisition, we own a 7.5% interest in the Bayonne Power Plant, a 165
megawatt gas-fired cogeneration power plant located in Bayonne, New Jersey. In
addition, we paid $105.3 million to restructure certain gas contracts related to
this acquisition.

On July 13, 1998, we signed a letter of intent to enter into a joint
venture to develop, own and operate approximately 2,000 megawatts of gas-fired
power plants in northern California primarily to serve the San Francisco Bay
Area. The gas-fired plants are to be constructed by Bechtel and operated by us.
We have announced that the first plant to be developed under the joint venture
will be the Delta Energy Center, an 880 megawatt gas-fired plant located at the
Dow Chemical facility in Pittsburg, California.

On July 17, 1998, we completed the purchase of a 60 megawatt geothermal
power plant located in Sonoma County, California, from the Sacramento Municipal
Utility District ("SMUD") for $13.0 million. We are the owner and operator of
the geothermal steam fields that provide steam to this facility. Under the
agreement, we paid SMUD $10.6 million at closing, and agreed to pay an
additional $2.4 million over the next two years. In connection with the
acquisition, SMUD agreed to purchase up to 50 megawatts of electricity from the
plant at current market prices plus a renewable power premium through 2001. In
addition, SMUD has the option to purchase 10 megawatts of off-peak power
production through 2005. We currently market the excess electricity into the
California power market.

On July 21, 1998, we completed the acquisition of a 70 megawatt gas-fired
power plant from The Dow Chemical Company for approximately $13.1 million. The
power plant is located at Dow's Pittsburg, California chemical facility. We will
sell up to 18 megawatts of electricity to Dow under a ten-year power sales
agreement, with the balance sold to Pacific Gas and Electric Company ("PG&E")
under an existing power sales agreement. In addition, we will sell approximately
200,000 lbs./hr of steam to Dow and to USS-POSCO Industries' nearby steel mill.

27
<PAGE> 31

In August 1998, we entered into a sale and leaseback transaction for
certain plant and equipment of our Greenleaf 1 & 2 Power Plants, two 49.5
megawatt gas-fired cogeneration facilities located in Sutter County, California,
for a net book value of $108.6 million. Under the terms of the agreement, we
received approximately $559,000 for the sale of all our rights, title and
interest in the stock of Calpine Greenleaf Corporation, and transferred all
non-recourse project financing of $71.6 million and deferred taxes of $21.4
million. A loss of $15.6 million was recorded on the balance sheet and is being
amortized over the term of the lease through June 2014. Additionally, we have an
early purchase option expiring September 30, 2003.

On September 28, 1998, we entered into a partnership agreement with Energy
Management, Inc. ("EMI") to acquire an ownership interest in a 265 megawatt
gas-fired plant under construction in Tiverton, Rhode Island. EMI and Calpine
will be co-general partners for this project, with EMI acting as the managing
general partner. We invested $40.0 million of equity in the power project, which
is scheduled to commence commercial operation in May 2000. We will receive 62.8%
of all cash and income distributions from the Tiverton project until we receive
a 10.5% pre-tax rate of return. Thereafter, we will receive 50% of all
distributions.

On November 18, 1998, we entered into a partnership agreement with EMI to
acquire an ownership interest in a 265 megawatt gas-fired plant under
construction in Rumford, Maine. EMI and Calpine will be co-general partners for
this project, with EMI acting as the managing general partner. We invested $40.0
million of equity in the power project, which is scheduled to commence
commercial operation in July 2000. We will receive 66 2/3% of all cash and
income distributions from the Rumford project until we receive a 10.5% pre-tax
rate of return. Thereafter, we will receive 50% of all distributions.

On January 4, 1999, we completed the acquisition of a 20% interest in 82
billion cubic feet of proven natural gas reserves located in the Sacramento
basin of Northern California. We paid approximately $14.9 million for $13.0
million in redeemable non-voting preferred stock and 20% of the outstanding
common stock of Sheridan California Energy, Inc. ("SCEI"). Additionally, we
signed a ten year gas contract enabling us to purchase 100% of SCEI's
production.

On February 17, 1999, we announced that the Delta Energy Center met the
California Energy Commission's Data Adequacy requirements. This ruling stated
that our Application for Certification contained adequate information for the
California Energy Commission to begin its analysis of the power plant's
environmental impacts and proposed mitigation. The Delta Energy Center, an 880
megawatt gas-fired power plant located at the Dow Chemical facility in
Pittsburg, California, is the first power plant that will be developed, owned
and operated under a joint venture with Bechtel Enterprises, and will provide
power to the Pittsburg, California and the greater San Francisco Bay Area. The
gas-fired power plant is to be constructed by Bechtel and operated by us.

On February 17, 1999, we announced plans to develop, own and operate a 545
megawatt gas-fired power plant in Westbrook, Maine. We acquired the development
rights for the Westbrook Power Plant from Genesis Power Corporation. This power
plant is scheduled to begin power deliveries in early 2001, and will serve the
New England market.

On February 24, 1999, we announced plans to develop, own and operate a 600
megawatt gas-fired power plant located in San Jose, California. This power
plant, called the Metcalf Energy Center, is the second power plant to be
developed under the

28
<PAGE> 32

joint venture with Bechtel Enterprises, and will provide electricity to the San
Francisco Bay area. We expect the plant to commence operation in mid 2002.

On March 19, 1999, we completed the acquisition of Unocal Corporation's
Geysers geothermal steam fields in northern California for approximately $102.1
million. The steam fields fuel our 12 Sonoma County power plants, totaling 544
megawatts of capacity. We purchased these plants from PG&E on May 7, 1999.

On April 14, 1999, we received approval from the California Energy
Commission to construct a 545 megawatt gas-fired power plant near Yuba City,
California. This power plant, called the Sutter Power Plant, was the first new
power plant approved in California's deregulated power industry. Electricity
produced by the Sutter Power Plant will be sold into California's energy market.
We expect the plant to commence operation in early 2001.

On April 22, 1999, we entered into a joint venture with GenTex Power
Corporation to develop, own and operate a 545 megawatt gas-fired power plant in
Bastrop County, Texas, called Lost Pines 1. Construction of this power plant is
expected to begin in October 1999. Under the definitive agreements we entered in
September 1999, we will manage all phases of the plant's development process,
with GenTex and ourselves jointly operating the plant. The output from Lost
Pines 1 will be divided equally, with GenTex selling its portion to its customer
base, while we will sell our portion to the wholesale power market in Texas. We
expect the plant to commence operation in mid-2001.

On April 23, 1999, we entered into a joint agreement with Pinnacle West
Capital Corporation to develop, own and operate a 545 megawatt gas-fired power
plant located in Phoenix, Arizona. This plant, called the West Phoenix Power
Plant, will provide power to the Phoenix metropolitan area, and construction
will commence in 2000. We expect the plant to commence operation in 2002.

On May 7, 1999, we completed the acquisitions from PG&E, of 12 Sonoma
County and 2 Lake County power plants for approximately $212.8 million. The
acquisitions were financed with a 24 year operating lease. Our geothermal steam
fields fuel the facilities, which have a combined capacity of approximately 694
megawatts of electricity. All of the generation from the facilities is sold to
the California energy market, with the exception of an agreement entered into on
April 29, 1999, to sell to Commonwealth Energy Corporation 75 megawatts of
geothermal electricity in 1999, 100 megawatts in 2000, and 125 megawatts in 2001
and through June 2002. Historically, we have served as a steam supplier for
these facilities, which had been owned and operated by PG&E. These acquisitions
have enabled us to consolidate our operations in The Geysers into a single
ownership structure and to integrate the power plant and steam field operations,
allowing us to optimize the efficiency and performance of the facilities. We
believe that these acquisitions provide us with significant synergies that
leverage our expertise in geothermal power generation and position us to benefit
from the demand for "green" energy in the competitive market.

On June 21, 1999, we acquired the rights to build, own and operate a 545
megawatt gas-fired power plant located in Ontelaunee Township, Pennsylvania. The
plant, called the Ontelaunee Energy Center, will provide power to residences and
businesses throughout the Pennsylvania-New Jersey-Maryland power pool.
Construction will commence in 2000 and the plant is scheduled to begin
production in 2002.

On July 26, 1999, we announced plans to enter into a $1.0 billion revolving
construction credit facility and expect to enter into definitive agreements in
the fall of 1999. The non-recourse credit facility will serve as a key component
of our development

29
<PAGE> 33

program and will be utilized to finance the construction of our diversified
portfolio of gas-fired power plants currently under development. We currently
intend to refinance the construction facility in the longer-term capital markets
prior to its four-year maturity.

On August 20, 1999, we announced the purchase of 18 F-class combustion
turbines from Siemens Westinghouse Power Corporation that will be capable of
producing 4,900 megawatts of electricity in a combined-cycle configuration.
Beginning in 2002, Siemens will deliver six turbines per year through 2004.
Combined with our existing turbine order we have 69 turbines under contract,
option or letter of intent capable of producing 17,745 megawatts.

On August 27, 1999, we announced an agreement with CGCA to acquire 80% of
its common stock for $25.00 per share or approximately $145.0 million. NRG
Energy, Inc., a wholly owned subsidiary of Northern States Power, will own the
remaining 20%. The transaction is subject to the approval of CGCA shareholders
and we expect to consummate the acquisition by year-end 1999. CCGA currently
owns interests in six natural gas-fired power plants, totaling 579 megawatts.
The plants are located in Pennsylvania, New Jersey, Illinois and Oklahoma.

On August 31, 1999, we completed the acquisition of an additional 50% of
the Aidlin Power Plant from Edison Mission Energy (5%) and General Electric
Capital Corporation (45%) for a total purchase price of $7.2 million. We now own
55% of the 20-megawatt Aidlin Power Plant.

On September 29, 1999 we completed the acquisition of development rights to
build, own and operate the Los Medanos Power Plant from Enron North America. The
Los Medanos Power Plant is a 500 megawatt gas-fired cogeneration plant located
adjacent to USS-POSCO Industries steel mill in Pittsburg, California. Los
Medanos will supply USS-POSCO with 60 megawatts of electricity and 75,000 pounds
per hour of steam, and market the excess electricity into the California power
exchange and under bilateral contracts. Construction commenced in September 1999
and commercial operation is scheduled to occur in 2001.

On September 30, 1999 we announced plans to build, own and operate an 800
megawatt gas-fired cogeneration power plant at Bayer Corporation's chemical
facility in Baytown, Texas. The Baytown Power Plant will supply Bayer with all
of its electric and steam requirements for 20 years and market excess
electricity into the Texas wholesale power market. Construction is estimated to
commence in 2000 and commercial operation in 2001.

On October 1, 1999, we completed the acquisition of Sheridan Energy, Inc.,
a natural gas exploration and production company, through a $41.0 million cash
tender offer. We purchased the outstanding shares of Sheridan Energy's common
stock for $5.50 per share. In addition, we redeemed $11.5 million of outstanding
preferred stock of Sheridan Energy. Sheridan Energy's oil and gas properties,
including 148 billion cubic feet equivalent of proven reserves, are located in
northern California and the Gulf Coast region, where we are developing low-cost
natural gas supplies and proprietary pipeline systems to support our
strategically-located natural gas-fired power plants.

On October 21, 1999, we completed the acquisition of the Calistoga
geothermal power plant from FPL Energy and Caithness Corporation for
approximately $78.0 million. Located in The Geysers region of northern
California, Calistoga is a 67 megawatt facility which provides electricity to
PG&E under a long-term contract.

On October 25, 1999, we announced that we had executed a letter of intent
which gives us the exclusive right to negotiate with LYONDELL-CITGO Refining LP
to build,

30
<PAGE> 34

own and operate a 560 megawatt gas-fired cogeneration power plant at the
LYONDELL-CITGO refinery in Houston, Texas. The Channel Energy Center will supply
all of the electricity and steam requirements for 20 years to the refinery.
Permitting for the facility is currently underway, with construction projected
to commence in early 2000 and commercial operation in 2001.

SELECTED OPERATING INFORMATION

Set forth below is certain selected operating information for the power
plants and steam fields for which results are consolidated in our consolidated
statements of operations. The information set forth under power plants consists
of the results for the West Ford Flat Power Plant, Bear Canyon Power Plant,
Greenleaf 1 & 2 Power Plants, Watsonville Power Plant, King City Power Plant,
Gilroy Power Plant, the Bethpage Power Plant since its acquisition on February
5, 1998, the Texas City and Clear Lake Power Plants since their acquisition on
March 31, 1998, the Pasadena Power Plant since it began commercial operation on
July 7, 1998, the Sonoma Power Plant since its acquisition on July 17, 1998 and
the Pittsburg Power Plant since its acquisition on July 21, 1998, and the 12
Sonoma County and 2 Lake County power plants purchased from PG&E on May 7, 1999.
The information set forth under steam fields consists of the results for the
Thermal Power Company Steam Fields prior to the acquisition.

<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
-------------------------------------------------------------- -----------------------
1994 1995 1996 1997 1998 1998 1999
---------- ---------- ---------- ---------- ---------- ---------- ----------
(DOLLARS IN THOUSANDS) (UNAUDITED)
<S> <C> <C> <C> <C> <C> <C> <C>
POWER PLANTS:

Electricity revenue
(1):

Energy................. $ 45,912 $ 54,886 $ 93,851 $ 110,879 $ 252,178 $ 93,735 $ 177,305

Capacity............... $ 7,967 $ 30,485 $ 65,064 $ 84,296 $ 193,535 $ 67,103 $ 106,155

Megawatt hours
produced............. 447,177 1,033,566 1,985,404 2,158,008 9,864,080 2,217,659 5,516,805

Average energy price
per kilowatt hour
(2).................. 10.267c 5.310c 4.727c 5.138c 2.557c 4.227c 3.214c

STEAM FIELDS:

Steam revenue (3):

Calpine................ $ 32,631 $ 39,669 $ 40,549 $ 42,102 $ 36,130 $ 17,960 $ 20,862

Other interest......... $ 2,051 $ -- $ -- $ -- $ -- $ -- $ --

Megawatt hours
produced............. 2,156,492 2,415,059 2,528,874 2,641,422 2,323,623 981,114 1,192,722

Average price per
kilowatt hour........ 1.608c 1.643c 1.603c 1.594c 1.555c 1.831c 1.749c
</TABLE>

- -------------------------
(1) Electricity revenue is composed of fixed capacity payments, which are not
related to production, and variable energy payments, which are related to
production.

(2) Represents variable energy revenue divided by the kilowatt-hours produced.
The significant increase in capacity revenue and the accompanying decline in
average energy price per kilowatt-hour since 1994 primarily reflects the
increase in our megawatt hour production as a result of additional gas-fired
power plants.

(3) The decline in steam revenue between 1998 and 1997 reflects the acquisition
and consolidation of the Sonoma Power Plant and the related steam fields. We
completed several acquisitions of geothermal power plants and steam fields
during 1999. Since the steam fields serve power plants owned by us following
their acquisitions, our steam fields will no longer recognize steam revenue.

31
<PAGE> 35

RESULTS OF OPERATIONS

SIX MONTHS ENDED JUNE 30, 1999 COMPARED TO SIX MONTHS ENDED JUNE 30, 1998

Revenue -- Total revenue increased 71% to $336.6 million for the six months
ended June 30, 1999 compared to $196.7 million for the same period in 1998.

Electricity and steam sales revenue for the six months ended June 30, 1999
increased 70% to $304.3 million as compared to $178.8 million for the same
period a year ago. This increase is primarily due to an increase of $106.3
million for power plants that were acquired during the first half of 1998, and
$32.7 million for our Pasadena plant that became operational in the third
quarter of 1998, partially offset by a decrease of $21.6 million at the Bear
Canyon and West Ford Flat Power Plants relating to the expiration of the fixed
priced period of their power sales agreements.

Service contract revenue increased to $13.2 million for the six months
ended June 30, 1999 compared to $8.5 million for the same period in 1998. The
increase was primarily attributable to third party excess gas sales, as well as
an increase for fuel management fees.

Income from unconsolidated investments in power projects for the six months
ended June 30, 1999 increased 165% to $18.3 million as compared to $6.9 million
for the same period a year ago. This increase is primarily attributable to an
increase of $11.4 million of equity income from our investment in Sumas, an
increase of $1.5 million of equity income from our investment in the Bayonne
Power Plant, and an increase of $1.1 million from our Kennedy International
Airport Power Plant. These increases were partially offset by a reduction of
$2.9 million in equity income from our Texas City and Clear Lake Power Plants,
which were consolidated on March 31, 1998.

Interest income on loans to power projects for the six months ended June
30, 1999 decreased to $709,000 compared to $2.6 million for the same period a
year ago. The decrease is primarily related to the acquisition of the remaining
50% interest in Texas Cogeneration Company on March 31, 1998, offset by dividend
income received from Sheridan California Energy.

Cost of revenue -- Cost of revenue increased to $238.2 million for the six
months ended June 30, 1999 compared to $136.1 million for the same period in
1998. The increase of $102.1 million was primarily attributable to increased
plant operating, fuel and depreciation expenses as a result of the acquisition
of the remaining interests in the Texas City, Clear Lake Power Plants on March
31, 1998, the acquisition of the remaining interest in the Bethpage Power Plant
on February 5, 1998, the acquisition of the Pittsburg Power Plant on July 21,
1998, the consolidation of our Geysers operations on May 7, 1999 and the startup
of the Pasadena Power Plant in July of 1998.

General and administrative expenses -- General and administrative expenses for
the six months ended June 30, 1999 increased to $21.0 million compared to $11.0
million for the same period in 1998. The increase was attributable to continued
growth in personnel and associated overhead costs necessary to support the
overall growth in our operations.

Interest expense -- Interest expense for the six months ended June 30, 1999
increased to $47.2 million from $40.8 million for the same period a year ago.
The increase was primarily attributable to $21.8 million of interest associated
with the issuances of senior

32
<PAGE> 36

notes in 1999 and 1998, partially offset by an increase in capitalized interest
of $10.3 million, and a decrease in interest expense of $4.7 million related to
the retirement of non-recourse project financing for the Greenleaf Power Plant
in 1998 and the Gilroy Power Plant in 1999.

Provision for income taxes -- The effective income tax rate was approximately
39% for the six months ended June 30, 1999. The reductions from the statutory
tax rate was primarily due to depletion in excess of tax basis benefits at our
geothermal facilities, and a decrease in the California taxes paid due to our
expansion into states other than California.

YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997

Revenue -- Total revenue increased 101% to $555.9 million in 1998 compared to
$276.3 million in 1997.

Electricity and steam sales revenue increased 114% to $507.9 million in
1998 compared to $237.3 million in 1997. The increase is primarily attributable
to the acquisition of the remaining interest in the Texas City, Clear Lake and
Bethpage Power Plants and the acquisition of the Pittsburg Power Plant. These
power plants accounted for $245.2 million in additional electricity revenues in
1998. We benefited from the startup of our power plant in Pasadena, Texas, which
became operational in July 1998. This power plant contributed $30.5 million in
revenue during 1998. During 1998, we produced 9,864,080 total electricity
megawatt hours, which was 7,706,072 megawatt hours higher than the same period
in 1997, as a result of the factors described above. We recently announced three
acquisitions, which we expect to complete during 1999, upon government approval.
These acquisitions when completed will eliminate steam revenue for The Geysers,
reflecting the consolidation of the acquired power plants and related steam
fields.

Service contract revenue increased 98% to $20.2 million in 1998 compared to
$10.2 million in 1997. The $10.0 million increase was primarily due to $3.3
million for fuel management fees, and $7.5 million for third party excess gas
sales.

Income from unconsolidated investments in power projects increased 59% to
$25.2 million in 1998 compared to $15.8 million in 1997. The increase of $9.4
million is primarily attributable to our investments in the Lockport, Stony
Brook and Kennedy International Airport Power Plants, which contributed $5.2
million of equity income during 1998, as well as $2.5 million of equity income
from the Bayonne Power Plant. For the year ended December 31, 1998, we also
recorded $11.7 million of equity income from the Sumas Power Plant compared to
$8.5 million for the same period in 1997. These increases in equity income were
partially offset by a $1.1 million decrease from the Auburndale Power Plant.

Interest income on loans to power projects decreased 80% to $2.6 million in
1998 compared to $13.0 million in 1997. This decrease was attributable to the
acquisition of the remaining 50% interest in TCC on March 31, 1998 and the sale
of a note receivable in December 1997.

Cost of revenue -- Cost of revenue increased to $375.3 million in 1998 compared
to $153.3 million in 1997. The increase of $222.0 million in 1998 was primarily
attributable to increased plant operating, fuel and depreciation expenses as a
result of the acquisition of the remaining interest in the Texas City, Clear
Lake and Bethpage Power Plants, the acquisition of the Pittsburg Power Plant and
the startup of the Pasadena Power Plant.

33
<PAGE> 37

Additionally, service contract expenses increased $8.8 million for the year
ended December 31, 1998, of which $6.6 million was related to costs associated
with the sale of third party excess gas and a $1.8 million increase for fuel
management contracts.

General and administrative expenses -- General and administrative expenses
increased 46% to $26.8 million in 1998 compared to $18.3 million in 1997. The
increase was attributable to the continued growth in personnel and overhead
costs necessary to support the overall growth in our operations.

Interest expense -- Interest expense increased 41% to $86.7 million in 1998
compared to $61.5 million in 1997. The increase was primarily attributable to
interest expense of $35.0 million related to the senior notes issued in 1998 and
1997. This increase was partially offset by $3.5 million for the repayment of
non-recourse project financing for our Geysers facilities, $2.9 million for
reduction of the TCC debt, $2.0 million for reduction of the indebtedness of the
Greenleaf 1 & 2 Power Plants and $1.7 million of interest capitalized on the
development and construction of power projects.

Interest income -- Interest income decreased 14% to $12.3 million in 1998
compared to $14.3 million in 1997. The decrease was primarily attributable to
less interest earned on restricted cash in 1998.

Other income, net -- Other income decreased 66% to $1.1 million in 1998 compared
to $3.2 million in 1997. The decrease was primarily attributable to gas refunds
received in 1997.

Provision for income taxes -- The effective income tax rate was approximately
37% in 1998 compared to 35% in 1997. The effective rates were lower than the
statutory rate (federal and state) primarily due to depletion in excess of tax
basis benefits at our geothermal facilities, and a decrease in the California
tax liability due to our expansion into states other than California.

YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED
DECEMBER 31, 1996

Revenue -- Total revenue increased 29% to $276.3 million in 1997 compared to
$214.6 million in 1996.

Electricity and steam sales revenue increased 19% to $237.3 million in 1997
compared to $199.5 million in 1996. Electricity and steam sales revenue for 1997
reflected a full year of operation at the Gilroy and King City Power Plants,
which contributed to increases in electricity and steam sales revenue in 1997
compared to 1996 of $25.4 million, and $4.3 million, respectively. Electricity
and steam sales revenue for 1997 compared to 1996 was also $6.0 million higher
at the Bear Canyon and West Ford Flat Power Plants as a result of increased
production and an increase in fixed energy prices to 13.83c per kilowatt-hour.
During 1996, the Bear Canyon and West Ford Flat Power Plants experienced the
maximum curtailment allowed under their power sales agreements with PG&E. In May
1997, the power sales agreements for the Bear Canyon and West Ford Flat Power
Plants were modified to remove curtailment. Without such curtailment, these
plants generated an additional $4.2 million in revenues in 1997 as compared to
1996. In addition, Thermal Power Company ("TPC") also contributed $2.7 million
more revenue for 1997 than 1996, primarily due to increased steam sales under
the alternative pricing agreement entered into with PG&E in March 1996.

34
<PAGE> 38

Service contract revenue increased to $10.2 million in 1997 compared to
$6.5 million in 1996. Service contract revenue during 1996 reflected a $2.8
million loss from our electricity trading operations. The increase in service
contract revenue for 1997 was also attributable to $2.8 million of revenue from
the Texas City and Clear Lake Power Plants, which were acquired in June 1997.

Income from unconsolidated investments in power projects increased to $15.8
million in 1997 compared to $6.5 million during 1996. The increase in 1997
compared to 1996 was primarily due to equity income of $6.3 million from our
June 1997 investment in the Texas City and Clear Lake Power Plants and an
increase in equity income of $2.2 million from our investment in Sumas
Cogeneration Company ("Sumas"). In accordance with a power sales agreement with
Puget Sound Power and Light Company, operations at Sumas were significantly
displaced from February to July 1997, and, in exchange, the Sumas Power Plant
received a higher price for energy sold and certain other payments. In addition,
the partnership agreement governing Sumas was amended in September 1997 to
increase our percentage of distributions.

Interest income on loans to power projects increased to $13.0 million in
1997 compared to $2.1 million in 1996. The increase was primarily related to
interest income on the loans made by Calpine Finance Company, a wholly-owned
subsidiary of our company, to the Texas City and Clear Lake Power Plants, and to
interest income on the loans to the sole shareholder of Sumas Energy, Inc., our
partner in Sumas.

Cost of revenue -- Cost of revenue increased 19% to $153.3 million in 1997
compared to $129.2 million in 1996. Plant operating, depreciation, and operating
lease expenses at the Gilroy and King City Power Plants for 1997 reflected a
full year of operations, which contributed to increases in cost of revenue in
1997 compared to 1996 of $13.0 million and $8.3 million, respectively.

Project development expenses -- Project development expenses increased 92% to
$7.5 million in 1997 compared to $3.9 million in 1996, due primarily to expanded
acquisition and development activities.

General and administrative expenses -- General and administrative expenses
increased 24% to $18.3 million in 1997 compared to $14.7 million in 1996. The
increases were primarily due to additional personnel and related expenses
necessary to support our expanding operations.

Interest expense -- Interest expense increased 36% to $61.5 million in 1997 from
$45.3 million in 1996. The increase was attributable to: (1) $10.8 million of
interest expense related to the 8 3/4% Senior Notes Due 2007 issued in July and
September 1997, (2) a $7.3 million increase in interest expense related to the
10 1/2% Senior Notes Due 2006 issued May 1996, (3) a $6.4 million increase in
interest expense on debt related to the Gilroy Power Plant acquired in August
1996 and (4) $5.4 million of interest expense on debt related to the acquisition
of the Texas City and Clear Lake Power Plants. These increases were offset by
$6.2 million of interest capitalized for the development and construction of
power plants, and a $7.6 million decrease in interest expense at Calpine Geysers
Company and TPC due to repayment of debt.

Interest income -- Interest income increased 66% to $14.3 million for 1997
compared with $8.6 million for 1996. Interest income earned on collateral
securities purchased in April 1996 in connection with the King City Power Plant
contributed to an increase in interest income of $1.2 million in 1997 as
compared to 1996. In addition, higher cash and cash

35
<PAGE> 39

equivalent balances resulting from the issuance of the 8 3/4% Senior Notes Due
2007 during 1997 resulted in higher interest income for 1997 as compared to
1996.

Other income, net -- Other income, net, increased to $3.2 million for 1997
compared with expense of $2.3 million for 1996. In 1997, we recorded a $1.1
million gain on the sale of a note receivable and received a refund of $961,000
from PG&E. In 1996, we recorded a $3.7 million loss for uncollectible amounts
related to an acquisition project.

Provision for income taxes -- The effective rate for the income tax provision
was approximately 35% in 1997 and 33% in 1996. The effective rates were lower
than the statutory tax rate (federal and state) primarily due to depletion in
excess of tax basis benefits at our geothermal facilities, a decrease in the
California taxes paid due to our expansion into states other than California,
and a revision of prior years' tax estimates.

LIQUIDITY AND CAPITAL RESOURCES

To date, we have obtained cash from our operations, borrowings under our
credit facilities and other working capital lines, sale of debt and equity, and
proceeds from non-recourse project financing. We utilized this cash to fund our
operations, service debt obligations, fund the acquisition, development and
construction of power generation facilities, finance capital expenditures and
meet our other cash and liquidity needs. The following table summarizes our cash
flow activities for the periods indicated:

<TABLE>
<CAPTION>
SIX MONTHS ENDED
YEAR ENDED DECEMBER 31, JUNE 30,
--------------------------------- ---------------------
1996 1997 1998 1998 1999
--------- --------- --------- --------- ---------
(IN THOUSANDS) (UNAUDITED)
<S> <C> <C> <C> <C> <C>
Cash flows from:
Operating activities......... $ 59,944 $ 108,461 $ 171,233 $ 23,073 $ 58,555
Investing activities......... (330,937) (402,158) (406,657) (174,923) (590,328)
Financing activities......... 345,153 246,240 283,443 203,696 755,528
--------- --------- --------- --------- ---------
Total................. $ 74,160 $ (47,457) $ 48,019 $ 51,846 $ 223,755
========= ========= ========= ========= =========
</TABLE>

Operating activities for the six months ended June 30, 1999 provided $58.6
million, consisting of approximately $44.1 million of depreciation and
amortization, $21.4 million of net income, $25.5 million of distributions from
unconsolidated investments in power projects, $13.3 million of deferred income
taxes, and a $7.2 million net increase in operating liabilities. This was offset
by $34.6 million net increase in operating assets and $18.3 million of income
from unconsolidated investments. Operating activities for 1998 provided $171.2
million, consisting of approximately $74.3 million of depreciation and
amortization, $45.7 million of net income, $34.4 million of distributions from
unconsolidated investments in power projects, $13.6 million of deferred income
taxes, $5.2 million net decrease in operating assets, and a $23.4 million net
increase in operating liabilities. This was offset by $25.2 million of income
from unconsolidated investments.

Investing activities for the six months ended June 30, 1999 used $590.3
million, primarily due to $102.2 million for the acquisition of steam fields
from Unocal, $14.9 million for the acquisition of a 20% interest in SCEI, a
$15.8 million increase in restricted cash, $79.3 million of capital expenditures
related to the construction of the Pasadena Power Plant Expansion, $344.6
million of other capital expenditures principally for turbine purchases and for
the Clear Lake Expansion project, $33.8 million of capitalized project
development costs, $14.0 million of interest capitalized on construction

36
<PAGE> 40

projects, $8.4 million of additional loans to principal owners of power plants,
$655,000 for the acquisition of additional investments, offset by $1.9 million
of maturities of collateral securities in connection with the King City Power
Plant, the repayment of $3.1 million of outstanding loans, and $18.4 million
from the sale and leaseback transaction of the Geysers Power Company plants.
Investing activities for 1998 used $406.7 million, primarily due to $158.1
million for the acquisition of the remaining 50% interest in the Texas City and
Clear Lake Power Plants, $42.4 million for the acquisition of the remaining 55%
interest in the Bethpage Power Plant, $24.0 million of capital expenditures
related to the construction of the Pasadena Power Plant, $13.1 million for the
acquisition of the Pittsburg Power Plant, $11.9 million for the acquisition of
the Sonoma Power Plant, $74.2 million of other capital expenditures, $16.2
million of capitalized project development costs, $40.0 million for the
acquisition of an equity interest in the Tiverton Power Plant, $40.0 million for
the acquisition of an equity interest in the Rumford Power Plant, $7.0 million
of interest capitalized on construction projects, offset by $559,000 related to
the sale and leaseback transaction of the Greenleaf 1 & 2 Power Plants, the
receipt of $13.8 million of loan payments, $6.0 million of maturities of
collateral securities in connection with the King City Power Plant, and $1.1
million of restricted cash.

Financing activities for the six months ended June 30, 1999 provided $755.5
million of cash consisting of $79.2 million of borrowings for the construction
of the Pasadena Power Plant, $77.6 million of borrowings related to a bridge
facility, $794.8 million of net proceeds from additional equity and senior debt
financings received in March and April of 1999, and $1.2 million for the
issuance of common stock for our Employee Stock Purchase Plan, partially offset
by $120.6 million in repayment of non-recourse project financing in April 1999,
and $77.6 million of repayments related to a bridge facility. Financing
activities for 1998 provided $283.4 million of cash consisting of $52.1 million
of borrowings for the construction of the Pasadena Power Plant, $5.8 million of
borrowings for contingent consideration in connection with the acquisition of
the Gilroy Power Plant, $394.9 million of net proceeds from additional
financings, and $1.1 million for the issuance of common stock, partially offset
by $162.1 million in repayment of non-recourse project financing, $8.3 million
of repurchase of Senior Notes Due 2006 which includes a premium paid and accrued
interest to the date of repurchase.

At June 30, 1999, cash and cash equivalents were $320.3 million and working
capital was $346.4 million. For 1999, cash and cash equivalents increased by
$223.8 million and working capital increased by $259.5 million as compared to
December 31, 1998. At December 31, 1998, cash and cash equivalents were $96.5
million and working capital was $86.9 million. For 1998, cash and cash
equivalents increased by $48.0 million and working capital increased by $112.6
million as compared to December 31, 1997.

As a developer, owner and operator of power generation facilities, we are
required to make long-term commitments and investments of substantial capital
for our projects. We historically have financed these capital requirements with
cash from operations, borrowings under our credit facilities, other lines of
credit, non-recourse project financing or long-term debt, and the sale of
equity.

We continue to evaluate current and forecasted cash flow as a basis for
financing operating requirements and capital expenditures. We believe that we
will have sufficient liquidity from cash flow from operations, borrowings
available under the lines of credit and working capital to satisfy all
obligations under outstanding indebtedness, to finance anticipated capital
expenditures and to fund working capital requirements for the next twelve
months.

37
<PAGE> 41

On January 4, 1999, we entered into a Credit Agreement with ING to provide
up to $265.0 million of non-recourse project financing for the construction of
the Pasadena facility expansion. As of June 30, 1999, $79.2 million was
outstanding as a construction loan under the agreement. The outstanding loan
bears interest at ING's base rate plus an applicable margin or at LIBOR plus an
applicable margin and is payable quarterly. The construction loan will convert
to a term loan once the project has completed construction. The construction
loan will mature on or before July 1, 2000, but is subject to an extension to
October 1, 2000 if there are sufficient construction funds available. The term
loan will be available for a period not to exceed five years from the
construction loan maturity date. In connection with the Credit Agreement, we
entered into a $10.0 million letter of credit facility. At June 30, 1999, there
were no letters of credit outstanding under the facility.

On March 26, 1999, we completed a public offering of 12,000,000 shares of
our common stock at $15.50 per share. The net proceeds from this public offering
were approximately $177.9 million. Additionally, in April 1999, we sold an
additional 1,800,000 shares of common stock at $15.50 per share pursuant to the
exercise of the underwriters' over-allotment option for net proceeds of
approximately $26.7 million.

On March 29, 1999, we completed a public offering of $250.0 million of our
7 5/8% Senior Notes Due 2006 and of our $350.0 million 7 3/4% Senior Notes Due
2009. After deducting underwriting discounts and expenses of the offering, the
aggregate net proceeds from the sale of the Senior Notes were approximately
$588.3 million. The Senior Notes Due 2006 bear interest at 7 5/8% per year,
payable semi-annually on April 15 and October 15 each year and mature on April
15, 2006. The Senior Notes Due 2006 are not redeemable prior to maturity. The
Senior Notes Due 2009 bear interest at 7 3/4% per year, payable semi-annually on
April 15 and October 15 each year and mature on April 15, 2009. The Senior Notes
Due 2009 are not redeemable prior to maturity.

The net proceeds from the sale of the common stock, the Senior Notes Due
2006, and the Senior Notes Due 2009 were used as follows: (1) $120.6 million to
refinance indebtedness relating to the Gilroy Power Plant, (2) $77.6 million to
repay indebtedness under a bridge facility provided by Credit Suisse First
Boston to finance a portion of the purchase price to acquire the steam fields
that service the Sonoma County power plants, (3) $50.0 million to repay
outstanding borrowings under our revolving credit facility, $23.4 million of
which was incurred to finance a portion of the steam fields that service the
Sonoma Power Plants, (4) $25.0 million to complete the expansion of the Clear
Lake Power Plant, (5) approximately $400.0 million to finance a portion of power
generation facilities currently under construction and the projects currently
under development, and (6) the remaining $119.6 million will be used for general
corporate purposes. Transaction costs incurred in connection with the senior
notes offered were recorded as deferred charge and are amortized over the
respective lives of the Senior Notes Due 2006 and the Senior Notes Due 2009
using the effective interest rate method.

At June 30, 1999, we had a $100.0 million revolving credit facility
available with a consortium of commercial lending institutions. We had no
borrowings and $20.9 million of letters of credit outstanding under the credit
facility. The credit facility contains certain restrictions that limit or
prohibit, among other things, the ability of Calpine or its subsidiaries to
incur indebtedness, make payments of certain indebtedness, pay dividends, make
investments, engage in transactions with affiliates, create liens, sell assets
and engage in mergers and consolidations.

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<PAGE> 42

At June 30, 1999, we also had $105.0 million of outstanding 9 1/4% Senior
Notes Due 2004, which mature on February 1, 2004, with interest payable
semi-annually on February 1 and August 1 of each year. In addition, we had
$171.8 million of outstanding 10 1/2% Senior Notes Due 2006, which mature on May
15, 2006, with interest payable semi-annually on May 15 and November 15 of each
year. During 1997, we issued $275.0 million of 8 3/4% Senior Notes Due 2007,
which mature on July 15, 2007, with interest payable semi-annually on January 15
and July 15 of each year. During 1998, we issued $400.0 million of 7 7/8% Senior
Notes due 2008, which mature on April 1, 2008, with interest payable
semi-annually on April 1 and October 1 of each year.

At June 30, 1999, we had a $12.0 million letter of credit outstanding with
The Bank of Nova Scotia to secure performance of the Clear Lake Power Plant.

We have a $1.1 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, 1999, we had no borrowings under this working capital line
and $74,000 of letters of credit outstanding. Borrowings accrue interest at
prime plus 1%.

FINANCIAL MARKET RISKS

From time to time, we use interest rate swap agreements to mitigate our
exposure to interest rate fluctuations. We do not use derivative financial
instruments for speculative or trading purposes. The following table summarizes
the fair market value of our existing interest rate swap agreements as of June
30, 1999 (in thousands):

<TABLE>
<CAPTION>
WEIGHTED
NOTIONAL AVERAGE
MATURITY DATE PRINCIPAL AMOUNT INTEREST RATE FAIR MARKET VALUE
- ------------- ---------------- ------------- -----------------
<S> <C> <C> <C>
2000 $ 21,800 9.9% $ (571)
2009 65,000 6.1% 1,156
2013 75,000 7.2% (3,480)
2014 79,970 6.7% (1,423)
--------- ------------- -----------------
Total $241,770 7.1% $(4,318)
========= ============= =================
</TABLE>

Short-term investments. As of June 30, 1999, we have short-term investments
of $271.3 million. These short-term investments consist of highly liquid
investments with maturities between three and twelve months. These investments
are subject to interest rate risk and will increase in value if market interest
rates increase. We have the ability to hold these investments to maturity, and
as a result, we would not expect the value of these investments to be affected
to any significant degree by the effect of a sudden change in market interest
rates. Declines in interest rates over time will reduce our interest income.

39
<PAGE> 43

Outstanding debt. As of June 30, 1999, we have outstanding long-term debt
of approximately $1.6 billion primarily made up of $1.5 billion of senior notes
and $79.2 million of construction financing. Our construction financing has a
floating interest rate which has averaged 6.8%. Our outstanding long-term senior
notes as of June 30, 1999 are as follows (in thousands):

<TABLE>
<CAPTION>
MATURITY DATE CARRYING AMOUNT INTEREST RATE FAIR MARKET VALUE
- ------------- --------------- ------------- -----------------
<S> <C> <C> <C>
2004 $ 105,000 9 1/4% $ 106,050
2006 171,750 10 1/2% 185,267
2006 250,000 7 5/8% 243,125
2007 275,000 8 3/4% 282,219
2008 400,000 7 7/8% 384,600
2009 350,000 7 3/4% 330,313
---------- ----------
Total $1,551,750 $1,513,574
========== ==========
</TABLE>

Gas prices fluctuations. We enter into derivative commodity instruments to
hedge our exposure to the impact of price fluctuations on gas purchases. Such
instruments include regulated natural gas contracts and over-the-counter swaps
and basis hedges with major energy derivative product specialists. All hedge
transactions are subject to our risk management policy which does not permit
speculative positions. These transactions are accounted for under the hedge
method of accounting. Cash flows from derivative instruments are recognized as
incurred through changes in working capital.

IMPACT OF RECENT ACCOUNTING PRONOUNCEMENTS

In June 1999, the FASB issued FASB Statement No. 137 entitled "Accounting
for Derivative Instruments and Hedging Activities -- Deferral of the Effective
Date of FASB Statement No. 133." The Statement would amend SFAS No. 133 to defer
its effective date to all fiscal quarters of all fiscal years beginning after
June 15, 2000. We have not yet analyzed the impact of adopting SFAS No. 133 on
the financial statements and have not determined the timing of or method of the
adoption of SFAS No. 133. However, the Statement could increase the volatility
of our earnings.

YEAR 2000 COMPLIANCE

Year 2000 Compliance -- The "Year 2000 problem" refers to the fact that
some computer hardware, software and embedded systems were designed to read and
store dates using only the last two digits of the year.

We are coordinating our efforts to address the impact of Year 2000 on our
business through a Year 2000 Project Team comprised of representatives from each
business unit and our Year 2000 Project Office. The Year 2000 Project Office is
charged with addressing additional Year 2000 related issues including, but not
limited to, business continuation and other contingency planning. The Year 2000
Project Team meets regularly to monitor the efforts of assigned staff and
contractors to identify, remediate and test our technology.

The Year 2000 Project Team is focusing on four separate technology domains:

- corporate applications, which include core business systems,

- non-information technology, which includes all operating and control
systems,

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<PAGE> 44

- end-user computing systems (that is, systems that are not considered core
business systems but may contain date calculations), and

- business partner and vendor systems.

Corporate Applications -- Corporate applications are those major core
systems, such as customer information, human resources and general ledger, for
which our Management Information Systems department has responsibility. We
utilize PeopleSoft for our major core systems. The PeopleSoft applications we
utilize are in operation and have been determined to be Year 2000 compliant.

Non-Information Technology/Embedded Systems -- Non-information technology
includes such items as power plant operating and control systems,
telecommunications and facilities-based equipment (e.g. telephones and two-way
radios) and other embedded systems. Each business unit is responsible for the
inventory and remediation of its embedded systems. In addition, we are working
with the Electric Power Research Institute, a consortium of power companies,
including investor-owned utilities, to coordinate vendor contacts and product
evaluation. Because many embedded systems are similar across utilities, this
concentrated effort should help to reduce total time expended in this area and
help to ensure that our efforts are consistent with the efforts and practices of
other power companies and utilities.

An Inventory phase for non-information technology/embedded systems was
completed in October 1998. An Initial Assessment phase was completed in December
1998. We plan to complete remediation of non-compliant systems by the fourth
quarter of 1999. To date, all embedded systems that we have identified can be
upgraded or modified within our current schedule. The schedule for addressing
Year 2000 issues with respect to mission critical embedded systems is as
follows:

<TABLE>
<CAPTION>
PERCENTAGE
PHASE COMPLETED STATUS ESTIMATED COMPLETION DATE
- ---------------------- ---------- ----------- --------------------------
<S> <C> <C> <C>
Inventory............. 100% Complete September 1998
Initial Assessment.... 100% Complete November 1998
Detail Assessment..... 100% Complete May 1999
Remediation........... 99% In Progress November 1999
Contingency Planning.. 5% In Progress November 1999
</TABLE>

Testing of embedded systems is complex because some of the testing must be
completed during power plant scheduled maintenance outages. Much of the testing
will be accomplished in the fall of 1999 during regularly scheduled maintenance
outage periods. At that time, at least one typical unit of each critical type
will be tested by us or in cooperation with other power companies, and the
requirement for further testing will be determined.

End-User Computing Systems -- Some of our business units have developed
systems, databases, spreadsheets, etc. that contain date calculations.
Compliance of individual workstations is also included in this domain. These
systems comprise a relatively small percentage of the required modification in
terms of both number and criticality.

Our end-user computing systems are being inventoried by each business unit
and evaluated and remediated by our MIS staff. We expect to complete this
process by year-end 1999.

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<PAGE> 45

Business Partner and Vendor Systems -- We have contracts with business
partners and vendors who provide products and services to us. We are vigorously
seeking to obtain Year 2000 assurances from these third parties. The Year 2000
Project Team and appropriate business units are jointly undertaking this effort.
We have sent letters and accompanying Year 2000 surveys to about 800 vendors and
suppliers. Over 600 responses have been received as of July 31, 1999. These
responses outline to varying degrees the approaches vendors are undertaking to
resolve Year 2000 issues within their own systems. Follow-up letters will be
sent to those vendors who have not responded or whose responses were inadequate.

Contingency Planning -- Contingency and business continuation planning are
in various stages of development for critical and high-priority systems. Our
existing disaster response plan and other contingency plans are currently being
evaluated and will be adopted for use in case of any Year 2000-related
disruption. We expect to complete our contingency planning by November 1999.

Costs -- The costs of expected modifications are currently estimated to be
approximately $1.7 million which will be charged to expense as incurred. From
January 1, 1999 through June 30, 1999, $321,000 was charged to expense.
Approximately 9% of the estimated total cost was incurred in 1998, 63% will be
incurred in 1999 and the remainder will be incurred in 2000. These costs have
been and will be funded through operating cash flow. These estimates may change
as additional evaluations are completed and remediation and testing progress.

Risks -- We currently expect to complete our Year 2000 efforts with respect
to critical systems by the fall of 1999. This schedule and our cost estimates
may be affected by, among other things, the availability of Year 2000 personnel,
the readiness of third parties, the timing for testing our embedded systems, the
availability of vendor resources to complete embedded system assessments and
produce required component upgrades and our ability to implement appropriate
contingency plans.

The cost or consequences of a materially incomplete or untimely resolution
of the Year 2000 problem could adversely affect our future operations, financial
results or our financial condition.

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<PAGE> 46

BUSINESS

OVERVIEW

Calpine is a leading independent power company engaged in the development,
acquisition, ownership and operation of power generation facilities and the sale
of electricity predominantly in the United States. We have experienced
significant growth in all aspects of our business over the last five years.
Currently, we own interests in 38 power plants having an aggregate capacity of
3,694 megawatts and have an acquisition pending in which we will acquire 80% of
CGCA which owns interests in 6 power plants with an aggregate capacity of 579
megawatts. We also have 8 gas-fired projects and one project expansion under
construction having an aggregate capacity of 4,485 megawatts and have announced
plans to develop 6 gas-fired power plants with a total capacity of 3,930
megawatts. Upon completion of pending acquisitions and projects under
construction, we will have interests in 52 power plants located in 14 states
having an aggregate capacity of 8,758 megawatts, of which we will have a net
interest in 7,381 megawatts. This represents significant growth from the 342
megawatts of capacity we had at the end of 1993. Of this total generating
capacity, 90% will be attributable to gas-fired facilities and 10% will be
attributable to geothermal facilities.

As a result of our expansion program, our revenues, cash flow, earnings and
assets have grown significantly over the last five years, as shown in the table
below.

<TABLE>
<CAPTION>
COMPOUND ANNUAL
1993 1998 GROWTH RATE
-------- ---------- ---------------
(DOLLARS IN MILLIONS)
<S> <C> <C> <C>
Total Revenue..................... $ 69.9 $ 555.9 51%
EBITDA............................ 42.4 255.3 43%
Net Income........................ 3.8 45.7 64%
Total Assets...................... 302.3 1,728.9 42%
</TABLE>

THE MARKET

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<PAGE> 47

In addition, as a result of a variety of factors, including deregulation of
the power generation market, utilities, independent power producers and
industrial companies are disposing of power generation facilities. To date,
numerous utilities have sold or announced their intentions to sell their power
generation facilities and have focused their resources on the transmission and
distribution segments. Many independent producers operating a limited number of
power plants are also seeking to dispose of their plants in response to
competitive pressures, and industrial companies are selling their power plants
to redeploy capital in their core businesses.

STRATEGY

- Development and expansion of power plants. We are actively pursuing the
development and expansion of highly efficient, low-cost, gas-fired power
plants to replace old and inefficient generating facilities and meet the
demand for new generation. Our strategy is to develop power plants in
strategic geographic locations that enable us to utilize existing power
generation assets and operate the power plants as integrated electric
generation systems. This allows us to achieve significant operating
synergies and efficiencies in fuel procurement, power marketing and
operations and maintenance.

In May 1999, we completed a 35 megawatt expansion of our Clear Lake Power
Plant to 412 megawatts, and we commenced commercial operations at our 169
megawatt Dighton Power Plant in August 1999.

We currently have nine projects under construction representing an
additional 4,485 megawatts. Of these new projects, we are currently
expanding our Pasadena facility by 545 megawatts to 785 megawatts and we
have eight new power plants under construction, including the Tiverton
Power Plant in Rhode Island; the Rumford Power Plant in Maine; the
Westbrook Power Plant in Maine; the Sutter Power Plant in California; the
Los Medanos Power Plant in California; the South Point Power Plant in
Arizona; the Magic Valley Power Plant in Texas; and the Lost Pines 1
Power Plant in Texas. We have also announced plans to develop six
additional power generation facilities, totaling 3,930 megawatts, in
California, Texas, Arizona and Pennsylvania.

44
<PAGE> 48

construction of our development program. We expect to finalize the
documentation relating to this facility in the fourth quarter of 1999.

On August 20, 1999, we announced the purchase of 18 F-class combustion
turbines from Siemens Westinghouse Power Corporation that will be capable
of producing 4,900 megawatts of electricity. Beginning in 2002, Siemens
will deliver six turbines per year through 2004. Combined with our
existing turbine order we have 69 turbines under contract, option or
letter of intent capable of producing 17,745 megawatts.

- Acquisition of power plants. Our strategy is to acquire power generating
facilities that meet our stringent criteria, provide significant
potential for revenue, cash flow and earnings growth and provide the
opportunity to enhance the operating efficiencies of the plants. We have
significantly expanded and diversified our project portfolio through the
acquisition of power generation facilities through the completion of 32
acquisitions to date.

On March 19, 1999, we completed the acquisition of Unocal Corporation's
Geysers geothermal steam fields in northern California for approximately
$102.1 million. The steam fields fuel our 12 Sonoma County power plants,
totaling 544 megawatts purchased from PG&E.

On May 7, 1999 we completed the acquisition from PG&E of 14 geothermal
power plants at The Geysers in northern California, with a combined
capacity of approximately 700 megawatts, for $212.8 million. With the
acquisition, we now own interests in and operate 18 geothermal power
plants that generate more than 800 megawatts of electricity, and we are
the nation's largest geothermal and green power producer. The combination
of our existing geothermal steam and power plant assets, the acquisition
of the Sonoma steam fields from Unocal, and the 14 power plants from PG&E
allows us to fully integrate the steam and power plant operations at The
Geysers into one efficient, unified system to maximize the renewable
natural resource, lower overall production costs and extend the life of
The Geysers.

On August 27, 1999, we announced an agreement with CGCA to acquire 80% of
its common stock for $25.00 per share or approximately $145.0 million.
NRG Energy, Inc., a wholly owned subsidiary of Northern States Power,
will own the remaining 20%. The transaction is subject to the approval of
CGCA shareholders and we expect to consummate the acquisition by year-end
1999. CCGA currently owns interests in six natural gas-fired power
plants, totaling 579 megawatts. The plants are located in Pennsylvania,
New Jersey, Illinois and Oklahoma.

On August 31, 1999, we completed the acquisition of an additional 50% of
the Aidlin Power Plant from Edison Mission Energy (5%) and General
Electric Capital Corporation (45%) for a total purchase price of $7.2
million. We now own 55% of the 20 megawatt Aidlin Power Plant.

On October 1, 1999, we completed the acquisition of Sheridan Energy,
Inc., a natural gas exploration and production company, through a $41.0
million cash tender offer. We purchased the outstanding shares of
Sheridan Energy's common stock for $5.50 per share. In addition, we
redeemed $11.5 million of outstanding preferred stock of Sheridan Energy.
Sheridan Energy's oil and gas properties, including 148 billion cubic
feet equivalent of proven reserves, are located in northern California
and the Gulf Coast region, where we are developing low-cost

45
<PAGE> 49

natural gas supplies and proprietary pipeline systems to support our
strategically-located natural gas-fired power plants.

- Enhancement of existing power plants. We continually seek to maximize the
power generation and revenue potential of our operating assets and
minimize our operating and maintenance expenses and fuel costs. This will
become even more significant as our portfolio of power generation
facilities expands to an aggregate of 52 power plants with an aggregate
capacity of 8,758 megawatts, after completion of our pending acquisitions
and projects currently under construction. We focus on operating our
plants as an integrated system of power generation, which enables us to
minimize costs and maximize operating efficiencies. As of June 30, 1999,
our gas-fired and geothermal power generation facilities have operated at
an average availability of approximately 96% and 99%, respectively. We
believe that achieving and maintaining a low-cost of production will be
increasingly important to compete effectively in the power generation
market.

On July 8, 1999, we announced a renegotiation of our Gilroy power sales
agreement with PG&E. The amendment provides for the termination of the
remaining 18 years of the long-term contract in exchange for a fixed
long-term payment schedule. The amended agreement is subject to approval
by the California Public Utilities Commission, whose decision we expect
to receive in the fourth quarter of 1999. We will continue to sell the
output from the Gilroy Power Plant through October 2002 to PG&E and
thereafter we will market the output in the California wholesale power
market.

DESCRIPTION OF FACILITIES

We currently have interests in 38 power generation facilities with a
current aggregate capacity of approximately 3,694 megawatts, consisting of 19
gas-fired power plants with a total capacity of 2,806 megawatts and 19
geothermal power generation facilities with a total capacity of 888 megawatts.
We also have an acquisition pending comprising 6 gas-fired facilities with an
aggregate capacity of 579 megawatts, 8 gas-fired projects and one project
expansion currently under construction with an aggregate capacity of 4,485
megawatts, and have announced the development of 6 additional power plants with
an aggregate capacity of 3,930 megawatts. Each of the power generation
facilities currently in operation produces electricity for sale to a utility or
other third-party end user. Thermal energy produced by the gas-fired
cogeneration facilities is sold to governmental and industrial users.

The gas-fired and geothermal power generation projects in which we have an
interest produce electricity and thermal energy that are typically sold pursuant
to long-term power sales agreements. 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

46
<PAGE> 50

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.

Upon completion of the pending acquisitions and projects under
construction, we will provide operating and maintenance services for 42 of the
52 power plants in which we have an interest. Such services include the
operation of power plants, geothermal steam fields, wells and well pumps,
gathering systems and gas pipelines. We also supervise maintenance, materials
purchasing and inventory control, manage cash flow, train staff and prepare
operating and maintenance manuals for each power generation facility that we
operate. As a facility develops an operating history, we analyze 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 we are generally reimbursed for certain costs, paid
an annual operating fee and may also be paid an incentive fee based on the
performance of the facility. The fees payable to us are generally subordinated
to any lease payments or debt service obligations of non-recourse financing for
the project.

In order to provide fuel for the gas-fired power generation facilities in
which we have an interest, natural gas reserves are acquired or natural gas is
purchased from third parties under supply agreements. We attempt to structure a
gas-fired power facility's fuel supply agreement so that gas costs have a direct
relationship to the fuel component of revenue energy payments. We currently hold
interests in geothermal leaseholds in The Geysers that produce steam that is
supplied to the power generation facilities owned by us for use in producing
electricity.

Certain power generation facilities in which we have an interest have been
financed primarily with non-recourse project financing that is structured to be
serviced out of the cash flows derived from the sale of electricity, thermal
energy and/or steam produced by such facilities and provides that the
obligations to pay interest and principal on the loans are secured almost solely
by the capital stock or partnership interests, physical assets, contracts and/or
cash flow attributable to the entities that own the facilities. The lenders
under non-recourse project financing generally have no recourse for repayment
against us or any of our assets or the assets of 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 we have an
interest are located on sites which are leased on a long-term basis. See
"-- Properties."

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<PAGE> 51

Set forth below is a map showing the locations of our power plants in
operation, pending acquisitions, power plants under construction and announced
development projects.

[DEPICTION OF A MAP OF THE UNITED STATES, WITH MARKERS INDICATING THE LOCATION
OF OUR FACILITIES]

<TABLE>
<CAPTION>
MEGAWATTS
-----------------------
# OF PLANT CALPINE NET
PLANTS CAPACITY INTEREST
------ -------- -----------
<S> <C> <C> <C>
In operation.................................... 38 3,694 2,955
Pending acquisitions............................ 6 579 400
Under construction
-- New facilities............................. 8 3,940 3,481
-- Expansion projects......................... -- 545 545
Announced development........................... 6 3,930 2,918
-- ------ ------
58 12,688 10,299
== ====== ======
</TABLE>

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<PAGE> 52

Set forth below is certain information regarding our operating power
plants, plants under construction, pending power plant acquisitions and
development projects.

<TABLE>
<CAPTION>
POWER NAMEPLATE CALPINE CALPINE NET
GENERATION CAPACITY INTEREST INTEREST
POWER PLANT TECHNOLOGY LOCATION (MEGAWATTS)(1) PERCENTAGE (MEGAWATTS)
----------- ---------- ------------- -------------- ---------- -----------
<S> <C> <C> <C> <C> <C>
OPERATING POWER PLANTS
Sonoma County (12 power
plants)(3)............ Geothermal California 544.0 100% 544.0
Texas City.............. Gas-Fired Texas 450.0 100% 450.0
Clear Lake.............. Gas-Fired Texas 412.0 100% 412.0
Pasadena................ Gas-Fired Texas 240.0 100% 240.0
Gordonsville............ Gas-Fired Virginia 240.0 50% 120.0
Lockport................ Gas-Fired New York 184.0 11.4% 20.9
Dighton(6).............. Gas-Fired Massachusetts 169.0 50% 84.5
Bayonne................. Gas-Fired New Jersey 165.0 7.5% 12.4
Auburndale.............. Gas-Fired Florida 150.0 50% 75.0
Lake County (2 power
plants)(3)............ Geothermal California 150.0 100% 150.0
Sumas(2)................ Gas-Fired Washington 125.0 70% 87.5
King City............... Gas-Fired California 120.0 100% 120.0
Gilroy.................. Gas-Fired California 120.0 100% 120.0
Kennedy International
Airport............... Gas-Fired New York 107.0 50% 53.5
Pittsburg............... Gas-Fired California 70.0 100% 70.0
Calistoga............... Geothermal California 67.0 100% 67.0
Sonoma(3)............... Geothermal California 60.0 100% 60.0
Bethpage................ Gas-Fired New York 57.0 100% 57.0
Greenleaf 1............. Gas-Fired California 49.5 100% 49.5
Greenleaf 2............. Gas-Fired California 49.5 100% 49.5
Stony Brook............. Gas-Fired New York 40.0 50% 20.0
Agnews.................. Gas-Fired California 29.0 20% 5.8
Watsonville............. Gas-Fired California 28.5 100% 28.5
West Ford Flat.......... Geothermal California 27.0 100% 27.0
Bear Canyon............. Geothermal California 20.0 100% 20.0
Aidlin.................. Geothermal California 20.0 55% 11.0
PENDING ACQUISITIONS
Grays Ferry............. Gas-Fired Pennsylvania 150.0 40% 60.0
Parlin.................. Gas-Fired New Jersey 122.0 80% 97.6
Morris.................. Gas-Fired Illinois 117.0 80% 93.6
Pryor................... Gas-Fired Oklahoma 110.0 80% 88.0
Newark.................. Gas-Fired New Jersey 58.0 80% 46.4
Philadelphia............ Gas-Fired Pennsylvania 22.0 66.4% 14.6
PROJECTS UNDER
CONSTRUCTION
Magic Valley............ Gas-Fired Texas 730.0 100% 730.0
Los Medanos............. Gas-Fired California 500.0 100% 500.0
Westbrook............... Gas-Fired Maine 545.0 100% 545.0
Pasadena Expansion...... Gas-Fired Texas 545.0 100% 545.0
South Point............. Gas-Fired Arizona 545.0 100% 545.0
Sutter.................. Gas-Fired California 545.0 100% 545.0
Lost Pines 1............ Gas-Fired Texas 545.0 50% 272.5
Tiverton(4)............. Gas-Fired Rhode Island 265.0 62.8% 166.4
Rumford(5).............. Gas-Fired Maine 265.0 66.7% 176.8
</TABLE>

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<PAGE> 53

- -------------------------
(1) Nameplate capacity may not represent the actual output for a facility at any
particular time.

(2) See "-- Operating Power Plants -- Sumas Power Plant" for a description of
our interest in the Sumas Power Plant. Based on our current estimates, the
payments to be received by us represent approximately 70% of distributable
cash.

(3) For these geothermal power plants, nameplate capacity refers to the
approximate capacity of the power plants. The capacity of these plants is
expected to gradually diminish as the production of the related steam fields
declines.

(4) See "Project Development and Acquisitions -- Project Development -- Projects
Under Construction -- Tiverton Power Plant" for a description of our
interest in the Tiverton Power Plant.

(5) See "Project Development and Acquisitions -- Project Development -- Projects
Under Construction -- Rumford Power Plant" for a description of our interest
in the Rumford Power Plant.

(6) See "Project Development and Acquisitions -- Project Development -- Projects
Under Construction -- Dighton Power Plant" for a description of our interest
in the Dighton Power Plant. Based on our current estimates, our interest
represents our right to receive approximately 50% of project cash flow
beginning at the commencement of commercial operation.

OPERATING POWER PLANTS

Sonoma County Power Plants. The Sonoma County power plants consist of 12
geothermal power plants and associated steam fields having combined capacity of
544 megawatts located at The Geysers in northern California. The power plants
were acquired from PG&E on May 7, 1999 and we market the output from these
plants into the California power market.

Texas City Power Plant. The Texas City Power Plant is a 450 megawatt
gas-fired cogeneration facility located in Texas City, Texas. Electricity
generated by the Texas City Power Plant is sold under two separate long-term
agreements to (1) Texas Utilities Electric Company ("TUEC") under a power sales
agreement terminating on September 30, 2002, and (2) Union Carbide Corporation
("UCC") under a steam and electricity services agreement terminating on June 30,
1999. Each agreement contains payment provisions for capacity and electric
energy payments. Under a steam and electricity services agreement expiring
October 19, 2003, the Texas City Power Plant will supply UCC with 300,000 lbs/hr
of steam on a monthly average basis, with the required supply of steam not
exceeding 600,000 lbs/hr at any given time. During 1998, the Texas City Power
Plant generated approximately 2,517,316,000 kilowatt hours of electric energy
for sale to TUEC and UCC and approximately $188.3 million of revenue.

50
<PAGE> 54

Clear Lake Power Plant. The Clear Lake Power Plant is a 412 megawatt gas/
hydrogen-fired cogeneration facility located in Pasadena, Texas. Electricity
generated by the Clear Lake Power Plant is sold under three separate long-term
agreements to (1) Texas-New Mexico Power Company ("TNP") under a power sales
agreement terminating in 2004, (2) Houston Lighting and Power Company ("HL&P")
under a power sales agreement terminating in 2005, and (3) Hoechst Celanese
Chemical Group, Inc. ("HCCG") under a power sales agreement terminating in 2004.
Each power sales agreement contains payment provisions for capacity and energy
payments. Under a steam purchase and sale agreement expiring August 31, 2004,
the Clear Lake Power Plant will supply up to 900,000 lbs/hr of steam to HCCG.
During 1998, the Clear Lake Power Plant generated approximately 2,912,649,000
kilowatt hours of electric energy for sale to TNP, HL&P and HCCG and
approximately $89.3 million of revenue.

Pasadena Power Plant. The Pasadena Power Plant is a 240 megawatt gas-fired
cogeneration facility located in Pasadena, Texas. Electricity generated by the
Pasadena Power Plant is sold under contract and into the open market. We entered
into an energy sales agreement with Phillips Petroleum Company ("Phillips")
terminating in 2018. Under this agreement, we provide 90 megawatts of
electricity and 200,000 lbs/hr of steam to Phillips' Houston Chemical Complex.
West Texas Utilities purchased 50 megawatts of capacity through the end of 1998.
In 1999, LG&E Energy Marketing will purchase up to 150 megawatts of electricity
under a one-year agreement. TUEC is also under contract to purchase up to 150
megawatts of electricity under a two-year agreement beginning December 1, 1999.
The remaining available electricity output is sold into the competitive market
through our power marketing organization. During 1998, the Pasadena Power Plant
generated approximately 812,314,000 kilowatt hours of electric energy with
approximately $30.5 million of revenue.

Gordonsville Power Plant. The Gordonsville Power Plant is a 240 megawatt
gas-fired cogeneration facility located near Gordonsville, Virginia. Electricity
generated by the Gordonsville Power Plant is sold to the Virginia Electric and
Power Company under two power sales agreements terminating on June 1, 2024, each
of which include payment provisions for capacity and energy. The Gordonsville
Power Plant sells steam to Rapidan Service Authority under the terms of a steam
purchase and sales agreement, which expires June 1, 2004. During 1998, the
Gordonsville Power Plant generated approximately 213,382,000 kilowatt hours of
electrical energy and approximately $37.4 million of revenue.

Lockport Power Plant. The Lockport Power Plant is a 184 megawatt gas-fired,
combined-cycle cogeneration facility located in Lockport, New York. The facility
is owned and operated by Lockport Energy Associates, L.P. ("LEA"). We own an
indirect 11.36% limited partnership interest in LEA. Electricity and steam is
sold to General Motors Corporation ("GM") under an energy sales agreement
expiring in December 2007 for use at the GM Harrison plant, which is located on
a site adjacent to the Lockport Power Plant. Electricity is also sold to New
York State Electricity and Gas Company ("NYSEG") under a power purchase
agreement expiring October 2007. NYSEG is required to purchase all of the
electric power produced by the Lockport Power Plant not required by GM. For
1998, the Lockport Power Plant generated approximately 1,284,830,000 kilowatt
hours of electricity and had $118.6 million in revenue.

Dighton Power Plant. In October 1997, we invested $16.0 million in the
development of a 169 megawatt gas-fired combined-cycle power plant to be located
in Dighton, Massachusetts. This investment, which is structured as subordinated
debt, will provide us with a preferred payment stream at a rate of 12.07% per
year for a period of twenty years

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<PAGE> 55

from the commercial operation date. The Dighton Power Plant was developed by EMI
and cost approximately $120.0 million. Commercial operation commenced in August
1999. The Dighton Power Plant is operated by EMI and sells its output into the
New England power market and to wholesale and retail customers in the
northeastern United States.

Bayonne Power Plant. The Bayonne Power Plant is a 165 megawatt gas-fired
cogeneration facility located in Bayonne, New Jersey. The facility is primarily
owned by an affiliate of Cogen Technologies, Inc. We own an indirect 7.5%
limited partnership interest in the facility. Electricity generated by the
Bayonne Power Plant is sold under various power sales agreements to Jersey
Central Power & Light Company and Public Service Electric and Gas Company of New
Jersey. The Bayonne Power Plant also sells steam to two industrial entities.
During 1998, the Bayonne Power Plant generated approximately 1,399,860,000
kilowatt hours of electrical energy and approximately $116.6 million in revenue.

Auburndale Power Plant. The Auburndale Power Plant is a 150 megawatt
gas-fired cogeneration facility located near the city of Auburndale, Florida.
Electricity generated by the Auburndale Power Plant is sold under various power
sales agreements to Florida Power Corporation ("FPC"), Enron Power Marketing and
Sonat Power Marketing. Auburndale sells 131.18 megawatts of capacity and energy
to FPC under three power sales agreements, each terminating at the end of 2013.
The Auburndale Power Plant sells steam under two steam purchase and sale
agreements. One agreement is with Cutrale Citrus Juices, USA, an affiliate of
Sucocitro Cutrale LTDA, expiring on July 1, 2014. The second agreement is with
Todhunter International, Inc., doing business as Florida Distillers Company,
expiring on July 1, 2009. During 1998, the Auburndale Power Plant generated
approximately 1,022,146,000 kilowatt hours of electrical energy and
approximately $49.6 million in revenue.

Lake County Power Plants. The Lake County power plants consist of two
geothermal power plants and associated steam fields having a combined capacity
of 150 megawatts located at The Geysers in northern California. We acquired
these power plants from PG&E on May 7, 1999, and we market the output from these
plants into the California power market.

Sumas Power Plant. The Sumas Power Plant is a 125 megawatt gas-fired,
combined cycle cogeneration facility located in Sumas, Washington. We currently
hold an ownership interest in the Sumas Power Plant, which entitles us to
receive certain scheduled distributions during the next two years. Upon receipt
of the scheduled distributions, we will no longer have any ownership interest in
the Sumas Power Plant. Electrical energy generated by the Sumas Power Plant is
sold to Puget Sound Power & Light Company ("Puget") under the terms of a 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. In
addition to the sale of electricity to Puget, pursuant to a long-term steam
supply and dry kiln lease agreement, the Sumas Power Plant produces and sells
approximately 23,000 lbs/hr of low pressure steam to an adjacent lumber-drying
facility owned by Sumas, which has been leased to and is operated by Socco, Inc.
During 1998, the Sumas Power Plant generated approximately 915,227,280 kilowatt
hours of electrical energy and approximately $49.6 million of total revenue.

King City Power Plant. The King City Power Plant is a 120 megawatt
gas-fired, combined-cycle cogeneration facility located in King City,
California. We operate the King City Power Plant under a long-term operating
lease for this facility with BAF Energy ("BAF"), terminating in 2018.
Electricity generated by the King City Power Plant is sold to PG&E under a power
sales agreement terminating in 2019. The power sales agreement

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<PAGE> 56

contains payment provisions for capacity and energy. In addition to the sale of
electricity to PG&E, the King City Power Plant produces and sells thermal energy
to a thermal host, Basic Vegetable Products, Inc., an affiliate of BAF, under a
long-term contract coterminous with the power sales agreement. During 1998, the
King City Power Plant generated approximately 428,825,000 kilowatt hours of
electrical energy and approximately $45.6 million of total revenue.

Gilroy Power Plant. The Gilroy Power Plant is a 120 megawatt gas-fired
cogeneration facility located in Gilroy, California. Electricity generated by
the Gilroy Power Plant is sold to PG&E under a power sales agreement terminating
in 2018. In July 1999 we announced a renegotiation of our Gilroy power sales
agreement with PG&E. The amendment provides for the termination of the remaining
18 years of the long-term contract in exchange for a fixed long-term payment
schedule. The amended agreement is subject to approval by the California Public
Utilities Commission, whose decision we expect to receive in the fourth quarter
of 1999. We will continue to sell the output from the Gilroy Power Plant through
October 2002 to PG&E and thereafter we will market the output in the California
wholesale power market. In addition, the Gilroy Power Plant produces and sells
thermal energy to a thermal host, Gilroy Foods, Inc., under a long-term contract
that is coterminous with the power sales agreement. During 1998, the Gilroy
Power Plant generated approximately 477,628,000 kilowatt hours of electrical
energy for sale to PG&E and approximately $39.3 million in revenue.

Kennedy International Airport Power Plant. The Kennedy International
Airport Power Plant is a 107 megawatt gas-fired cogeneration facility located at
John F. Kennedy International Airport in Queens, New York. The facility is owned
and operated by KIAC Partners. We own an indirect 50% general partnership
interest in KIAC. Electricity and thermal energy generated by the Kennedy
International Airport Power Plant is sold to the Port Authority, and incremental
electric power is sold to Consolidated Edison Company of New York, the New York
Power Authority and other utility customers. Electric power and chilled and hot
water generated by the Kennedy International Airport Power Plant is sold to the
Port Authority under an energy purchase agreement that expires November 2015.
For 1998, the Kennedy International Airport Power Plant generated approximately
533,755,000 kilowatt hours of electrical energy, 266,252 mmbtu of chilled water
and 178,405 mmbtu of hot water for sale to the Port Authority, and generated
approximately $56.1 million in revenue.

Pittsburg Power Plant. The Pittsburg Power Plant is a 70 megawatt gas-fired
cogeneration facility, located at The Dow Chemical Company's ("Dow") Pittsburg,
California chemical facility. We sell up to 18 megawatts of electricity to Dow
under a power sales agreement expiring in 2008. Surplus energy is sold to PG&E
under an existing power sales agreement. In addition, we sell approximately
200,000 lbs/hr of steam to Dow under an energy sales agreement expiring in 2003
and to USS-POSCO Industries' nearby steel mill under a process steam contract
expiring in 2001. From its acquisition, in July 1998, through the end of 1998,
the Pittsburg Power Plant generated approximately 92,358,000 kilowatt hours of
electrical energy to Dow and PG&E and approximately $9.4 million in revenue.

Sonoma Power Plant. The Sonoma Power Plant consists of a 60 megawatt
geothermal power plant and associated steam fields located in Sonoma County,
California. Electricity generated by the Sonoma Power Plant is sold to the
Sacramento Municipal Utility District ("SMUD") under a power sales agreement for
up to 50 megawatts of off-peak power production, terminating in 2001. In
addition, SMUD has the option to

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purchase up to an additional 10 megawatts of peak power production through 2005.
We market the excess electricity into the California power market. From its
acquisition, in June 1998, through the end of 1998, the Sonoma Power Plant
generated approximately 215,433,000 kilowatt hours of electrical energy and
approximately $6.2 million in revenue.

Bethpage Power Plant. The Bethpage Power Plant is a 57 megawatt gas-fired,
combined cycle cogeneration facility located adjacent to a Northrup Grumman
Corporation ("Grumman") facility in Bethpage, New York. Electricity and steam
generated by the Bethpage Power Plant are sold to Grumman under an energy
purchase agreement expiring August 2004. Electric power not sold to Grumman is
sold to Long Island Power Authority ("LIPA") under a generation agreement also
expiring August 2004. Grumman is also obligated to purchase a minimum of 158,000
klbs of steam per year from the Bethpage Power Plant. For 1998, the Bethpage
Power Plant generated approximately 474,991,000 kilowatt hours of electrical
energy for sale to Grumman and LIPA and approximately $32.9 million in revenue.

Greenleaf 1 Power Plant. The Greenleaf 1 Power Plant is a 49.5 megawatt
gas-fired cogeneration facility located near Yuba City, California. We operate
this facility under an operating lease with Union Bank of California,
terminating in 2014 (the "Greenleaf Lease"). Electricity generated by the
Greenleaf 1 Power Plant is sold to PG&E under a power sales agreement
terminating in 2019 which contains payment provisions for capacity and energy.
In addition, the Greenleaf 1 Power Plant sells thermal energy, in the form of
hot exhaust to dry wood waste, to a thermal host which is owned and operated by
us. For 1998, the Greenleaf 1 Power Plant generated approximately 326,543,000
kilowatt hours of electrical energy for sale to PG&E and approximately $17.8
million in revenue.

Greenleaf 2 Power Plant. The Greenleaf 2 Power Plant is a 49.5 megawatt
gas-fired cogeneration facility located near Yuba City, California. This
facility is also operated by us under the Greenleaf Lease. Electricity generated
by the Greenleaf 2 Power Plant is sold to PG&E under a power sales agreement
terminating in 2019 which includes payment provisions for capacity and energy.
In addition to the sale of electricity to PG&E, the Greenleaf 2 Power Plant
sells thermal energy to Sunsweet Growers, Inc. pursuant to a 30-year contract.
For 1998, the Greenleaf 2 Power Plant generated approximately 377,101,000
kilowatt hours of electrical energy for sale to PG&E and approximately $20.3
million in revenue.

Stony Brook Power Plant. The Stony Brook Power Plant is a 40 megawatt
gas-fired cogeneration facility located on the campus of the State University of
New York at Stony Brook, New York ("SUNY"). The facility is owned by Nissequogue
Cogen Partners ("NCP"). We own an indirect 50% general partner interest in NCP.
Steam and electric power is sold to SUNY under an energy supply agreement
expiring in 2023. Under the energy supply agreement, SUNY is required to
purchase, and the Stony Brook Power Plant is required to provide, all of SUNY's
electric power and steam requirements up to 36.125 megawatts of electricity and
280,000 lbs/hr of process steam. The remaining electricity is sold to LIPA under
a long-term agreement. LIPA is obligated to purchase electric power generated by
the facility not required by SUNY. SUNY is required to purchase a minimum of
402,000 klbs per year of steam. For 1998, the Stony Brook Power Plant generated
approximately 326,584,000 kilowatt hours of electrical energy and 1,185,000 klbs
of steam for sale to SUNY and LIPA and approximately $31.1 million in revenue.

Agnews Power Plant. The Agnews Power Plant is a 29 megawatt gas-fired,
combined-cycle cogeneration facility located on the East Campus of the
state-owned

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Agnews Developmental Center in San Jose, California. We hold a 20% ownership
interest in GATX Calpine-Agnews, Inc., which is the sole stockholder of O.L.S.
Energy-Agnews, Inc. ("O.L.S. Energy-Agnews"). O.L.S. Energy-Agnews leases the
Agnews Power Plant under a sale leaseback arrangement. Electricity generated by
the Agnews Power Plant is sold to PG&E under a power sales agreement terminating
in 2021 which contains payment provisions for capacity and energy. In addition,
the Agnews Power Plant produces and sells electricity and approximately 7,000
lbs/hr of steam to the Agnews Developmental Center pursuant to a 30-year energy
service agreement. During 1998, the Agnews Power Plant generated approximately
215,180,000 kilowatt hours of electrical energy and total revenue of $11.7
million.

Watsonville Power Plant. The Watsonville Power Plant is a 28.5 megawatt
gas-fired, combined cycle cogeneration facility located in Watsonville,
California. We operate the Watsonville Power Plant under an operating lease with
the Ford Motor Credit Company, terminating in 2009. Electricity generated by the
Watsonville Power Plant is sold to PG&E under a power sales agreement
terminating in 2009 which contains payment provisions for capacity and energy.
During 1998, the Watsonville Power Plant produced and sold steam to Farmers
Processing, a food processor. In addition, the Watsonville Power Plant sold
process water produced from its water distillation facility to Farmer's Cold
Storage, Farmer's Processing and Cascade Properties. For 1998, the Watsonville
Power Plant generated approximately 206,007,000 kilowatt hours of electrical
energy for sale to PG&E and approximately $11.4 million in revenue.

West Ford Flat Power Plant. The West Ford Flat Power Plant consists of a 27
megawatt geothermal power plant and associated steam fields located in northern
California. Electricity generated by the West Ford Flat Power Plant is sold to
PG&E under a power sales agreement terminating in 2008 which contains payment
provisions for capacity and energy. During 1998, the West Ford Flat Power Plant
generated approximately 235,529,000 kilowatt hours of electrical energy for sale
to PG&E and approximately $34.6 million of revenue.

Bear Canyon Power Plant. The Bear Canyon Power Plant consists of a 20
megawatt geothermal power plant and associated steam fields located in northern
California, two miles south of the West Ford Flat Power Plant. Electricity
generated by the Bear Canyon Power Plant is sold to PG&E under two 10 megawatt
power sales agreements terminating in 2008 which contain payment provisions for
capacity and energy. During 1998, the Bear Canyon Power Plant generated
approximately 176,508,000 kilowatt hours of electrical energy and approximately
$20.4 million of revenue.

Aidlin Power Plant. The Aidlin Power Plant consists of a 20 megawatt
geothermal power plant and associated steam fields located in northern
California. We hold an indirect 55% ownership interest in the Aidlin Power
Plant. Electricity generated by the Aidlin Power Plant is sold to PG&E under two
10 megawatt power sales agreements terminating in 2009 which contain payment
provisions for capacity and energy. During 1998, the Aidlin Power Plant
generated approximately 170,046,000 kilowatt hours of electrical energy and
revenue of $24.4 million.

Calistoga Power Plant. The Calistoga Power Plant consists of a 67 megawatt
geothermal power plant and associated steam fields located in northern
California. Electricity generated by the Calistoga Power Plant is sold to PG&E
under a power sales agreement terminating in 2014 which contains payment
provisions for capacity and energy.

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During 1998, the Calistoga Power Plant generated approximately 614,073,000
kilowatt hours of electrical energy for sale to PG&E and approximately $27.9
million in revenue.

PROJECT DEVELOPMENT AND ACQUISITIONS

We are actively engaged in the development and acquisition of power
generation projects. We have historically focused principally on the development
and acquisition of interests in gas-fired and geothermal power projects,
although we also consider projects that utilize other power generation
technologies. We have significant expertise in a variety of power generation
technologies and have substantial capabilities in each aspect of the development
and acquisition process, including design, engineering, procurement,
construction management, fuel and resource acquisition and management, financing
and operations.

ACQUISITIONS

We will consider the acquisition of an interest in operating projects as
well as projects under development where we would assume responsibility for
completing the development of the project. In the acquisition of power
generation facilities, we generally seek to acquire an ownership interest in
facilities that offer us attractive opportunities for revenue and earnings
growth, and that permit us to assume sole responsibility for the operation and
maintenance of the facility. In evaluating and selecting a project for
acquisition, we consider a variety of factors, including the type of power
generation technology utilized, the location of the project, the terms of any
existing power or thermal energy sales agreements, gas supply and transportation
agreements and wheeling agreements, the quantity and quality of any geothermal
or other natural resource involved, and the actual condition of the physical
plant. In addition, we assess the past performance of an operating project and
prepare financial projections to determine the profitability of the project. We
generally seek to obtain a significant equity interest in a project and to
obtain the operation and maintenance contract for that project. See
"-- Strategy" and "Risk Factors -- Our power project development and acquisition
activities may not be successful."

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

PENDING ACQUISITIONS

COGENERATION CORPORATION OF AMERICA. On August 27, 1999 we announced an
agreement with CGCA to acquire 80% of its common stock for $25.00 per share or
approximately $145.0 million. NRG Energy, Inc., a wholly owned subsidiary of
Northern States Power will own the remaining 20%. The transaction is subject to
shareholder approval and we expect to consummate the acquisition by year-end
1999. CGCA currently owns interests in six natural gas-fired power plants,
totaling 579 megawatts. The plants are located in Pennsylvania, New Jersey,
Illinois and Oklahoma. As of June 30, 1999, CGCA had approximately $296.6
million of indebtedness, including $216.1 million of non-recourse project debt.

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Grays Ferry Power Plant. The Grays Ferry Power Plant is a 150 megawatt,
natural gas-fired cogeneration project located in Philadelphia,
Pennsylvania. CGCA owns 50% of the project and 50% is owned by Trigen Energy
Corporation. The facility is operated by Trigen. Electricity generated by
the Grays Ferry Power Plant is sold under two long-term power sales
agreements to PECO Energy Company, expiring in 2017. An affiliate of Trigen
purchases the steam produced by the project pursuant to a 25-year contract
expiring in 2022.

Parlin Power Plant. The Parlin Power Plant consists of a 122 megawatt
natural gas-fired cogeneration power plant located in Parlin, New Jersey.
The facility is operated by NRG Energy, Inc. Electricity generated by the
Parlin Power Plant is sold pursuant to a long-term contract expiring in 2011
to Jersey Central Power and Light Company ("JCP&L"), and steam produced is
sold to E.I. Dupont de Nemours and Company under a long-term agreement
expiring in 2021.

Morris Power Plant. The Morris Power Plant consists of a 117 megawatt
natural gas-fired cogeneration facility located in Morris, Illinois. The
facility is operated by NRG Energy, Inc. Electricity and steam produced by
the facility is sold to Equistar Chemicals, L.P. pursuant to a long-term
contract expiring in 2023. Any surplus electricity is marketed to the
Illinois power market.

Pryor Power Plant. The Pryor Power Plant is a 110 megawatt natural gas-fired
cogeneration power plant located in Pryor, Oklahoma. The facility is
operated by NRG Energy, Inc. The Pryor Power Plant sells 100-megawatts of
capacity and varying amounts of electrical energy to Oklahoma Gas and
Electric under a contract expiring in 2007. Steam produced from the Pryor
facility is sold to a number of industrial users under contracts with
various termination dates ranging from 1998 to 2007. Surplus electricity is
also sold to the Public Service of Oklahoma at its avoided cost.

Newark Power Plant. The Newark Power Plant consists of a 58 megawatt natural
gas-fired cogeneration power plant located in Newark, New Jersey. The
facility is operated by NRG Energy, Inc. Electricity produced by the
facility is sold pursuant to a long-term contract expiring in 2015 to JCP&L.
Steam produced is sold to Newark Boxboard under a long-term contract
expiring in 2015.

Philadelphia Water Project. The Philadelphia Water Project consists of two
standby peak shaving facilities located at the Philadelphia Water
Department's Northeast and Southwest wastewater treatment plants. CGCA owns
83% of the project and the project is operated by O'Brien Energy Services
Company. The project sells capacity and energy on demand to the Philadelphia
Municipal Authority pursuant to two long-term contracts expiring in 2013.

SHERIDAN ENERGY, INC. On October 1, 1999 we completed the acquisition of
Sheridan Energy, a natural gas exploration and production company, through a
$41.0 million cash tender offer. We purchased the outstanding shares of Sheridan
Energy's common stock for $5.50 per share. In addition, we redeemed $11.5
million of outstanding preferred stock of Sheridan Energy. Sheridan Energy's oil
and gas properties, including 148 billion cubic feet equivalent of proven
reserves, are located in northern California and the Gulf Coast region, where we
are developing low-cost natural gas supplies and proprietary pipeline systems to
support our strategically-located natural gas-fired power plants. As of June 30,
1999, Sheridan Energy had indebtedness of $71.5 million.

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PROJECT DEVELOPMENT

The development of power generation projects involves numerous elements,
including evaluating and selecting development opportunities, designing and
engineering the project, obtaining power sales agreements, acquiring necessary
land rights, permits and fuel resources, obtaining financing and managing
construction. We intend to focus primarily on development opportunities where we
are able to capitalize on our expertise in implementing an innovative and fully
integrated approach to project development in which we control the entire
development process. Utilizing this approach, we believe that we are able to
enhance the value of our projects throughout each stage of development in an
effort to maximize our return on investment.

We are pursuing the development of highly efficient, low-cost power plants
that seek to take advantage of inefficiencies in the electricity market. We
intend to sell all or a portion of the power generated by such plants into the
competitive market through a portfolio of short-, medium-and long-term power
sales agreements. We expect that these projects will represent a prototype for
our future plant developments. See "-- Strategy" and "Risk Factors -- Our power
project development and acquisition activities may not be successful."

The development of power generation facilities is subject to substantial
risks. In connection with the development of a power generation facility, we
must generally obtain power 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 we 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 we 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, and obtaining all
required governmental permits and approvals, the development of a power project
may require us 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 we were unable
to complete the development of a facility, we would generally not be able to
recover our 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. We cannot assure that we will be successful
in the development of power generation facilities in the future.

Projects Under Construction

Magic Valley Power Plant. In May 1998, we announced that we had signed a
20-year power sales agreement to provide electricity to the Magic Valley
Electric Cooperative, Inc. of Mercedes, Texas beginning in 2001. The power will
be supplied by our Magic Valley Generating Station, a 730 megawatt natural
gas-fired power plant under development in Edinburg, Texas. Magic Valley
Electric Cooperative Inc., a 51,000 member non-profit electric cooperative,
initially will purchase from 250 to 400 megawatts of capacity, with an option to
purchase additional capacity. We are marketing additional capacity to other

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wholesale customers, initially targeting south Texas. Construction commenced in
April 1999 with commercial operations scheduled to begin in February 2001.

Los Medanos Power Plant. In September 1999, we finalized an agreement with
Enron North America for the development rights of a 500 megawatt gas-fired plant
in Pittsburg, California. Construction commenced in September 1999 and
commercial operations will begin in 2001. The facility will provide electricity
and industrial steam totaling approximately 55 megawatts to USS-POSCO Industries
under a long-term agreement. The balance of the plant's output will be sold into
the California power market.

Westbrook Power Plant. In February 1999, we acquired from Genesis Power
Corporation ("Genesis"), a New England based power developer, the development
rights to a 545 megawatt gas-fired combined-cycle power plant to be located in
Westbrook, Maine. It is estimated that the development of the Westbrook Power
Plant will cost approximately $300.0 million. Construction commenced in February
1999 and commercial operation is scheduled for early 2001. Upon completion, the
Westbrook Power Plant will be operated by our company. It is anticipated that
the output generated by the Westbrook Power Plant will be sold into the New
England power market and to wholesale and retail customers in the northeastern
United States.

Pasadena Expansion. We are currently expanding the Pasadena Power Plant by
an additional 545 megawatts. Construction began in November 1998 and commercial
operation is expected to begin in June 2000. The electricity output from this
expansion will be sold into the competitive market through our power sales
activities.

South Point Power Plant. In May 1998, we announced that we had entered into
a long-term lease agreement with the Fort Mojave Indian Tribe to develop a 545
megawatt gas-fired power plant on the tribe's reservation in Mojave County,
Arizona. The electricity generated will be sold to the Arizona, Nevada and
California power markets. Construction commenced in August 1999 and we
anticipate that the South Point Power Plant will begin operation in March 2001.

Sutter Power Plant. In February 1997, we announced plans to develop a 545
megawatt gas-fired combined cycle project in Sutter County, in northern
California. The Sutter Power Plant would be northern California's first newly
constructed power plant since deregulation of the California power market in
1998. Construction commenced in August 1999 and the Sutter Power Plant is
expected to provide electricity to the deregulated California power market
commencing in the year 2001. We are currently pursuing regulatory agency permits
for this project. In January 1998, we announced that the Sutter Power Plant has
met the California Energy Commission's Data Adequacy requirements in its
Application for Certification.

Lost Pines 1 Power Plant. In September 1999, we entered into definitive
agreements with Austin, Texas-based GenTex Power Corporation, the power
generation affiliate of the Lower Colorado River Authority, to build a 545
megawatt gas-fired facility in Bastrop County, Texas. Construction of this
facility is scheduled to began in October 1999 and commercial operation in June
2001. Upon commercial operation, GenTex will take half of the electrical output
for sale to its customers and we will market the remaining energy to the Texas
power market.

Tiverton Power Plant. In September 1998, we invested $40.0 million of
equity in the development of a 265 megawatt gas-fired power plant to be located
in Tiverton, Rhode Island. The Tiverton Power Plant is being developed by Energy
Management Inc.

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("EMI"). It is estimated that the development of the Tiverton Power Plant will
cost approximately $172.5 million. For our investment in the Tiverton Power
Plant, we will earn 62.8% of the Tiverton Power Plant project cash flow until a
specified pre-tax return is reached, whereupon our company and EMI will share
projected cash flows equally through the remaining life of the project.
Construction commenced in late 1998 and commercial operation is currently
scheduled for 2000. Upon completion, the Tiverton Power Plant will be operated
by EMI and will sell its output in the New England power market and to wholesale
and retail customers in the northeastern United States.

Rumford Power Plant. In November 1998, we invested $40.0 million of equity
in the development of a 265 megawatt gas-fired power plant to be located in
Rumford, Maine. The Rumford Power Plant is being developed by EMI. It is
estimated that the development of the Rumford Power Plant will cost
approximately $160.0 million. For our investment in the Rumford Power Plant, we
will earn 66.7% of the Rumford Power Plant project cash flow until a specified
pre-tax return is reached, whereupon our company and EMI will share projected
cash flows equally through the remaining life of the project. Construction
commenced in late 1998 and commercial operation is currently scheduled for 2000.
Upon completion, the Rumford Power Plant will be operated by EMI and will sell
its output in the New England power market and to wholesale and retail customers
in the northeastern United States.

Announced Development Projects

Delta Energy Center. In February 1999, we, together with Bechtel
Enterprises, announced plans to develop an 880 megawatt gas-fired cogeneration
project in Pittsburg, California (the "Delta Energy Center"). The Delta Energy
Center will provide steam and electricity to the nearby Dow Chemical Company
facility and market the excess electricity into the California power market. We
anticipate that construction will commence in early 2000 and that operation of
the facility will commence in 2002. We are currently pursuing regulatory agency
permits for this project. On February 3, 1999, our company and Bechtel announced
that the Delta Energy Center has met the California Energy Commission's Data
Adequacy requirements in its Application for Certification.

Baytown Power Plant. In October 1999 we announced plans to build, own and
operate an 800 megawatt gas-fired cogeneration power plant at Bayer
Corporation's chemical facility in Baytown, Texas. The Baytown Power Plant will
supply Bayer with all of its electric and steam requirements for 20 years and
market excess electricity into the Texas wholesale power market. Construction is
estimated to commence in 2000 and commercial operation in 2001.

Metcalf Energy Center. In February 1999, we, together with Bechtel
Enterprises, announced plans to develop a 600 megawatt gas-fired cogeneration
project in San Jose, California (the "Metcalf Energy Center"). We expect the
California Energy Commission review, licensing and public hearing process will
be completed by mid-2000. We anticipate that construction will commence
following this approval and that commercial operation of the facility will
commence in mid-2002. Electricity generated by the Metcalf Energy Center will be
sold into the California power market.

West Phoenix Power Plant. In April 1999, we announced an agreement with
Pinnacle West Capital Corporation to develop a 545 megawatt gas-fired facility
at Arizona Public Services West Phoenix Power Station in Phoenix, Arizona.
Construction is scheduled to

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begin in mid-2000 with final completion in late 2002. The facility is estimated
to cost $220 million and the electricity will be sold into the Arizona power
market.

Ontelaunee Energy Center. In June 1999, we announced that we had acquired
the rights to develop a 545 megawatt gas-fired power plant in Ontelaunee
Township in eastern Pennsylvania. Permitting for the proposed $255 million
facility is underway and construction is scheduled to begin in early 2000.
Commercial operation is estimated for late 2002. Output from the plant will be
sold into the Pennsylvania/New Jersey/Maryland (PJM) power pool and pursuant to
bilateral contracts.

Channel Energy Center. In October 1999, we announced that we had executed a
letter of intent which gives us the exclusive right to negotiate with
LYONDELL-CITGO Refining LP to build, own and operate a 560 megawatt gas-fired
cogeneration power plant at the LYONDELL-CITGO refinery in Houston, Texas. The
Channel Energy Center will supply all of the electricity and steam requirements
for 20 years to the refinery. Permitting for the facility is currently underway,
with construction projected to commence in early 2000 and commercial operation
in 2001.

GAS FIELDS

Montis Niger. In January 1997, we purchased Montis Niger, Inc., a gas
production and pipeline company operating primarily in the Sacramento Basin in
northern California. On July 25, 1997, Montis Niger, Inc. was renamed Calpine
Gas Company. As of January 1, 1998, Calpine Gas Company had approximately 8.1
billion cubic feet of proven natural gas reserves and approximately 13,837 gross
acres and 13,738 net acres under lease in the Sacramento Basin. In addition,
Calpine Gas Company owns and operates an 80-mile pipeline delivering gas to the
Greenleaf 1 and 2 Power Plants which had been either produced by Calpine Gas
Company or purchased from third parties. Calpine Gas Company currently supplies
approximately 79% of the fuel requirements for the Greenleaf 1 and 2 Power
Plants.

Sheridan. In January 1999, we announced that we had acquired a 20% interest
in 82 billion cubic feet of proven natural gas reserves located in the
Sacramento Basin in northern California. Sheridan Energy owns the remaining 80%
interest in these reserves. In addition, we signed a 10-year agreement with
Sheridan under which we will purchase all of Sheridan's Sacramento Basin
production, which currently approximates 20,000 mmbtu per day.

GOVERNMENT REGULATION

We are 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

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produced, discharged or disposed of by a plant and the geographical location,
zoning, land use and operation of a plant. Applicable federal environmental laws
typically have both state and local enforcement and implementation provisions.
These environmental laws and regulations generally require that a wide variety
of permits and other approvals be obtained before the commencement of
construction or operation of an energy-producing facility and that the facility
then operate in compliance with such permits and approvals.

FEDERAL ENERGY REGULATION

PURPA

The enactment of the Public Utility Regulatory Policies Act of 1978, as
amended ("PURPA") and the adoption of regulations thereunder by FERC provided
incentives for the development of cogeneration facilities and small power
production facilities (those utilizing renewable fuels and having a capacity of
less than 80 megawatts).

A domestic electricity generating project must be a QF under FERC
regulations in order to take advantage of certain rate and regulatory incentives
provided by PURPA. PURPA exempts owners of QFs from the Public Utility Holding
Company Act of 1935, as amended ("PUHCA"), and exempts QFs from most provisions
of the Federal Power Act (the "FPA") and, except under certain limited
circumstances, state laws concerning rate or financial regulation. These
exemptions are important to us and our competitors. We believe that each of the
electricity generating projects in which we own an interest and which operates
as a QF power producer currently meets the requirements under PURPA necessary
for QF status.

PURPA provides two primary benefits to QFs. First, QFs generally are
relieved of compliance with extensive federal, state and local regulations that
control the financial structure of an electric generating plant and the prices
and terms on which electricity may be sold by the plant. Second, the FERC's
regulations promulgated under PURPA require that electric utilities purchase
electricity generated by QFs at a price based on the purchasing utility's
"avoided cost," and that the utility sell back-up power to the QF on a
non-discriminatory basis. The term "avoided cost" is defined as the incremental
cost to an electric utility of electric energy or capacity, or both, which, but
for the purchase from QFs, such utility would generate for itself or purchase
from another source. The FERC regulations also permit QFs and utilities to
negotiate agreements for utility purchases of power at rates lower than the
utility's avoided costs. 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. A geothermal facility may qualify as a QF if it produces less than 80
megawatts of electricity. 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.

We endeavor to develop our projects, monitor compliance by the projects
with applicable regulations and choose our customers in a manner which minimizes
the risks of

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any project losing its QF status. Certain factors necessary to maintain QF
status are, however, subject to the risk of events outside our 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, we 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 facilities in which we have 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 also trigger certain rights of termination under
the facility's power sales agreement, could subject the facility to rate
regulation as a public utility under the FPA and state law and could result in
us 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 our remaining projects to lose
their qualifying status, because QFs may not be controlled or more than 50%
owned by such public utility holding companies. Loss of QF status may also
trigger defaults under covenants to maintain QF status in the projects' power
sales agreements, steam sales agreements and financing agreements and result in
termination, penalties or acceleration of indebtedness under such agreements
such that loss of status may be on a retroactive or a prospective basis.

Under the Energy Policy Act of 1992, if a facility 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 would be required. In
addition, the facility would be required to cease selling electricity to any
retail customers (such as the thermal energy customer) to retain its EWG status
and could become subject to state regulation of sales of thermal energy. See
"-- Public Utility Holding Company Regulation."

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

Public Utility Holding Company Regulation

Under PUHCA, any corporation, partnership or other legal entity which owns
or controls 10% or more of the outstanding voting securities of a "public
utility company" or a company which is a "holding company" for a public utility
company is subject to registration with the SEC and regulation under PUHCA,
unless eligible for an exemption. A holding company of a public utility company
that is subject to registration is required by PUHCA to limit its utility
operations to a single integrated utility system and to divest any other
operations not functionally related to the operation of that utility system.
Approval by the SEC is required for nearly all important financial and business
dealings of a

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registered 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-QF electric generating
facilities without subjecting those producers to registration or regulation
under PUHCA. The effect of such amendments has been to enhance the development
of non-QFs which do not have to meet the fuel, production and ownership
requirements of PURPA. We believe that these amendments benefit us by expanding
our ability to own and operate facilities that do not qualify for QF status.
However, they have also resulted in increased competition by allowing utilities
to develop such facilities which are not subject to the constraints of PUHCA.

Federal Natural Gas Transportation Regulation

We have an ownership interest in 19 gas-fired cogeneration projects. The
cost of natural gas is ordinarily the largest expense of a gas-fired 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, whether firm or non-firm transportation is purchased and the operating
of the gas pipeline); 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 and terms and conditions for such services are
subject to continuing FERC oversight.

STATE REGULATION

State public utility commissions ("PUCs") have historically had broad
authority to regulate both the rates charged by, and the financial activities
of, electric utilities operating in their states and to promulgate regulation
for implementation of PURPA. Since a power sales agreement becomes a part of a
utility's cost structure (generally reflected in its retail rates), power sales
agreements with independent electricity producers, such as EWGs, are potentially
under the regulatory purview of PUCs and in particular the process by which the
utility has entered into the power sales agreements. If a PUC has approved the
process by which a utility secures its power supply, a PUC is generally inclined
to "pass through" the expense associated with power purchase agreement with an
independent power producer to the utility's retail customer. However, a
regulatory commission under certain circumstances may disallow the full
reimbursement to a utility for the cost to purchase power from a QF or an EWG.
In addition, retail sales of electricity or thermal energy by an independent
power producer may be subject to PUC regulation depending on state law.
Independent power producers which are not QFs under PURPA, or EWGs pursuant to
the Energy Policy Act of 1992, are considered to be public utilities in many
states and are subject to broad regulation by a PUC, ranging from requirement of
certificate of public convenience and necessity to regulation of organizational,
accounting, financial and other

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corporate matters. States may assert jurisdiction over the siting and
construction of electric generating facilities including QFs and EWGs and, with
the exception of QFs, over the issuance of securities and the sale or other
transfer of assets by these facilities.

In the State of California, restructuring legislation was enacted in
September 1996 and was implemented in 1998. This legislation established an
Independent Systems Operator ("ISO") responsible for centralized control and
efficient and reliable operation of the state-wide electric transmission grid,
and a Power Exchange responsible for an efficient competitive electric energy
auction open on a non-discriminatory basis to all electric services providers.
Other provisions include the quantification and qualification of utility
stranded costs to be eligible for recovery through competitive transition
charges ("CTC"), market power mitigation through utility divestiture of fossil
generation plants, the unbundling and establishment of rate structure for
historical utility functions, the continuation of public purpose programs and
issues related to issuance of rate reduction bonds.

The California Energy Commission ("CEC") and Legislature have
responsibility for development of a competitive market mechanism for allocation
and distribution of funds made available by the legislation for enhancement of
in-state renewable resource technologies and public interest research and
development programs. Funds are to be available through the four-year transition
period to a fully competitive electric services industry.

In addition to the significant opportunity provided for power producers
such as us through implementation of customer choice (direct access), the
California restructuring legislation both recognizes the sanctity of existing
contracts (including QF power sales contracts), provides for mitigation of
utility horizontal market power through divestiture of fossil generation by
California public utilities and provides funds for continuation of public
services programs including fuel diversity through enhancement for in-state
renewable technologies (includes geothermal) for the four-year transition period
to a fully competitive electric services industry.

Other states in which we conduct operations either have implemented or are
actively considering similar restructuring legislation.

State PUCs also have jurisdiction over the transportation of natural gas by
local distribution companies ("LDCs"). Each state's regulatory laws are somewhat
different; however, all generally require the LDC to obtain approval from the
PUC for the construction of facilities and transportation services if the LDC's
generally applicable tariffs do not cover the proposed transaction. LDC rates
are usually subject to continuing PUC oversight.

REGULATION OF CANADIAN GAS

The Canadian natural gas industry is subject to extensive regulation by
governmental authorities. At the federal level, a party exporting gas from
Canada must obtain an export license from the Canadian National Energy Board
("NEB"). The NEB also regulates Canadian pipeline transportation rates and the
construction of pipeline facilities. Gas producers also must obtain a removal
permit or license from provincial authorities before natural gas may be removed
from the province, and provincial authorities may regulate intra-provincial
pipeline and gathering systems. In addition, a party importing natural gas into
the United States first must obtain an import authorization from the U.S.
Department of Energy.

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ENVIRONMENTAL REGULATIONS

The exploration for and development of geothermal resources and the
construction and operation of power projects are subject to extensive federal,
state and local laws and regulations adopted for the protection of the
environment and to regulate land use. The laws and regulations applicable to us
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 us. In most cases, analogous state laws also exist that may impose
similar, and in some cases more stringent, requirements on us 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. We believe that
all of our 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, our
operations have, in certain instances, necessitated variances under applicable
California air pollution control laws. However, we believe that we are 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. We are
required to obtain a wastewater and storm water discharge permit for wastewater
and runoff, respectively, from certain of our facilities. We believe that, with
respect to our geothermal operations, we are exempt from newly promulgated
federal storm water requirements. We believe that we are 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. We believe that we are 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, we are subject to certain solid waste

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requirements under applicable California laws. We believe that our 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, we are not subject to liability for any Superfund matters.
However, we generate certain wastes, including hazardous wastes, and sends
certain of our wastes to third-party waste disposal sites. As a result, there
can be no assurance that we will not incur liability under CERCLA in the future.

COMPETITION

The power generation industry is characterized by intense competition, and
we encounter competition from utilities, industrial companies and other
independent power producers. In recent years, there has been increasing
competition in an effort to obtain power sales agreements, and this competition
has contributed to a reduction in electricity prices. In addition, many states
are implementing or considering regulatory initiatives designed to increase
competition in the domestic power industry. In California, the CPUC issued
decisions which provide for direct access for all customers as of April 1, 1998.
In Texas, recently enacted legislation will phase-in a deregulated power market
commencing January 1, 2001. Regulatory initiatives are also being considered in
other states, including New York and states in New England. 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 supply of electricity
in the future will increase this pressure.

EMPLOYEES

As of September 30, 1999, we had 698 employees. None of our employees are
covered by collective bargaining agreements, and we have never experienced a
work stoppage, strike or labor dispute. We consider relations with our employees
to be good.

PROPERTIES

Our principal executive office is located in San Jose, California, under a
lease that expires in June 2001.

We have leasehold interests in 105 leases comprising 19,813 acres of
federal, state and private geothermal resource lands in The Geysers area in
northern California. These leases comprise our West Ford Flat Power Plant, Bear
Canyon Power Plant and certain steam fields. In the Glass Mountain and Medicine
Lake areas in northern California, we hold leasehold interests in 20 leases
comprising approximately 23,598 acres of federal geothermal resource lands.

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In general, under the leases, we have 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. We believe that our leases are valid and
that we have complied with all the requirements and conditions material to the
continued effectiveness of the leases. A number of our leases for undeveloped
properties may expire in any given year. Before leases expire, we perform
geological evaluations in an effort to determine the resource potential of the
underlying properties. We cannot assure that we will decide to renew any
expiring leases.

We own 77 acres in Sutter County, California, on which the Greenleaf 1
Power Plant is located.

We own Calpine Gas Company, which leases property covering approximately
13,837 gross acres and 13,738 net acres.

See "-- Description of Facilities" for a description of the other material
leased or owned properties in which we have an interest. We believe that our
properties are adequate for our current operations.

LEGAL PROCEEDINGS

On September 30, 1997, a lawsuit was filed by Indeck North American Power
Fund ("Indeck") in the Circuit Court of Cook County, Illinois against Norweb
plc. and certain other parties, including us. Some of Indeck's claims relate to
Calpine Gordonsville, Inc.'s acquisition of a 50% interest in Gordonsville
Energy from Northern Hydro Limited and Calpine Auburndale, Inc.'s acquisition of
a 50% interest in Auburndale Power Plant Partners Limited Partnership from
Norweb Power Services (No. 1) Limited. Indeck is claiming that Calpine
Gordonsville, Inc., Calpine Auburndale, Inc. and Calpine Corporation tortiously
interfered with Indeck's contractual rights to purchase such interests and
conspired with other parties to do so. Indeck is seeking $25.0 million in
compensatory damages, $25.0 million in punitive damages, and the recovery of
attorneys' fees and costs. In July 1998, the court granted motions to dismiss,
without prejudice, the claims against Calpine Gordonsville, Inc. and Calpine
Auburndale, Inc. In August 1998, Indeck filed an amended complaint and the
defendants filed motions to dismiss. We expect a hearing on the motions to be
held in the near future. We are unable to predict the outcome of these
proceedings but we do not believe that these proceedings will have a materially
adverse effect on our financial results.

An action was filed against Lockport Energy Associates ("LERA") and the New
York Public Service Commission ("NYPSC") in August 1997 by New York State
Electricity and Gas Company ("NYSEG") in the Federal District Court for the
Northern District of New York. NYSEG has requested the Court to direct NYPSC and
the Federal Energy Regulatory Commission (the "FERC") to modify contract rates
to be paid to the Lockport Power Plant. In October 1997, NYPSC filed a
cross-claim alleging that the FERC violated PURPA and the Federal Power Act by
failing to reform the NYSEG contract that was previously approved by the NYPSC.
Although we are unable to predict

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the outcome of this case, in any event, we retain the right to require The
Brooklyn Union Gas Company to purchase our interest in the Lockport Power Plant
for $18.9 million, less equity distributions received by us, at any time before
December 19, 2001.

We and our affiliates are involved in various other claims and legal
actions arising out of the normal course of business. We do not expect that the
outcome of these proceedings will have a material adverse effect on our
financial position or results of operations, although we cannot assure you in
this regard.

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MANAGEMENT

DIRECTORS AND EXECUTIVE OFFICERS

The following table sets forth certain information with respect to our
directors and executive officers.

<TABLE>
<CAPTION>
NAME AGE POSITION
---- --- --------
<S> <C> <C>
Peter Cartwright.................... 69 Chairman of the Board, President,
Chief Executive Officer and Director
Ann B. Curtis....................... 48 Executive Vice President, Chief
Financial Officer, Corporate
Secretary and Director
Jeffrey E. Garten................... 52 Director
Susan C. Schwab..................... 44 Director
George J. Stathakis................. 69 Director
John O. Wilson...................... 61 Director
V. Orville Wright................... 79 Director
Thomas R. Mason..................... 55 Executive Vice President
Robert D. Kelly..................... 42 Senior Vice President-Finance
</TABLE>

Set forth below is certain information with respect to each director and
executive officer.

Peter Cartwright founded our company in 1984 and has served as a Director
and as our President and Chief Executive Officer since inception. Mr. Cartwright
became Chairman of our board of directors in September 1996. From 1979 to 1984,
Mr. Cartwright was Vice President and General Manager of the Western Regional
Office of Gibbs & Hill, Inc. ("Gibbs & Hill"), an architect-engineering firm
that specialized 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.

Ann B. Curtis has served as Executive Vice President of our company since
August 1998, and before that was our Senior Vice President since September 1992,
and has been employed by us since our inception in 1984. Ms. Curtis became a
Director of our company in September 1996. She is responsible for our 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 our Chief Financial Officer and
Corporate Secretary. From our inception in 1984 through 1992, she served as our
Vice President for Management and Financial Services. Prior to joining our
company, Ms. Curtis was Manager of Administration for the Western Regional
Office of Gibbs & Hill.

Jeffrey E. Garten became a Director of our company in January 1997. Mr.
Garten has served as Dean of the Yale School of Management and William S.
Beinecke Professor in the Practice of International Trade and Finance since
November 1995. Mr. Garten served

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as Undersecretary of Commerce of International Trade in the United States
Department of Commerce from November 1993 to October 1995. From October 1990 to
October 1992, Mr. Garten was a managing director of The Blackstone Group, an
investment banking firm. Prior thereto, Mr. Garten founded and managed The Eliot
Group, a small investment bank, from November 1987 to October 1990, and served
as managing director of Lehman Brothers from January 1979 to November 1987.

Susan C. Schwab became a Director of our company in January 1997. Dr.
Schwab has served as Dean of the School of Public Affairs at the University of
Maryland since August 1995. Dr. Schwab served as Director, Corporate Business
Development at Motorola, Inc. from July 1993 to August 1995. She also served as
Assistant Secretary of Commerce for the U.S. and Foreign Commercial Service from
March 1989 to May 1993.

George J. Stathakis became a Director of our company in September 1996 and
has served as a Senior Advisor to us since December 1994. Mr. Stathakis has been
providing financial, business and management advisory services to numerous
corporations 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.

John O. Wilson became a Director of our company in January 1997. Mr. Wilson
has served as a Senior Research Fellow at the Berkeley Roundtable on the
International Economy and as Executive Vice President and Chief Economist of SDR
Capital Management, Inc. since January 1999. Mr. Wilson served as Executive Vice
President and Chief Economist at Bank of America from August 1984 to January
1999. He joined Bank of America in June 1975 as Director of Economics-Policy
Research. He served as a faculty member at the University of California at
Berkeley from September 1979 to June 1991, at the University of Connecticut from
September 1974 to June 1975, and at Yale University from January 1967 to
September 1970. Mr. Wilson also served as Director of Regulatory Analysis of the
U.S. Atomic Energy Commission from April 1972 to October 1972, as Director of
Welfare Reform of the Department of Health, Education and Welfare from April
1971 to April 1972, and as Assistant Director of the U.S. Office of Economic
Opportunity from August 1969 to April 1971.

V. Orville Wright became a Director of our company in January 1997. Mr.
Wright served in various positions with MCI Communications Corp., including Vice
Chairman and Co-Chief Executive Officer from 1988 to 1991, Vice Chairman and
Chief Executive Officer from 1985 to 1987, and President and Chief Operating
Officer from 1975 to 1985. Prior to 1975, Mr. Wright served in senior positions
at Xerox Corp. from 1973 to 1975, at Amdahl Corporation from 1971 to 1973, at
RCA from 1969 to 1971, and at IBM from 1949 to 1969.

Thomas R. Mason has served as our Executive Vice President since August
1999 and Senior Vice President since March 1999 until August 1999. Mr. Mason is
responsible for managing our power plant construction and operations activities.
Prior to joining us, Mr. Mason was President and Chief Operating Officer of
CalEnergy Operating Services Inc., a wholly owned subsidiary of MidAmerica
Energy Holdings Company from 1995 to

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February 1999. He obtained a Masters of Business Administration Degree from the
University of Chicago in 1970 and a Bachelor of Science Degree in Electrical
Engineering from Purdue University in 1966.

Robert D. Kelly has served as our Senior Vice President-Finance since
January 1998 and Vice President, Finance from April 1994 to January 1998. Mr.
Kelly's responsibilities include all project and corporate finance activities.
From 1992 to 1994, Mr. Kelly served as our Director-Project Finance, and from
1991 to 1992, he served as Project Finance Manager. Prior to joining us, he was
the Marketing Manager of Westinghouse Credit Corporation from 1990 to 1991. From
1989 to 1990, Mr. Kelly was Vice President of Lloyds Bank PLC. From 1982 to
1989, Mr. Kelly was employed in various positions with The Bank of Nova Scotia.
He obtained a Master of Business Administration Degree from Dalhousie
University, Canada in 1980 and a Bachelor of Commerce Degree from Memorial
University, Canada, in 1979.

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PRINCIPAL STOCKHOLDERS

The following table sets forth certain information known to us regarding
beneficial ownership of our common stock as of August 31, 1999 by (1) each
person known by us to be the beneficial owner of more than five percent of the
outstanding shares of our common stock, (2) each of our directors, (3) certain
of our executive officers and (4) all of our officers and directors as a group.
All figures reflect the 2 for 1 stock split effective on October 7, 1999.

<TABLE>
<CAPTION>
NAME AND ADDRESS NUMBER OF SHARES PERCENTAGE OF SHARES
OF BENEFICIAL OWNER BENEFICIALLY OWNED(1) BENEFICIALLY OWNED(1)
------------------- --------------------- ---------------------
<S> <C> <C>
Putnam Investments, Inc.................. 5,698,912 10.4%
One Post Office Square
Boston, MA 02109
Fidelity Management & Research Co........ 5,274,960 9.7%
82 Devonshire Street, E34E
Boston, MA 02109
Ohio Public Employee Retirement System... 4,200,000 7.7%
277 East Town Street
Columbus, OH 43215
Wellington Management Company, LLP....... 4,024,600 7.4%
75 State Street
Boston, MA 02109
Peter Cartwright(2)...................... 2,011,604 3.6%
Ann B. Curtis(3)......................... 534,008 *
Thomas R. Mason.......................... 2,000 *
Robert D. Kelly(4)....................... 243,320 *
Jeffrey E. Garten(5)..................... 31,122 *
Susan C. Schwab(5)....................... 29,848 *
George J. Stathakis(6)................... 95,562 *
John O. Wilson(5)........................ 37,348 *
V. Orville Wright(7)..................... 45,960 *
All executive officers and directors as a
group (9 persons)(8)................... 3,030,772 5.3%
</TABLE>

- -------------------------
* Less than one percent

(1) This table is based in part upon information supplied by Schedules 13F
filed by principal stockholders with the Securities and Exchange Commission
(the "Commission"). Beneficial ownership is determined in accordance with
the rules of the Commission and generally includes voting or investment
power with respect to securities. Shares of common stock subject to
options, warrants and convertible notes currently exercisable or
convertible, or exercisable or convertible within 60 days after a specified
date, 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. The number of shares
of common stock outstanding as of October 27, 1999 was 54,569,788.

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<PAGE> 77

(2) Includes options to purchase 1,999,704 shares of our common stock issuable
upon the exercise of options outstanding as of August 31, 1999 or within 60
days thereafter.

(3) Includes options to purchase 533,382 shares of our common stock issuable
upon the exercise of options outstanding as of August 31, 1999 or within 60
days thereafter.

(4) Includes options to purchase 240,720 shares of our common stock issuable
upon the exercise of options outstanding as of August 31, 1999 or within 60
days thereafter.

(5) Represents shares of our common stock issuable upon exercise of options
that are exercisable as of August 31, 1999 or will become exercisable
within 60 days thereafter.

(6) Includes options to purchase 89,562 shares of our common stock issuable
upon the exercise of options outstanding as of August 31, 1999 or within 60
days thereafter.

(7) Includes options to purchase 35,960 shares of our common stock issuable
upon the exercise of options outstanding as of August 31, 1999 or within 60
days thereafter.

(8) Includes options to purchase 3,184,270 shares of our common stock issuable
upon the exercise of options outstanding as of August 31, 1999 or within 60
days thereafter.

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DESCRIPTION OF CAPITAL STOCK

Our authorized capital stock consists of 100,000,000 shares of common
stock, $.001 par value, and 10,000,000 shares of preferred stock, $.001 par
value. The following summary is qualified in its entirety by the provisions of
our certificate of incorporation and bylaws, which have been filed as exhibits
to the Registration Statement of which this prospectus constitutes a part. The
information provided below reflects the 2 for 1 stock split effective on October
7, 1999.

COMMON STOCK

There will be 61,769,788 shares of common stock outstanding upon the
completion of this offering, based on the 54,569,788 shares outstanding as of
October 27, 1999. The holders of common stock are entitled to one vote per share
on all matters to be voted upon by the stockholders. Subject to preferences that
may be applicable to any outstanding preferred stock, the holders of common
stock are entitled to receive ratably such dividends, if any, as may be declared
from time to time by the board of directors out of funds legally available
therefor. See "Dividend Policy." In the event of our liquidation, dissolution or
winding up, the holders of common stock are entitled to share ratably in all
assets remaining after payment of liabilities, subject to prior liquidation
rights of preferred stock, if any, then outstanding. The common stock has no
preemptive or conversion rights or other subscription rights. There are no
redemption or sinking fund provisions applicable to the common stock. All
outstanding shares of common stock to be outstanding upon the completion of the
common stock offering will be fully paid and non-assessable.

PREFERRED STOCK

The board of directors has the authority to issue the preferred stock in
one or more series and to fix the rights, preferences, privileges and
restrictions granted to or imposed upon any wholly unissued shares of
undesignated preferred stock and to fix the number of shares constituting any
series and the designations of such series, without any further vote or action
by the stockholders. The board of directors, without stockholder approval, can
issue preferred stock with voting and conversion rights which could adversely
affect the voting power of the holders of common stock. The issuance of
preferred stock may have the effect of delaying, deferring or preventing a
change in control of our company, or could delay or prevent a transaction that
might otherwise give our stockholders an opportunity to realize a premium over
the then prevailing market price of the common stock. There will be no shares of
preferred stock outstanding upon the completion of the common stock offering.

ANTI-TAKEOVER EFFECTS OF PROVISIONS OF THE CERTIFICATE OF INCORPORATION, BYLAWS
AND DELAWARE LAW

CERTIFICATE OF INCORPORATION AND BYLAWS

Our certificate of incorporation and bylaws provide that our board of
directors is classified into three classes of Directors serving staggered,
three-year terms. The certificate of incorporation also provides that Directors
may be removed only by the affirmative vote of the holders of two-thirds of the
shares of our capital stock entitled to vote. Any vacancy on the board of
directors may be filled only by vote of the majority of Directors then in
office. Further, the certificate of incorporation provides that any "Business
Combination"

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(as therein defined) requires the affirmative vote of the holders of two-thirds
of the shares of our capital stock entitled to vote, voting together as a single
class. The certificate of incorporation also provides that all stockholder
actions must be effected at a duly called meeting and not by a consent in
writing. The bylaws provide that our stockholders may call a special meeting of
stockholders only upon a request of stockholders owning at least 50% of our
capital stock. These provisions of the certificate of incorporation and bylaws
could discourage potential acquisition proposals and could delay or prevent a
change in control of our company. These provisions are intended to enhance the
likelihood of continuity and stability in the composition of the board of
directors and in the policies formulated by the board of directors and to
discourage certain types of transactions that may involve an actual or
threatened change of control of our company. These provisions are designed to
reduce our vulnerability to an unsolicited acquisition proposal. The provisions
also are intended to discourage certain tactics that may be used in proxy
fights. However, such provisions could have the effect of discouraging others
from making tender offers for our shares and, as a consequence, they also may
inhibit fluctuations in the market price of our shares that could result from
actual or rumored takeover attempts. Such provisions also may have the effect of
preventing changes in our management.

DELAWARE ANTI-TAKEOVER STATUTE

We are subject to Section 203 of the Delaware General Corporation Law
("Section 203"), which, subject to certain exceptions, prohibits a Delaware
corporation from engaging in any business combination with any interested
stockholder for a period of three years following the date that such stockholder
became an interested stockholder, unless: (1) prior to such date, the board of
directors of the corporation approved either the business combination or the
transaction that resulted in the stockholder becoming an interested stockholder;
(2) upon consummation of the transaction that resulted in the stockholder
becoming an interested stockholder, the interested stockholder owned at least
85% of the voting stock of the corporation outstanding at the time the
transaction commenced, excluding for purposes of determining the number of
shares outstanding those shares owned (x) by persons who are directors and also
officers and (y) by employee stock plans in which employee participants do not
have the right to determine confidentially whether shares held subject to the
plan will be tendered in a tender or exchange offer; or (3) on or subsequent to
such date, the business combination is approved by the board of directors and
authorized at an annual or special meeting of stockholders, and not by written
consent, by the affirmative vote of at least 66 2/3% of the outstanding voting
stock that is not owned by the interested stockholder.

Section 203 defines business combination to include: (1) any merger or
consolidation involving the corporation and the interested stockholder; (2) any
sale, transfer, pledge or other disposition of 10% or more of the assets of the
corporation involving the interested stockholder; (3) subject to certain
exceptions, any transaction that results in the issuance or transfer by the
corporation of any stock of the corporation to the interested stockholder; (4)
any transaction involving the corporation that has the effect of increasing the
proportionate share of the stock of any class or series of the corporation
beneficially owned by the interested stockholder; or (5) the receipt by the
interested stockholder of the benefit of any loans, advances, guarantees,
pledges or other financial benefits provided by or through the corporation. In
general, Section 203 defines an interested stockholder as any entity or person
beneficially owning 15% or more of the outstanding voting stock of the
corporation and any entity or person affiliated with or controlling or
controlled by such entity or person.

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UNDERWRITING

Under the terms and subject to the conditions contained in an underwriting
agreement dated October 27, 1999, we have agreed to sell to the underwriters
named below, for whom Credit Suisse First Boston Corporation, CIBC World Markets
Corp., Donaldson, Lufkin & Jenrette Securities Corporation, Goldman, Sachs &
Co., Salomon Smith Barney Inc. and Gerard Klauer Mattison & Co., Inc. are acting
as representatives, the following respective numbers of shares of common stock:

<TABLE>
<CAPTION>
Number
Underwriter of Shares
----------- ---------
<S> <C>
Credit Suisse First Boston Corporation...................... 1,166,400
CIBC World Markets Corp..................................... 1,166,400
Donaldson, Lufkin & Jenrette Securities Corporation......... 1,166,400
Goldman, Sachs & Co......................................... 1,166,400
Salomon Smith Barney Inc.................................... 1,166,400
Gerard Klauer Mattison & Co., Inc........................... 648,000
Deutsche Bank Securities Inc................................ 144,000
Friedman Billings Ramsey.................................... 144,000
ING Barings LLC............................................. 144,000
PaineWebber Incorporated.................................... 144,000
Warburg Dillon Read LLC..................................... 144,000
---------
Total............................................. 7,200,000
=========
</TABLE>

The underwriting agreement provides that the underwriters are obligated to
purchase all the shares of common stock in the offering if any are purchased,
other than those shares covered by the over-allotment option described below.
The underwriting agreement also provides that if an underwriter defaults the
purchase commitments of non-defaulting underwriters may be increased or the
offering of common stock may be terminated.

We have granted to the underwriters a 30-day option to purchase on a pro
rata basis up to 1,080,000 additional shares at the public offering price less
the underwriting discounts and commissions. The option may be exercised only to
cover any over-allotments of common stock.

The underwriters propose to offer the shares of common stock initially at
the public offering price on the cover page of this prospectus and to selling
group members at that price less a concession of $1.00 per share. The
underwriters and selling group members may allow a discount of $0.10 per share
on sales to other broker/dealers. After the public offering, the public offering
price and concession and discount to broker/dealers may be changed by the
representatives.

The following table summarizes the compensation and estimated expenses we
will pay.

<TABLE>
<CAPTION>
Per Share Total
--------------------------------- ---------------------------------
Without With Without With
Over-Allotment Over-Allotment Over-Allotment Over-Allotment
--------------- --------------- --------------- ---------------
<S> <C> <C> <C> <C>
Underwriting Discounts and
Commissions paid by us.... $ 1.72 $ 1.72 $12,384,000 $14,241,600
Expenses payable by us...... $ 0.11 $ 0.10 $ 800,000 $ 800,000
</TABLE>

We and each of our officers and directors have agreed that we will not
offer, sell, contract to sell, pledge or otherwise dispose of, directly or
indirectly, or file with the SEC a registration statement under the Securities
Act of 1933 relating to any additional shares of our common stock or securities
convertible into or exchangeable or exercisable for any of our common stock, or
publicly disclose the intention to make an offer, sale, pledge,

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disposition or filing, without the prior written consent of Credit Suisse First
Boston Corporation for a period of 90 days after the date of this prospectus,
except in our case issuances pursuant to the exercise of employee stock options
outstanding on the date hereof and the concurrent offering of HIGH TIDES.

We have agreed to indemnify the underwriters against liabilities under the
Securities Act, or contribute to payments which the underwriters may be required
to make in that respect.

The representatives may engage in over-allotment, stabilizing transactions,
syndicate covering transactions and penalty bids in accordance with Regulation M
under the Securities Exchange Act of 1934.

- Over-allotment involves syndicate sales in excess of the offering size,
which creates a syndicate short position.

- Stabilizing transactions permit bids to purchase the underlying security
so long as the stabilizing bids do not exceed a specified maximum.

- Syndicate covering transactions involve purchases of the common stock in
the open market after the distribution has been completed in order to
cover syndicate short positions.

- Penalty bids permit the representatives to reclaim a selling concession
from a syndicate member when the common stock originally sold by such
syndicate member is purchased in a syndicate covering transaction to
cover syndicate short positions.

These stabilizing transactions, syndicate covering transactions and penalty bids
may cause the price of the common stock to be higher than it would otherwise be
in the absence of such transactions. These transactions may be effected on The
New York Stock Exchange or otherwise and, if commenced, may be discontinued at
any time.

Credit Suisse First Boston, New York branch expects to be the lead arranger
and a lender for our proposed $1.0 billion revolving construction loan facility
and, in such capacity, expects to receive customary fees for such services. The
decision of Credit Suisse First Boston Corporation to distribute the common
stock offered hereby and the HIGH TIDES being offered concurrently was made
independent of Credit Suisse First Boston, New York branch which lender had no
involvement in determining whether or when to distribute the common stock or the
HIGH TIDES under the offerings or the terms of the offerings. Credit Suisse
First Boston Corporation will not receive any benefit from the offerings other
than its portion of the underwriting fees as paid by us.

From time to time, certain of the underwriters have provided advisory and
investment banking services to us, for which customary compensation has been
received. It is expected that such underwriters will continue to provide such
services to us in the future. In addition, Credit Suisse First Boston
Corporation, CIBC World Markets Corp. and ING Barings LLC are acting as
underwriters in the concurrent offering of HIGH TIDES.

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NOTICE TO CANADIAN RESIDENTS

RESALE RESTRICTIONS

The distribution of the common stock in Canada is being made only on a
private placement basis exempt from the requirement that we prepare and file a
prospectus with the securities regulatory authorities in each province where
trades of common stock are effected. Accordingly, any resale of the common stock
in Canada must be made in accordance with applicable securities law which will
vary depending on the relevant jurisdiction, and which may require resales to be
made in accordance with available statutory exemptions or pursuant to a
discretionary exemption granted by the applicable Canadian securities regulatory
authority. Purchasers are advised to seek legal advice prior to any resale of
the common stock.

REPRESENTATIONS OF PURCHASERS

Each purchaser of common stock in Canada who receives a purchase
confirmation will be deemed to represent to us and the dealer from whom such
purchase confirmation is received that (1) such purchaser is entitled under
applicable provincial securities laws to purchase such common stock without the
benefit of a prospectus qualified under such securities laws, (2) where required
by law, that such purchaser is purchasing as principal and not as agent, and (3)
such purchaser has reviewed the text above under "Resale Restrictions".

RIGHTS OF ACTION (ONTARIO PURCHASERS)

The securities being offered are those of a foreign issuer and Ontario
purchasers will not receive the contractual right of action prescribed by
Ontario securities law. As a result, Ontario purchasers must rely on other
remedies that may be available, including common law rights of action for
damages or rescission or rights of action under the civil liability provisions
of the U.S. federal securities laws.

ENFORCEMENT OF LEGAL RIGHTS

All of the issuer's directors and officers as well as the experts named
herein may be located outside of Canada and, as a result, it may not be possible
for Canadian purchasers to effect service of process within Canada upon the
issuer or such persons. All or a substantial portion of the assets of the issuer
and such persons may be located outside of Canada and, as a result, it may not
be possible to satisfy a judgment against the issuer or such persons in Canada
or to enforce a judgment obtained in Canadian courts against such issuer or
persons outside of Canada.

NOTICE TO BRITISH COLUMBIA RESIDENTS

A purchaser of common stock to whom the Securities Act (British Columbia)
applies is advised that such purchaser is required to file with the British
Columbia Securities Commission a report within ten days of the sale of any
common stock acquired by such purchaser pursuant to this offering. Such report
must be in the form attached to British Columbia Securities Commission Blanket
Order BOR #95/17, a copy of which may be obtained from us. Only one such report
must be filed in respect of common stock acquired on the same date and under the
same prospectus exemption.

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TAXATION AND ELIGIBILITY FOR INVESTMENT

Canadian purchasers of common stock should consult their own legal and tax
advisors with respect to the tax consequences of an investment in the common
stock in their particular circumstances and with respect to the eligibility of
the common stock for investment by the purchaser under relevant Canadian
legislation.

LEGAL MATTERS

The validity of the securities offered hereby will be passed upon for us by
Brobeck, Phleger & Harrison LLP, San Francisco, California. The underwriters
have been represented by Skadden, Arps, Slate, Meagher & Flom LLP, New York, New
York.

EXPERTS

The consolidated financial statements and schedules as of December 31,
1998, 1997 and 1996 incorporated by reference in this prospectus and elsewhere
in the registration statement have been audited by Arthur Andersen LLP,
independent public accountants, as set forth in their reports. In those reports,
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 and supporting schedules
referred to above have been included herein in reliance upon the authority of
that firm as experts in giving said reports.

The consolidated financial statements of Sumas Cogeneration Company, L.P.
and Subsidiary as of December 31, 1998 and 1997 and for each of the years ended
December 31, 1998, 1997 and 1996 included in our Annual Report on Form 10-K as
amended filed with the Securities and Exchange Commission on February 18, 1999
and incorporated by reference 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.

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