AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON SEPTEMBER 19, 1996
REGISTRATION NO. 333-07497

SECURITIES AND EXCHANGE COMMISSION
 WASHINGTON, D.C. 20549
AMENDMENT NO. 2
TO
FORM S-1
 REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

CALPINE CORPORATION
 (EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)

        DELAWARE                                4911                               77-0212977
(STATE OF INCORPORATION)            (PRIMARY STANDARD INDUSTRIAL                 (IRS EMPLOYER
                                    CLASSIFICATION CODE NUMBER)               IDENTIFICATION NO.)	

50 WEST SAN FERNANDO STREET
SAN JOSE, CA 95113
 (408) 995-5115
(ADDRESS, INCLUDING ZIP CODE, AND TELEPHONE NUMBER, INCLUDING AREA CODE,
OF REGISTRANT'S PRINCIPAL EXECUTIVE OFFICES)

PETER CARTWRIGHT
PRESIDENT AND CHIEF EXECUTIVE OFFICER
CALPINE CORPORATION
50 WEST SAN FERNANDO STREET
SAN JOSE, CA 95113
 (408) 995-5115
(NAME, ADDRESS, INCLUDING ZIP CODE, AND TELEPHONE NUMBER,
INCLUDING AREA CODE, OF AGENT FOR SERVICE)

COPIES TO:

 JOSEPH E. RONAN, JR., ESQ.              SCOTT D. LESTER, ESQ.                 JOSEPH A. COCO, ESQ.
      GENERAL COUNSEL               BROBECK, PHLEGER & HARRISON LLP           SKADDEN, ARPS, SLATE,
    CALPINE CORPORATION                       ONE MARKET                          MEAGHER & FLOM
50 WEST SAN FERNANDO STREET               SPEAR STREET TOWER                     919 THIRD AVENUE
     SAN JOSE, CA 95113                 SAN FRANCISCO, CA 94105                 NEW YORK, NY 10022
       (408) 995-5115                       (415) 442-0900                        (212) 735-3000	

APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC:
As soon as practicable after the effective date of this Registration Statement.
If any of the securities being registered on this Form is to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. / /
If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. / /
If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. / /
If delivery of the prospectus is expected to be made pursuant to Rule 434, please check the following box. / /
CALCULATION OF REGISTRATION FEE

                                                                 PROPOSED           PROPOSED
                                               AMOUNT             MAXIMUM            MAXIMUM           AMOUNT OF
         TITLE OF EACH CLASS OF                 TO BE         OFFERING PRICE        AGGREGATE        REGISTRATION
      SECURITIES TO BE REGISTERED           REGISTERED(1)       PER UNIT(2)     OFFERING PRICE(2)       FEE(3)
- --------------------------------------------------------------------------------------------------------------------
Common Stock, $.001 par value...........   20,751,750 shares      $21.00          $435,786,750         $150,272
- --------------------------------------------------------------------------------------------------------------------	

(1) Includes 2,706,750 shares of Common Stock which the Underwriters have the option to purchase to cover over-allotments, if any.
(2) Estimated solely for the purpose of calculating the amount of the registration fee pursuant to Rule 457(a) of the Securities Act of 1933.
(3) Previously paid.

THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(a) OF THE SECURITIES ACT OF 1933, AS AMENDED, OR UNTIL THE REGISTRATION STATEMENT SHALL BECOME EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING PURSUANT TO SAID
SECTION 8(a), MAY DETERMINE.

EXPLANATORY NOTE
The Registration Statement contains a Prospectus relating to a public offering in the United States and Canada of an aggregate of 14,436,000 shares of Common Stock, $.001 par value, of the Company (the "U.S. Offering"), together with a separate prospectus cover page relating to a concurrent offering outside the United States and Canada of an aggregate of 3,609,000 shares of Common Stock, $.001 par value, of the Company (the "International Offering"). The complete prospectus for the U.S. Offering follows immediately. Following such prospectus are certain pages of the prospectus for the International Offering as follows: a front cover page (page A-1), table of contents (page A-2), a page to replace a portion of the "Risk Factors" section (page A-3), a page to replace a portion of the "Shares Eligible for Future Sale" section (page A-4), pages containing the "Subscription and Sale" section to replace the "Underwriting" section (pages A-5 through A-8), and a back cover page (page A-9). All other pages of the prospectus for the U.S. Offering are to be used for both the U.S. Offering and the International Offering.
Copies of the complete Prospectus for each of the U.S. Offering and the International Offering in the exact forms in which they are to be used after effectiveness will be filed with the Securities and Exchange Commission pursuant to Rule 424(b) of the General Rules and Regulations under the Securities Act of 1933, as amended.

INFORMATION CONTAINED HEREIN IS SUBJECT TO COMPLETION OR AMENDMENT. A REGISTRATION STATEMENT RELATING TO THESE SECURITIES HAS BEEN FILED WITH THE SECURITIES AND EXCHANGE COMMISSION. THESE SECURITIES MAY NOT BE SOLD NOR MAY OFFERS TO BUY BE ACCEPTED PRIOR TO THE TIME THE REGISTRATION STATEMENT BECOMES EFFECTIVE. THIS PROSPECTUS SHALL NOT CONSTITUTE AN OFFER TO SELL OR THE SOLICITATION OF AN OFFER TO BUY NOR SHALL THERE BE ANY SALE OF THESE SECURITIES IN ANY STATE IN WHICH SUCH OFFER, SOLICITATION OR SALE WOULD BE UNLAWFUL PRIOR TO REGISTRATION OR QUALIFICATION UNDER THE SECURITIES LAWS OF ANY SUCH STATE.
SUBJECT TO COMPLETION, DATED SEPTEMBER 19, 1996
[LOGO]
18,045,000 Shares
Calpine Corporation Common Stock

($.001 par value)
Of the shares of Common Stock, $.001 par value ("Common Stock"), of Calpine Corporation (the "Company" or "Calpine") offered hereby, 5,477,820 shares are being sold by the Company and 12,567,180 shares are being sold by the Selling Stockholder named herein under "Principal and Selling Stockholders." Of the 18,045,000 shares of Common Stock being offered, 14,436,000 shares are initially being offered in the United States and Canada (the "U.S. Shares") by the U.S. Underwriters (the "U.S. Offering") and 3,609,000 shares are initially being concurrently offered outside the United States and Canada (the "International Shares") by the Managers (the "International Offering" and, together with the U.S. Offering, the "Common Stock Offering"). The offering price and underwriting discounts and commissions of the U.S. Offering and the International Offering are identical.
Prior to the Common Stock Offering, there has been no public market for the Common Stock. It is anticipated that the initial public offering price will be between $17.00 and $20.00 per share. For information relating to the factors considered in determining the initial public offering price to the public, see "Underwriting."
The Common Stock has been approved for listing on the New York Stock Exchange under the symbol "CPN," subject to notice of issuance.

FOR A DISCUSSION OF CERTAIN FACTORS THAT SHOULD BE CONSIDERED IN CONNECTION WITH
AN INVESTMENT
IN THE COMMON STOCK, SEE "RISK FACTORS" BEGINNING ON PAGE 8 HEREIN.
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED UPON THE ACCURACY OR AD-
EQUACY OF THIS PROSPECTUS. ANY REPRESENTATION
TO THE CONTRARY IS A CRIMINAL
OFFENSE.

                                                   Underwriting                          Proceeds to
                                   Price to       Discounts and      Proceeds to           Selling
                                    Public         Commissions        Calpine(1)         Stockholder
                               ----------------  ----------------  ----------------    ----------------
Per Share....................         $                 $                 $                   $
Total(2).....................         $                 $                 $                   $	

(1) Before deduction of expenses payable by Calpine, estimated at $809,000.
(2) The Company has granted the U.S. Underwriters and the Managers an option, exercisable by CS First Boston Corporation for 30 days from the date of this Prospectus, to purchase a maximum of 2,706,750 additional shares to cover over-allotments of shares. If the option is exercised in full, the total Price to Public will be $ , Underwriting Discounts and Commissions will be $ , Proceeds to Calpine will be $ and Proceeds to Selling Stockholder will be $ .
The U.S. Shares are offered by the several U.S. Underwriters when, as and if delivered to and accepted by the U.S. Underwriters and subject to their right to reject orders in whole or in part. It is expected that the U.S. Shares will be ready for delivery on or about , 1996, against payment in immediately available funds.
CS First Boston
Morgan Stanley & Co.
Incorporated
PaineWebber Incorporated
Salomon Brothers Inc
The date of this Prospectus is , 1996.

IN CONNECTION WITH THE COMMON STOCK OFFERING, CS FIRST BOSTON CORPORATION ON BEHALF OF THE U.S. UNDERWRITERS AND MANAGERS MAY OVER-ALLOT OR EFFECT TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICE OF THE COMMON STOCK AT A LEVEL ABOVE THAT WHICH MIGHT OTHERWISE PREVAIL IN THE OPEN MARKET. SUCH TRANSACTIONS MAY BE EFFECTED ON THE NEW YORK STOCK EXCHANGE OR OTHERWISE. SUCH STABILIZING, IF COMMENCED, MAY BE DISCONTINUED AT ANY TIME.
DURING THE COMMON STOCK OFFERING, CERTAIN PERSONS AFFILIATED WITH PERSONS PARTICIPATING IN THE DISTRIBUTION MAY ENGAGE IN TRANSACTIONS FOR THEIR OWN ACCOUNTS OR FOR THE ACCOUNTS OF OTHERS IN THE COMMON STOCK PURSUANT TO EXEMPTIONS FROM RULES 10B-6, 10B-7, AND 10B-8 UNDER THE SECURITIES EXCHANGE ACT OF 1934.

PROSPECTUS SUMMARY
The following summary is qualified in its entirety by the more detailed information and financial statements appearing elsewhere in this Prospectus. This Prospectus contains forward-looking statements that involve risks and uncertainties. The Company's actual results could differ materially from those projected in such forward-looking statements as a result of certain factors, including those set forth under "Risk Factors" and elsewhere in this Prospectus. Unless the context indicates otherwise, (i) all references in this Prospectus to the "Company" or "Calpine" include Calpine Corporation and its consolidated subsidiaries, (ii) all references to "Common Stock" refer to the Company's Common Stock, $.001 par value, (iii) all information in this Prospectus relating to the Company's Common Stock assumes no exercise of the Underwriters' over-allotment option, and (iv) all information in this Prospectus assumes the following transactions are completed prior to or concurrent with the consummation of the Common Stock Offering: (1) the reincorporation of the Company in Delaware, (2) the conversion of the Company's outstanding Class B Common Stock into Common Stock and the elimination of the Class A Common Stock and Class B Common Stock, (3) a 5.194-for-1 stock split of the Company's Common Stock, and (4) the conversion of the Company's outstanding Preferred Stock into 2,179,487 shares of Common Stock.
THE COMPANY
Calpine is engaged in the acquisition, development, ownership and operation of power generation facilities and the sale of electricity and steam in the United States and selected international markets. The Company has interests in 15 power generation facilities and steam fields having an aggregate capacity of 1,057 megawatts. Since its inception in 1984, Calpine has developed substantial expertise in all aspects of electric power generation. The Company's vertical integration has resulted in significant growth over the last five years as Calpine has applied its extensive engineering, construction management, operations, fuel management and financing capabilities to successfully implement its acquisition and development program. During the last five years, Calpine has expanded substantially, from $41.2 million of total assets as of December 31, 1991 to $911.0 million of total assets on a pro forma basis as of June 30, 1996. Calpine's revenue on a pro forma basis for 1995 increased to $224.3 million, representing a compound annual growth rate of 55% since 1991. The Company's EBITDA (as defined herein) on a pro forma basis for 1995 increased to $123.8 million. See "Pro Forma Consolidated Financial Data." Calpine's strategy is to capitalize on opportunities in the power market through an ongoing program to acquire, develop, own and operate electric power generation facilities, as well as marketing power and energy services to utilities and other end users.
THE MARKET
The power generation industry represents the third largest industry in the United States, with an estimated end user market of approximately $207.5 billion of electricity sales and 3 million gigawatt hours of production in 1995. In response to increasing customer demand for access to low cost electricity and enhanced services, new regulatory initiatives are currently being adopted or considered at both state and federal levels to increase competition in the domestic power generation industry. To date, such initiatives are under consideration at the federal level and in approximately thirty states. For example, in April 1996, the Federal Energy Regulatory Commission ("FERC") adopted Order No. 888, opening wholesale power sales to competition and providing for open and fair electric transmission services by public utilities. In addition, the California Public Utilities Commission ("CPUC") has issued an electric industry restructuring decision which envisions commencement of deregulation and implementation of customer choice of electricity supplier by January 1, 1998. Calpine believes that industry trends and such regulatory initiatives will lead to the transformation of the existing market, which is largely characterized by electric utility monopolies selling to a captive customer base, to a more competitive market where end users may purchase electricity from a variety of suppliers, including non-utility generators, power marketers, public utilities and others. The Company believes that these market trends will create substantial opportunities for companies such as Calpine that are low cost power producers and have an integrated power services capability which enables them to produce and sell energy to customers at competitive rates.
The Company also believes that these market trends will result in the disposition of power generation facilities by utilities, independent power producers and industrial companies. Utilities such as Pacific Gas & Electric Company ("PG&E") and Southern California Edison Company have announced their intentions to sell power generation facilities totalling approximately 3,150 megawatts and 5,000 megawatts, respectively. The independent power industry, which represents approximately 8% of the installed capacity in the United States, or approximately 59,000 megawatts, and has accounted for approximately 50% of all additional capacity in the United States since 1990, is currently undergoing significant consolidation. Many independent producers operating a limited number of power plants are seeking to dispose of such plants in response to
3

competitive pressures, and industrial companies are selling their power plants to redeploy capital in their core businesses. Over 200 independent power plant and portfolio sale transactions have occurred in the past two years. The Company believes that this consolidation will continue in the highly fragmented independent power industry.
The power generation industry outside the United States is approximately three times larger than the domestic market, and the demand for electricity is growing rapidly. In 1996, it has been estimated that in excess of 590 gigawatts of new capacity will be required outside the United States over the ensuing ten-year period. In order to satisfy this anticipated increase in demand, many countries have adopted active government programs designed to encourage private investment in power generation facilities. The Company believes that these market trends will create significant opportunities to acquire and develop power generation facilities in such countries.
STRATEGY
Calpine's objective is to become a leading power company by capitalizing on these emerging opportunities in the domestic and international power markets. The key elements of the Company's strategy are as follows:
Expand and diversify domestic portfolio of power projects. In pursuing its growth strategy, the Company intends to focus on opportunities where it is able to capitalize on its extensive management and technical expertise to implement a fully integrated approach to the acquisition, development and operation of power generation facilities. This approach includes design, engineering, procurement, finance, construction management, fuel and resource acquisition, operations and power marketing, which Calpine believes provides it with a competitive advantage. By pursuing this strategy, the Company has significantly expanded and diversified its project portfolio. Since 1993, the Company has completed transactions involving five gas-fired cogeneration facilities and two steam fields. As a result of these transactions, the Company has more than doubled its aggregate power generation capacity and substantially diversified its fuel mix since 1993.
The Company is also pursuing the development of highly efficient, low cost power plants that seek to take advantage of inefficiencies in the electricity market. The Company intends to sell all or a portion of the power generated by such merchant plants into the competitive market, rather than exclusively through long-term power sales agreements. As part of Calpine's initial effort to develop merchant plants, the Company entered into an agreement with Phillips Petroleum Company to develop a gas-fired cogeneration project with a capacity of 240 megawatts. Under this agreement, approximately 90 megawatts of electricity will be sold to the Phillips Houston Chemical Complex, with the remainder to be sold into the competitive market through Calpine's power marketing activities. The Company expects that this project will represent a prototype for future merchant plant developments. The development of this project is subject to the satisfaction of various conditions, including completion of financing and obtaining required approvals. See "Business -- Development and Future Projects."
Enhance the performance and efficiency of existing power projects. The Company continually seeks to maximize the power generation potential of its operating assets and minimize its operating and maintenance expenses and fuel costs. To date, the Company's power generation facilities have operated at an average availability in excess of 97%. The Company believes that achieving and maintaining a low cost of production will be increasingly important to compete effectively in the power generation market.
Continue to develop an integrated power marketing capability. The Company has established an integrated power marketing capability, conducted through its wholly owned subsidiary, Calpine Power Services Company ("CPSC"). In 1995, CPSC received approval from the FERC to conduct power marketing activities. The Company believes that a power marketing capability complements its business strategy of providing low cost power generation services. CPSC's power marketing activities will focus on the development of long-term customer service relationships, supported primarily by generating assets that are owned, operated or controlled by Calpine. CPSC will aggregate the Company's own resources, the resources of its customers, power pool resources, and market power supply to provide the customized services demanded by its customers at a competitive price.
Selectively expand into international markets. Internationally, the Company intends to utilize its geothermal and gas-fired expertise in selected markets of Southeast Asia and Latin America, where demand for power is rapidly growing and private investment is encouraged. In November 1995, the Company made an investment in the Cerro Prieto steam fields, located in Baja California, Mexico. In March 1996, the Company entered into a joint venture agreement to pursue the development of a geothermal resource in Indonesia with
4

an estimated potential capacity in excess of 500 megawatts. Calpine believes that its investments in these projects will effectively position it for future expansion in Southeast Asia and Latin America.
BACKGROUND
Calpine was founded in 1984 by Peter Cartwright, the Company's President and Chief Executive Officer. Through 1988, the Company provided engineering, management, finance and operating and maintenance services to the emerging independent power production industry. Since 1989, the Company has focused on the acquisition, development, ownership, operation and maintenance of gas-fired and geothermal power generation facilities. Prior to the Common Stock Offering, the Company has been a wholly owned subsidiary of Electrowatt Ltd. ("Electrowatt"), a major utility, industrial products and engineering services company based in Zurich, Switzerland. Electrowatt has advised the Company that its current strategy is to focus its resources on its industrial business. As a result of the Common Stock Offering, Electrowatt will no longer own any interest in the Company and Calpine management will hold stock options representing approximately 11.7% of the Company's Common Stock.
Calpine was incorporated under the laws of the State of California in 1984 and was reincorporated in the State of Delaware in September 1996. The principal executive offices of the Company are located at 50 West San Fernando Street, San Jose, California 95113, and its telephone number is (408) 995-5115.
RISK FACTORS
Prospective investors should carefully consider the information presented in this Prospectus, particularly the matters set forth under the caption "Risk Factors."
THE COMMON STOCK OFFERING
Of the Common Stock offered hereby, 14,436,000 shares are initially being offered in the United States and Canada by the U.S. Underwriters in the U.S. Offering and 3,609,000 shares are initially being concurrently offered outside the United States and Canada by the Managers in the International Offering.

Total Common Stock offered...................  18,045,000 shares
  By the Company
     U.S. Offering...........................  4,382,256 shares
     International Offering..................  1,095,564 shares
          Total..............................  5,477,820 shares
  By the Selling Stockholder
     U.S. Offering...........................  10,053,744 shares
     International Offering..................  2,513,436 shares
          Total..............................  12,567,180 shares
Common Stock to be outstanding after
  the Common Stock Offering..................  18,045,000 shares(1)
Use of proceeds..............................  The net proceeds of the sale of shares of
                                               Common Stock by the Company will be used for
                                                 repayment of approximately $13.0 million of
                                                 outstanding indebtedness and for working
                                                 capital and general corporate purposes,
                                                 including the development and acquisition
                                                 of power generation facilities. See "Use of
                                                 Proceeds."
NYSE trading symbol..........................  CPN	

(1) Excludes 2,392,026 shares of Common Stock reserved for issuance upon exercise of options previously granted and outstanding as of June 30, 1996 under the Company's Stock Option Program. Of such amount, options to purchase 1,366,696 shares were exercisable as of June 30, 1996. See "Management -- Stock Option Program" and "-- 1996 Stock Incentive Plan."

5

SUMMARY CONSOLIDATED FINANCIAL DATA

                                        YEAR ENDED DECEMBER 31,                                  SIX MONTHS ENDED JUNE 30,
                ------------------------------------------------------------------------   --------------------------------------
                  1991        1992        1993        1994                1995               1995                 1996
                ---------   ---------   ---------   ---------   ------------------------   ---------    -------------------------
                                                                    ACTUAL  PRO FORMA(1)                   ACTUAL    PRO FORMA(2)
                                                                 ---------  ------------                ---------   -------------
                                            (DOLLARS AND SHARES IN THOUSANDS, EXCEPT PER SHARE DATA)
STATEMENT OF
  OPERATIONS
  DATA:
 Total
   revenue....    $39,052     $39,577     $69,915     $94,762    $132,098      $224,261      $50,352      $81,994       $93,068
 Cost of
   revenue....     25,064      25,921      42,501      52,845      77,388       142,298       30,618       51,319        65,940
 Gross
   profit.....     13,988      13,656      27,414      41,917      54,710        81,963       19,734       30,675        27,128
 Project
   development
   expenses...      1,067         806       1,280       1,784       3,087         3,087        1,308        1,410         1,410
 General and
administrative
   expenses...      3,443       3,924       5,080       7,323       8,937         8,937        3,659        5,874         5,874
 Income from
 operations...      9,478       6,902      21,054      31,772      42,686        69,939       14,767       23,391        19,844
 Interest
   expense....      1,925       1,225      13,825      23,886      32,154        57,523       15,116       18,665        27,900
 Other income,
   net........       (416)       (310)     (1,133)     (1,988)     (1,895)       (9,158)        (855)      (2,777)       (5,303)
 Net income
   (loss).....      5,958       3,460       3,754       6,021       7,378        12,810          298        4,423        (1,623)
 Weighted
   average
   shares
   outstanding(3)...                                               14,187        14,187                    14,476        14,476
 Net income
   (loss) per
   share(3)...                                                      $0.52         $0.90                     $0.31        $(0.11)
OTHER
 FINANCIAL
 DATA:
 Depreciation
   and
   amortization...    $  219    $  232    $12,540     $21,580    $ 26,896       $42,734      $ 9,882      $15,757       $21,302
 EBITDA(4)....    $ 4,909     $ 9,898     $42,370     $53,707    $ 69,515      $123,770      $25,440      $41,345       $46,993
SELECTED
 OPERATING
 INFORMATION:(5)
 Power plants:
   Electricity
   revenue:(6)
     Energy...    $33,426     $38,325     $37,088     $45,912     $54,886       $89,292      $22,323      $34,362       $36,839
   Capacity...    $ 7,562     $ 7,707     $ 7,834     $ 7,967     $30,485       $83,591      $ 9,051      $19,774       $28,364
   Megawatt
     hours
   produced...    392,471     403,274     378,035     447,177   1,033,566     2,387,730      324,059      736,739       860,969
   Average
     energy
     price per
     kilowatt
    hour(7)...     8.517c      9.503c      9.811c     10.267c      5.310c        3.740c       6.889c       4.664c        4.279c
 Steam fields:
   Steam
     revenue:
    Calpine...    $36,173     $33,385     $31,066     $32,631     $39,669       $39,669      $17,639      $15,866       $15,866
     Other
   interest...    $ 2,820     $ 2,501     $ 2,143     $ 2,051          --            --           --           --            --
   Megawatt
     hours
   produced...  2,095,576   2,105,345   2,014,758   2,156,492   2,415,059     2,415,059    1,027,317    1,040,271     1,040,271
   Average
     price per
     kilowatt
     hour.....     1.861c      1.705c      1.648c      1.608c      1.643c        1.643c       1.717c       1.525c        1.525c	

                                                                                                   AS OF JUNE 30, 1996
                                             AS OF DECEMBER 31,                         -----------------------------------------
                         ----------------------------------------------------------                     PRO         PRO FORMA AS
                          1991        1992         1993         1994         1995        ACTUAL      FORMA(2)      ADJUSTED(2)(8)
                         -------     -------     --------     --------     --------     --------     ---------     --------------
                                                                      (IN THOUSANDS)
BALANCE SHEET DATA:
  Cash and cash
    equivalents........  $   958     $ 2,160     $  6,166     $ 22,527     $ 21,810     $ 38,403     $ 16,047        $  110,877
  Property, plant and
    equipment, net.....      351         424      251,070      335,453      447,751      530,203      657,724           657,724
  Total assets.........   41,245      55,370      302,256      421,372      554,531      792,812      910,977         1,005,807
  Total liabilities....   34,624      44,865      288,827      402,723      529,304      713,156      831,321           831,321
  Stockholder's
    equity.............    6,621      10,505       13,429       18,649       25,227       79,656       79,656           174,486
                                                                                                     (see footnotes on next page)	

6

(1) The pro forma information presented under statement of operations data and other financial data for the year ended December 31, 1995 gives effect to the following transactions as if such transactions had occurred on January 1, 1995: (i) the acquisition by the Company of the Greenleaf 1 and 2 Facilities (the "Greenleaf Transaction"); (ii) the acquisition by the Company of the lease for the Watsonville Facility (the "Watsonville Transaction"); (iii) the entry by the Company into the agreements in respect of the Cerro Prieto Steam Fields (the "Cerro Prieto Transaction");
(iv) the entry by the Company into a transaction involving a lease for the King City Facility (the "King City Transaction"); (v) the acquisition by the Company of the Gilroy Facility (the "Gilroy Transaction"); (the Greenleaf Transaction, the Watsonville Transaction, the Cerro Prieto Transaction, the King City Transaction and the Gilroy Transaction being collectively referred to as the "Transactions"); (vi) the $50.0 million Preferred Stock investment in Calpine by Electrowatt (the "Preferred Stock Investment") and the application of the proceeds therefrom; and (vii) the sale of the Company's 10 1/2% Senior Notes Due 2006 (the "10 1/2% Senior Notes") and the application of the net proceeds therefrom. The pro forma information presented under selected operating information for the year ended December 31, 1995 gives effect to the Greenleaf Transaction, the Watsonville Transaction, the King City Transaction and the Gilroy Transaction as if such transactions had occurred on January 1, 1995. See "Pro Forma Consolidated Financial Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Business -- Description of Facilities."
(2) The pro forma information presented under statement of operations data, other financial data and selected operating information for the six months ended June 30, 1996 gives effect to (i) the King City Transaction, (ii) the Gilroy Transaction and (iii) the sale of the 10 1/2% Senior Notes and the application of the net proceeds therefrom as if such transactions had occurred on January 1, 1996. The pro forma information presented under balance sheet data as of June 30, 1996 gives effect to the Gilroy Transaction as if such transaction had occurred on June 30, 1996. See "Pro Forma Consolidated Financial Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Business -- Description of Facilities."
(3) The actual and pro forma weighted average shares outstanding and net income
(loss) per share for the year ended December 31, 1995 and the six months ended June 30, 1996 give effect to the issuance of Common Stock upon the conversion of the Company's outstanding Preferred Stock.
(4) EBITDA is defined as income from operations plus depreciation, capitalized interest, other income, non-cash charges and cash received from investments in power projects, reduced by the income from unconsolidated investments in power projects. EBITDA is presented not as a measure of operating results but rather as a measure of the Company's ability to service debt. EBITDA should not be construed as an alternative either (i) to income from operations (determined in accordance with generally accepted accounting principles) or (ii) to cash flows from operating activities (determined in accordance with generally accepted accounting principles).
(5) For an explanation of such selected operating information, see "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Selected Operating Information."
(6) The significant increase in capacity revenue and the accompanying decline in average energy price per kilowatt hour since 1994 reflects the increase in the Company's megawatt hour production as a result of acquisitions of gas-fired cogeneration facilities by the Company.
(7) Average energy price per kilowatt hour represents energy revenue divided by the kilowatt hours produced.
(8) Adjusted to reflect the sale of the 5,477,820 shares of Common Stock offered by the Company hereby at an assumed initial offering price of $18.50 per share, and the application of the net proceeds therefrom as described in "Use of Proceeds."
7

RISK FACTORS
Prospective purchasers of the Common Stock should carefully consider the factors set forth below, as well as the other information contained in this Prospectus, in evaluating an investment in the Common Stock.
HIGH LEVERAGE
The Company is highly leveraged as a result of outstanding indebtedness of the Company and non-recourse debt financing of certain of the Company's subsidiaries incurred to finance the acquisition and development of power generation facilities. As of June 30, 1996, the Company's total consolidated indebtedness was $499.8 million, its total consolidated assets were $792.8 million and its stockholder's equity was $79.7 million. At such date, on a pro forma basis after giving effect to the Gilroy Transaction, the Company's total consolidated indebtedness would have been $615.8 million, its total consolidated assets would have been $911.0 million and its stockholder's equity would have been $79.7 million. See "Capitalization," "Pro Forma Consolidated Financial Data" and "Management's Discussion and Analysis of Financial Condition and Results of Operations." The ability of the Company to meet its debt service obligations and to repay outstanding indebtedness according to its terms will be dependent primarily upon the performance of the power generation facilities in which the Company has an interest.
The Indenture dated May 16, 1996 (the "10 1/2% Indenture") relating to the Company's 10 1/2% Senior Notes and the Indenture dated February 17, 1994 (the "9 1/4% Indenture") relating to the Company's 9 1/4% Senior Notes Due 2004 (the "9 1/4% Senior Notes") (collectively, the "Indentures") contain certain restrictive covenants. Such restrictions will affect, and in many respects will significantly limit or prohibit, among other things, the ability of the Company or its subsidiaries or such other entities, as the case may be, to incur indebtedness, make prepayments of certain indebtedness, pay dividends, make investments, engage in transactions with affiliates, create liens, sell assets and engage in mergers and consolidations. The Indentures also contain provisions that require the Company, in the event of certain change of control transactions, to make an offer to purchase the 10 1/2% Senior Notes and the 9 1/4% Senior Notes. The Common Stock Offering will not constitute a change of control transaction under the Indentures. There can be no assurance that the Company will have the financial resources necessary to purchase the 10 1/2% Senior Notes and the 9 1/4% Senior Notes upon a change of control. Such change of control provisions contained in the Indentures may not be waived by the Board of Directors of the Company.
The Company believes that, based on current levels of operations and anticipated growth, cash flow from operations, together with other available sources of funds, including borrowings under the Company's existing borrowing arrangements, will be adequate to make required payments of principal and interest on the Company's debt, including the 10 1/2% Senior Notes and the 9 1/4% Senior Notes, and to enable the Company to comply with the terms of its debt agreements, although there can be no assurance that this will be the case. If the Company is unable to comply with the terms of its debt agreements and fails to generate sufficient cash flow from operations in the future, the Company may be required to refinance all or a portion of its existing debt or to obtain additional financing. There can be no assurance that any such refinancing would be possible or that any additional financing could be obtained, particularly in view of the Company's high levels of debt and the debt incurrence restrictions under existing debt agreements. If cash flow is insufficient and no such refinancing or additional financing is available, the Company may be forced to default on its debt obligations. In the event of a default under the terms of any of the indebtedness of the Company, subject to the terms of such indebtedness, the obligees thereunder would be permitted to accelerate the maturity of such obligations, which could cause defaults under other obligations of the Company. See "-- Possible Unavailability of Financing," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Certain Transactions."
POSSIBLE UNAVAILABILITY OF FINANCING
Each power generation facility acquired or developed by the Company will require substantial capital investment. The Company's ability to arrange financing and the cost of such financing are dependent upon numerous factors, including general economic and capital market conditions, conditions in energy markets, regulatory developments, credit availability from banks or other lenders, investor confidence in the industry
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and the Company, the continued success of the Company's current facilities, and provisions of tax and securities laws that are conducive to raising capital. There can be no assurance that financing for new facilities will be available to the Company on acceptable terms in the future. In addition, there can be no assurance that all required governmental permits and approvals for the Company's new or acquired facilities will be obtained, that the Company will be able to obtain favorable power sales agreements and adequate financing, or that the Company will be successful in the development of power generation facilities in the future. Historically, the Company has been successful in obtaining debt financing for its facilities and has relied on Electrowatt, currently the Company's sole stockholder, to provide funding for a substantial portion of its facility equity commitments. The Company currently has an existing $50.0 million credit facility with Credit Suisse (the "Credit Suisse Credit Facility"), which was arranged for the Company by Electrowatt. In connection with the Common Stock Offering, Electrowatt will sell all of its shares of Common Stock of the Company and, as a result, the Company will no longer be able to rely on Electrowatt for financing. Upon the completion of the Common Stock Offering, the Credit Suisse Credit Facility will terminate.
On July 20, 1996, the Company entered into a Commitment Letter with The Bank of Nova Scotia for a $50.0 million three-year revolving credit facility (the "Bank of Nova Scotia Facility"). The Bank of Nova Scotia Facility will become effective upon the completion of the Common Stock Offering, and will contain certain restrictions that will significantly limit or prohibit, among other things, the ability of the Company or its subsidiaries to incur indebtedness, make prepayments of certain indebtedness, pay dividends, make investments, engage in transactions with affiliates, create liens, sell assets and engage in mergers and consolidations. See "Management's Discussion and Analysis of Result of Operations and Financial Condition -- Liquidity and Capital Resources."
The Company's power generation facilities have been financed using a variety of leveraged financing structures, consisting of corporate debt, non-recourse debt and lease obligations. As of June 30, 1996, on a pro forma basis after giving effect to the Gilroy Transaction, the Company would have had approximately $615.8 million of total consolidated indebtedness, of which approximately 53% would have represented non-recourse subsidiary debt. See "Pro Forma Consolidated Financial Data." Each non-recourse debt and lease obligation is structured to be fully paid out of cash flow provided by the facility or facilities, the assets of which (together with pledges of stock or partnership interests in the entity owning the facility) collateralize such obligations, without any claim against the Company's general corporate funds. Such leveraged financing permits the development of larger facilities, but also increases the risk to the Company that its interest in a particular facility could be impaired or that fluctuations in revenues could adversely affect the Company's ability to meet its lease or debt obligations. The significant debt collateralized by the interests of the Company in each operating facility reduces the liquidity of such assets since any sale or transfer of a facility would be subject both to the lien securing the facility indebtedness and to transfer restrictions in the financing agreements. While the Company intends to utilize non-recourse or lease financing when appropriate, there can be no assurance that market conditions and other factors will permit the same limited equity investment by the Company or the same substantially non-recourse nature of financings for future facilities. In the event of a default under a financing agreement, and assuming the Company or the other equity investors in a facility are unable or choose not to cure such default within applicable cure periods, if any, the lenders or lessors would generally have rights to the facility, any related geothermal resource or natural gas reserves, related contracts and cash flows and all licenses and permits necessary to operate the facility. In the event of foreclosure after such a default, the Company might not retain any interest in such facility. The Company does not believe the existence of non-recourse or lease financing will materially affect its ability to continue to borrow funds in the future in order to finance new facilities. There can be no assurance, however, that the Company will continue to be able to obtain the financing required to develop its power facilities on terms satisfactory to the Company. See "Business -- Description of Facilities."
The Company has from time to time guaranteed certain obligations of its subsidiaries and other affiliates. There can be no assurance that, in respect of any financings of facilities in the future, lenders or lessors will not require the Company to guarantee the indebtedness of such future facilities, rendering the Company's general corporate funds vulnerable in the event of a default by such facility or related subsidiary. If the lenders or lessors were to require such guarantees, and the Company were unable to incur indebtedness in respect of such
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guarantees under the restrictions on indebtedness (including guarantees) contained in the Indentures, the Company's ability to fund new facilities could be adversely affected. The Indentures do not limit the ability of the Company's subsidiaries to incur non-recourse or lease financing for investment in new facilities.
Calpine Geysers Company, L.P. ("CGC"), a wholly owned subsidiary of Calpine, owns the West Ford Flat Facility, the Bear Canyon Facility, the PG&E Unit 13 and Unit 16 Steam Fields and the SMUDGEO #1 Steam Fields. Calpine Greenleaf Corporation ("Calpine Greenleaf"), a wholly owned subsidiary of Calpine, owns the Greenleaf 1 and 2 Facilities. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- General" and "Business -- Description of Facilities." The non-recourse facility financing of each of CGC and Calpine Greenleaf is collateralized by all of the assets and properties of each of the facilities and steam fields owned by such subsidiary. In the event of a reduction in revenue derived from one or more of these facilities or steam fields which results in a failure to make any payments on, or if such subsidiary otherwise defaults in its obligations under the terms of, its non-recourse project financing, the lenders would be entitled to foreclose on all of the assets of such subsidiary, including the assets pertaining to each such facility and steam field.
RISKS RELATED TO THE DEVELOPMENT AND OPERATION OF GEOTHERMAL ENERGY RESOURCES
The development and operation of geothermal energy resources are subject to substantial risks and uncertainties similar to those experienced in the development of oil and gas resources. The successful exploitation of a geothermal energy resource ultimately depends upon the heat content of the extractable fluids, the geology of the reservoir, the total amount of recoverable reserves and operational factors relating to the extraction of fluids, including operating expenses, energy price levels and capital expenditure requirements relating primarily to the drilling of new wells. In connection with the development of a project, the Company estimates the productivity of the geothermal resource and the expected decline in such productivity. The productivity of a geothermal resource may decline more than anticipated, resulting in insufficient recoverable reserves being available for sustained generation of the electrical power capacity desired. An incorrect estimate by the Company or an unexpected decline in productivity could have a material adverse effect on the Company's results of operations.
Geothermal reservoirs are highly complex, and, as a result, there exist numerous uncertainties in determining the extent of the reservoirs and the quantity and productivity of the steam reserves. Reservoir engineering is an inexact process of estimating underground accumulations of steam or fluids that cannot be measured in any precise way, and depends significantly on the quantity and accuracy of available data. As a result, the estimates of other reservoir specialists may differ materially from those of the Company. Estimates of reserves are generally revised over time on the basis of the results of drilling, testing and production that occur after the original estimate was prepared. While the Company has extensive experience in the operation and development of geothermal energy resources and in preparing such estimates, there can be no assurance that the Company will be able to successfully manage the development and operation of its geothermal reservoirs or that the Company will accurately estimate the quantity or productivity of its steam reserves.
IMPACT OF AVOIDED COST PRICING; ENERGY PRICE FLUCTUATIONS
Nine of the existing power plants in which the Company has an interest sell electricity to PG&E under separate long-term power sales agreements. Each of these agreements provides for both capacity payments and energy payments for the term of the agreement. During the initial ten-year period of certain of the agreements, PG&E pays a fixed price for each unit of electrical energy according to schedules set forth in such agreements. The fixed price periods under these power sales agreements expire at various times in 1998 through 2000. After the fixed price periods expire, while the basis for the capacity and capacity bonus payments under these power sales agreements remains the same, the energy payments adjust to PG&E's then prevailing avoided cost of energy, which is determined and published from time to time by the CPUC. The term "avoided cost" refers to the incremental costs that an electric utility would incur to produce or purchase an amount of power equivalent to that purchased from qualifying facilities (as defined under the Public Utility Regulatory Policies Act of 1978, as amended ("PURPA")). The currently prevailing avoided cost of energy is substantially lower than the fixed energy prices under these power sales agreements and is generally expected
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to remain so. While avoided cost does not affect capacity payments under the power sales agreements, in the event that the avoided cost of energy does not increase significantly, the Company's energy revenue under these power sales agreements would be materially reduced at the expiration of the fixed price period. Such reduction could have a material adverse effect on the Company's results of operations. The Company cannot accurately predict the likely level of avoided cost energy prices at the expiration of the fixed price periods. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- General" and "Business -- Description of Facilities." Prices paid for the steam delivered by the Company's steam fields are based on a formula that partially reflects the price levels of nuclear and fossil fuels, and, therefore, a reduction in the price levels of such fuels may reduce revenue under the steam sales agreements for the steam fields. See "Business -- Description of Facilities -- Steam Fields."
IMPACT OF CURTAILMENT
Each of the Company's power and steam sales agreements contains curtailment provisions pursuant to which the purchasers of energy or steam are entitled to reduce the number of hours of energy or amount of steam purchased thereunder. Curtailment provisions are customary in power and steam sales agreements. During 1995, certain of the Company's power generation facilities experienced maximum curtailment primarily as a result of a high degree of precipitation during the period, which resulted in higher levels of energy generation by hydroelectric power facilities that supply electricity. See "Management's Discussion and Analysis of Financial Condition and Results of Operations." In limited circumstances, energy production from third party geothermal power plants may be curtailed, which would reduce deliveries of steam by the Company under the steam sales agreements. The Company expects maximum curtailment during 1996 under its power sales agreements for certain of its facilities, and there can be no assurance that the Company will not experience curtailment in the future. In the event of such curtailment, the Company's results of operations may be materially adversely affected. See "Business -- Description of Facilities."
POWER PROJECT DEVELOPMENT AND ACQUISITION RISKS
The development of power generation facilities is subject to substantial risks. In connection with the development of a power generation facility, the Company must generally obtain power and/or steam sales agreements, governmental permits and approvals, fuel supply and transportation agreements, sufficient equity capital and debt financing, electrical transmission agreements, site agreements and construction contracts, and there can be no assurance that the Company will be successful in doing so. In addition, project development is subject to certain environmental, engineering and construction risks relating to cost-overruns, delays and performance. Although the Company may attempt to minimize the financial risks in the development of a project by securing a favorable long-term power sales agreement, entering into power marketing transactions, obtaining all required governmental permits and approvals and arranging adequate financing prior to the commencement of construction, the development of a power project may require the Company to expend significant sums for preliminary engineering, permitting and legal and other expenses before it can be determined whether a project is feasible, economically attractive or financeable. If the Company were unable to complete the development of a facility, it would generally not be able to recover its investment in such a facility.
The process for obtaining initial environmental, siting and other governmental permits and approvals is complicated and lengthy, often taking more than one year, and is subject to significant uncertainties. As a result of competition, it may be difficult to obtain a power sales agreement for a proposed project, and the prices offered in new power sales agreements for both electric capacity and energy may be less than the prices in prior agreements.
The Company has grown substantially in recent years as a result of acquisitions of interests in power generation facilities and steam fields such as the Transactions. The Company believes that although the domestic power industry is undergoing consolidation and that significant acquisition opportunities are available, the Company is likely to confront significant competition for acquisition opportunities. In addition, there can be no assurance that the Company will continue to identify attractive acquisition opportunities at
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favorable prices or, to the extent that any opportunities are identified, that the Company will be able to consummate such acquisitions.
START-UP RISKS
The commencement of operation of a newly constructed power plant or steam field involves many risks, including start-up problems, the breakdown or failure of equipment or processes and performance below expected levels of output or efficiency. New plants have no operating history and may employ recently developed and technologically complex equipment. Insurance is maintained to protect against certain of these risks, warranties are generally obtained for limited periods relating to the construction of each project and its equipment in varying degrees, and contractors and equipment suppliers are obligated to meet certain performance levels. Such insurance, warranties or performance guarantees may not be adequate to cover lost revenues or increased expenses and, as a result, a project may be unable to fund principal and interest payments under its financing obligations and may operate at a loss. A default under such a financing obligation could result in the Company losing its interest in such power generation facility or steam field. See "-- Possible Unavailability of Financing."
In addition, power sales agreements, which are typically entered into with a utility early in the development phase of a project, often enable the utility to terminate such agreement, or to retain security posted as liquidated damages, in the event that a project fails to achieve commercial operation or certain operating levels by specified dates or fails to make certain specified payments. In the event such a termination right is exercised, a project may not commence generating revenues, the default provisions in a financing agreement may be triggered (rendering such debt immediately due and payable) and the project may be rendered insolvent as a result.
GENERAL OPERATING RISKS
The Company currently operates all of the power generation facilities in which it has an interest, except for two steam fields. See "Business -- Description of Facilities." The continued operation of power generation facilities and steam fields involves many risks, including the breakdown or failure of power generation equipment, transmission lines, pipelines or other equipment or processes and performance below expected levels of output or efficiency. To date, the Company's power generation facilities have operated at an average availability in excess of 97%, and although from time to time the Company's power generation facilities and steam fields have experienced certain equipment breakdowns or failures, such breakdowns or failures have not had a material adverse effect on the operation of such facilities or on the Company's results of operations. Although the Company's facilities contain certain redundancies and back-up mechanisms, there can be no assurance that any such breakdown or failure would not prevent the affected facility or steam field from performing under applicable power or steam sales agreements. In addition, although insurance is maintained to protect against certain of these operating risks, the proceeds of such insurance may not be adequate to cover lost revenues or increased expenses, and, as a result, the entity owning such power generation facility or steam field may be unable to service principal and interest payments under its financing obligations and may operate at a loss. A default under such a financing obligation could result in the Company losing its interest in such power generation facility or steam field. See "-- Possible Unavailability of Financing."
DEPENDENCE ON THIRD PARTIES
The nature of the Company's power generation facilities is such that each facility generally relies on one power or steam sales agreement with a single electric utility customer for substantially all, if not all, of such facility's revenue over the life of the project. During 1995, approximately 87% and 9% of the Company's revenue was attributable to revenue received pursuant to power and steam sales agreements with PG&E and Sacramento Municipal Utility District ("SMUD"), respectively. The power and steam sales agreements are generally long-term agreements, covering the sale of electricity or steam for initial terms of 20 or 30 years. However, the loss of any one power or steam sales agreement with any of these utility customers could have a material adverse effect on the Company's results of operations. In addition, any material failure by any utility customer to fulfill its obligations under a power or steam sales agreement could have a material adverse effect on the cash flow available to the Company and, as a result, on the Company's results of operations. During
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1995, an additional 4% of the Company's revenue was attributable to operating and maintenance services performed by the Company for power generation facilities that sell electricity to PG&E.
Furthermore, each power generation facility may depend on a single or limited number of entities to purchase thermal energy, or to supply or transport natural gas to such facility. The failure of any one utility customer, steam host, gas supplier or gas transporter to fulfill its contractual obligations could have a material adverse effect on a power project and on the Company's business and results of operations.
INTERNATIONAL INVESTMENTS
The Company has made an investment in the Cerro Prieto geothermal steam fields located in Mexico and intends to pursue investments primarily in Latin America and Southeast Asia. Such investments are subject to risks and uncertainties relating to the political, social and economic structures of those countries. Risks specifically related to investments in non-United States projects may include risks of fluctuations in currency valuation, currency inconvertibility, expropriation and confiscatory taxation, increased regulation and approval requirements and governmental policies limiting returns to foreign investors.
POWER MARKETING BUSINESS
It is part of the Company's strategy to continue to develop an integrated nationwide power marketing business to market power generated both by the Company's generation facilities and power generated by third parties. The Company believes that this strategy will enhance the earning potential of its operating assets, generate additional revenue and expand its customer base. However, the power marketing industry is only in its early stages of development, and there are no assurances that the industry will develop in such a way as to permit the Company to achieve these goals. Furthermore, the Company has only recently commenced its power marketing business, and there can be no assurance that its power marketing strategy will be successful or that the Company's goals will be achieved.
GOVERNMENT REGULATION
The Company's activities are subject to complex and stringent energy, environmental and other governmental laws and regulations. The construction and operation of power generation facilities require numerous permits, approvals and certificates from appropriate federal, state and local governmental agencies, as well as compliance with environmental protection legislation and other regulations. While the Company believes that it has obtained the requisite approvals for its existing operations and that its business is operated in accordance with applicable laws, the Company remains subject to a varied and complex body of laws and regulations that both public officials and private individuals may seek to enforce. There can be no assurance that existing laws and regulations will not be revised or that new laws and regulations will not be adopted or become applicable to the Company that may have a material adverse effect on the Company's business or results of operations, nor can there be any assurance that the Company will be able to obtain all necessary licenses, permits, approvals and certificates for proposed projects or that completed facilities will comply with all applicable permit conditions, statutes or regulations. In addition, regulatory compliance for the construction of new facilities is a costly and time consuming process, and intricate and changing environmental and other regulatory requirements may necessitate substantial expenditures to obtain permits and may create a significant risk of expensive delays or significant loss of value in a project if the project is unable to function as planned due to changing requirements or local opposition. See "Business -- Government Regulation."
The Company's operations are subject to the provisions of various energy laws and regulations, including PURPA, the Public Utility Holding Company Act of 1935, as amended ("PUHCA"), and state and local regulations. See "Business -- Government Regulation." PUHCA provides for the extensive regulation of public utility holding companies and their subsidiaries. PURPA provides to qualifying facilities ("QFs") and owners of QFs certain exemptions from certain federal and state regulations, including rate and financial regulations.
Under present federal law, the Company is not and will not be subject to regulation as a holding company under PUHCA as long as the power plants in which it has an interest are QFs under PURPA or are subject to
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another exemption. In order to be a QF, a facility must be not more than 50% owned by an electric utility or electric utility holding company. A QF that is a cogeneration facility must produce not only electricity, but also useful thermal energy for use in an industrial or commercial process or heating or cooling applications in certain proportions to the facility's total energy output, and it must meet certain energy efficiency standards. Therefore, loss of a thermal energy customer could jeopardize a cogeneration facility's QF status. All geothermal power plants up to 80 megawatts that meet PURPA's ownership requirements and certain other standards are considered QFs. If one of the power plants in which the Company has an interest were to lose its QF status and not otherwise receive a PUHCA exemption, the project subsidiary or partnership in which the Company has an interest owning or leasing that plant could become a public utility company, which could subject the Company to significant federal, state and local laws, including rate regulation and regulation as a public utility holding company under PUHCA. This loss of QF status, which may be prospective or retroactive, in turn, could cause all of the Company's other power plants to lose QF status because, under FERC regulations, a QF cannot be owned by an electric utility or electric utility holding company. In addition, a loss of QF status could, depending on the power sales agreement, allow the power purchaser to cease taking and paying for electricity or to seek refunds of past amounts paid and thus could cause the loss of some or all contract revenues or otherwise impair the value of a project and could trigger defaults under provisions of the applicable project contracts and financing agreements (rendering such debt immediately due and payable). If a power purchaser ceased taking and paying for electricity or sought to obtain refunds of past amounts paid, there can be no assurance that the costs incurred in connection with the project could be recovered through sales to other purchasers. See "Business -- Government Regulation -- Federal Energy Regulation."
Currently, Congress is considering proposed legislation that would amend PURPA by eliminating the requirement that utilities purchase electricity from QFs at avoided costs. The Company does not know whether such legislation will be passed or what form it may take. The Company believes that if any such legislation is passed, it would apply to new projects. As a result, although such legislation may adversely affect the Company's ability to develop new projects, the Company believes it would not affect the Company's existing QFs. There can be no assurance, however, that any legislation passed would not adversely impact the Company's existing projects.
Many states are implementing or considering regulatory initiatives designed to increase competition in the domestic power generation industry. In a December 20, 1995 policy decision, the CPUC outlined a new market structure that would provide for a competitive power generation industry and direct access to generation for all consumers within five years. As part of its policy decision, the CPUC indicated that power sales agreements of existing QFs would be honored. The Company cannot predict the final form or timing of the proposed restructuring and the impact, if any, that such restructuring would have on the Company's existing business or results of operations.
SEISMIC DISTURBANCES
Areas in which the Company operates and is developing many of its geothermal and gas-fired projects are subject to frequent low-level seismic disturbances, and more significant seismic disturbances are possible. While the Company's existing power generation facilities are built to withstand relatively significant levels of seismic disturbances, and the Company believes it maintains adequate insurance protection, there can be no assurance that earthquake, property damage or business interruption insurance will be adequate to cover all potential losses sustained in the event of serious seismic disturbances or that such insurance will continue to be available to the Company on commercially reasonable terms.
AVAILABILITY OF NATURAL GAS
To date, the Company's fuel acquisition strategy has included various combinations of Company-owned gas reserves, gas prepayment contracts and short-, medium- and long-term supply contracts. In its gas supply arrangements, the Company attempts to match the fuel cost with the fuel component included in the facility's power sales agreements, in order to minimize a project's exposure to fuel price risk. The Company believes that there will be adequate supplies of natural gas available at reasonable prices for each of its facilities when current gas supply agreements expire. There can be no assurance, however, that gas supplies will be available
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for the full term of the facilities' power sales agreements, or that gas prices will not increase significantly. If gas is not available, or if gas prices increase above the fuel component of the facilities' power sales agreements, there could be a material adverse impact on the Company's net revenues.
COMPETITION
The power generation industry is characterized by intense competition, and the Company encounters competition from utilities, industrial companies and other power producers. In recent years, there has been increasing competition in an effort to obtain new power sales agreements, and this competition has contributed to a reduction in electricity prices. In this regard, many utilities often engage in "competitive bid" solicitations to satisfy new capacity demands. This competition adversely affects the ability of the Company to obtain power sales agreements and the price paid for electricity. There also is increasing competition between electric utilities, particularly in California where the CPUC has launched an initiative designed to give all electric consumers the ability to choose between competing suppliers of electricity. See "Business -- Government Regulation -- State Regulation." This competition has put pressure on electric utilities to lower their costs, including the cost of purchased electricity, and increasing competition in the future will increase this pressure. See "Business -- Competition."
DEPENDENCE ON SENIOR MANAGEMENT
The Company's success is largely dependent on the skills, experience and efforts of its senior management. The loss of the services of one or more members of the Company's senior management could have a material adverse effect on the Company's business and development. To date, the Company generally has been successful in retaining the services of its senior management. See "Management."
ANTI-TAKEOVER PROVISIONS
Certain provisions of Delaware law applicable to the Company could have the effect of delaying, deterring or preventing a change in control of the Company, including Section 203 of the Delaware General Corporation Law, which prohibits a Delaware corporation from engaging in any business combination with any interested stockholder for a period of three years from the date the person became an interested stockholder unless certain conditions are met. In addition, the Company's Certificate of Incorporation and By-laws contain certain provisions that could discourage potential takeover attempts and make more difficult attempts by stockholders to change management. The Company's Board of Directors is classified into three classes of directors serving staggered, three-year terms and has the authority without action by the Company's stockholders to fix the rights and preferences and issue shares of Preferred Stock, and to impose various procedural and other requirements that could make it more difficult for stockholders to effect certain corporate actions. The Company's Certificate of Incorporation provides that Directors may be removed only by the affirmative vote of the holders of two-thirds of the shares of capital stock of the Company entitled to vote. Any vacancy on the Board of Directors may be filled only by vote of the majority of Directors then in office. Further, the Company's Certificate of Incorporation provides that any "Business Combination" (as therein defined) requires the affirmative vote of the holders of two-thirds of the shares of capital stock of the Company entitled to vote, voting together as a single class. These provisions, and certain other provisions of the Certificate of Incorporation which may have the effect of delaying proposed stockholder actions until the next annual meeting of stockholders, could have the effect of delaying or preventing a tender offer for the Company's Common Stock or other changes of control or management of the Company, which could adversely affect the market price of the Company's Common Stock. See "Description of Capital Stock."
NO PRIOR MARKET; STOCK PRICE VOLATILITY; DILUTION
Prior to the Common Stock Offering, there has been no public market for the Company's Common Stock. Consequently, the initial public offering price will be determined by negotiations among the Company, the Selling Stockholder and the Representatives of the Underwriters and may not be indicative of the prices that prevail in the public market. There can be no assurance that an active public market for the Common Stock will develop or be sustained after the Common Stock Offering. The trading price of the Company's
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Common Stock could be subject to wide fluctuations in response to quarter-to-quarter variations in operating results, announcements of new acquisitions or power projects by the Company or its competitors, general conditions in the independent power production industry, and other events or factors. In addition, stock markets have experienced extreme price and trading volume volatility in recent years. This volatility has had a substantial effect on the market prices of securities of many companies for reasons frequently unrelated to the operating performance of the specific companies. These broad market fluctuations may adversely affect the market price of the Company's Common Stock. Moreover, investors in the Common Stock Offering will incur immediate, substantial book value dilution. See "Dilution" and "Underwriting."
QUARTERLY FLUCTUATIONS; SEASONALITY
The Company's quarterly operating results have fluctuated in the past and may continue to do so in the future as a result of a number of factors, including but not limited to the timing and size of acquisitions, the completion of development projects, the timing and amount of curtailment, and variations in levels of production. Furthermore, the majority of capacity payments under certain of the Company's power sales agreements are received during the months of May through October. The market price of the Common Stock could be subject to significant fluctuations in response to those variations in quarterly operating results and other factors. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Quarterly Results of Operations and Seasonality."
SHARES ELIGIBLE FOR FUTURE SALE
Sales of substantial amounts of Common Stock in the public market after the Common Stock Offering could adversely affect the prevailing market price of the Common Stock. Other than the 18,045,000 shares of Common Stock offered hereby, there will be no shares of Common Stock outstanding immediately following the completion of the Common Stock Offering. All of the shares of Common Stock sold in the Common Stock Offering will be freely transferable without registration or further registration under the Securities Act of 1933, as amended (the "Securities Act"), unless held by an "affiliate" of the Company (as defined in the Securities Act). As of the date of this Prospectus, options to purchase 2,392,026 shares of Common Stock were outstanding under the Company's Stock Option Program. Of such amount, options to purchase 1,366,696 shares were exercisable, all of which will become eligible for sale 180 days after the date of this Prospectus, upon expiration of certain lock-up agreements with the Underwriters and pursuant to Rule 701, subject in some cases to certain volume and other resale restrictions. See "Shares Eligible for Future Sale."
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USE OF PROCEEDS
The aggregate net proceeds to the Company from the sale of the 5,477,820 shares of Common Stock offered by the Company in the Common Stock Offering (assuming an initial public offering price of $18.50 per share and after deducting underwriting discounts and commissions and estimated offering expenses), are estimated to be approximately $94.8 million ($142.1 million if the Underwriters' over-allotment option is exercised in full). The Company expects to use a portion of the net proceeds from the Common Stock Offering to repay the outstanding balance on the Credit Suisse Credit Facility. The outstanding balance is approximately $13.0 million as of the date of this Prospectus and bears interest at 6.0% per annum. The remaining net proceeds are expected to be used for working capital and general corporate purposes, and for the development and acquisition of power generation facilities, including investments in the Pasadena Cogeneration Project and the Indonesian Geothermal Project. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources" and "Business -- Development and Future Projects." Pending such uses, the Company expects to invest the net proceeds in short-term, interest-bearing securities.
DIVIDEND POLICY
The Company does not anticipate paying any cash dividends on its Common Stock in the foreseeable future because it intends to retain its earnings to finance the expansion of its business and for general corporate purposes. In addition, the Company's ability to pay cash dividends is restricted under the Indentures and will be restricted under the Bank of Nova Scotia Facility. Future cash dividends, if any, will be at the discretion of the Company's Board of Directors and will depend upon, among other things, the Company's future operations and earnings, capital requirements, general financial condition, contractual restrictions and such other factors as the Board of Directors may deem relevant.
17

CAPITALIZATION
The following table sets forth, as of June 30, 1996: (i) the actual consolidated capitalization of the Company; (ii) the pro forma consolidated capitalization of the Company after giving effect to the Gilroy Transaction and the conversion of the Company's outstanding Preferred Stock into Common Stock upon the completion of the Common Stock Offering; and (iii) the pro forma as adjusted consolidated capitalization of the Company after giving effect to the sale of the shares of Common Stock offered by the Company hereby at an assumed initial public offering price of $18.50 per share and the application of the estimated net proceeds therefrom (after deducting underwriting discounts and commissions). This table should be read in conjunction with "Pro Forma Consolidated Financial Data" and the consolidated financial statements and related notes thereto appearing elsewhere in this Prospectus.

                                                                    AS OF JUNE 30, 1996
                                                        --------------------------------------------
                                                                                          PRO FORMA
                                                         ACTUAL         PRO FORMA        AS ADJUSTED
                                                        --------       -----------       -----------
                                                                       (IN THOUSANDS)
Short-term debt:
  Current portion of non-recourse project
     financing.......................................   $ 27,178        $  27,178         $  27,178
                                                        ========        =========         =========
Long-term debt:
  Long-term line of credit...........................         --               --                --
  Non-recourse long-term project financing, less
     current portion.................................   $180,974        $ 296,974         $ 296,974
  Notes payable......................................      6,598            6,598             6,598
  Senior notes.......................................    285,000          285,000           285,000
                                                        --------       -----------       -----------
     Total long-term debt............................    472,572          588,572           588,572
                                                        --------       -----------       -----------
Stockholder's equity:
  Preferred Stock, $.001 par value: 5,000,000 shares
     authorized and outstanding; pro forma and pro
     forma as adjusted, 10,000,000 shares authorized,
     no shares outstanding...........................          5               --                --
  Common Stock, $.001 par value: 33,760,000 shares
     authorized, 10,387,693 shares outstanding; pro
     forma, 33,760,000 shares authorized, 12,567,180
     shares outstanding; pro forma as adjusted,
     100,000,000 shares authorized, 18,045,000 shares
     outstanding(1)..................................         10               13                18
  Additional paid-in capital.........................     56,209           56,211           151,036
  Retained earnings..................................     23,463           23,463            23,463
  Cumulative translation adjustment..................        (31)             (31)              (31)
                                                        --------       -----------       -----------
     Total stockholder's equity......................     79,656           79,656           174,486
                                                        --------       -----------       -----------
       Total capitalization..........................   $552,228        $ 668,228         $ 763,058
                                                        ========        =========         =========	

(1) Does not include 2,392,026 shares of Common Stock reserved for issuance upon exercise of options previously granted and outstanding as of June 30, 1996 under the Company's Stock Option Program. See "Management -- Stock Option Program" and "-- 1996 Stock Incentive Plan."
18

DILUTION
The net tangible book value of the Company as of June 30, 1996 was $69.7 million, or $5.55 per share of Common Stock. Net tangible book value per share is equal to the Company's total assets (excluding deferred financing and offering expenses) less its total liabilities, divided by the total number of outstanding shares of Common Stock. After giving effect to the sale of 5,477,820 shares of Common Stock offered by the Company hereby (at an assumed initial public offering price of $18.50 per share), and the receipt and application of the net proceeds therefrom, the pro forma net tangible book value of the Company as of June 30, 1996 would have been approximately $164.5 million or $9.12 per share. This represents an immediate dilution of $9.38 per share to new stockholders purchasing shares in the Common Stock Offering. The following table illustrates this per share dilution:

Assumed initial public offering price.....................              $18.50
  Net tangible book value before the Common Stock
     Offering.............................................    $5.55
  Increase attributable to new stockholders...............     3.57
                                                              -----
Pro forma net tangible book value after the Common Stock
  Offering................................................                9.12
                                                                        ------
Total dilution to new stockholders........................              $ 9.38
                                                                        ======	

The calculations in the table set forth above assume no exercise of the Underwriters' over-allotment option and do not reflect 2,392,026 shares of Common Stock reserved for issuance pursuant to options granted and outstanding as of June 30, 1996 under the Company's Stock Option Program. See "Management -- Stock Option Program" and "-- 1996 Stock Incentive Plan."
19

SELECTED CONSOLIDATED FINANCIAL DATA
The consolidated financial data set forth below for and as of the five years ended December 31, 1995 have been derived from the audited consolidated financial statements of the Company. The consolidated financial data for the six months ended June 30, 1995 and June 30, 1996 and as of June 30, 1996 are unaudited, but have been prepared on the same basis as the audited consolidated financial statements and, in the opinion of management, contain all adjustments, consisting only of normal recurring adjustments necessary for the fair presentation of the financial position and results of operations for these periods. Consolidated operating results for the six months ended June 30, 1996 are not necessarily indicative of the results that may be expected for the entire year. The following selected consolidated financial data should be read in conjunction with the consolidated financial statements and the related notes thereto appearing elsewhere in this Prospectus, and "Management's Discussion and Analysis of Financial Condition and Results of Operations."

                                                                                                          SIX MONTHS ENDED
                                                            YEAR ENDED DECEMBER 31,                           JUNE 30,
                                            --------------------------------------------------------     -------------------
                                             1991        1992        1993        1994         1995        1995        1996
                                            -------     -------     -------     -------     --------     -------     -------
                                                                    (DOLLARS AND SHARES IN THOUSANDS, EXCEPT PER SHARE DATA)
STATEMENT OF OPERATIONS DATA:
Revenue:
  Electricity and steam sales.............       --          --     $53,000     $90,295     $127,799     $49,014     $72,030
  Service contract revenue................  $29,067     $29,817      16,896       7,221        7,153       3,129       5,434
  Income (loss) from unconsolidated
    investments in power projects.........    9,985       9,760          19      (2,754)      (2,854)     (1,791)      1,713
  Interest income on loans to power
    projects..............................       --          --          --          --           --          --       2,817
                                            --------    --------    --------    --------    --------     --------    --------
    Total revenue.........................   39,052      39,577      69,915      94,762      132,098      50,352      81,994
Cost of revenue...........................   25,064      25,921      42,501      52,845       77,388      30,618      51,319
                                            --------    --------    --------    --------    --------     --------    --------
Gross profit..............................   13,988      13,656      27,414      41,917       54,710      19,734      30,675
Project development expenses..............    1,067         806       1,280       1,784        3,087       1,308       1,410
General and administrative expenses.......    3,443       3,924       5,080       7,323        8,937       3,659       5,874
Compensation expense related to stock
  options(1)..............................       --       1,224          --          --           --          --          --
Provision for write-off of project
  development costs(2)....................       --         800          --       1,038           --          --          --
                                            --------    --------    --------    --------    --------     --------    --------
Income from operations....................    9,478       6,902      21,054      31,772       42,686      14,767      23,391
Interest expense..........................    1,925       1,225      13,825      23,886       32,154      15,116      18,665
Other income, net.........................     (416)       (310)     (1,133)     (1,988)      (1,895)       (855)     (2,777)
                                            --------    --------    --------    --------    --------     --------    --------
    Income before provision for income
      taxes, extraordinary item and
      cumulative effect of change in
      accounting
      principle...........................    7,969       5,987       8,362       9,874       12,427         506       7,503
Provision for income taxes................    3,149       2,527       4,195       3,853        5,049         208       3,080
                                            --------    --------    --------    --------    --------     --------    --------
    Income before extraordinary item and
      cumulative effect of change in
      accounting principle................    4,820       3,460       4,167       6,021        7,378         298       4,423
Extraordinary item:
  Utilization of net operating loss
    carryforward..........................    1,138          --          --          --           --          --          --
                                            --------    --------    --------    --------    --------     --------    --------
    Income before cumulative effect of
      change in accounting principle......    5,958       3,460       4,167       6,021        7,378         298       4,423
Cumulative effect of adoption of SFAS No.
  109.....................................       --          --        (413)         --           --          --          --
                                            --------    --------    --------    --------    --------     --------    --------
        Net income........................  $ 5,958     $ 3,460     $ 3,754     $ 6,021     $  7,378     $   298     $ 4,423
                                            ========    ========    ========    ========    ========     ========    ========
Weighted average shares outstanding(3)....                                                    14,187                  14,476
                                                                                            ========                 ========
Net income per share(3)...................                                                  $   0.52                 $  0.31
                                                                                            ========                 ========
OTHER FINANCIAL DATA:
  Depreciation and amortization...........  $   219     $   232     $12,540     $21,580     $ 26,896     $ 9,882     $15,757
  EBITDA(4)...............................  $ 4,909     $ 9,898     $42,370     $53,707     $ 69,515     $25,440     $41,345	

(See footnotes on next page)
20

                                                                   AS OF DECEMBER 31,
                                               ----------------------------------------------------------     AS OF JUNE 30,
                                                1991        1992         1993         1994         1995            1996
                                               -------     -------     --------     --------     --------     --------------
                                               (IN THOUSANDS)
BALANCE SHEET DATA:
Cash and cash equivalents..................    $   958     $ 2,160     $  6,166     $ 22,527     $ 21,810        $ 38,403
Property, plant and equipment, net.........        351         424      251,070      335,453      447,751         530,203
Total assets...............................     41,245      55,370      302,256      421,372      554,531         792,812
Total liabilities..........................     34,624      44,865      288,827      402,723      529,304         713,156
Stockholder's equity.......................      6,621      10,505       13,429       18,649       25,227          79,656	

(1) Represents a non-cash charge for compensation expense associated with the grant of certain options under the Company's Stock Option Program. See "Management -- Stock Option Program."
(2) Represents a write-off of certain capitalized project costs.
(3) The weighted average shares outstanding and earnings per share for the year ended December 31, 1995 and the six months ended June 30, 1996 give effect to the issuance of Common Stock upon the conversion of the Company's outstanding Preferred Stock.
(4) EBITDA is defined as income from operations plus depreciation, capitalized interest, other income, non-cash charges and cash received from investments in power projects, reduced by the income from unconsolidated investments in power projects. EBITDA is presented not as a measure of operating results but rather as a measure of the Company's ability to service debt. EBITDA should not be construed as an alternative either (i) to income from operations (determined in accordance with generally accepted accounting principles) or (ii) to cash flows from operating activities (determined in accordance with generally accepted accounting principles).
21

PRO FORMA CONSOLIDATED FINANCIAL DATA
The following unaudited pro forma consolidated statement of operations for the year ended December 31, 1995 gives effect to: (i) the Transactions; (ii) the Preferred Stock Investment and the application of the proceeds therefrom; and
(iii) the sale of the 10 1/2% Senior Notes and the application of the net proceeds therefrom as if such transactions had occurred on January 1, 1995. The following unaudited pro forma consolidated statement of operations for the six months ended June 30, 1996 gives effect to: (i) the King City Transaction; (ii) the Gilroy Transaction; and (iii) the sale of the 10 1/2% Senior Notes and the application of the net proceeds therefrom, as if such transactions had occurred on January 1, 1996. For further discussion regarding the Transactions, see "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Business -- Description of Facilities." The following unaudited pro forma consolidated balance sheet as of June 30, 1996 gives effect to the Gilroy Transaction as if such transaction had occurred on June 30, 1996. The following unaudited pro forma consolidated financial data does not give effect to the Common Stock Offering or the application of the net proceeds therefrom.
The pro forma consolidated financial data and accompanying notes should be read in conjunction with the consolidated financial statements and related notes thereto appearing elsewhere in this Prospectus. The pro forma adjustments are based upon available information and certain assumptions that management believes are reasonable and are described in the notes accompanying the pro forma consolidated financial data. The pro forma consolidated financial data are presented for informational purposes only and do not purport to represent what the Company's results of operations or financial position would actually have been had such transactions in fact occurred at such dates, or to project the Company's results of operations or financial position at any future date or for any future period. In the opinion of management, all adjustments necessary to present fairly such pro forma consolidated financial data have been made.
22

PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS

                                                                 YEAR ENDED DECEMBER 31, 1995
                                            ----------------------------------------------------------------------
                                                                                                PRO FORMA FOR THE
                                                                                                TRANSACTIONS, THE
                                                                                                 PREFERRED STOCK
                                                       ADJUSTMENTS FOR THE      ADJUSTMENTS     INVESTMENT AND THE
                                                       TRANSACTIONS AND THE    FOR THE SALE        SALE OF THE
                                                         PREFERRED STOCK      OF THE 10 1/2%      10 1/2% SENIOR
                                             ACTUAL       INVESTMENT(1)        SENIOR NOTES           NOTES
                                            --------   --------------------   ---------------   ------------------
                                            (DOLLARS IN THOUSANDS, EXCEPT PER SHARE DATA)
STATEMENT OF OPERATIONS DATA:
Revenue:
  Electricity and steam sales.............  $127,799         $ 89,349                  --            $217,148
  Service contract revenue................     7,153              250                  --               7,403
  Income (loss) from unconsolidated
    investments in power projects.........    (2,854)              --                  --              (2,854)
  Interest income on loans to power
    projects..............................        --            2,564                  --               2,564
                                            --------         --------         ---------------      ----------
    Total revenue.........................   132,098           92,163                  --             224,261
                                            --------         --------         ---------------      ----------
Cost of revenue:
  Plant operating expenses................    33,162           37,369                  --              70,531
  Depreciation and amortization...........    26,264           15,838                  --              42,102
  Operating lease expense.................     1,542           11,703                  --              13,245
  Service contract expense................     5,846               --                  --               5,846
  Production royalties....................    10,574               --                  --              10,574
                                            --------         --------         ---------------      ----------
    Total cost of revenue.................    77,388           64,910                  --             142,298
                                            --------         --------         ---------------      ----------
Gross profit..............................    54,710           27,253                  --              81,963
Project development expenses..............     3,087               --                  --               3,087
General and administrative expenses.......     8,937               --                  --               8,937
                                            --------         --------         ---------------      ----------
    Income from operations................    42,686           27,253                  --              69,939
Interest expense..........................    32,154           16,193             $ 9,176(2)           57,523
Other income, net.........................    (1,895)          (7,263)                 --              (9,158)
                                            --------         --------         ---------------      ----------
  Income before provision for income
    taxes.................................    12,427           18,323              (9,176)             21,574
Provision for income taxes................     5,049            7,443              (3,728)              8,764
                                            --------         --------         ---------------      ----------
      Net income..........................  $  7,378         $ 10,880             $(5,448)           $ 12,810
                                            =========  ==================     ==============    ==================
      Net income per share................  $   0.52                                                 $   0.90
                                            =========                                           ==================
OTHER FINANCIAL DATA:
Depreciation and amortization.............  $ 26,896                                                 $ 42,734
EBITDA....................................  $ 69,515                                                 $123,770	

See Notes to Pro Forma Consolidated Statements of Operations
23

PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS

                                                             SIX MONTHS ENDED JUNE 30, 1996
                                -----------------------------------------------------------------------------------------
                                                                                                      PRO FORMA FOR THE
                                                                                                          KING CITY
                                                                                     ADJUSTMENTS        TRANSACTION,
                                              ADJUSTMENTS          ADJUSTMENTS         FOR THE           THE GILROY
                                                FOR THE              FOR THE         SALE OF THE       TRANSACTION AND
                                               KING CITY             GILROY            10 1/2%         THE SALE OF THE
                                ACTUAL     TRANSACTION(3)(5)    TRANSACTION(4)(5)   SENIOR NOTES    10 1/2% SENIOR NOTES
                                -------   -------------------   -----------------   -------------   ---------------------
                                                      (DOLLARS IN THOUSANDS, EXCEPT PER SHARE DATA)
STATEMENT OF OPERATIONS DATA:
Revenue:
  Electricity and steam
    sales.....................  $72,030         $ 1,583              $ 9,491                --             $83,104
  Service contract revenue....    5,434              --                   --                --               5,434
  Income (loss) from
    unconsolidated investments
    in power projects.........    1,713              --                   --                --               1,713
  Interest income on loans to
    power
    projects..................    2,817              --                   --                --               2,817
                                -------         -------              -------          --------              ------
    Total revenue.............   81,994           1,583                9,491                --              93,068
                                -------         -------              -------          --------              ------
Cost of revenue:
  Plant operating expenses....   22,901           1,669                4,035                --              28,605
  Depreciation and
    amortization..............   15,413           2,800                2,745                --              20,958
  Operating lease expense.....    3,239           3,372                   --                --               6,611
  Service contract expense....    4,484              --                   --                --               4,484
  Production royalties........    5,282              --                   --                --               5,282
                                -------         -------              -------          --------              ------
    Total cost of revenue.....   51,319           7,841                6,780                --              65,940
                                -------         -------              -------          --------              ------
Gross profit..................   30,675          (6,258)               2,711                --              27,128
Project development
  expenses....................    1,410              --                   --                --               1,410
General and administrative
  expenses....................    5,874              --                   --                --               5,874
                                -------         -------              -------          --------              ------
    Income from operations....   23,391          (6,258)               2,711                --              19,844
Interest expense..............   18,665           1,391                4,585           $ 3,259(6)           27,900
Other income, net.............   (2,777)         (2,526)                  --                --              (5,303)
                                -------         -------              -------          --------              ------
    Income (loss) before
      provision for income
      taxes...................    7,503          (5,123)              (1,874)           (3,259)             (2,753)
Provision for (benefit from)
  income taxes................    3,080          (2,103)                (769)           (1,338)             (1,130)
                                -------         -------              -------          --------              ------
         Net income (loss)....  $ 4,423         $(3,020)             $(1,105)          $(1,921)            $(1,623)
                                =======         =======              =======          ========              ======
         Net income (loss) per
           share..............  $  0.31                                                                    $ (0.11)
                                =======                                                                     ======
OTHER FINANCIAL DATA:
Depreciation and
  amortization................  $15,757                                                                    $21,302
EBITDA........................  $41,345                                                                    $46,993	

See Notes to Pro Forma Consolidated Statements of Operations
24

NOTES TO PRO FORMA CONSOLIDATED STATEMENTS OF OPERATIONS
(1) Represents the pro forma results of operations for the facilities involved in the Transactions for the periods during 1995 prior to the completion of the Transactions, as if the Transactions had been completed on January 1, 1995, including: (i) the Greenleaf 1 and 2 Facilities for the period through April 21, 1995; (ii) the Watsonville Facility for the period through June 28, 1995; (iii) the Cerro Prieto Steam Fields for the period through December 14, 1995; (iv) the King City Facility for the period through December 31, 1995; and (v) the Gilroy Facility for the period through December 31, 1995. The information provided for the Cerro Prieto Steam Fields does not include the portion of service contract revenue which is contingent on future results. The pro forma adjustments reflect the historical results of operations of the facilities, as adjusted to give effect to the changes resulting from purchase price allocations and other transaction effects, as applicable. Such adjustments include depreciation and amortization applicable to new asset bases, interest expense amounts applicable to debt instruments outstanding, income tax amounts at the estimated effective rate of approximately 41%, and other adjustments. The following table sets forth adjustments to results of operations for such periods:

                                                 GREENLEAF
                                                  1 AND 2    WATSONVILLE   CERRO PRIETO   KING CITY    GILROY
                                                 FACILITIES   FACILITY     STEAM FIELDS   FACILITY    FACILITY    TOTAL
                                                 ---------   -----------   ------------   ---------   --------   -------
                                                                                                          (IN THOUSANDS)
STATEMENT OF OPERATIONS DATA:
Revenue:
  Electricity and steam sales..................   $ 5,314      $ 3,978            --       $43,836    $ 36,221   $89,349
  Service contract revenue.....................        --           --        $  250            --          --       250
  Income (loss) from unconsolidated investments
    in power projects..........................        --           --            --            --          --        --
  Interest income on loans to power projects...        --           --         2,564            --          --     2,564
                                                  -------       ------        ------       -------     -------
    Total revenue..............................     5,314        3,978         2,814        43,836      36,221    92,163
                                                  -------       ------        ------       -------     -------
Cost of revenue:
  Plant operating expenses.....................     5,954        2,857            --        14,743      13,815    37,369
  Depreciation and amortization................     1,802          147            --         8,399       5,490    15,838
  Operating lease expense......................        --        1,586            --        10,117          --    11,703
  Service contract expense.....................        --           --            --            --          --        --
  Production royalties.........................        --           --            --            --          --        --
                                                  -------       ------        ------       -------     -------
    Total cost of revenue......................     7,756        4,590            --        33,259      19,305    64,910
                                                  -------       ------        ------       -------     -------
Gross profit...................................    (2,442)        (612)        2,814        10,577      16,916    27,253
Project development expenses...................        --           --            --            --          --        --
General and administrative expenses............        --           --            --            --          --        --
                                                  -------       ------        ------       -------     -------
    Income from operations.....................    (2,442)        (612)        2,814        10,577      16,916    27,253
Interest expense...............................     1,921           --           932         4,172       9,168    16,193
Other income, net..............................      (105)          --            --        (7,158)         --    (7,263)
                                                  -------       ------        ------       -------     -------
    Income before provision for income taxes...    (4,258)        (612)        1,882        13,563       7,748    18,323
Provision (benefit) for income taxes...........    (1,730)        (249)          765         5,509       3,148     7,443
                                                  -------       ------        ------       -------     -------
        Net income.............................   $(2,528)     $  (363)       $1,117       $ 8,054    $  4,600   $10,880
                                                  =======       ======        ======       =======     =======	

The adjustments reflected in the table set forth above for the Greenleaf 1 and 2 Facilities and the Watsonville Facility are not necessarily indicative of a full year's results. See "Risk Factors -- Quarterly Fluctuations; Seasonality." Other income, net for the King City Facility reflects interest income from amounts contractually invested pursuant to collateral fund requirements. See "Business -- Description of Facilities -- Power Generation Facilities -- King City Facility."
(2) Reflects $18.9 million of interest expense related to the 10 1/2% Senior Notes and $540,000 of amortization expense for the costs associated with the sale of the 10 1/2% Senior Notes, reduced by $4.4 million of actual
25

interest expense in 1995 as a result of the repayment of the $57 million loan from The Bank of Nova Scotia to Calpine Thermal Company, a wholly-owned subsidiary of the Company (the "$57 Million Bank of Nova Scotia Loan"), $3.4 million of interest expense as a result of the repayment of the $45 million loan from The Bank of Nova Scotia to the Company (the "$45 Million Bank of Nova Scotia Loan") (assuming an interest rate of 7.5%) and $2.4 million of interest expense as a result of the repayment of all amounts outstanding under the Credit Suisse Credit Facility. The $2.4 million represents $704,000 of actual interest expense in 1995 and $1.7 million of assumed interest expense to fund the King City and Cerro Prieto Transactions (assuming an interest rate of 6.0%).
(3) Represents the pro forma results of operations for the King City Facility for the period of January 1 through April 30, 1996. Other income, net for the King City Facility reflects interest income from amounts contractually invested pursuant to collateral fund requirements. See "Business -- Description of Facilities -- Power Generation Facilities -- King City Facility."
(4) Represents the pro forma results of operations for the Gilroy Facility for the period of January 1 through June 30, 1996.
(5) Results for the six months ended June 30, 1996 reflected in the Pro Forma Consolidated Statement of Operations are not necessarily indicative of a full year's results. See "Risk Factors -- Quarterly Fluctuations; Seasonality."
(6) Reflects $7.0 million of interest expense related to the 10 1/2% Senior Notes and $201,000 of amortization expense for the costs associated with the sale of the 10 1/2% Senior Notes, reduced by $1.9 million of actual interest expense as a result of the repayment of the $57 Million Bank of Nova Scotia Loan, $1.1 million of interest expense as a result of the repayment of the $45 Million Bank of Nova Scotia Loan (assuming an interest rate of 7.5%) and $973,000 of interest expense as a result of the repayment of all amounts outstanding under the Credit Suisse Credit Facility. The $973,000 represents $707,000 of actual interest expense and $266,000 of assumed interest expense to fund a portion of the King City Transaction (assuming an interest rate of 6.0%).
26

PRO FORMA CONSOLIDATED BALANCE SHEET

                                                                           AS OF JUNE 30, 1996
                                                               -------------------------------------------
                                                                          ADJUSTMENTS        PRO FORMA
                                                                            FOR THE           FOR THE
                                                                             GILROY           GILROY
                                                                ACTUAL    TRANSACTION       TRANSACTION
                                                               --------   ------------   -----------------
                                                                            (IN THOUSANDS)
ASSETS
Current assets:
  Cash and cash equivalents..................................  $ 38,403     $(22,356)(1)     $  16,047
  Accounts receivable........................................    43,227        9,000(2)         52,227
  Collateral securities, current portion.....................     9,745           --             9,745
  Other current assets.......................................    13,369           --            13,369
                                                               --------   ------------   -----------------
    Total current assets.....................................   104,744      (13,356)           91,388
Property, plant and equipment, net...........................   530,203      127,521(3)        657,724
Investments in power projects................................    12,693           --            12,693
Notes receivable.............................................    37,386           --            37,386
Collateral securities, net of current portion................    88,669           --            88,669
Other assets.................................................    19,117        4,000(4)         23,117
                                                               --------   ------------   -----------------
    Total assets.............................................  $792,812     $118,165         $ 910,977
                                                               =========  =============  ==================
LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities:
  Current portion of non-recourse project financing..........  $ 27,178     $     --         $  27,178
  Other current liabilities..................................    25,680        2,165(5)         27,845
                                                               --------   ------------   -----------------
    Total current liabilities................................    52,858        2,165            55,023
Long-term credit facility....................................        --           --                --
Non-recourse long-term project financing, less current
  portion....................................................   180,974      116,000(6)        296,974
Notes payable................................................     6,598           --             6,598
Senior Notes Due 2004........................................   105,000           --           105,000
Senior Notes Due 2006........................................   180,000           --           180,000
Deferred lease incentive.....................................    81,495           --            81,495
Deferred income taxes, net...................................   100,068           --           100,068
Other liabilities............................................     6,163           --             6,163
                                                               --------   ------------   -----------------
    Total liabilities........................................   713,156      118,165           831,321
                                                               --------   ------------   -----------------
Stockholder's equity:
  Preferred stock............................................    50,000           --            50,000
  Common stock...............................................     6,224           --             6,224
  Retained earnings..........................................    23,463           --            23,463
  Cumulative translation adjustment..........................       (31)          --               (31)
                                                               --------   ------------   -----------------
    Total stockholder's equity...............................    79,656           --            79,656
                                                               --------   ------------   -----------------
    Total liabilities and stockholder's equity...............  $792,812     $118,165         $ 910,977
                                                               =========  =============  ==================	

See Notes to Pro Forma Consolidated Balance Sheet
27

NOTES TO PRO FORMA CONSOLIDATED BALANCE SHEET
(1) Represents the cash required to finance, in part, the Gilroy Transaction.
(2) Represents the accounts receivable in the Gilroy Transaction.
(3) Represents the property, plant and equipment acquired in the Gilroy Transaction.
(4) Represents debt reserve amount.
(5) Represents the accounts payable and accrued liabilities in the Gilroy Transaction.
(6) Project financing required to finance, in part, the Gilroy Transaction.
28

MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion should be read in conjunction with, and is qualified in its entirety by reference to, the consolidated financial statements of the Company, including the notes thereto, appearing elsewhere in this Prospectus.
GENERAL
Calpine is engaged in the acquisition, development, ownership and operation of power generation facilities and the sale of electricity and steam in the United States and selected international markets. The Company has interests in 15 power generation facilities and steam fields having an aggregate capacity of 1,057 megawatts. Since its inception in 1984, Calpine has developed substantial expertise in all aspects of electric power generation. The Company's vertical integration has resulted in significant growth over the last five years as Calpine has applied its extensive engineering, construction management, operations, fuel management and financing capabilities to successfully implement its acquisition and development program. During the last five years, Calpine has expanded substantially, from $41.2 million of total assets as of December 31, 1991 to $911.0 million of total assets on a pro forma basis as of June 30, 1996. Calpine's revenue on a pro forma basis for 1995 increased to $224.3 million, representing a compound annual growth rate of 55% since 1991. The Company's EBITDA on a pro forma basis for 1995 increased to $123.8 million. See "Pro Forma Consolidated Financial Data."
On September 9, 1994, the Company acquired Thermal Power Company, which owns a 25% undivided interest in certain steam fields at The Geysers steam fields in northern California (the "Geysers") with a total capacity of 604 megawatts for a purchase price of $66.5 million. In January 1995, the Company purchased the working interest in certain of the geothermal properties at the PG&E Unit 13 and Unit 16 Steam Fields from a third party for a purchase price of $6.75 million. On April 21, 1995, the Company acquired the stock of certain companies that own 100% of the Greenleaf 1 and 2 Facilities, consisting of two 49.5 megawatt natural gas-fired cogeneration facilities, for an adjusted purchase price of $81.5 million. On June 29, 1995, the Company acquired the operating lease for the Watsonville Facility, a 28.5 megawatt natural gas-fired cogeneration facility, for a purchase price of $900,000. On November 17, 1995, the Company entered into a series of agreements to invest up to $20.0 million in the Cerro Prieto Steam Fields. In April 1996, the Company entered into a transaction involving a lease for the 120 megawatt King City Facility, which required an investment of $108.3 million, primarily related to the collateral fund requirements. On August 29, 1996, the Company acquired the 120 megawatt Gilroy Facility for a purchase price of $125.0 million plus certain contingent consideration, which the Company currently estimates will amount to approximately $24.1 million. See "Business -- Description of Facilities."
Each of the power generation facilities produces electricity for sale to a utility. Thermal energy produced by the gas-fired cogeneration facilities is sold to governmental and industrial users, and steam produced by the geothermal steam fields is sold to utility-owned power plants. The electricity, thermal energy and steam generated by these facilities are typically sold pursuant to long-term take-and-pay power or steam sales agreements generally having original terms of 20 or 30 years.
Each of the Company's power and steam sales agreements contains curtailment provisions under which the purchasers of energy or steam are entitled to reduce the number of hours of energy or amount of steam purchased thereunder. During 1995, certain of the Company's power generation facilities experienced maximum curtailment primarily as a result of low gas prices and a high degree of precipitation during the period, which resulted in high levels of energy generation by hydroelectric power facilities that supply electricity. The Company expects maximum curtailment during 1996 under its power sales agreements for certain of its facilities. See "Business -- Description of Facilities."
Many states are implementing or considering regulatory initiatives designed to increase competition in the domestic power generation industry. In December 1995, the CPUC issued an electric industry restructuring decision which envisions commencement of deregulation and implementation of customer choice of electricity supplier by January 1, 1998. As part of its policy decision, the CPUC indicated that power sales
29

agreements of existing QFs would be honored. The Company cannot predict the final form or timing of the proposed restructuring and the impact, if any, that such restructuring would have on the Company's existing business or results of operations. The Company believes that any such restructuring would not have a material effect on its power sales agreements and, accordingly, believes that its existing business and results of operations would not be materially affected, although there can be no assurance in this regard.
Electricity and steam sales represents the sale of electricity and geothermal steam from the Company's majority-owned facilities to utilities under the terms and conditions of long-term power and steam sales agreements. Revenue attributable to the West Ford Flat Facility, the Bear Canyon Facility, the Greenleaf 1 and 2 Facilities, the Watsonville Facility, the King City Facility, the Gilroy Facility, the PG&E Unit 13 and Unit 16 Steam Fields, the Thermal Power Company Steam Fields and the SMUDGEO #1 Steam Fields is included in electricity and steam sales. See "Business -- Description of Facilities."
Service contract revenue consists of revenue earned on services performed under operating and maintenance agreements for projects that are not consolidated in the Company's consolidated financial statements. The Company recognizes revenue on these agreements at the time services are performed.
Income from unconsolidated investments in power projects represents the Company's share of income from projects that are not consolidated in the Company's consolidated financial statements and, accordingly, are accounted for under the equity method of accounting. The Company's share of income from such projects is calculated according to the Company's equity ownership or in accordance with the terms of the appropriate partnership agreement. The Company's current investments which are accounted for under the equity method consist of the Aidlin Facility, the Agnews Facility and the Sumas Facility.
Depreciation and amortization expense for natural gas-fired cogeneration facilities is computed using a straight-line method over the estimated remaining useful life. Depreciation and amortization expense also reflects the amortization of the Company's geothermal power generation facilities and steam fields using the units of production method of depreciation. The Company capitalizes all capital costs related to the operating power plants and steam fields, as well as the cost of drilling wells and estimated future development and de-commissioning costs. These capital costs are then amortized using the units of production method based on current production over the estimated useful life of the geothermal resource. It is reasonably possible that the estimate of useful lives, total units of production or total capital costs to be amortized using the units of production method could differ materially in the near term from the amounts assumed in arriving at current depreciation and amortization expense.
Capitalized project costs are costs related to the development or acquisition of new projects which are capitalized upon the execution of a memorandum of understanding or a power sales agreement. Upon the start-up of plant operations or the completion of an acquisition, such costs are generally transferred to property, plant and equipment and amortized over the estimated useful life of the project. As of June 30, 1996, the Company had deferred $2.8 million of development costs associated with projects currently in the development stage.
General and administrative expenses include administrative, accounting, finance, legal, human resources, insurance and other expenses incurred in connection with the Company's operations. In addition, general and administrative expenses also include the expenses associated with management of the Company's operating and maintenance agreements and the expenses incurred in the management of the Company's project investments.
Provision for income taxes includes income taxes calculated at the effective rate for each applicable period reflecting statutory rates and as adjusted for percentage depletion in excess of basis and other items.
SELECTED OPERATING INFORMATION
Set forth below is certain selected operating information for the power generation facilities and steam fields, for which results are consolidated in the Company's statements of operations. The information set forth under power plants consists of the results for the West Ford Flat Facility, the Bear Canyon Facility, the
30

Greenleaf 1 and 2 Facilities and the Watsonville Facility since their acquisitions on April 21, 1995 and June 29, 1995, respectively, and the King City Facility subsequent to May 2, 1996. The information set forth under steam fields consists of the results for the PG&E Unit 13 and Unit 16 Steam Fields, the SMUDGEO #1 Steam Fields and, for 1994 and 1995, the Thermal Power Company Steam Fields since the acquisition of Thermal Power Company on September 9, 1994. The information provided for the other interest included under steam revenue prior to 1995 represents revenue attributable to a working interest that was held by a third party in the PG&E Unit 13 and Unit 16 Steam Fields. In January 1995, the Company purchased this working interest. Prior to the Company's acquisition of the remaining interest in the West Ford Flat Facility, Bear Canyon Facility, the PG&E Unit 13 and Unit 16 Steam Fields and the SMUDGEO #1 Steam Fields in April 1993, the Company's revenue from these facilities was accounted for under the equity method and, therefore, does not represent the actual revenue of the Company from these facilities for the periods set forth below. See "-- General."

                                              YEAR ENDED DECEMBER 31,                              SIX MONTHS ENDED JUNE 30,
                        -------------------------------------------------------------------    ----------------------------------
                                                                             1995                                  1996
                                                                    -----------------------               -----------------------
                         1991       1992       1993       1994      ACTUAL    PRO FORMA(1)      1995      ACTUAL     PRO FORMA(2)
                        -------    -------    -------    -------    -------   ------------     -------    -------    ------------
                                                                    (DOLLARS IN THOUSANDS)
POWER PLANTS:
  Electricity
    revenue:
    Energy...........   $33,426    $38,325    $37,088    $45,912    $54,886      $ 89,292      $22,323    $34,362        $36,839
    Capacity(3)......   $ 7,562    $ 7,707    $ 7,834    $ 7,967    $30,485      $ 83,591      $ 9,051    $19,774        $28,364
  Megawatt hours
    produced.........   392,471    403,274    378,035    447,177    1,033,566   2,387,730      324,059    736,759        860,969
  Average energy
    price per
    kilowatt
    hour(3)..........    8.517c     9.503c     9.811c    10.267c     5.310c        3.740c       6.889c     4.664c         4.279c
STEAM FIELDS:
  Steam revenue:
    Calpine..........   $36,173    $33,385    $31,066    $32,631    $39,669      $ 39,669      $17,639    $15,866        $15,866
    Other interest...   $ 2,820    $ 2,501    $ 2,143    $ 2,051         --            --           --         --             --
  Megawatt hours
    produced.........   2,095,576  2,105,345  2,014,758  2,156,492  2,415,059   2,415,059      1,027,317  1,040,271    1,040,271
  Average price per
    kilowatt hour....    1.861c     1.705c     1.648c     1.608c     1.643c        1.643c       1.717c     1.525c         1.525c	

(1) Pro forma results for the year ended December 31, 1995 give effect to the Greenleaf Transaction, the Watsonville Transaction, the King City Transaction and the Gilroy Transaction as if such transactions had occurred on January 1, 1995.
(2) Pro forma results for the six months ended June 30, 1996 give effect to the King City Transaction and the Gilroy Transaction as if such transactions had occurred on January 1, 1996.
(3) Represents energy revenue divided by the kilowatt hours produced. The significant increase in capacity revenue and the accompanying decline in average energy price per kilowatt hours since 1994 reflects the increase in the Company's megawatt hour production as a result of acquisitions of gas-fired cogeneration facilities by the Company.
RESULTS OF OPERATIONS
SIX MONTHS ENDED JUNE 30, 1996 COMPARED TO SIX MONTHS ENDED JUNE 30, 1995
Revenue. Revenue increased 63% to $82.0 million for the six months ended June 30, 1996 compared to $50.4 million for the comparable period in 1995. Electricity and steam sales revenue increased 47% to $72.0 million for the six months ended June 30, 1996, compared to $49.0 million for the comparable period in 1995. The increase in electricity and steam sales revenue was primarily attributable to $11.0 million of revenue from the King City Facility, an increase in revenue of $6.0 million from the Greenleaf 1 and 2 Facilities, and $3.9 million of revenue from the Watsonville Facility. The remaining increase in electricity and steam sales revenue of $2.1 million is primarily a result of higher generation and higher prices at other Company power generation facilities and steam fields. Service contract revenue from related parties increased 48% to $4.6 million for the six months ended June 30, 1996 compared to $3.1 million for the same period in 1995, primarily as a result of service revenue earned in connection with overhauls at the Aidlin Facility and the Agnews Facility. Income from unconsolidated investments in power projects increased to $1.7 million for the six months ended June 30, 1996 compared to a loss of $1.8 million for the comparable period in 1995, primarily as a result of $1.9 million of equity income from the Company's investment in the Sumas Facility. This increase is primarily
31

attributable to a contractual increase in the energy price under the power sales agreement. Interest income on loans to power projects increased to $2.8 million for the six months ended June 30, 1996 as a result of $1.9 million attributable to the recognition of interest income on loans to the sole shareholder of the general partner in the Sumas Facility, and interest income of $962,000 on loans to Coperlasa related to the Cerro Prieto Steam Fields.
Cost of revenue. Cost of revenue increased 68% to $51.3 million for the six months ended June 30, 1996 compared to $30.6 million for the comparable period in 1995. The increase was primarily due to plant operating, depreciation and operating lease expenses attributable to (i) a full six months of operations during 1996 at the Greenleaf 1 and 2 Facilities, which were purchased on April 21, 1995, (ii) a full six months of operations during 1996 at the Watsonville Facility which was acquired on June 29, 1995, and (iii) operations at the King City Facility subsequent to May 2, 1996. The increase in cost of revenue was also due to the increase in service contract expenses as a result of expenses related to the Cerro Prieto Steam Fields, partially offset by lower operating and depreciation expenses at the Company's other existing power generation facilities and steam fields.
General and administrative expenses. General and administrative expenses increased 60% to $5.9 million for the six months ended June 30, 1996 compared to $3.7 million for the comparable period in 1995. The increase was primarily due to additional personnel and related expenses necessary to support the Company's expanding operations.
Interest expense. Interest expense increased 24% to $18.7 million for the six months ended June 30, 1996 compared to $15.1 million for the comparable period in 1995. The increase was primarily attributable to $2.4 million of interest on the Company's 10 1/2% Senior Notes issued in May 1996 and $1.7 million of interest expense related to the Greenleaf 1 and 2 Facilities acquired in April 1995, offset in part by a $1.5 million decrease in interest expense as a result of repayments of principal on certain indebtedness.
Other income, net. Other income, net increased to $2.8 million for the six months ended June 30, 1996 compared to $855,000 for the comparable period in 1995. The increase was primarily due to $1.5 million of interest income on collateral securities purchased in connection with the King City Transaction and to an increase in interest income from the investment of the proceeds of the Preferred Stock Investment and a portion of the proceeds from the sale of the 10 1/2% Senior Notes.
Provision for income taxes. The effective rate for the income tax provision was approximately 41% for the six months ended June 30, 1996. The effective rate was based on statutory tax rates.
YEAR ENDED DECEMBER 31, 1995 COMPARED TO YEAR ENDED DECEMBER 31, 1994
Revenue. Revenue increased 39% to $132.1 million in 1995 compared to $94.8 million in 1994, primarily due to a 42% increase in electricity and steam sales to $127.8 million in 1995 compared to $90.3 million in 1994. Such an increase was primarily attributable to the $28.3 million of revenue from the Greenleaf 1 and 2 Facilities, $5.9 million of revenue from the Watsonville Facility, the $5.2 million of additional revenue from the Thermal Power Company Steam Fields as a result of a full year of operation in 1995, and an increase of $3.0 million of revenue from the SMUDGEO #1 Steam Fields attributable to increased production as a result of an extended outage during 1994. Such an increase also reflects a substantial increase in capacity payments for electricity sales from $8.0 million in 1994 to $30.5 million in 1995 as a result of the transactions stated above. This revenue increase was partially offset by a $2.7 million decrease in revenue from the West Ford Flat and Bear Canyon Facilities as a result of curtailments by PG&E due to low gas prices and high levels of precipitation during 1995 as compared to 1994, offset in part by contractual price increases for 1995. Without such curtailment, the West Ford Flat and Bear Canyon Facilities would have generated an additional $5.2 million of revenue in 1995. Revenue for 1995 also reflects curtailment of steam production at the Thermal Power Company Steam Fields as a result of higher precipitation and lower gas prices in 1995, and at the PG&E Unit 13 and Unit 16 Steam Fields as a result of hydro-spill conditions. Without curtailment, the Thermal Power Company Steam Fields and the PG&E Unit 13 and Unit 16 Steam Fields would have generated an additional $5.7 million and $800,000 of revenue during 1995, respectively.
Revenue for 1995 and 1994 reflects reversals of $2.7 million and $3.2 million, respectively, of previously deferred revenue. Company revenue from sales of steam were previously calculated considering a future period
32

when steam would be delivered without receiving corresponding revenue. See Note 2 of the notes to consolidated financial statements appearing elsewhere in this Prospectus. In May 1994, the Company ceased deferring revenue and recognized $4.0 million of its previously deferred revenue. Based on estimates and analyses performed by the Company, the Company no longer expects that it will be required to make these deliveries to SMUD. Concurrently, $800,000 of the revenue increase was reserved for future construction of gathering systems required for future production of the steam fields, with the offset recorded in property, plant and equipment. In October 1995, PG&E agreed to the termination of the free steam provision with respect to the PG&E Unit 13 Steam Fields. During 1995, the Company took additional measures regarding future capital commitments and other actions which will increase steam production and, based on additional analyses and estimates performed, the Company recognized the remaining $2.7 million of previously deferred revenue.
Cost of revenue. Cost of revenue increased 47% to $77.4 million in 1995 compared to $52.8 million in 1994. The increase was due to plant operating, production royalty and depreciation and amortization expenses attributable to
(i) a full year of operations at Thermal Power Company, which was purchased on September 9, 1994, (ii) operations at the Greenleaf 1 and 2 Facilities subsequent to April 21, 1995, and (iii) operations at the Watsonville Facility subsequent to June 29, 1995. The increases were partially offset by lower depreciation and production royalty expenses at the West Ford Flat and Bear Canyon Facilities and the PG&E Unit 13 and Unit 16 Steam Fields due to curtailment by PG&E during 1995.
Project development expenses. Project development expenses increased to $3.1 million in 1995, compared to $1.8 million in 1994, due to new project development activities.
General and administrative expenses. General and administrative expenses were $8.9 million in 1995 compared to $7.3 million in 1994. The increase in 1995 was primarily due to additional personnel and related expenses necessary to support the Company's expanded operations.
Interest expense. Interest expense increased to $32.2 million in 1995 from $23.9 million in 1994. Approximately $3.6 million of the increase was attributable to a full year of interest expense incurred on the debt related to the Thermal Power Company acquisition in September 1994 and $4.1 million of interest expense incurred on the debt related to the Greenleaf Transaction in April 1995. In addition, 1995 included a full year of interest expense on the 9 1/4% Senior Notes issued on February 17, 1994.
Provision for income taxes. The effective rate for the income tax provision was approximately 41% for 1995 and 39% for 1994. The effective rates were based on statutory tax rates, with minor reductions for depletion in excess of tax basis benefits. Due to curtailment of production during 1995, the allowance for statutory depletion decreased in 1995 from 1994.
YEAR ENDED DECEMBER 31, 1994 COMPARED TO YEAR ENDED DECEMBER 31, 1993
Revenue. Revenue increased 36% to $94.8 million in 1994 from $69.9 million in 1993, primarily due to a 70% increase in electricity and steam sales to $90.3 million in 1994 compared to $53.0 million in 1993. Such increases were primarily attributable to the $5.8 million of revenue from the Thermal Power Company Steam Fields, the $5.1 million and $3.0 million of additional revenue from the West Ford Flat and the Bear Canyon Facilities, respectively, as a result of the acquisition of the additional interests in such facilities in 1994, the effects of curtailment at such facilities in 1993 as a result of higher precipitation in 1993 and the sale of $804,000 of electricity to the Northern California Power Agency. These revenue increases were partially offset by a decrease of $3.5 million in electricity and steam sales from the SMUDGEO #1 Steam Fields as a result of a four-month shut-down for major maintenance.
In May 1994, the Company recognized approximately $5.9 million of its previously deferred revenue. The revenue was previously deferred when it was expected that steam would have been delivered without receiving corresponding revenue. Based on current estimates and analyses performed by the Company, the Company no longer expects that it will be required to make these deliveries to SMUD. This resulted in a $4.0 million increase in revenue during 1994, while the remaining $1.9 million was treated as a purchase price reduction to property, plant and equipment. Concurrently, $800,000 of the revenue increase was reserved for future
33

construction of gathering systems required for future production of the steam fields, with the offset recorded in property, plant and equipment.
Service contract revenue decreased 57% to $7.2 million in 1994 compared to $16.9 million in 1993, primarily reflecting the elimination of intercompany revenue for services provided to the power generation facilities and steam fields owned by CGC after the acquisition of the remaining interest in CGC in April 1993. In addition, the decline reflected the higher revenue recognized in 1993 on services associated with the Aidlin Facility overhaul, maintenance at the Agnews Facility, the start-up of the Sumas Facility and the completion of the Sumas construction management project.
Unconsolidated investments in power projects contributed a loss of $2.8 million in 1994 compared to income of $19,000 in 1993. The decrease is partially attributable to a full year of operating loss at the Sumas Facility of $2.9 million in 1994, as compared to approximately eight months of operating loss of $1.9 million in 1993. The 1994 Sumas Facility operating loss is attributable to higher interest, depreciation and general and administrative expenses. The decrease from 1993 income from unconsolidated investments in power projects is also attributable to $2.0 million of equity income from CGC recognized prior to the April 1993 acquisition under the equity method of accounting.
Cost of revenue. Cost of revenue increased 24% to $52.8 million in 1994 from $42.5 million in 1993. The increase was attributable to higher plant operating, production royalty and depreciation expenses due to a full year of operations at CGC during 1994, and to additional expenses of Thermal Power Company as a result of its acquisition by the Company on September 9, 1994. Service contract expenses decreased by $8.8 million primarily due to the elimination of $6.2 million of operation expenses incurred at CGC after the acquisition of the remaining interest in April 1993, as well as higher 1993 costs incurred in connection with the Aidlin Facility overhaul and higher maintenance expenses at the Agnews Facility.
Project development expenses. Project development expenses increased to $1.8 million in 1994 from $1.3 million in 1993 due to increased expenses attributable to new project development activities.
General and administrative expenses. General and administrative expenses increased 43% to $7.3 million in 1994 from $5.1 million in 1993 due to additional personnel and related expenses necessary to support the Company's expanded operations.
Provision for write-off of project development expenses. The Company established in 1994 a $1.0 million reserve for capitalized project costs associated with the development of projects which the Company has determined may not be consummated.
Interest expense. Interest expense increased to $23.9 million in 1994 from $13.8 million in 1993. The Company incurred $8.5 million of interest expense related to the 9 1/4% Senior Notes issued in February 1994. A portion of the proceeds of the 9 1/4% Senior Notes was used to repay all of the $52.6 million then outstanding under the Credit Suisse Credit Facility, and to repay the non-recourse notes payable to Freeport-McMoran Resource Partners, L.P. ("FMRP") plus accrued interest. Interest expense also increased approximately $1.0 million due to a full year of interest expense at higher interest rates related to CGC debt. Additionally, interest expense of $1.3 million was incurred on the new debt related to the Company's acquisition of Thermal Power Company in September 1994.
Provision for income taxes. The effective rate for the income tax provision was 39% in 1994 compared to 50% for 1993. The 1994 effective rate reflects a reduction for a depletion in excess of tax basis benefit at Thermal Power Company and CGC. The effective rate for 1993 reflects a provision of $700,000 due to a change in the California state income tax regulations to disallow 50% of net operating loss carryforwards.
QUARTERLY RESULTS OF OPERATIONS AND SEASONALITY
The Company's quarterly operating results have fluctuated in the past and may continue to do so in the future as a result of a number of factors, including, but not limited to, the timing and size of acquisitions, the completion of development projects, the timing and amount of curtailment and variations in levels of production. Furthermore, the majority of capacity payments under certain of the Company's power sales agreements are received during the months of May through October. The market price of the Common Stock
34

could be subject to significant fluctuations in response to those variations in quarterly operating results and other factors.
LIQUIDITY AND CAPITAL RESOURCES
To date, the Company has obtained cash from its operations, borrowings under the Credit Suisse Credit Facility and other working capital lines, equity contributions from Electrowatt and proceeds from non-recourse project financings and other long-term debt. The Company utilized this cash to fund its operations, service debt obligations, fund the acquisition, development and construction of power generation facilities, finance capital expenditures and meet its other cash and liquidity needs.
The following table summarizes the Company's cash flow activities for the periods indicated:

                                                                            SIX MONTHS ENDED JUNE
                                          YEAR ENDED DECEMBER 31,                    30,
                                     ----------------------------------     ----------------------
                                       1993         1994         1995         1995         1996
                                     --------     --------     --------     --------     ---------
                                                            (IN THOUSANDS)
Cash flows from:
  Operating activities...........    $ 24,310     $ 34,196     $ 26,653     $  5,126     $   5,035
  Investing activities...........     (27,082)     (84,444)     (38,497)     (23,874)     (126,051)
  Financing activities...........       6,778       66,609       11,127        3,742       137,609
                                     --------     --------     --------     --------     ---------
     Total.......................    $  4,006     $ 16,361     $   (717)    $(15,006)    $  16,593
                                     ========     ========     ========     ========     =========	

Operating activities for 1995 consisted of approximately $7.4 million of net income from operations, $25.9 million of depreciation and amortization and a $2.9 million loss from unconsolidated investments in power projects, offset by an $8.5 million net increase in operating assets and liabilities. Operating activities for the six months ended June 30, 1996 consisted of approximately $4.4 million of net income from operations, $15.0 million of depreciation and amortization and $1.7 million in deferred income taxes, offset by $1.7 million of income from unconsolidated investments in power projects and a $14.4 million net increase in operating assets and liabilities.
Investing activities used $38.5 million during 1995, primarily due to $17.4 million of capital expenditures, $14.8 million for the acquisition of the Greenleaf 1 and 2 Facilities and a $6.3 million investment in notes receivable. Investing activities used $126.1 million during the six months ended June 30, 1996, primarily due to $11.0 million of capital expenditures and capitalized project costs, $98.4 million for the purchase of collateral securities, a $12.1 million investment in Coperlasa and $4.9 million for deferred transaction costs in connection with the King City Transaction, offset by a $1.1 million decrease in restricted cash requirements.
Financing activities provided $11.1 million of cash during 1995. Borrowings in 1995 included $76.0 million of non-recourse project financing and $37.5 million from the Company's lines of credit. Proceeds were primarily used to repay $60.4 million of project debt assumed in the acquisition of the Greenleaf 1 and 2 Facilities, and $15.0 million borrowed from the lines of credit for the acquisition of the Greenleaf 1 and 2 Facilities. In addition, $19.0 million was used to reduce the balance outstanding under non-recourse project financing, and $6.0 million was used to repay short-term borrowings. Financing activities provided $137.6 million of cash during the six months ended June 30, 1996. The Company issued $50.0 million of Preferred Stock to Electrowatt, incurred the $45 Million Bank of Nova Scotia Loan and borrowed an additional $33.8 million under the Credit Suisse Credit Facility and received net proceeds of $175.2 million from the 10 1/2% Senior Notes during the six months ended June 30, 1996. In addition, the Company repaid $46.2 million of bank debt and all of the $53.7 million of borrowings outstanding under the Credit Suisse Credit Facility and $66.6 million of non-recourse project financing.
In 1995, working capital decreased $50.5 million and cash and cash equivalents decreased $717,000. The decrease in working capital is primarily due to the reclassification of the $57 Million Bank of Nova Scotia Loan from long-term to current. On May 16, 1996, the Company issued the 10 1/2% Senior Notes, a portion of the net proceeds of which was used to refinance current indebtedness and to repay the $57 Million Bank of
35

Nova Scotia Loan. As of June 30, 1996, cash and cash equivalents were $38.4 million and working capital was $51.9 million. For the six months ended June 30, 1996, working capital increased $100.9 million and cash and cash equivalents increased $16.6 million as compared to the twelve months ended December 31, 1995. Working capital at December 31, 1995 included the $57 Million Bank of Nova Scotia Loan. A portion of the net proceeds from the issuance of the 10 1/2% Senior Notes was used to refinance current bank debt and borrowings under the Credit Suisse Credit Facility and to repay the $57 Million Bank of Nova Scotia Loan. Working capital also increased as a result of the investment of the balance of the proceeds from the issuance of the 10 1/2% Senior Notes in short-term marketable securities. The increase in working capital was also due to the proceeds from the issuance of $50.0 million of preferred stock which were invested until May 1, 1996 for the King City Transaction.
As a developer, owner and operator of power generation projects, the Company may be required to make long-term commitments and investments of substantial capital for its projects. The Company historically has financed these capital requirements with borrowings under its credit facilities, other lines of credit, non-recourse project financing or long-term debt.
At June 30, 1996, the Company had $208.2 million of non-recourse project financing associated with power generating facilities and steam fields at the West Ford Flat Facility, the Bear Canyon Facility, the PG&E Unit 13 and Unit 16 Steam Fields, the SMUDGEO #1 Steam Fields and the Greenleaf 1 and 2 Facilities. As of June 30, 1996, the annual maturities for all non-recourse project debt were $18.1 million for the remainder of 1996, $24.8 million for 1997, $26.0 million for 1998, $18.7 million for 1999, $18.0 million for 2000 and $100.2 million thereafter.
The Company currently has the Credit Suisse Credit Facility, which was arranged by Electrowatt and provides for total borrowings of up to $50.0 million, with borrowings bearing interest at either LIBOR or at the Credit Suisse base rate plus a mutually-agreed margin. As of June 30, 1996, the Company had no borrowings outstanding under the Credit Suisse Credit Facility. Upon the completion of the Common Stock Offering, the Credit Suisse Credit Facility will terminate and is expected to be replaced by a comparable facility. On July 20, 1996, the Company entered into a Commitment Letter with The Bank of Nova Scotia for a $50.0 million three-year revolving credit facility. The Bank of Nova Scotia Facility will become effective upon the completion of the Common Stock Offering.
The Company currently has outstanding $105.0 million of its 9 1/4% Senior Notes which mature on February 1, 2004 and bear interest at 9 1/4% payable semi-annually on February 1 and August 1 of each year and $180.0 million of its 10 1/2% Senior Notes which mature on May 15, 2006 and bear interest at 10 1/2% payable semi-annually on May 15 and November 15 of each year. Under the provisions of the Indentures, the Company may, under certain circumstances, be limited in its ability to make restricted payments, as defined, which include dividends and certain purchases and investments, incur additional indebtedness and engage in certain transactions. In addition, the Bank of Nova Scotia Facility will contain certain restrictions that will significantly limit or prohibit, among other things, the ability of the Company or its subsidiaries to incur indebtedness, make prepayments of certain indebtedness, pay dividends, make investments, engage in transactions with affiliates, create liens, sell assets and engage in mergers and consolidations.
The Company has a $1.2 million working capital line with a commercial lender that may be used to fund short-term working capital commitments and letters of credit. At June 30, 1996, the Company had no borrowings under this working capital line and $900,000 of letters of credit outstanding. Borrowings are at prime plus 1%.
The Company also had outstanding a non-interest bearing promissory note to Natomas Energy Company in the amount of $6.5 million representing a portion of the September 1994 purchase price of Thermal Power Company. This note, which has been discounted to yield 8% per annum, is due September 9, 1997.
On August 29, 1996, in connection with the acquisition of the Gilroy Facility, the Company entered into a non-recourse project loan in the aggregate amount of $116.0 million. Such loan, which was provided by Banque Nationale de Paris, consists of a 15-year tranche in the amount of $81.0 million and an 18-year tranche in the amount of $35.0 million and bears interest at fixed and floating rates.
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The Company intends to continue to seek the use of non-recourse project financing for new projects, where appropriate. The debt agreements of the Company's subsidiaries and other affiliates governing the non-recourse project financing generally restrict their ability to pay dividends, make distributions or otherwise transfer funds to the Company. The dividend restrictions in such agreements generally require that, prior to the payment of dividends, distributions or other transfers, the subsidiary or other affiliate must provide for the payment of other obligations, including operating expenses, debt service and reserves. However, the Company does not believe that such restrictions will adversely affect its ability to meet its debt obligations.
At June 30, 1996, the Company had commitments for capital expenditures in 1996 totaling $6.5 million related to various projects at its geothermal facilities. The Company intends to fund capital expenditures for the ongoing operation and development of the Company's power generation facilities primarily through the operating cash flow of such facilities. Capital expenditures for 1995 were $17.4 million compared to $7.0 million for 1994, primarily due to the purchase of new equipment and the additional working interest. For the six months ended June 30, 1996, capital expenditures included $4.0 million for the purchase of geothermal leases for the Glass Mountain Project and $2.7 million for the new rotor at the PG&E Unit 13 facility.
The Company continues to pursue the acquisition and development of geothermal resources and new power generation projects. The Company expects to commit significant capital during the remainder of 1996 and in future years for the acquisition and development of these projects. The Company's actual capital expenditures may vary significantly during any year.
In April 1996, the Company entered into a transaction involving a lease of the King City Facility. The Company financed this transaction with the $45 Million Bank of Nova Scotia Loan, $13.3 million of borrowings under the Credit Suisse Credit Facility (both of which were repaid with a portion of the net proceeds from the sale of the 10 1/2% Senior Notes) and $50.0 million of proceeds from the Preferred Stock Investment by Electrowatt. See "Business -- Description of Facilities -- King City Facility."
The Company believes that it will have sufficient liquidity from cash flow from operations, borrowings available from lines of credit and working capital lines to satisfy all obligations under outstanding indebtedness, to finance anticipated capital expenditures and to fund working capital requirements.
IMPACT OF RECENT ACCOUNTING PRONOUNCEMENTS
In March 1995, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards ("SFAS") No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of. This pronouncement requires that long-lived assets and certain identifiable intangible assets be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss is to be recognized when the sum of undiscounted cash flows is less than the carrying amount of the asset. Measurement of the loss for assets that the entity expects to hold and use are to be based on the fair market value of the asset. SFAS No. 121 must be adopted for fiscal years beginning in 1996. The Company has adopted SFAS No. 121 effective January 1, 1996, and determined that adoption of this pronouncement had no material impact on the results of operations or financial condition of the Company as of January 1, 1996.
In October 1995, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards ("SFAS") No. 123, Accounting for Stock-Based Compensation. The disclosure requirements of SFAS No. 123 are effective for the Company's 1996 fiscal year. The Company does not expect the new pronouncement to have an impact on its results of operations since the intrinsic value-based method prescribed by APB Opinion No. 25 and also allowed by SFAS No. 123 will continue to be used by the Company to account for its stock-based compensation plans.
37

BUSINESS
OVERVIEW
Calpine is engaged in the acquisition, development, ownership and operation of power generation facilities and the sale of electricity and steam in the United States and selected international markets. The Company has interests in 15 power generation facilities and steam fields having an aggregate capacity of 1,057 megawatts. Since its inception in 1984, Calpine has developed substantial expertise in all aspects of electric power generation. The Company's vertical integration has resulted in significant growth over the last five years as Calpine has applied its extensive engineering, construction management, operations, fuel management and financing capabilities to successfully implement its acquisition and development program. During the last five years, Calpine has expanded substantially, from $41.2 million of total assets as of December 31, 1991 to $911.0 million of total assets on a pro forma basis as of June 30, 1996. Calpine's revenue on a pro forma basis for 1995 increased to $224.3 million, representing a compound annual growth rate of 55% since 1991. The Company's EBITDA on a pro forma basis for 1995 increased to $123.8 million. See "Pro Forma Consolidated Financial Data." Calpine's strategy is to capitalize on opportunities in the power market through an ongoing program to acquire, develop, own and operate electric power generation facilities, as well as marketing power and energy services to utilities and other end users.
THE MARKET
The power generation industry represents the third largest industry in the United States, with an estimated end user market of approximately $207.5 billion of electricity sales and 3.0 million gigawatt hours of production in 1995. In response to increasing customer demand for access to low cost electricity and enhanced services, new regulatory initiatives are currently being adopted or considered at both state and federal levels to increase competition in the domestic power generation industry. To date, such initiatives are under consideration at the federal level and in approximately thirty states. For example, in April 1996, FERC adopted Order No. 888, opening wholesale power sales to competition and providing for open and fair electric transmission services by public utilities. In addition, the CPUC has issued an electric industry restructuring decision which envisions commencement of deregulation and implementation of customer choice of electricity supplier by January 1, 1998. Calpine believes that industry trends and such regulatory initiatives will lead to the transformation of the existing market, which is largely characterized by electric utility monopolies selling to a captive customer base, to a more competitive market where end users may purchase electricity from a variety of suppliers, including non-utility generators, power marketers, public utilities and others. The Company believes that those market trends will create substantial opportunities for companies such as Calpine that are low cost power producers and have an integrated power services capability which enables them to produce and sell energy to customers at competitive rates.
The Company also believes that these market trends will result in the disposition of power generation facilities by utilities, independent power producers and industrial companies. Utilities such as PG&E and Southern California Edison Company have announced their intentions to sell power generation facilities totalling approximately 3,150 megawatts and 5,000 megawatts, respectively. The independent power industry, which represents approximately 8% of the installed capacity in the United States, or approximately 59,000 megawatts, and has accounted for approximately 50% of all additional capacity in the United States since 1990, is currently undergoing significant consolidation. Many independent producers operating a limited number of power plants are seeking to dispose of such plants in response to competitive pressures, and industrial companies are selling their power plants to redeploy capital in their core businesses. Over 200 independent power plant and portfolio sale transactions have occurred in the past two years. The Company believes that this consolidation will continue in the highly fragmented independent power industry.
The power generation industry outside the United States is approximately three times larger than the domestic market, and the demand for electricity is growing rapidly. In 1996, it has been estimated that in excess of 590 gigawatts of new capacity will be required outside the United States over the ensuing ten-year period. In order to satisfy this anticipated increase in demand, many countries have adopted active government programs designed to encourage private investment in power generation facilities. The Company believes that
38

these programs will create significant opportunities to acquire and develop power generation facilities in such countries.
STRATEGY
Calpine's objective is to become a leading power company by capitalizing on these emerging market opportunities in the domestic and international power markets. The key elements of the Company's strategy are as follows:
Expand and diversify its domestic portfolio of power projects. In pursuing its growth strategy, the Company intends to focus on opportunities where it is able to capitalize on its extensive management and technical expertise to implement a fully integrated approach to the acquisition, development and operation of power generation facilities. This approach includes design, engineering, procurement, finance, construction, management, fuel and resource acquisition, operations and power marketing, which Calpine believes provides it with a competitive advantage. By pursuing this strategy, the Company has significantly expanded and diversified its project portfolio. Since 1993, the Company has completed transactions involving five gas-fired cogeneration facilities and two steam fields. As a result of these transactions, the Company has more than doubled its aggregate power generation capacity and substantially diversified its fuel mix since 1993.
The Company is also pursuing the development of highly efficient, low cost power plants that seek to take advantage of inefficiencies in the electricity market. The Company intends to sell all or a portion of the power generated by such merchant plants into the competitive market, rather than exclusively through long-term power sales agreements. As part of Calpine's initial effort to develop merchant plants, the Company entered into an agreement with Phillips Petroleum Company to develop a gas-fired cogeneration project with a capacity of 240 megawatts. Under this agreement, approximately 90 megawatts of electricity will be sold to the Phillips Houston Chemical Complex, with the remainder to be sold into the competitive market through Calpine's power marketing activities. The Company expects that this project will represent a prototype for future merchant plant developments. The development of this project is subject to the satisfaction of various conditions, including completion of financing and obtaining required approvals. See "-- Development and Future Projects."
Enhance the performance and efficiency of existing power projects. The Company continually seeks to maximize the power generation potential of its operating assets and minimize its operating and maintenance expenses and fuel costs. To date, the Company's power generation facilities have operated at an average availability in excess of 97%. The Company believes that achieving and maintaining a low cost of production will be increasingly important to compete effectively in the power generation market.
Continue to develop an integrated power marketing capability. The Company has established an integrated power marketing capability, conducted through its wholly owned subsidiary, CPSC. In 1995, CPSC received approval from the FERC to conduct power marketing activities. The Company believes that a power marketing capability complements its business strategy of providing low cost power generation services. CPSC's power marketing activities will focus on the development of long-term customer service relationships, supported primarily by generating assets that are owned, operated or controlled by Calpine. CPSC will aggregate the Company's own resources, the resources of its customers, power pool resources, and market power supply to provide the customized services demanded by its customers at a competitive price.
Selectively expand into international markets. Internationally, the Company intends to utilize its geothermal and gas-fired expertise in selected markets of Southeast Asia and Latin America, where demand for power is rapidly growing and private investment is encouraged. In November 1995, the Company made an investment in the Cerro Prieto Steam Fields, located in Baja California, Mexico. In March 1996, the Company entered into a joint venture agreement to pursue the development of a geothermal resource in Indonesia with an estimated potential capacity in excess of 500 megawatts. Calpine believes that its
39

investments in these projects will effectively position it for future expansion in Southeast Asia and Latin America.
POWER GENERATION TECHNOLOGIES
NATURAL GAS-FIRED
Natural gas-fired power plants offer significant advantages over power plants utilizing other fuel sources, such as coal, oil and nuclear energy, including readily available supplies of natural gas, currently favorable prices, highly efficient technology, higher availabilities, shorter construction periods and lower capital and operating costs. In addition, natural gas-fired power plants have fewer environmental impacts, including significantly lower emission levels of certain pollutants than power plants utilizing other fossil fuels such as coal and oil. During recent years, natural gas-fired power plants have accounted for a substantial portion of the annual increase in independent power capacity in the United States, and natural gas-fired power generation has become the predominant power generation technology utilized for the production of electricity by new power plants in the United States. Industry analysts have predicted that natural gas will continue to be the dominant fuel for new power generation facilities in the United States for the foreseeable future.
LOGO
GEOTHERMAL
Geothermal energy is a clean, alternative source of power that is produced by utilizing hot water or steam that has been naturally heated by the earth. Geothermal energy is found in areas of the world where heat within the earth's crust is close to the surface. These areas generally coincide with the boundaries of the earth's tectonic plates. Exploitable geothermal reservoirs have three primary defining characteristics: (i) a high heat flow near the surface, (ii) a porous geologic medium where water can circulate to become heated
40

and (iii) an impermeable cap rock to prevent dispersion of the heated fluids. Factors that affect the ability to exploit geothermal energy include the ability to drill wells and produce fluids from the porous medium, the temperature and quantity of the fluids and the chemical characteristics of the fluids. In addition, the productive capacity of geothermal wells decreases over time, requiring the drilling of new wells in an effort to maintain production.
LOGO
Geothermal energy facilities, such as those currently owned and operated by the Company, provide significant advantages over other alternative power generation technologies, such as wind, solar or solid waste/biomass, including lower operating and maintenance costs per kilowatt hour, shorter construction periods and higher plant availability. Geothermal energy also provides a reliable and environmentally preferred source of electricity, emitting significantly lower levels of pollutants than are released from power plants utilizing fossil fuels. As a result of these and other advantages, as well as federal and state tax incentives that have been adopted to encourage the development of geothermal power generation projects, the Company believes that there will continue to be demand for the production of electricity using geothermal energy.
The geothermal energy capacity of the United States is located predominantly in the western states in tectonically active regions. Total installed geothermal capacity in the United States was approximately 2,925 megawatts as of the end of 1995, with approximately 2,650 megawatts located in California and 275 megawatts located in Nevada, Utah and Hawaii. The Geysers constitute the world's largest developed geothermal reservoir. The Geysers steam fields have been in commercial production since 1960, and currently are capable of producing an amount of steam sufficient to generate 1,200 megawatts of electricity.
DESCRIPTION OF FACILITIES
The Company has interests in 15 power generation facilities and steam fields with a current aggregate capacity of approximately 1,057 megawatts, consisting of seven natural gas-fired cogeneration facilities with a total capacity of 522 megawatts, three geothermal power generation facilities (which include a steam field and a power plant) with a total capacity of 67 megawatts and five geothermal steam fields that supply utility power plants with a total current capacity of approximately 468 megawatts. Each of the power generation facilities produces electricity for sale to a utility. Thermal energy produced by the gas-fired cogeneration facilities is sold to governmental and industrial users, and steam produced by the geothermal steam fields is sold to utility- owned power plants.
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The natural gas-fired and geothermal power generation projects in which the Company has an interest produce electricity, thermal energy and steam that are typically sold pursuant to long-term, take-and-pay power or steam sales agreements generally having original terms of 20 or 30 years. Revenue from a power sales agreement usually consists of two components: energy payments and capacity payments. Energy payments are based on a power plant's net electrical output, where payment rates may be determined by a schedule of prices covering a fixed number of years under the power sales agreement, after which payment rates are usually indexed to the fuel costs of the contracting utility or to general inflation indices. Capacity payments are based on a power plant's net electrical output and/or its available capacity. Energy payments are made for each kilowatt hour of energy delivered, while capacity payments, under certain circumstances, are made whether or not any electricity is delivered. The Company is paid for steam supplied by its steam fields on the basis of the amount of electrical energy produced by, or steam delivered to, the contracting utility's power plants.
The Company currently provides operating and maintenance services for all power generation facilities in which the Company has an interest, except for the Thermal Power Company Steam Fields and the Cerro Prieto Steam Fields. Such services include the operation of power plants, geothermal steam fields, wells and well pumps, gathering systems and gas pipelines. The Company also supervises maintenance, materials purchasing and inventory control; manages cash flow; trains staff; and prepares operating and maintenance manuals for each power generation facility. As a facility develops an operating history, the Company analyzes its operation and may modify or upgrade equipment or adjust operating procedures or maintenance measures to enhance the facility's reliability or profitability. These services are performed under the terms of an operating and maintenance agreement pursuant to which the Company is generally reimbursed for certain costs, is paid an annual operating fee and may also be paid an incentive fee based on the performance of the facility. The fees payable to the Company are generally subordinated to any lease payments or debt service obligations of non-recourse debt for the project.
In order to provide fuel for the gas-fired power generation projects in which the Company has an interest, natural gas reserves are acquired or natural gas is purchased from third parties under supply agreements. The Company structures a gas-fired power facility's fuel supply agreement so that gas costs have a direct relationship to the fuel component of revenue energy payments.
Certain power generation facilities in which the Company has an interest have been financed primarily with non-recourse project financing that is structured to be serviced out of the cash flows derived from the sale of electricity, thermal energy and/or steam produced by such facilities and provides that the obligations to pay interest and principal on the loans are secured almost solely by the capital stock or partnership interests, physical assets, contracts and/or cash flow attributable to the entities that own the projects. The lenders under non-recourse project financing generally have no recourse for repayment against the Company or any assets of the Company or any other entity other than foreclosure on pledges of stock or partnership interests and the assets attributable to the entities that own the facilities.
Substantially all of the power generation facilities in which the Company has an interest are located on sites which are leased on a long-term basis. The Company currently holds interests in geothermal leaseholds in the Thermal Power Company Steam Fields that produce steam for sale under steam sales agreements and for use in producing electricity from its wholly owned geothermal power generation facilities. See "-- Properties."
The continued operation of power generation facilities and steam fields involves many risks, including the breakdown or failure of power generation equipment, transmission lines, pipelines or other equipment or processes and performance below expected levels of output or efficiency. To date, the Company's power generation facilities have operated at an average availability in excess of 97%, and although from time to time the Company's power generation facilities and steam fields have experienced certain equipment breakdowns or failures, such breakdowns or failures have not had a material adverse effect on the operation of such facilities or on the Company's results of operations. Although the Company's facilities contain certain redundancies and back-up mechanisms, there can be no assurance that any such breakdown or failure would not prevent the affected facility or steam field from performing under applicable power and/or steam sales agreements. In
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addition, although insurance is maintained to protect against certain of these operating risks, the proceeds of such insurance may not be adequate to cover lost revenue or increased expenses, and, as a result, the entity owning such power generation facility or steam field may be unable to service principal and interest payments under its financing obligations and may operate at a loss. A default under such a financing obligation could result in the Company losing its interest in such power generation facility or steam field.
LOGO
Insurance coverage for each power generation facility includes commercial general liability, workers' compensation, employer's liability and property damage coverage which generally contains business interruption insurance covering debt service and continuing expenses for a period ranging from 12 to 18 months.
The Company believes that each of the currently operating power generation facilities in which the Company has an interest is exempt from financial and rate regulation as a public utility under federal and state laws. See "-- Government Regulation."
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The table below sets forth certain information regarding the Company's power generation facilities and steam fields currently in operation.
POWER GENERATION FACILITIES

                                                                                  COMMENCEMENT                    TERM OF
                          POWER         NAMEPLATE       CALPINE     CALPINE NET        OF                          POWER
                        GENERATION       CAPACITY       INTEREST     INTEREST      COMMERCIAL       UTILITY        SALES
      FACILITY          TECHNOLOGY    (MEGAWATTS)(1)   (PERCENTAGE) (MEGAWATTS)    OPERATION       PURCHASER     AGREEMENT
- ---------------------  ------------   --------------   ----------   -----------   ------------   -------------   ---------
Sumas................   Gas-Fired            125            75%(2)        93.8        1993        Puget Sound       2013
                       Cogeneration                                                                 Power &
                                                                                                     Light
King City............   Gas-Fired            120           100%          120          1989       Pacific Gas &      2019
                       Cogeneration                                                                Electric
Gilroy...............   Gas-Fired            120           100%          120          1988       Pacific Gas &      2018
                       Cogeneration                                                                Electric
Greenleaf 1..........   Gas-Fired             49.5         100%           49.5        1989       Pacific Gas &      2019
                       Cogeneration                                                                Electric
Greenleaf 2..........   Gas-Fired             49.5         100%           49.5        1989       Pacific Gas &      2019
                       Cogeneration                                                                Electric
Agnews...............   Gas-Fired             29            20%            5.8        1990       Pacific Gas &      2021
                       Cogeneration                                                                Electric
Watsonville..........   Gas-Fired             28.5         100%           28.5        1990       Pacific Gas &      2009
                       Cogeneration                                                                Electric
West Ford Flat.......   Geothermal            27           100%           27          1988       Pacific Gas &      2008
                                                                                                   Electric
Bear Canyon..........   Geothermal            20           100%           20          1988       Pacific Gas &      2008
                                                                                                   Electric
Aidlin...............   Geothermal            20             5%            1          1989       Pacific Gas &      2009
                                                                                                   Electric	

STEAM FIELDS

                                  APPROXIMATE      CALPINE      CALPINE NET   COMMENCEMENT
                                   CAPACITY        INTEREST      INTEREST     OF COMMERCIAL        UTILITY         ESTIMATED
         STEAM FIELD             (MEGAWATTS)(3)   (PERCENTAGE)  (MEGAWATTS)     OPERATION         PURCHASER         LIFE(4)
- ------------------------------   -------------    ----------    ----------    -------------    ----------------    ---------
Thermal Power Company.........        151             100%          151            1960          Pacific Gas          2018
                                                                                                  & Electric
PG&E Unit 13..................        100             100%          100            1980          Pacific Gas          2018
                                                                                                  & Electric
PG&E Unit 16..................         78             100%           78            1985          Pacific Gas          2018
                                                                                                  & Electric
SMUDGEO #1....................         59             100%           59            1983           Sacramento          2018
                                                                                                  Municipal
                                                                                               Utility District
Cerro Prieto..................         80             100%(5)        80            1973            Comision           2000(6)
                                                                                                  Federal de
                                                                                                 Electricidad	

(1) Nameplate capacity may not represent the actual output for a facility at any particular time.
(2) See "-- Power Generation Facilities -- Sumas Facility" for a description of the Company's interest in the Sumas partnership and current sales of power by the Sumas Facility.
(3) Capacity is expected to gradually diminish as the production of the related steam fields declines. See "-- Steam Fields."
(4) Other than for the Cerro Prieto Steam Fields, the steam sales agreements remain in effect so long as steam is produced in commercial quantities. There can be no assurance that the estimated life shown accurately predicts actual productive capacity of the steam fields. See "-- Steam Fields."
(5) See "-- Steam Fields -- Cerro Prieto Steam Fields" for a description of the Company's interest in and current sales of steam by the Cerro Prieto Steam Fields.
(6) Represents the actual termination of the steam sales agreement. See "-- Steam Fields -- Cerro Prieto Steam Fields."
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POWER GENERATION FACILITIES
Sumas Facility
The Sumas cogeneration facility (the "Sumas Facility") is a 125 megawatt natural gas-fired, combined cycle cogeneration facility located in Sumas, Washington, near the Canadian border. In 1991, the Company and Sumas Energy, Inc. ("SEI") formed Sumas Cogeneration Company, L.P. ("Sumas") for the purpose of developing, constructing, owning and operating the Sumas Facility. The Company is the sole limited partner in Sumas and SEI is the general partner. The Company currently holds a 50% interest in Sumas and SEI holds the other 50% interest. At the time the Company receives a 24.5% pre-tax rate of return on its partnership investment in Sumas, the Company's interest will be reduced to 11.33% and SEI's interest will increase to 88.67%. Further, the Company receives an additional 25% of the cash flow of the Sumas Facility to repay principal and interest on $11.5 million of loans to the sole shareholder of SEI. A $1.5 million loan bears interest at 20% and matures in 2003 and a $10.0 million loan bearing interest at 16.25% and matures in 2004. The Sumas Facility commenced commercial operation in April 1993.
The Company managed the engineering, procurement and construction of the power plant and related facilities of the Sumas Facility, including the gas pipeline. The Sumas Facility was constructed by a Washington joint venture formed by Industrial Power Corporation and Haskell Corporation. The Sumas Facility is comprised of an MS 7001EA combined cycle gas turbine manufactured by General Electric Company ("General Electric"), a Vogt heat recovery steam generator, a General Electric steam turbine and a 3.5 mile gas pipeline. Since start-up in April 1993, the Sumas Facility has operated at an average availability of approximately 96.5%.
The Sumas Facility's $135.0 million construction and gas reserves acquisition cost was financed through $120.0 million of construction and term loan financing provided to Sumas and ENCO Gas, Ltd. ("ENCO"), a wholly owned Canadian subsidiary of Sumas, by The Prudential Insurance Company of America ("Prudential") and Credit Suisse. The credit facilities originally included term loans of $70.0 million at a combined fixed interest rate of 10.28% per annum and variable rate loans of $50.0 million currently based on LIBOR, which are amortized over a 15-year period.
Electrical energy generated by the Sumas Facility is sold to Puget Sound Power & Light Company ("Puget") under the terms of a 20-year power sales agreement terminating in 2013. Under the power sales agreement, Puget has agreed to purchase an annual average of 123 megawatts of electrical energy.
The power sales agreement provides for the sale of electrical energy at a total price equal to the sum of (i) a fixed price component and (ii) a variable price component multiplied by an escalation factor for the year in which the energy is delivered. The schedule of annual fixed average energy prices (expressed in cents per kilowatt hour) in effect through 2013 under the Sumas power sales agreement is as follows:

                      FIXED                              FIXED                              FIXED
                      ENERGY                             ENERGY                             ENERGY
        YEAR          PRICE                YEAR          PRICE                YEAR          PRICE
- --------------------  ------       --------------------  ------       --------------------  ------
1996................  3.19c
1997................  3.38c
1998................  3.64c
1999................  3.98c
2000................  4.23c
2001................  6.23c
2002................  6.11c
2003................  6.22c
2004................  6.33c
2005................  6.45c
2006................  6.57c
2007................  5.23c
2008................  5.31c
2009................  5.40c
2010................  5.49c
2011................  5.58c
2012................  5.58c
2013................  5.58c	

The variable price component is set according to a scheduled rate set forth in the agreement, which in 1995 was .97c per kilowatt hour, and escalates annually by a factor equal to the U.S. Gross National Product Implicit Price Deflator. For 1995, the average price paid by Puget under the power sales agreement was 2.954c per kilowatt hour. Pursuant to the power sales agreement, Puget may displace the production of the Sumas Facility when the cost of Puget's replacement power is less than the Sumas Facility's incremental power generation costs. Thirty-five percent of the savings to Puget under this displacement provision are shared with
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the Sumas Facility. In 1995, the Sumas Facility's net profit was increased by $278,000 as a result of the displacement provision. The Company currently estimates a similar level of displacement in 1996 as that experienced in 1995.
In addition to the sale of electricity to Puget, pursuant to a long-term steam supply and dry kiln lease agreement, the Sumas Facility produces and sells approximately 23,000 pounds per hour of low pressure steam to an adjacent lumber-drying facility owned by Sumas, which has been leased to and is operated by Socco, Inc. ("Socco"), an SEI affiliate. It is necessary to continue to operate the dry kiln facility in order to maintain the Sumas Facility's QF status. See "-- Government Regulation."
In connection with the development of the Sumas Facility, Canadian natural gas reserves located primarily in northeastern British Columbia, Canada were acquired by Sumas through its wholly owned subsidiary, ENCO. The gas reserves owned by ENCO totalled 138 billion cubic feet as of January 1, 1996. Firm transportation is contracted for on the Westcoast Energy Inc. pipeline. Gas is delivered to Huntington, British Columbia where it is transferred into Sumas' own pipeline for transportation to the plant. ENCO is currently supplying approximately 12,000 million British thermal units per day ("mmbtu/day") to the Sumas Facility. The remaining 13,000 mmbtu/day requirement is being supplied under a one-year contract with West Coast Gas Services, Inc. The Company believes that the gas reserves owned by ENCO and the availability of supplemental gas supplies are sufficient to fuel the Sumas Facility through the year 2013.
The Company operates and maintains the Sumas Facility under an operating and maintenance agreement pursuant to which the Company is reimbursed for certain costs and is entitled to a fixed annual fee and an incentive payment based on project performance. This agreement has an initial term of ten years expiring in April 2003 and provides for extensions.
The Sumas Facility is located on 13.5 acres located in Sumas, Washington, which are leased from the Port of Bellingham under the terms of a 23.5-year lease expiring in 2014, subject to renewal. The lease provides for rental payments according to a fixed schedule.
During 1995, the Sumas Facility generated approximately 1,026,000,000 kilowatt hours of electrical energy and approximately $31.5 million of total revenue. In 1995, the Company recognized a loss of approximately $3.0 million in accordance with the terms of the Sumas partnership agreement, and recorded revenue of $2.0 million for services performed under the operating and maintenance agreement.
King City Facility
The King City cogeneration facility (the "King City Facility") is a 120 megawatt natural gas-fired combined cycle facility located in King City, California. In April 1996, the Company entered into a long-term operating lease for this facility with BAF Energy, A California Limited Partnership ("BAF"). Under the terms of the operating lease, Calpine makes semi-annual lease payments to BAF, a portion of which is supported by a $100.7 million collateral fund, owned by the Company. The collateral consists of a portfolio of investment grade and U.S. Treasury Securities that will mature serially in amounts equal to a portion of the lease payments.
The Company financed the collateral fund and other transaction costs with the $45 Million Bank of Nova Scotia Loan and $13.3 million of borrowings under the Credit Suisse Credit Facility (both of which were repaid with a portion of the net proceeds from the sale of the 10 1/2% Senior Notes), as well as $50.0 million of proceeds from the Preferred Stock Investment by Electrowatt.
The power plant consists of a General Electric Frame 7 Model EA combustion turbine generator, a Nooter/Eriksen heat recovery steam generator, an ASEA Brown Boveri ("ABB") steam turbine generator and two Nebraska Boiler auxiliary boilers. The King City Facility commenced commercial operation in 1989 and has operated at an average availability of approximately 97%.
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Electricity generated by the King City Facility is sold to PG&E under a 30-year power sales agreement terminating in 2019. The power sales agreement contains payment provisions for capacity and energy. The power sales agreement provides for a firm capacity payment of $184 per kilowatt year for 111 megawatts for the term of the agreement so long as the King City Facility delivers 80% of the firm capacity during designated periods of the year. Additional capacity payments are received for as-delivered capacity in excess of 111 megawatts delivered during peak and partial peak hours. The following schedule sets forth the as-delivered capacity prices per kilowatt year:

                                                       AS-DELIVERED
                        YEAR                          CAPACITY PRICE
----------------------------------------------------  --------------
1996................................................       $176
1997................................................       $188
1998................................................       $188	

Thereafter, the payment for as-delivered capacity will be the greater of $188 per kilowatt year or PG&E's then current as-delivered capacity rate. Through 1998, payments for electrical energy produced are based on 100% of PG&E's avoided cost of energy for the period of January 1 through April 30, and 80% at avoided cost and 20% at fixed prices for the period of May 1 through December
31. The schedule of fixed average energy prices (expressed in cents per kilowatt hour) in effect through 1998 under the King City Facility power sales agreement is as follows:

                                                          ENERGY
                          YEAR                            PRICE
--------------------------------------------------------  ------
1996....................................................  12.24c
1997....................................................  13.14c
1998....................................................  13.14c	

Thereafter, PG&E is required to pay for electrical energy actually delivered at prices equal to PG&E's then avoided cost of energy (as determined by the CPUC). PG&E's avoided cost of energy varies from month to month and has ranged from an annual average of 1.84c to 2.96c per kilowatt hour since 1992. During 1995, PG&E's avoided cost of energy averaged approximately 1.84c per kilowatt hour.
Through April 28, 1999, the power sales agreement allows for dispatchable operation which gives PG&E the right to curtail the number of hours per year that the King City Facility operates. PG&E has an option to extend its curtailment rights for two additional one-year terms. If PG&E exercises the curtailment extension option, it will be required to pay an additional .7c per kilowatt hour for all energy delivered from the King City Facility.
In addition to the sale of electricity to PG&E, the King City Facility produces and sells thermal energy to a thermal host, Basic Vegetable Products, Inc. ("BVP"), an affiliate of BAF, under a long-term contract coterminous with the power sales agreement. It is necessary to continue to operate the host facility in order to maintain the King City Facility's QF status. See "-- Government Regulation." The BVP facility was built in 1957 and processes between 30% and 40% of the dehydrated onion and garlic production in the United States.
Natural gas for the King City Facility is supplied pursuant to a contract with Chevron U.S.A. Inc. ("Chevron") expiring June 30, 1997. Natural gas is transported under a firm transportation agreement, expiring June 30, 1997, via a dedicated 38-mile pipeline owned and operated by PG&E. The Company believes that upon expiration of these agreements that it will be able to obtain sufficient quantities and firm transportation of natural gas to operate the King City Facility for the remaining term of the power sales agreement.
Fee title to the premises is owned by Basic American, Inc., who has leased the premises to an affiliate of BAF for a term equivalent to the term of the power sales agreement for the King City Facility. The Company is subleasing the premises, together with certain easements, from such affiliate of BAF pursuant to a ground sublease for approximately 15 acres.
47

Gilroy Facility
On August 29, 1996, the Company acquired the Gilroy cogeneration facility (the "Gilroy Facility"), a 120 megawatt gas-fired cogeneration power plant located in Gilroy, California, from McCormick & Company, Inc. The Company purchased the Gilroy Facility for a purchase price of $125.0 million plus certain contingent consideration, which the Company currently estimates will amount to approximately $24.1 million.
The acquisition of the Gilroy Facility was financed utilizing a non-recourse project loan in the aggregate amount of $116.0 million. Such loan, which was provided by Banque Nationale de Paris, consists of a 15-year tranche in the amount of $81.0 million and an 18-year tranche in the amount of $35.0 million and bears interest at fixed and floating rates.
The power plant consists of a General Electric Frame 7 Model EA combustion turbine generator, an AEG-KANIS (ABB) steam turbine, a Henry Vogt heat recovery steam generator, two auxiliary boilers and an inlet chiller using a Henry Vogt ice machine. The Gilroy Facility commenced commercial operation in March 1988 and has operated at an average availability of approximately 98.5%.
Electricity generated by the Gilroy Facility is sold to PG&E under an original 30-year power sales agreement terminating in 2018. The power sales agreement contains payment provisions for capacity and energy. The power sales agreement provides for a firm capacity payment of $172 per kilowatt year for 120 megawatts for the term of the agreement so long as the Gilroy Facility delivers 80% of the firm capacity during designated periods of the year. Additional capacity payments are received for as-delivered capacity in excess of 120 megawatts delivered. The following schedule sets forth the as-delivered capacity prices per kilowatt year:

                                                           AS-DELIVERED
                          YEAR                            CAPACITY PRICE
--------------------------------------------------------  --------------
1996....................................................       $176
1997....................................................       $188	

Thereafter, the payment for as-delivered capacity will be the greater of $188 per kilowatt year or PG&E's then current as-delivered capacity rate. In addition, the power sales agreement provides for payments for electrical energy actually delivered during the period of dispatchable operation at a price equal to PG&E's avoided cost of energy excluding adders (as determined by the CPUC). Thereafter, during the period of baseload operation, PG&E is required to pay for electrical energy actually delivered at prices equal to PG&E's then avoided cost of energy. PG&E's avoided cost of energy varies from month to month and has ranged from an annual average of 1.84c to 2.96c per kilowatt hour since 1992. During 1995, PG&E's avoided cost of energy averaged approximately 1.84c per kilowatt hour.
Through December 31, 1998, the power sales agreement allows for dispatchable operation which gives PG&E the right to curtail the number of hours per year that the Gilroy Facility operates.
In addition to the sale of electricity to PG&E, the Gilroy Facility produces and sells thermal energy to a thermal host, Gilroy Foods, Inc. ("Gilroy Foods"), under a long-term contract that is coterminous with the power sales agreement. Gilroy Foods is a recognized leader in the production of dehydrated onions and garlic. Simultaneously with the acquisition by the Company of the Gilroy Facility, Gilroy Foods was acquired by ConAgra, Inc., an international food company with 1995 revenues of approximately $24.1 billion. It is necessary to continue to operate the host facility in order to maintain the Gilroy Facility's QF status. See "-- Government Regulation."
Natural gas for the Gilroy Facility is supplied pursuant to a contract with Amoco Energy Trading Corporation ("Amoco") expiring July 31, 1997. The Company believes that upon expiration of this fuel supply agreement, it will be able to obtain a sufficient quantity of natural gas to operate the Gilroy Facility for the remaining term of the power sales agreement. Natural gas is transported under a firm transportation agreement, expiring July 1, 1997, via a dedicated 300-yard pipeline owned and maintained by PG&E.
The Gilroy Facility is located on approximately five acres of land which is leased to the Company by Gilroy Foods. The lease term runs concurrent with the term of the power sales agreement.
48

Greenleaf 1 and 2 Facilities
On April 21, 1995, Calpine completed the acquisition of the Greenleaf 1 and 2 cogeneration facilities (the "Greenleaf 1 and 2 Facilities") from Radnor Power Corporation, an affiliate of LFC Financial Corporation ("LFC"), for an adjusted purchase price of $81.5 million.
On June 30, 1995, Calpine refinanced the existing debt on the Greenleaf 1 and 2 Facilities by borrowing $76.0 million from Sumitomo Bank. The non-recourse project financing with Sumitomo Bank is divided into two tranches, a $60.0 million fixed rate loan facility which bears interest on the unpaid principal at a fixed rate of 7.415% per annum with amortization of principal based on a fixed schedule through June 30, 2005, and a $16.0 million floating rate loan facility which bears interest based on LIBOR plus an applicable margin (6.5% as of December 31, 1995) with the amortization of principal based on a fixed schedule through December 31, 2010.
The Greenleaf 1 and 2 Facilities have a combined natural gas requirement of approximately 22,000 mmbtu/day. The Company, through its wholly owned subsidiary Calpine Fuels Corporation ("Calpine Fuels"), entered into a gas supply agreement with Montis Niger, Inc. ("MNI"), an affiliate of LFC, which owns and operates a local gas field that is connected to the facilities. Calpine Fuels is committed to purchasing all gas produced by MNI under this agreement which terminates in December 2019. The quantity of gas produced by MNI varies and is currently less than the facilities' full requirements. As a result, Calpine Fuels has supplemented the MNI gas supply with a short-term contract with Coastal Gas Marketing Company, which expires on September 30, 1996. This gas is delivered over PG&E's intrastate pipeline which is directly connected to each facility. The Greenleaf 1 and 2 Facilities have interruptible transportation agreements with PG&E, expiring in June 1997. The Company believes that it will be able to obtain a sufficient quantity of natural gas to operate the Greenleaf 1 and 2 Facilities for the remaining term of the power sales agreement.
Greenleaf 1 Facility. The Greenleaf 1 cogeneration facility (the "Greenleaf 1 Facility") is a 49.5 megawatt natural gas-fired cogeneration facility located near Yuba City, California. The Greenleaf 1 Facility includes an LM5000 gas turbine manufactured by General Electric, a Vogt heat recovery steam generator and a condensing General Electric steam turbine. The Greenleaf 1 Facility commenced commercial operation in March 1989. Since its acquisition by the Company in April 1995, the power plant has operated at an average availability of approximately 94.4%.
Electricity generated by the Greenleaf 1 Facility is sold to PG&E under a 30-year power sales agreement terminating in 2019 which contains payment provisions for capacity and energy. The power sales agreement provides for a firm capacity payment of $184 per kilowatt year for 49.2 megawatts for the term of the agreement, so long as the Greenleaf 1 Facility delivers 80% of its firm capacity during certain designated periods of the year, and an as-delivered capacity payment for an additional .3 megawatts of capacity. The following schedule sets forth the as-delivered capacity prices per kilowatt year through 1997 under the Greenleaf 1 Facility power sales agreement:

                                                       AS-DELIVERED
                        YEAR                          CAPACITY PRICE
----------------------------------------------------  --------------
1996................................................       $176
1997................................................       $188	

Thereafter, the payment for as-delivered capacity will be the greater of $188 per kilowatt year or PG&E's then current as-delivered capacity rate. In addition, the power sales agreement provides for payments for up to 49.5 megawatts of electrical energy actually delivered at a price equal to PG&E's avoided cost of energy (as determined by the CPUC). PG&E's avoided cost of energy varies from month to month and has ranged from an annual average of 1.84c to 2.96c per kilowatt hour since 1992. During 1995, PG&E's avoided cost of energy averaged approximately 1.84c per kilowatt hour.
49

In accordance with the power sales agreement, PG&E is entitled to curtail the Greenleaf 1 Facility during hydro-spill periods, or during periods of negative avoided costs. During 1995, the Greenleaf 1 Facility did not experience curtailment, and the Company does not expect to experience curtailment at such facility during 1996. PG&E may also interrupt or reduce deliveries if necessary to repair its system or because of system emergencies, forced outages, force majeure and compliance with prudent electrical practices.
In addition to the sale of electricity to PG&E, the Greenleaf 1 Facility sells thermal energy, in the form of hot exhaust to dry wood waste, to a thermal host which is owned and operated by the Company. It is necessary to continue to operate the host facility in order to maintain the Greenleaf 1 Facility's QF status. See "-- Government Regulation."
The Greenleaf 1 Facility is located on 77 acres owned by the Company near the rural area of Yuba City, California.
From April 21, 1995 through December 31, 1995, the Greenleaf 1 Facility generated approximately 258,921,000 kilowatt hours of electric energy for sale to PG&E and approximately $13.9 million in revenue.
Greenleaf 2 Facility. The Greenleaf 2 cogeneration facility (the "Greenleaf 2 Facility") is a 49.5 megawatt natural gas-fired cogeneration facility located near Yuba City, California. The Greenleaf 2 Facility includes a STIG LM5000 gas turbine manufactured by General Electric and a Deltak heat recovery steam generator. The Greenleaf 2 Facility commenced commercial operation in December 1989. Since its acquisition by the Company in April 1995, the power plant has operated at an average availability of approximately 95%.
Electricity generated by the Greenleaf 2 Facility is sold to PG&E under a 30-year power sales agreement terminating in 2019 which includes payment provisions for capacity and energy. The power sales agreement provides for a firm capacity payment of $184 per kilowatt year for 49.2 megawatts for the term of the agreement, so long as the Greenleaf 2 Facility delivers 80% of its firm capacity during certain designated periods of the year, and an as-delivered capacity payment for an additional .3 megawatts of capacity. The following schedule sets forth the as-delivered capacity prices per kilowatt year through 1997 under the Greenleaf 2 Facility power sales agreement:

                                                       AS-DELIVERED
                        YEAR                          CAPACITY PRICE
----------------------------------------------------  --------------
1996................................................       $176
1997................................................       $188	

Thereafter, the payment for as-delivered capacity will be the greater of $188 per kilowatt year or PG&E's then current as-delivered capacity rate. In addition, the power sales agreement provides for payments for up to 49.5 megawatts of electrical energy actually delivered at a price equal to PG&E's avoided cost of energy (as determined by the CPUC). PG&E's avoided cost of energy varies from month to month and has ranged from an annual average of 1.84c to 2.96c per kilowatt hour since 1992. During 1995, PG&E's avoided cost of energy averaged approximately 1.84c per kilowatt hour.
In accordance with the power sales agreement, PG&E is entitled to curtail the Greenleaf 2 Facility during hydro-spill periods or during any period of negative avoided costs. During 1995, the Greenleaf 2 Facility did not experience curtailment, and the Company does not expect to experience curtailment at such facility during 1996. PG&E may also interrupt or reduce deliveries if necessary to repair its system or because of system emergencies, forced outages, force majeure and compliance with prudent electrical practices.
In addition to the sale of electricity to PG&E, the Greenleaf 2 Facility sells thermal energy to Sunsweet Growers, Inc. ("Sunsweet") pursuant to a 30-year contract. Sunsweet is the largest producer of dried fruit in the United States. It is necessary to continue to operate the host facility in order to maintain the status of the Greenleaf 2 Facility as a QF. See "-- Government Regulation."
The Greenleaf 2 Facility is located on 2.5 acres of land under a lease from Sunsweet, which runs concurrent with the power sales agreement.
50

From April 21, 1995 through December 31, 1995, the Greenleaf 2 Facility generated approximately 276,038,000 kilowatt hours of electric energy for sale to PG&E and approximately $14.5 million of revenue.
Agnews Facility
The Agnews cogeneration facility (the "Agnews Facility") is a 29 megawatt natural gas-fired combined cycle cogeneration facility located on the East Campus of the state-owned Agnews Developmental Center in San Jose, California. Calpine holds a 20% ownership interest in GATX Calpine-Agnews, Inc., which is the sole stockholder of O.L.S. Energy-Agnews, Inc. ("O.L.S. Energy-Agnews"). O.L.S. Energy-Agnews leases the Agnews Facility under a sale leaseback arrangement. The other stockholder of GATX Calpine-Agnews, Inc. is GATX Capital Corporation ("GATX"), which has an 80% ownership interest. In connection with the sale leaseback arrangement, Calpine has agreed to reimburse GATX for its proportionate share of certain payments that may be made by GATX with respect to the Agnews Facility. The Company and GATX managed the development and financing of the Agnews Facility, which commenced commercial operations in December 1990.
The Company managed the engineering, construction and start-up of the Agnews Facility. The construction work was performed by Power Systems Engineering, Inc. under a turnkey contract. The power plant consists of an LM2500 aeroderivative gas turbine manufactured by General Electric, a Deltak unfired heat recovery steam generator and a Shin Nippon steam turbine-generator. Since start-up, the Agnews Facility has operated at an average availability of approximately 96.5%.
The total cost of the Agnews Facility was approximately $39 million. The construction financing was provided by Credit Suisse in the amount of $28.0 million. After the commencement of commercial operation, the facility was sold to Nynex Credit Corporation under a sale leaseback arrangement with O.L.S. Energy-Agnews. Under the sale leaseback, O.L.S. Energy-Agnews has entered into a 22-year lease, commencing March 1991, providing for the payment of a fixed base rental, renewal options and a purchase option at fair market value at the termination of the lease.
Electricity generated by the Agnews Facility is sold to PG&E under a 30-year power sales agreement terminating in 2021 which contains payment provisions for capacity and energy. The power sales agreement provides for a payment of $196 per kilowatt year for 24 megawatts of firm capacity for the term of the agreement, so long as the Agnews Facility delivers at least 80% of its firm capacity of 24 megawatts during certain designated periods of the year, and an as-delivered capacity payment for an additional 4 megawatts of capacity. The following schedule sets forth the as-delivered capacity prices per kilowatt year through 1998 under the Agnews Facility power sales agreement:

                                                       AS-DELIVERED
                        YEAR                          CAPACITY PRICE
----------------------------------------------------  --------------
1996................................................       $176
1997................................................       $188
1998................................................       $188	

Thereafter, the payment for as-delivered capacity will be at the greater of $188 per kilowatt year or PG&E's then current as-delivered capacity rate. In addition, the power sales agreement provides for payments for up to 32 megawatts of electrical energy actually delivered at a price equal to (i) through 1998, the product of PG&E's fixed incremental energy rate and PG&E's utility electric generation gas cost, and (ii) thereafter, PG&E's avoided cost of energy (as determined by the CPUC). PG&E's avoided cost of energy varies from month to month and has ranged from an annual average of 1.84c to 2.96c per kilowatt hour since 1992. During 1995, PG&E's avoided cost of energy averaged approximately 1.84c per kilowatt hour.
Under certain circumstances, PG&E may curtail energy deliveries for up to 1,000 off-peak hours per year. During 1995, PG&E curtailed the energy purchased under the power sales agreement by 1,000 hours. The Company currently expects the maximum amount of curtailment allowed under the agreement during 1996.
51

In addition to the sale of electricity to PG&E, the Agnews Facility produces and sells electricity and approximately 7,000 pounds per hour of steam to the Agnews Developmental Center pursuant to a 30-year energy service agreement. The energy service agreement provides that the State of California will purchase from the Agnews Facility all of its requirements for steam (up to a specified maximum) and for electricity (which has historically been less than one megawatt per year) for the East Campus of the Agnews Developmental Center for the term of the agreement. Steam sales are priced at the cost of production for the Agnews Developmental Center. Electricity sales are priced at the rates that would otherwise be paid to PG&E by the Agnews Developmental Center. The State of California is required to utilize the minimum amount of steam required to maintain the Agnews Facility's QF status. See "-- Government Regulation."
The supply of natural gas for the Agnews Facility is currently provided under a full requirements fuel supply agreement between O.L.S. Energy-Agnews and Amoco Energy Trading Corporation ("Amoco") which expires June 30, 1997. The Company believes that, upon expiration of this fuel supply agreement, it will be able to obtain a sufficient quantity of natural gas to operate the Agnews Facility for the remaining term of the power sales agreement. Intrastate transportation is provided under a firm gas transportation agreement with PG&E expiring in June 1997.
The Agnews Facility is operated by the Company under an operating and maintenance agreement pursuant to which the Company is reimbursed for certain costs and is entitled to a fixed annual fee and an incentive payment based on performance. This agreement has an initial term of six years expiring on December 31, 1996 and may be automatically renewed for an additional six-year term, provided certain performance standards are met, and thereafter upon mutually agreeable terms. The Company expects the contract will be renewed on December 31, 1996.
The Agnews Facility is located on 1.4 acres of land leased from the Agnews Development Center under the terms of a 30-year lease that expires in 2021. This lease provides for rental payments to the State of California on a fixed payment basis until January 1, 1999, and thereafter based on the gross revenues derived from sales of electricity by the Agnews Facility, as well as a purchase option at fair market value.
During 1995, the Agnews Facility generated approximately 225,683,000 kilowatt hours of electrical energy and total revenue of $10.8 million. In 1995, the Company recognized a loss of approximately $82,000 as a result of the Company's 20% ownership interest and recorded revenue of $1.5 million for services performed under the operating and maintenance agreement.
Watsonville Facility
The Watsonville cogeneration facility (the "Watsonville Facility") is a 28.5 megawatt natural gas-fired combined cycle cogeneration facility located in Watsonville, California. On June 29, 1995, the Company acquired the operating lease for this facility for $900,000 from Ford Motor Credit Company. Under the terms of the lease, rent is payable each month from July through December. The lease terminates on December 29, 2009. The Watsonville Facility commenced commercial operation in May 1990. The power plant consists of a General Electric LM2500 gas turbine, a Deltak heat recovery steam generator and a Shin Nippon steam turbine. Since its acquisition by the Company in June 1995, the power plant has operated at an average availability of approximately 96.5%.
Electricity generated by the Watsonville Facility is sold to PG&E under a 20-year power sales agreement terminating in 2009 which contains payment provisions for capacity and energy. The power sales agreement provides for a payment of $178 per kilowatt year for 20.9 megawatts of firm capacity for the term of the agreement, so long as the Watsonville Facility delivers at least 80% of its firm capacity of 20.9 megawatts during certain designated periods of the year, and an as-delivered capacity payment for an additional 7.6 megawatts of capacity. In addition, the power sales agreement provides for payments for up to 28.5 megawatts of electrical energy actually delivered. Through April of 2000, 1% of energy will be sold under the fixed energy price schedule set forth below, and 99% of the energy will be sold at PG&E's avoided cost of energy. The following schedule sets forth the fixed average energy prices (expressed in cents per kilowatt
52

hour) and the as-delivered capacity prices per kilowatt year through 2000 for energy deliveries under the Watsonville Facility power sales agreement:

                                              ENERGY     AS-DELIVERED
                    YEAR                       PRICE    CAPACITY PRICE
--------------------------------------------  -------   --------------
1996........................................  12.24c         $176
1997........................................  13.14c         $188
1998........................................  13.90c         $188
1999........................................  13.90c         $188
2000........................................  13.90c         $188	

Thereafter, PG&E will pay for energy delivered at prices equal to PG&E's avoided cost of energy (as determined by the CPUC), and will pay for as-delivered capacity at the greater of $188 per kilowatt year or PG&E's then current as-delivered capacity rate. PG&E's avoided cost of energy varies from month to month and has ranged from an annual average of 1.84c to 2.96c per kilowatt hour since 1992. During 1995, PG&E's avoided cost of energy averaged approximately 1.84c per kilowatt hour.
Under certain circumstances, PG&E may curtail energy deliveries for a block of up to 400 hours between January 1 and April 15 and an additional 900 off-peak hours from October 1 though April 30. From June 29, 1995 through December 31, 1995, PG&E curtailed energy purchases of 212 hours under the power sales agreement.
In addition to the sale of electricity to PG&E, during 1995 the Watsonville Facility produced and sold steam to two thermal hosts, Norcal Frozen Foods, Inc. ("Norcal") and Farmers Processing, both food processors. In August 1995, Norcal sold its facility to a subsidiary of Dean Foods ("Dean Foods"), which closed the facility on February 9, 1996. The lessor of the Watsonville Facility has constructed a water distillation facility on the site of the Watsonville Facility to replace the Dean Foods food processing facility. This facility commenced operations in August 1996 and is operated by the Company. It is necessary to continue to operate the host facilities in order to maintain the Watsonville Facility's QF status. See "-- Government Regulation."
Amoco is the supplier of natural gas to the Watsonville Facility. The Company has negotiated a contract with Amoco, which it expects to execute by September 1, 1996 and which will be effective through June 30, 1997. In the interim, the Company has executed a series of monthly contracts with Amoco. PG&E provides firm gas transportation to the Watsonville Facility under a contract expiring June 30, 1997. The Company believes that upon expiration of this fuel supply agreement, it will be able to obtain a sufficient quantity of natural gas to operate the Watsonville Facility for the remaining term of the power sales agreement.
The Watsonville Facility is located on 1.8 acres of land leased from Dean Foods under the terms of a 30-year lease expiring in 2010.
For the period from June 29, 1995 to December 31, 1995, the Watsonville Facility generated approximately 117,147,000 kilowatt hours of electrical energy for sale to PG&E and approximately $5.9 million in revenue.
West Ford Flat Facility
The West Ford Flat geothermal facility (the "West Ford Flat Facility") consists of a 27 megawatt geothermal power plant and associated steam fields located in the eastern portion of The Geysers area of northern California. The West Ford Flat Facility includes a power plant consisting of two turbines manufactured by Mitsubishi Heavy Industries, Inc. with rotors remanufactured by ABB Industries, Inc., two generators manufactured by Electric Machinery, Inc., and seven production wells and steam leases. The West Ford Flat Facility commenced commercial operation in December 1988. Since start-up, the West Ford Flat Facility has operated at an average availability of approximately 98%.
53

Electricity generated by the West Ford Flat Facility is sold to PG&E under a 20-year power sales agreement terminating in 2008 which contains payment provisions for capacity and energy. The power sales agreement provides for a firm capacity payment of $167 per kilowatt year for 27 megawatts of firm capacity for the term of the agreement, so long as the West Ford Flat Facility delivers 80% of its firm capacity during certain designated periods of the year. In addition, the power sales agreement provides for energy payments for electricity actually delivered based on a fixed price derived from a scheduled forecast of energy prices over the initial ten-year term of the agreement ending December 1998. The schedule of fixed average energy prices (expressed in cents per kilowatt hour) in effect through 1998 under the West Ford Flat Facility power sales agreement is as follows:

                                                          ENERGY
                          YEAR                            PRICE
--------------------------------------------------------  ------
1996....................................................  12.89c
1997....................................................  13.83c
1998....................................................  13.83c	

Thereafter, PG&E is required to pay for electrical energy actually delivered at prices equal to PG&E's avoided cost of energy (as determined by the CPUC). PG&E's avoided cost of energy varies from month to month and has ranged from an annual average of 1.84c to 2.96c per kilowatt hour since 1992. During 1995, PG&E's avoided cost of energy averaged approximately 1.84c per kilowatt hour. The Company cannot accurately predict the avoided cost of energy prices that will be in effect at the expiration of the fixed price period under this agreement.
Under certain circumstances, PG&E may curtail energy deliveries for up to 1,000 off-peak hours per year. During 1995, PG&E curtailed the energy purchased under this agreement by 1,000 hours. In the event of any such curtailment, the Company's results of operations may be materially adversely affected. The Company currently expects the maximum amount of curtailment allowed under the agreement during 1996.
The Company believes that the geothermal reserves that supply energy for use by the West Ford Flat Facility will be sufficient to operate at full capacity for the entire term of the power sales agreement due principally to high reservoir pressures, low projected decline rates, limited development in adjacent areas and the substantial productive acreage dedicated to the West Ford Flat Facility.
The West Ford Flat Facility is located on 267 acres of leased land located in The Geysers. For a description of the leases covering the properties located in The Geysers, see "-- Properties."
During 1995, the West Ford Flat Facility generated approximately 216,614,000 kilowatt hours of electrical energy for sale to PG&E and approximately $29.4 million of revenue.
Bear Canyon Facility
The Bear Canyon facility (the "Bear Canyon Facility") consists of a 20 megawatt geothermal power plant and associated steam fields located in the eastern portion of The Geysers area of northern California, two miles south of the West Ford Flat Facility. The Bear Canyon Facility includes a power plant consisting of two turbine generators manufactured by Mitsubishi Heavy Industries, Inc. with rotors remanufactured by ABB Industries, Inc., as well as eight production wells, an injection well and steam reserves. The Bear Canyon Facility commenced commercial operation in October 1988. Since start-up, the Bear Canyon Facility has operated at an average availability of approximately 98.4%.
Electricity generated by the Bear Canyon Facility is sold to PG&E under two 10 megawatt, 20-year power sales agreements terminating in 2008 which contain payment provisions for capacity and energy. One of the power sales agreements provides for a firm capacity payment of $156 per kilowatt year on four megawatts for the term of the agreement, so long as the Bear Canyon Facility delivers 80% of its firm capacity during certain designated periods of the year, and an as-delivered capacity payment for the additional six megawatts of capacity. The other agreement provides for an as-delivered capacity payment for the entire 10 megawatts. Both agreements provide for energy payments for electricity actually delivered based on a fixed price basis
54

through the initial ten-year term of the agreement ending September 1998. The following schedule sets forth the fixed average energy prices (expressed in cents per kilowatt hour) and the as-delivered capacity prices per kilowatt year through 1998 for energy deliveries under the Bear Canyon Facility power sales agreements:

                                              ENERGY     AS-DELIVERED
                    YEAR                       PRICE    CAPACITY PRICE
--------------------------------------------  -------   --------------
1996........................................  12.89c         $176
1997........................................  13.83c         $188
1998........................................  13.83c         $188	

Thereafter, PG&E will pay for energy delivered at prices equal to PG&E's avoided cost of energy (as determined by the CPUC), and will pay for as-delivered capacity at the greater of $188 per kilowatt year or PG&E's then current as-delivered capacity rate. PG&E's avoided cost of energy varies from month to month and has ranged from an annual average of 1.84c to 2.96c per kilowatt hour since 1992. During 1995, PG&E's avoided cost of energy averaged approximately 1.84c per kilowatt hour. The Company cannot accurately predict the avoided cost of energy prices that will be in effect at the expiration of the fixed price period under this agreement.
Under certain circumstances, PG&E may curtail energy deliveries for up to 1,000 off-peak hours per year. During 1995, PG&E curtailed the energy purchased under this agreement by 1,000 hours. In the event of any such curtailment, the Company's results of operations may be materially adversely affected. The Company currently expects the maximum amount of curtailment allowed under the agreement during 1996.
The Company believes that the geothermal reserves for the Bear Canyon Facility will be sufficient to operate at full capacity for substantially all of the remaining term of the power sales agreements due principally to high reservoir pressures, low projected decline rates, limited development in adjacent areas and the substantial productive acreage dedicated to the Bear Canyon Facility.
The Bear Canyon Facility is located on 284 acres of land located in The Geysers covered by two leases, one with the State of California and the other with a private landowner. For a description of the leases covering the properties located at The Geysers, see "-- Properties."
During 1995, the Bear Canyon Facility generated approximately 164,847,000 kilowatt hours of electrical energy and approximately $21.8 million of revenue.
Aidlin Facility
The Aidlin geothermal facility (the "Aidlin Facility") consists of a 20 megawatt geothermal power plant and associated steam fields located in the western portion of The Geysers area of northern California. The Company holds an indirect 5% ownership interest in the Aidlin Facility. The Company's ownership interest is held in the form of a 10% general partnership interest in a limited partnership (the "Aidlin Partnership"), which in turn owns a 50% ownership interest, as both a limited and general partner, in Geothermal Energy Partners Ltd. ("GEP"), a limited partnership which is the owner of the Aidlin Facility. MetLife Capital Corporation owns the remaining 90% interest in the Aidlin Partnership as a limited partner. The remaining 50% of GEP is owned by subsidiaries of Mission Energy Company and Sumitomo Corporation. The Aidlin Facility commenced commercial operation in May 1989.
The Aidlin Facility includes a power plant consisting of two turbine generators manufactured by Fuji Electric and ABB Industries, Inc., as well as seven production wells and two injection wells. Since start-up, the Aidlin Facility has operated at an average availability of approximately 99%.
The construction of the Aidlin Facility was financed with a $59.4 million term loan provided by Prudential, which bears interest at a fixed rate of 10.48% per annum and matures on June 30, 2008 according to a specified amortization schedule.
Electricity generated by the Aidlin Facility is sold to PG&E under two 10 megawatt, 20-year power sales agreements terminating in 2009 which contain payment provisions for capacity and energy. The power sales
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agreements provide for an aggregate firm capacity payment for 17 megawatts of $167 per kilowatt year for the term of the agreements, so long as the Aidlin Facility delivers 80% of its capacity during certain designated periods of the year. In addition, the Aidlin Facility power sales agreements provide for energy payments for 20 megawatts based on a schedule of fixed energy prices (expressed in cents per kilowatt hour) in effect through 1999 as follows:

                                                          ENERGY
                          YEAR                            PRICE
--------------------------------------------------------  ------
1996....................................................  12.89c
1997....................................................  13.83c
1998....................................................  13.83c
1999....................................................  13.83c	

Thereafter, PG&E is required to pay for electrical energy actually delivered at prices equal to PG&E's avoided cost of energy (as determined by the CPUC). PG&E's avoided cost of energy varies from month to month and has ranged from an annual average of 1.84c to 2.96c per kilowatt hour since 1992. During 1995, PG&E's avoided cost of energy averaged approximately 1.84c per kilowatt hour. The Company cannot accurately predict the avoided cost of energy that will be in effect at the expiration of the fixed price period under this agreement.
Under certain circumstances, PG&E may curtail energy deliveries for up to 1,000 off-peak hours per year. During 1995, PG&E curtailed the energy purchased under this agreement by 1,000 hours. The Company currently expects the maximum amount of curtailment under the agreement in 1996.
The output of the Aidlin Facility is expected to decline over the remaining life of the facility unless additional reserves are developed on existing or adjacent leases and enhanced water injection projects are successful in reducing field declines. See "Risk Factors -- Risks Related to the Development and Operation of Geothermal Energy Resources."
The Aidlin Facility is operated and maintained by the Company under an operating and maintenance agreement pursuant to which the Company is reimbursed for certain costs and is entitled to an incentive payment based on project performance. This agreement expires on December 31, 1999.
The Aidlin Facility is located on 713.8 acres of land located in The Geysers, which is leased by GEP from a private landowner. The lease will remain in force so long as geothermal steam is produced in commercial quantities.
During 1995, the Aidlin Facility generated approximately 174,087,000 kilowatt hours of electrical energy and revenue of $21.7 million. In 1995, the Company recognized revenue of approximately $277,000 as a result of the Company's 5% ownership interest and $3.5 million for services performed under the operating and maintenance agreement.
STEAM FIELDS
Thermal Power Company Steam Fields
The Company acquired Thermal Power Company on September 9, 1994 for a purchase price of $66.5 million. Thermal Power Company owns a 25% undivided interest in certain geothermal steam fields located at The Geysers in northern California (the "Thermal Power Company Steam Fields"). Union Oil Company of California ("Union Oil") owns the remaining 75% interest in the steam fields and operates and maintains the steam fields. The Thermal Power Company Steam Fields include the leasehold rights to 13,908 acres of steam fields which supply steam to 12 PG&E power plants located in The Geysers and include 247 production wells, 19 injection wells and 52 miles of steam-transporting pipeline. See "-- Properties." The 12 plants have a nameplate capacity of 978 megawatts and currently have the capability to operate at 604 megawatts providing the Company with an effective interest in 151 megawatts. The steam fields commenced commercial operation in 1960.
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The Thermal Power Company Steam Fields produce steam for sale to PG&E under a long-term steam sales agreement. Under this steam sales agreement, the Company is paid on the basis of the amount of electricity produced by the power plants to which steam is supplied. PG&E is obligated to use its best efforts to operate its power plants to maintain monthly and annual steam field capacity. The price paid for steam under the steam sales agreement is determined according to a formula that consists of the average of three indices multiplied by a fixed price of 1.65c per kilowatt hour. The indices used are the Producer Price Index for Crude Petroleum, the Producer Price Index for Natural Gas and the Consumer Price Index ("CPI"). The price of steam under the steam sales agreement in 1995 was 1.647c per kilowatt hour. In addition, the Company receives a monthly fee for effluent disposal and maintenance. During 1995, such monthly fee was $144,000 per month.
In March 1996, the Company and Union Oil Company of California ("Union Oil") entered into an alternative pricing agreement with PG&E for any steam produced in excess of 40% of average field capacity as defined in the steam sales contract. The alternative pricing strategy is effective through December 31, 2000. Under the alternative pricing agreement, PG&E has the option to purchase a portion of the steam that PG&E would likely curtail under the existing steam sales agreement. The price for this portion of steam will be set by the Company and Union Oil with the intent that it be at competitive market prices. The Company and Union Oil will solely determine the price and duration of these alternative prices.
The steam sales agreement with PG&E also provides for offset payments, which constitute a remedy for insufficient steam. Under the steam sales agreement, the Company is required to pay PG&E for the unamortized costs, including site clean-up, removal and abandonment costs, of power plants that are installed but are unused as a result of steam supply deficiency. The offset payments are calculated based upon a fixed amortization schedule for all power plants, which may be adjusted for future capital expenditures, and upon the steam fields' capacity in megawatts. In accordance with the steam sales agreement, the Company makes offset payments at a reduced rate until total offsets calculated since July 1, 1991 equal $15 million. Accordingly, the Company's share of offsets in 1995 was $757,000. In approximately 1999, when total offsets may exceed $15 million in accordance with the agreement, the Company's share of offset payments to PG&E would be approximately 2 1/2 times their current rate (as calculated at the current steam field capacity).
In accordance with the steam sales agreement, PG&E may curtail the power plants which receive steam in order to produce energy from lower cost sources. PG&E is contractually obligated to operate all of the power plants at a minimum of 40% of the field capacity during any given year, and at 25% of the field capacity in any given month. During 1995, the Thermal Power Company Steam Fields experienced extensive curtailment of steam production due to low gas prices and abundant hydro power. The Company receives a monthly fee for PG&E's right to curtail its power plants. Such fee was $12,800 per month during 1995. See "Management's Discussion and Analysis of Financial Condition and Results of Operations."
The steam sales agreement with PG&E terminates two years after the closing of the last operating power plant. In addition, PG&E may terminate the contract earlier with a one-year written notice. If PG&E terminates in accordance with the steam sales agreement, the Company will provide capacity maintenance services for five years after the termination date, and will retain a right of first refusal to purchase the PG&E facilities at PG&E's unamortized cost. Alternatively, the Company may terminate the agreement with a two-year written notice to PG&E. If the Company terminates, PG&E has the right to take assignment of the Thermal Power Company Steam Fields' facilities on the date of termination. In that case, the Company would continue to pay offset payments for three years following the date of termination. Under the steam sales agreement, PG&E may retire older power plants upon a minimum of six-months' notice. The Company is unable to predict PG&E's schedule for the retirement of such power plants, which may change from time to time. If steam is abandoned (i.e., cannot be transported to the remaining plants), the abandoned steam may be delivered for use to other PG&E power plants, subject to existing contract conditions, or to other customers upon closure of a PG&E power plant.
The Thermal Power Company Steam Fields currently supply steam sufficient to operate the PG&E power plants at approximately 60% of their combined nameplate capacity. This percentage reflects a decline in productivity since the commencement of operations. While it is not possible to accurately predict long-term
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steam field productivity, the Company has estimated that the current annual rate of decline in steam field productivity of the Thermal Power Company Steam Fields was approximately 9% until 1995, during which year extensive curtailment interrupted the decline trend. The Company expects steam field productivity to continue to decline in the future. The Company plans to work with Union Oil and PG&E to partially offset the expected rate of decline by the development of water injection projects and power plant improvements.
During 1995, the PG&E power plants produced 2,688,176,000 kilowatt hours of electrical energy of which the Company's 25% share is 672,044,000 kilowatt hours for approximately $11.0 million of revenue.
PG&E Unit 13 and Unit 16 Steam Fields
The Company holds the leasehold rights to 1,631 acres of steam fields (the "PG&E Unit 13 and Unit 16 Steam Fields") that supply steam to PG&E's Unit 13 power plant (the "Unit 13") and PG&E's Unit 16 power plant (the "Unit 16"), all of which are located in The Geysers. See "-- Properties." Unit 13 and Unit 16 have nameplate capacities of 134 and 113 megawatts, respectively, and currently operate at outputs of approximately 100 and 78 megawatts, respectively. The PG&E Unit 13 Steam Field includes 956 acres, 30 production wells, two injection wells and five miles of pipeline, and commenced commercial operations in May 1980. The PG&E Unit 16 Steam Field includes 675 acres, 19 producing wells, two injection wells, and three miles of pipeline, and commenced commercial operation in October 1985.
The PG&E Unit 13 and Unit 16 Steam Fields produce steam for sale to PG&E under long-term steam sales agreements. Under the steam sales agreements with PG&E, the Company is paid for steam on the basis of the amount of electricity produced by Unit 13 and Unit 16. The price paid for steam under the PG&E Unit 13 and Unit 16 Steam Fields agreements is determined according to a formula that is essentially a weighted average of PG&E's fossil (oil and gas) fuel price and PG&E's nuclear fuel price. The price of steam for 1995 was 1.207c per kilowatt hour. The price for 1996 is expected to be approximately .995c. The Company receives an additional .05c per kilowatt hour from PG&E for the disposal of liquid effluents produced at Unit 13 and Unit 16.
During conditions of hydro-spill, PG&E may curtail energy deliveries from Unit 13 and Unit 16 which would reduce deliveries of steam under this agreement. Curtailments are primarily the result of a higher degree of precipitation during the period, which results in higher levels of energy generation by hydroelectric power facilities that supply electricity for sale by PG&E. In the event of any such curtailment, the Company's results of operations may be materially adversely affected. PG&E curtailed approximately 64,000,000 kilowatt hours under the steam sales agreement during 1995. The Company currently expects approximately the same amount of curtailment under the agreement during 1996 that was experienced in 1995.
The steam sales agreement with PG&E continues in effect for as long as either Unit 13 or Unit 16 remains in commercial operation, which depends on maintaining the productive capacity of the respective steam fields. However, PG&E may terminate the agreement if the quantity, quality or purity of the steam is such that the operation of Unit 13 or Unit 16 becomes economically impractical. The Company currently estimates that the productive capacity of the PG&E Unit 13 and Unit 16 Steam Fields is approximately 22 years. However, no assurance can be given that the operation of either Unit 13 or Unit 16 will not become economically impractical at any time during these periods.
The Company is required to supply a sufficient quantity of steam of specified quality to Unit 16. If an insufficient quantity of steam is delivered, the Company may be subject to penalty provisions, including suspension of PG&E's obligation to pay for steam delivered. Specifically, if the Company fails to deliver to Unit 16 in any calendar month a sufficient quantity of steam adequate to operate the power plant at or above a capacity factor of 50%, no payment shall be made for steam delivered to such Unit during such month until the cost of that Unit has been completely amortized by PG&E.
In order to increase the efficiency of Unit 13 by approximately 20%, the Company agreed to purchase new rotors for approximately $10 million. In exchange, PG&E agreed to amend the steam sales agreement to remove the penalty provision for a failure to deliver a sufficient quantity of steam to Unit 13 and to require
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PG&E to operate at variable pressure operations which will optimize production at the PG&E Unit 13 and Unit 16 Steam Fields.
The PG&E Unit 13 and Unit 16 Steam Fields currently supply steam sufficient to operate Unit 13 and Unit 16 at approximately 72% of their combined nameplate capacities. This percentage reflects a decline in the productivity of the PG&E Unit 13 and Unit 16 Steam Fields since the commencement of operations of Unit 13 and Unit 16. While it is not possible to accurately predict long-term steam field productivity, the Company has estimated that the annual rate of decline in steam field productivity of the PG&E Unit 13 and Unit 16 Steam Fields was approximately 10% until curtailment of neighboring plants and Unit 13 and Unit 16 in 1995 reduced the decline to zero. The Company expects steam field productivity to continue to decline in the future, but at decreasing annual rates of decline. The Company considered these declines in steam field productivity in developing its original projections for the PG&E Unit 13 and Unit 16 Steam Fields at the time the Company acquired its initial interest in 1990. The Company plans to partially offset the expected rate of decline by implementing enhanced water injection and power plant improvements.
During 1995, the PG&E Unit 13 and Unit 16 Steam Fields produced sufficient steam to permit Unit 13 and Unit 16 to produce approximately 1,296,900,000 kilowatt hours of electrical energy and approximately $16.3 million of revenue.
SMUDGEO #1 Steam Fields
The Company holds the leasehold rights to 394 acres of steam fields that supply steam to the power plant for SMUD SMUDGEO #1 steam fields (the "SMUDGEO #1 Steam Fields"). See "-- Properties." The SMUD power plant has a nameplate capacity of 72 megawatts and currently operates at an output of 59 megawatts. The SMUDGEO #1 Steam Fields include 19 producing wells, one injection well and two miles of pipeline. Commercial operation of the SMUD power plant commenced in October 1983.
The steam sales agreement with SMUD provides that SMUD will pay for steam based upon the quantity of steam delivered to the SMUD power plant. The current price paid for steam delivered under the steam sales agreement is $1.746 per thousand pounds of steam, which is adjusted semi-annually based on changes in the Gross National Product Implicit Price Deflator Index and Producers Price Index for Fuels, Related Products and Power. SMUD may suspend payments for steam in any month if the Company is unable to deliver 50% of the steam requirement until the cost of the plant and related facilities have been completely amortized by the value of such steam delivered to the plant. Based on current estimates and analyses performed by the Company, the Company does not expect SMUD to suspend payments for steam under this provision. The Company receives an additional .15c per kilowatt hour from SMUD for the disposal of liquid effluents produced at the SMUDGEO #1 Steam Fields.
The steam sales agreement with SMUD continues until the expiration or termination of the geothermal lease covering the SMUDGEO #1 Steam Fields, which continues for so long as steam is produced in commercial quantities. The Company and SMUD each have the right to terminate the agreement if their respective operations become economically impractical. In the event that SMUD exercises its right to terminate, the Company will have no further obligation to deliver steam to the power plants.
The SMUDGEO #1 Steam Fields currently supply steam sufficient to operate the SMUD power plant at approximately 82% of its nameplate capacity. This percentage reflects a decline in the productivity of the SMUDGEO #1 Steam Fields since commencement of operations. Although the SMUDGEO #1 Steam Fields increased in productivity in 1995 due to curtailment of neighboring plants, the Company expects the SMUDGEO #1 Steam Fields' productivity to decline in the future.
During 1995, the SMUDGEO #1 Steam Fields produced approximately 6,600,835 thousand pounds of steam and approximately $12.3 million of revenue.
Cerro Prieto Steam Fields
On November 17, 1995, the Company entered into a series of agreements with Constructora y Perforadora Latina, S.A. de C.V. ("Coperlasa") and certain of Coperlasa's creditors pursuant to which the
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Company has agreed to invest up to $20 million in the Cerro Prieto steam fields (the "Cerro Prieto Steam Fields") located in Baja California, Mexico. The Cerro Prieto Steam Fields provide geothermal steam to three geothermal power plants owned and operated by Comision Federal de Electricidad, the Mexican national utility ("CFE").
The Company's investment consists of a loan of up to $18.5 million and a $1.5 million payment for an option to purchase a 29% equity interest in Coperlasa for $5.8 million, which payment was made in December 14, 1995. This option expires in May 1997.
The $18.5 million loan was made in installments throughout 1996, which provided capital to Coperlasa to fund the drilling of new wells and the repair of existing wells to meet its performance under its agreement with CFE. The loan matures in November 1999 and bears interest at an effective rate of 18.8% per annum. Repayment of this loan will be interest only for the first 18 months. Thereafter, 100% of the cash flow generated from the sale of steam less operating expenses and capital expenditures will be used to pay principal and interest on the loan. The Company's loan is senior to the existing debt at Coperlasa.
Pursuant to a technical services agreement, the Company receives fees for its technical services provided to Coperlasa. In addition, if the Company is successful in assisting Coperlasa in producing steam at a lower cost, the Company will receive 30% of the savings.
The Cerro Prieto Steam Fields are located near the city of Mexicali, Baja California, at the border of Baja California and the State of California. The Cerro Prieto geothermal resource, which has been commercially produced by CFE since 1973, provides approximately 70% of Baja California's electricity requirements since this region is not connected to the Mexican national power grid.
The steam sales agreement between Coperlasa and CFE was entered into in May 1991. Under this agreement, CFE pays for steam delivered up to 1,600 tons per hour plus 10%. Payments for the steam delivered are made in Mexican pesos and are adjusted by a formula that accounts for the increases in inflation in Mexico and the United States as well as for the devaluation of the peso against the U.S. dollar. This agreement has a termination date of October 2000. While the Company believes that Coperlasa is in an advantageous position to renegotiate or bid for the right to supply steam over a longer term, there can be no assurance that the steam sales agreement will be extended beyond its current termination date.
DEVELOPMENT AND FUTURE PROJECTS
The Company is continually engaged in the evaluation of various opportunities for the development and acquisition of additional power generation facilities. However, there is no assurance the Company will be successful in the acquisition or development of power generation projects in the future. See "Risk Factors -- Project Development Risks."
PASADENA COGENERATION PROJECT
Calpine was selected by Phillips Petroleum Company ("Phillips") to negotiate for the development of a 240 megawatt gas-fired cogeneration project at the Phillips Houston Chemical Complex ("HCC") located in Pasadena, Texas (the "Pasadena Cogeneration Project"). In July 1995 and March 1996, the Company entered into Energy Project Development Agreements with Phillips pursuant to which the Company and Phillips propose to enter into 20-year agreements for the purchase and sale of all of the HCC's steam and electricity requirements of approximately 90 megawatts. It is anticipated that the remainder of available electricity output will be sold into the competitive market through Calpine's power marketing activities. Pursuant to the Energy Project Development Agreements, the Company has agreed to make $3.5 million of capital expenditures on the Pasadena Cogeneration Project during 1996. In addition, the Company has provided a $3.0 million letter of credit to Phillips to secure the performance under the Energy Project Development Agreement. On August 2, 1996, the Company entered into a commitment letter with ING Capital Corporation to provide $100.0 million of non-recourse project financing for the Pasadena Cogeneration Project. The Company expects to complete financing and commence construction in September 1996, with commercial operation scheduled to begin in August 1998. However, there can be no assurances that the Company will be successful in completing either the agreements with Phillips or any additional power sales agreements or that the anticipated schedule for financing and construction will be met.
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GLASS MOUNTAIN GEOTHERMAL PROJECT
Calpine is pursuing the development of a geothermal power project at Glass Mountain, which is located in northern California about 25 miles south of the Oregon border (the "Glass Mountain Project"). Glass Mountain is believed to be the largest undeveloped geothermal resource in the United States. In area, the resource is larger than The Geysers, where approximately 1,200 megawatts of capacity is operating. The Company believes that Glass Mountain has an estimated potential in excess of 1,000 megawatts.
In August 1994, the Company entered into a partnership with Trans-Pacific Geothermal Glass Mountain, Ltd. ("TGC") to construct and operate a 30 megawatt project at Glass Mountain. TGC had previously signed a memorandum of understanding ("MOU") with Bonneville Power Administration ("BPA") and the Springfield, Oregon Utility Board ("SUB") to develop the project at Vale, Oregon. BPA and SUB consented on August 25, 1994 to the assignment of the MOU to the Calpine partnership and the relocation of the project to Glass Mountain. The memorandum of understanding contemplates execution of a 45-year power purchase agreement subject to satisfaction of certain conditions precedent and includes an option for an additional 100 megawatts.
Subject to the execution of the power purchase agreement with BPA, the Company plans to begin construction of an initial 45 megawatt phase of the Glass Mountain Project in 1998. The Company is in the process of preparing an Environmental Impact Statement and commercial operation is planned for 2000. There can be no assurances, however, that the Company and BPA will enter into a definitive agreement, that this project will be completed on this schedule, if at all, or that commercial operation of this project will be successful.
In March 1996, the Company completed the acquisition of certain Glass Mountain geothermal leases previously held by FMRP. As a result, the Company currently holds an interest in approximately 29,000 acres of federal geothermal leases at Glass Mountain. See "-- Properties."
COSO GEOTHERMAL PROJECT
In January 1992, the Company was selected by the Los Angeles Department of Water and Power (the "Department") to negotiate for the development of up to 150 megawatts of electric generating capacity utilizing geothermal energy from the Department's Coso geothermal leaseholds. Data from four deep exploration wells and a number of shallow, temperature gradient wells indicate that a productive area could exist with a capacity to support 200 megawatts or more. The resource is on land leased by the Department from the United States Bureau of Land Management ("BLM"), which is subleased to the Company.
The Company entered into definitive agreements with the Department in 1995 which granted the Company the right to develop the Department's Coso geothermal leaseholds located in Inyo County, California and to produce steam or electricity for sale to third parties. In addition, the agreements include an amended power sales agreement with the Department which grants the Department an option to purchase up to 150 megawatts of electricity from the geothermal resource. The ordinance approving the agreements has been passed by the Los Angeles City Council and approved by the Mayor.
In January 1996, certain litigation was filed against the Department seeking to compel the Department to submit the agreements entered into with the Company to a public bidding procedure in accordance with the Charter of the City of Los Angeles. In August 1996, the court ruled that certain of the rights granted by the Department in the agreements, including the right to produce steam or electricity for sale to third parties, were void and were required to be submitted to such a public bidding procedure. The Company is unable to predict the impact of such ruling on the agreements and the development of the Department's Coso geothermal leaseholds.
NAVAJO SOUTH COAL PROJECT
Calpine, BHP Minerals International Inc. and BHP Power Inc. have entered into a memorandum of understanding to assess the development of the Navajo South Project, a 1,700 megawatt coal-fired power generation facility in the Four Corners area of New Mexico. It is anticipated that this new power plant will
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provide electricity to the west and southwest United States markets. BHP Minerals International Inc. is the owner and operator of three coal mines in the Four Corners area of New Mexico. One of these, the Navajo Mine, is located on the Navajo Reservation.
BLACK HILLS COAL PROJECT
Calpine and Black Hills Corporation have entered into a joint venture agreement to assess the development of the WYGEN Project, an 80 megawatt coal-fired power generation facility located in northeastern Wyoming. It is anticipated that this new power plant will provide electricity to the western United States markets, with a commercial operation date expected in 1999. Black Hills Corporation, the parent of Black Hills Power & Light Company, is a public utility located in South Dakota.
INDONESIAN GEOTHERMAL PROJECT
Calpine plans to develop geothermal facilities in the Lampung Province of Indonesia, located in southern Sumatra. The geothermal resource at Ulubelu is estimated to have potential capacity in excess of 500 megawatts. The Company anticipates that the facility would sell electricity to Perusahaan Umum Listrik Negara ("PLN"), the state-owned electric company. The first phase of the project is expected to be 110 megawatts.
The Company's joint venture partner will be PT. Dharmasatrya Arthasentosa ("DATRA"), a company with interests in coal mining and other ventures. The Company expects that it will be the project's managing partner, with responsibility for the design, construction and operation of the power plant. The ownership structure, as planned, will be a joint venture with DATRA in which the Company would be the managing partner and hold at least a 50% equity interest, and as much as 85% of the project. DATRA would hold up to 50% of the project.
In March 1996, the Company and DATRA entered into a joint venture agreement to develop Ulubelu. The Company and DATRA are negotiating with the National Resource Agency Pertamina ("Pertamina"), regarding resource development. Deep test well drilling and flow tests by Pertamina are planned during 1996 and 1997 at Ulubelu. Commercial operation is anticipated in 2001 for the initial phase of the project. There can be no assurances, however, that this transaction will be consummated on these terms, if at all, that the proposed timetable will be met or that commercial operation of these resources will be feasible.
GOVERNMENT REGULATION
The Company is subject to complex and stringent energy, environmental and other governmental laws and regulations at the federal, state and local levels in connection with the development, ownership and operation of its energy generation facilities. Federal laws and regulations govern transactions by electrical and gas utility companies, the types of fuel which may be utilized by an electric generating plant, the type of energy which may be produced by such a plant and the ownership of a plant. State utility regulatory commissions must approve the rates and, in some instances, other terms and conditions under which public utilities purchase electric power from independent producers and sell retail electric power. Under certain circumstances where specific exemptions are otherwise unavailable, state utility regulatory commissions may have broad jurisdiction over non-utility electric power plants. Energy producing projects also are subject to federal, state and local laws and administrative regulations which govern the emissions and other substances produced, discharged or disposed of by a plant and the geographical location, zoning, land use and operation of a plant. Applicable federal environmental laws typically have both state and local enforcement and implementation provisions. These environmental laws and regulations generally require that a wide variety of permits and other approvals be obtained before the commencement of construction or operation of an energy- producing facility and that the facility then operate in compliance with such permits and approvals.
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FEDERAL ENERGY REGULATION
PURPA
The enactment in 1978 of PURPA and the adoption of regulations thereunder by FERC provided incentives for the development of cogeneration facilities and small power production facilities (those utilizing renewable fuels and having a capacity of less than 80 megawatts).
A domestic electricity generating project must be a QF under FERC regulations in order to take advantage of certain rate and regulatory incentives provided by PURPA. PURPA exempts owners of QFs from PUHCA, and exempts QFs from most provisions of the Federal Power Act (the "FPA") and, except under certain limited circumstances, state laws concerning rate or financial regulation. These exemptions are important to the Company and its competitors. The Company believes that each of the electricity generating projects in which the Company owns an interest currently meets the requirements under PURPA necessary for QF status. Most of the projects which the Company is currently planning or developing are also expected to be QFs.
PURPA provides two primary benefits to QFs. First, QFs generally are relieved of compliance with extensive federal, state and local regulations that control the financial structure of an electric generating plant and the prices and terms on which electricity may be sold by the plant. Second, FERC's regulations promulgated under PURPA require that electric utilities purchase electricity generated by QFs at a price based on the purchasing utility's "avoided cost," and that the utility sell back-up power to the QF on a non- discriminatory basis. The term "avoided cost" is defined as the incremental cost to an electric utility of electric energy or capacity, or both, which, but for the purchase from QFs, such utility would generate for itself or purchase from another source. FERC regulations also permit QFs and utilities to negotiate agreements for utility purchases of power at rates lower than the utility's avoided costs. Due to increasing competition for utility contracts, the current practice is for most power sales agreements to be awarded at a rate below avoided cost. While public utilities are not explicitly required by PURPA to enter into long-term power sales agreements, PURPA helped to create a regulatory environment in which it has been common for long-term agreements to be negotiated.
In order to be a QF, a cogeneration facility must produce not only electricity, but also useful thermal energy for use in an industrial or commercial process for heating or cooling applications in certain proportions to the facility's total energy output and must meet certain energy efficiency standards. Finally, a QF (including a geothermal or hydroelectric QF or other qualifying small power producer) must not be controlled or more than 50% owned by an electric utility or by most electric utility holding companies, or a subsidiary of such a utility or holding company or any combination thereof.
The Company endeavors to develop its projects, monitor compliance by the projects with applicable regulations and choose its customers in a manner which minimizes the risks of any project losing its QF status. Certain factors necessary to maintain QF status are, however, subject to the risk of events outside the Company's control. For example, loss of a thermal energy customer or failure of a thermal energy customer to take required amounts of thermal energy from a cogeneration facility that is a QF could cause the facility to fail requirements regarding the level of useful thermal energy output. Upon the occurrence of such an event, the Company would seek to replace the thermal energy customer or find another use for the thermal energy which meets PURPA's requirements, but no assurance can be given that this would be possible.
If one of the projects in which the Company has an interest should lose its status as a QF, the project would no longer be entitled to the exemptions from PUHCA and the FPA. This could trigger certain rights of termination under the power sales agreement, could subject the project to rate regulation as a public utility under the FPA and state law and could result in the Company inadvertently becoming a public utility holding company by owning more than 10% of the voting securities of, or controlling, a facility that would no longer be exempt from PUHCA. This could cause all of the Company's remaining projects to lose their qualifying status, because QFs may not be controlled or more than 50% owned by such public utility holding companies. Loss of QF status may also trigger defaults under covenants to maintain QF status in the projects' power sales agreements, steam sales agreements and financing agreements and result in termination, penalties or
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acceleration of indebtedness under such agreements such that loss of status may be on a retroactive or a prospective basis.
If a project were to lose its QF status, the Company could attempt to avoid holding company status (and thereby protect the QF status of its other projects) on a prospective basis by restructuring the project, by changing its voting interest in the entity owning the non-qualifying project to nonvoting or limited partnership interests and selling the voting interest to an individual or company which could tolerate the lack of exemption from PUHCA, or by otherwise restructuring ownership of the project so as not to become a holding company. These actions, however, would require approval of the Securities and Exchange Commission ("SEC") or a no-action letter from the SEC, and would result in a loss of control over the non-qualifying project, could result in a reduced financial interest therein and might result in a modification of the Company's operation and maintenance agreement relating to such project. A reduced financial interest could result in a gain or loss on the sale of the interest in such project, the removal of the affiliate through which the ownership interest is held from the consolidated income tax group or the consolidated financial statements of the Company, or a change in the results of operations of the Company. Loss of QF status on a retroactive basis could lead to, among other things, fines and penalties being levied against the Company and its subsidiaries and claims by utilities for refund of payments previously made.
Under the Energy Policy Act of 1992, if a project can be qualified as an exempt wholesale generator ("EWG"), it will be exempt from PUHCA even if it does not qualify as a QF. Therefore, another response to the loss or potential loss of QF status would be to apply to have the project qualified as an EWG. However, assuming this changed status would be permissible under the terms of the applicable power sales agreement, rate approval from FERC and approval of the utility would be required. In addition, the project would be required to cease selling electricity to any retail customers (such as the thermal energy customer) and could become subject to state regulation of sales of thermal energy. See "-- Public Utility Holding Company Regulation."
Currently, Congress is considering proposed legislation that would amend PURPA by eliminating the requirement that utilities purchase electricity from QFs at avoided costs. The Company does not know whether such legislation will be passed or what form it may take. The Company believes that if any such legislation is passed, it would apply to new projects. As a result, although such legislation may adversely affect the Company's ability to develop new projects, the Company believes it would not affect the Company's existing QFs. There can be no assurance, however, that any legislation passed would not adversely impact the Company's existing projects.
Public Utility Holding Company Regulation
Under PUHCA, any corporation, partnership or other legal entity which owns or controls 10% or more of the outstanding voting securities of a "public utility company" or a company which is a "holding company" for a public utility company is subject to registration with the SEC and regulation under PUHCA, unless eligible for an exemption. A holding company of a public utility company that is subject to registration is required by PUHCA to limit its utility operations to a single integrated utility system and to divest any other operations not functionally related to the operation of that utility system. Approval by the SEC is required for nearly all important financial and business dealings of the holding company. Under PURPA, most QFs are not public utility companies under PUHCA.
The Energy Policy Act of 1992, among other things, amends PUHCA to allow EWGs, under certain circumstances, to own and operate non-QFs without subjecting those producers to registration or regulation under PUHCA. The expected effect of such amendments would be to enhance the development of non-QFs which do not have to meet the fuel, production and ownership requirements of PURPA. The Company believes that the amendments could benefit the Company by expanding its ability to own and operate facilities that do not qualify for QF status, but may also result in increased competition by allowing utilities to develop such facilities which are not subject to the constraints of PUHCA.
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Federal Natural Gas Transportation Regulation
The Company has an ownership interest in and operates six natural gas-fired cogeneration projects. The cost of natural gas is ordinarily the largest expense (other than debt costs) of a project and is critical to the project's economics. The risks associated with using natural gas can include the need to arrange transportation of the gas from great distances, including obtaining removal, export and import authority if the gas is transported from Canada; the possibility of interruption of the gas supply or transportation (depending on the quality of the gas reserves purchased or dedicated to the project, the financial and operating strength of the gas supplier, and whether firm or non-firm transportation is purchased); and obligations to take a minimum quantity of gas and pay for it (i.e., take-and-pay obligations).
Pursuant to the Natural Gas Act, FERC has jurisdiction over the transportation and storage of natural gas in interstate commerce. With respect to most transactions that do not involve the construction of pipeline facilities, regulatory authorization can be obtained on a self-implementing basis. However, pipeline rates for such services are subject to continuing FERC oversight. Order No. 636, issued by FERC in April 1992, mandates the restructuring of interstate natural gas pipeline sales and transportation services and will result in changes in the terms and conditions under which interstate pipelines will provide transportation services, as well as the rates pipelines may charge for such services. The restructuring required by the rule includes: (i) the separation (unbundling) of a pipeline's sales and transportation services, (ii) the implementation of a straight fixed-variable rate design methodology under which all of a pipeline's fixed costs are recovered through its reservation charge, (iii) the implementation of a capacity releasing mechanism under which holders of firm transportation capacity on pipelines can release that capacity for resale by the pipeline, and (iv) the opportunity for pipelines to recover 100% of their prudently incurred costs (transition costs) associated with implementing the restructuring mandated by the rule. Pipelines were required to file tariff sheets implementing Order No. 636 by December 31, 1992. FERC affirmed the major components of Order No. 636 in Order Nos. 636A and B issued in August and November 1992. The restructuring required by the rule became effective in late 1993.
STATE REGULATION
State public utility commissions ("PUCs") have broad authority to regulate both the rates charged by and financial activities of electric utilities, and to promulgate regulations implementing PURPA. Since a power sales contract will become a part of a utility's cost structure (and therefore is generally reflected in its retail rates), power sales contracts with independents are potentially under the regulatory purview of PUCs, particularly the process by which the utility has entered into the power sales contracts. If a PUC has approved of the process by which a utility secures its power supply, a PUC generally will be inclined to allow a utility to "pass through" the expenses associated with an independent power contract to the utility's retail customers. However, a regulatory commission may disallow the full reimbursement to a utility for the purchase of electricity from QFs. In addition, retail sales of electricity or thermal energy by an independent power producer may be subject to PUC regulation, depending on state law.
Independent power producers which are not QFs under PURPA are considered to be public utilities in many states and are subject to broad regulation by PUCs ranging from the requirement of certificates of public convenience and necessity to regulation of organizational, accounting, financial and other corporate matters. In addition, states may assert jurisdiction over the siting and construction of facilities not qualifying as QFs (as well as QFs), and over the issuance of securities and the sale or other transfer of assets by these facilities (but not QFs).
CPUC and the California Assembly Joint Legislative Committee on Lowering the Cost of Electric Services commenced proceedings and hearings related to the restructure of the California electric services industry in 1994. The proceedings and hearings were initiated as a result of the CPUC Order Instituting Rulemaking and Order Instituting Investigation on the Commission Proposed Policies Governing Restructuring California's Electric Services Industry and Reforming Regulation, issued by the CPUC on April 20, 1994. The FERC, as authorized under the Energy Policy Act of 1992, is also holding hearings on policy issues related to a more competitive electric services industry.
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On December 20, 1995, the CPUC issued an electric industry restructuring decision which envisions commencement of deregulation and implementation of customer choice beginning January 1, 1998, with all consumers participating by 2003. Because restructuring the California electric industry requires participation and oversight by the FERC, the CPUC seeks to build a consensus involving the California Legislature, the Governor, public and municipal utilities, and customers. This consensus would be reflected in filings for approval by the FERC and provides a cooperative spirit whereby both agencies would move forward to implement the new market structure no later than January 1, 1998.
The decision provides for phased-in customer choice, development of a non-discriminatory market structure, recovery of utilities stranded costs, sanctity of existing contracts and continuation of existing public policy programs including the promotion of fuel diversity through a renewable energy purchase requirement.
On February 5, 1996, the CPUC issued a proposed procedural plan that facilitates the transition of the electric generation market to competition by January 1, 1998. This electric restructuring "roadmap" focuses on the multiple and interrelated tasks that must be accomplished and sets forth the process to achieve the necessary procedural milestones that must be completed in order to meet the implementation goal.
In addition to the significant opportunity provided for power producers such as Calpine resulting from the implementation of direct access, the decision recognizes the sanctity of existing QF contracts. The decision recognizes that horizontal market power concerns will likely require investor owned utilities to divest themselves of a substantial portion of their generating assets and requires the utilities to file with the Commission a plan for voluntary divestiture of up to 50% of their fossil generating assets. The decision to commit to the establishment of a restructuring policy maintains California's resource diversity provided by existing renewal resources (including geothermal) and encourages development of new renewable resources. The continued resource diversity would be provided by a renewable portfolio standard which establishes that a renewable purchase requirement be placed on providers of electricity and creates a system of tradeable credits for meeting the purchase requirement.
State PUCs also have jurisdiction over the transportation of natural gas by local distribution companies ("LDCs"). Each state's regulatory laws are somewhat different; however, all generally require the LDC to obtain approval from the PUC for the construction of facilities and transportation services if the LDC's generally applicable tariffs do not cover the proposed transaction. LDC rates are usually subject to continuing PUC oversight.
REGULATION OF CANADIAN GAS
The Canadian natural gas industry is subject to extensive regulation by governmental authorities. At the federal level, a party exporting gas from Canada must obtain an export license from the Canadian National Energy Board ("NEB"). The NEB also regulates Canadian pipeline transportation rates and the construction of pipeline facilities. Gas producers also must obtain a removal permit or license from provincial authorities before natural gas may be removed from the province, and provincial authorities may regulate intraprovincial pipeline and gathering systems. In addition, a party importing natural gas into the United States first must obtain an import authorization from the U.S. Department of Energy.
ENVIRONMENTAL REGULATIONS
The exploration for and development of geothermal resources and the construction and operation of power projects are subject to extensive federal, state and local laws and regulations adopted for the protection of the environment and to regulate land use. The laws and regulations applicable to the Company primarily involve the discharge of emissions into the water and air and the use of water, but can also include wetlands preservation, endangered species, waste disposal and noise regulations. These laws and regulations in many cases require a lengthy and complex process of obtaining licenses, permits and approvals from federal, state and local agencies.
Noncompliance with environmental laws and regulations can result in the imposition of civil or criminal fines or penalties. In some instances, environmental laws also may impose clean-up or other remedial
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obligations in the event of a release of pollutants or contaminants into the environment. The following federal laws are among the more significant environmental laws as they apply to the Company. In most cases, analogous state laws also exist that may impose similar, and in some cases more stringent, requirements on the Company as those discussed below.
Clean Air Act
The Federal Clean Air Act of 1970 (the "Clean Air Act") provides for the regulation, largely through state implementation of federal requirements, of emissions of air pollutants from certain facilities and operations. As originally enacted, the Clean Air Act sets guidelines for emissions standards for major pollutants (i.e., sulfur dioxide and nitrogen oxide) from newly built sources. In late 1990, Congress passed the Clean Air Act Amendments (the "1990 Amendments"). The 1990 Amendments attempt to reduce emissions from existing sources, particularly previously exempted older power plants. The Company believes that all of the Company's operating plants are in compliance with federal performance standards mandated for such plants under the Clean Air Act and the 1990 Amendments. With respect to its Aidlin geothermal plant and one of its steam field pipelines, the Company's operations have, in certain instances, necessitated variances under applicable California air pollution control laws. However, the Company believes that it is in material compliance with such laws with respect to such facilities.
Clean Water Act
The Federal Clean Water Act (the "Clean Water Act") establishes rules regulating the discharge of pollutants into waters of the United States. The Company is required to obtain a wastewater and stormwater discharge permit for wastewater and runoff, respectively, from certain of the Company's facilities. The Company believes that, with respect to its geothermal operations, it is exempt from newly-promulgated federal stormwater requirements. The Company believes that it is in material compliance with applicable discharge requirements under the Clean Water Act.
Resource Conservation and Recovery Act
The Resource Conservation and Recovery Act ("RCRA") regulates the generation, treatment, storage, handling, transportation and disposal of solid and hazardous waste. The Company believes that it is exempt from solid waste requirements under RCRA. However, particularly with respect to its solid waste disposal practices at the power generation facilities and steam fields located at The Geysers, the Company is subject to certain solid waste requirements under applicable California laws. The Company believes that its operations are in material compliance with such laws.
Comprehensive Environmental Response, Compensation, and Liability Act
The Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended ("CERCLA" or "Superfund"), requires cleanup of sites from which there has been a release or threatened release of hazardous substances and authorizes the United States Environmental Protection Agency ("EPA") to take any necessary response action at Superfund sites, including ordering potentially responsible parties ("PRPs") liable for the release to take or pay for such actions. PRPs are broadly defined under CERCLA to include past and present owners and operators of, as well as generators of wastes sent to, a site. As of the present time, the Company is not subject to liability for any Superfund matters. However, the Company generates certain wastes, including hazardous wastes, and sends certain of its wastes to third-party waste disposal sites. As a result, there can be no assurance that the Company will not incur liability under CERCLA in the future.
COMPETITION
The Company competes with independent power producers, including affiliates of utilities, in obtaining long-term agreements to sell electric power to utilities. In addition, utilities may elect to expand or create generating capacity through their own direct investments in new plants. Over the past decade, obtaining a power sales agreement with a utility has become an increasingly more difficult, expensive and competitive process. In the past few years, more contracts have been awarded through some form of competitive bidding. Increased competition also has lowered profit margins of successful projects. The Company believes that the
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power marketing business represents an opportunity to take advantage of growing competition in the electric power industry. The Company also believes that the power marketing business will be highly competitive.
The demand for power in the United States traditionally has been met by utilities constructing large-scale electric generating plants under rate-based regulation. The enactment of PURPA in 1978 spawned the growth of the independent power industry, which expanded rapidly in the 1980s. The initial independent power producers were an entrepreneurial group of cogenerators and small power producers who recognized the potential business opportunities offered by PURPA. This initial group of independents was later joined by larger, better capitalized companies, such as subsidiaries of fuel supply companies, engineering companies, equipment manufacturers and affiliates of other industrial companies. In addition, a number of regulated utilities have created subsidiaries (known as utility affiliates) that compete with independent power producers. Some independent power producers specialize in market "niches," such as a specific technology or fuel (e.g., gas-fired cogeneration, geothermal, hydroelectric, refuse-to-energy, wind, solar, coal and wood), or a specific region of the country where they believe they have a market advantage. The Company presently conducts its operations primarily in the United States and concentrates on gas-fired and geothermal cogeneration plants.
The Company is the second largest producer of geothermal energy in the United States. Although the Company is an established leader in the geothermal power industry and has been rapidly growing, most of the Company's competitors have significantly greater capital, financial and operational resources than the Company.
Recent amendments to PUHCA made by the Energy Policy Act of 1992 are likely to increase the number of competitors in the independent power industry by reducing certain restrictions currently applicable to certain projects that are not QFs under PURPA. However, the recent amendments also should make it simpler for the Company to develop new projects itself, for example, by enabling the Company to develop large, gas-fired generation projects without the necessity of locating its projects in the vicinity of a steam host or otherwise finding a steam host to accept the useful thermal output required of a cogeneration facility under PURPA.
EMPLOYEES
As of July 31, 1996, the Company employed 235 people. None of the Company's employees are covered by collective bargaining agreements, and the Company has never experienced a work stoppage, strike or labor dispute. The Company considers relations with its employees to be good.
PROPERTIES
The Company's principal executive office is located in San Jose, California under a lease that expires in June 2001. The Company also maintains a regional office in Santa Rosa, California under a lease that expires in 1999.
The Company, through its ownership of CGC and Thermal Power Company, has leasehold interests in 111 leases comprising 27,287 acres of federal, state and private geothermal resource lands in The Geysers area in northern California. These leases comprise its West Ford Flat Facility, Bear Canyon Facility, PG&E Unit 13 and Unit 16 Steam Fields, SMUDGEO #1 Steam Fields and Thermal Power Company's 25% undivided interest in the Thermal Power Company Steam Fields which are operated by Union Oil. The Company has subleasehold interests in three leases comprising 6,825 acres of federal geothermal resource lands in the Coso area in central California. In the Glass Mountain and Medicine Lake areas in northern California, the Company holds leasehold interests in 23 leases comprising approximately 29,000 acres of federal geothermal resource lands.
In general, under the leases, the Company has the exclusive right to drill for, produce and sell geothermal resources from these properties and the right to use the surface for all related purposes. Each lease requires the payment of annual rent until commercial quantities of geothermal resources are established. After such time, the leases require the payment of minimum advance royalties or other payments until production commences, at which time production royalties are payable. Such royalties and other payments are payable to landowners, state and federal agencies and others, and vary widely as to the particular lease. The leases are generally for
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initial terms varying from 10 to 20 years or for so long as geothermal resources are produced and sold. Certain of the leases contain drilling or other exploratory work requirements. In certain cases, if a requirement is not fulfilled, the lease may be terminated and in other cases additional payments may be required. The Company believes that its leases are valid and that it has complied with all the requirements and conditions material to their continued effectiveness. A number of the Company's leases for undeveloped properties may expire in any given year. Before leases expire, the Company performs geological evaluations in an effort to determine the resource potential of the underlying properties. No assurance can be given that the Company will decide to renew any expiring leases.
The Company, through its ownership of the Greenleaf 1 Facility, owns 77 acres in Sutter County, California.
See "-- Description of Facilities" for a description of the other material properties leased or owned by the projects in which the Company has ownership interests. The Company believes that its properties are adequate for its current operations.
LEGAL PROCEEDINGS
The Company, together with over 100 other parties, was named as a defendant in the second amended complaint in an action brought in August 1993 by the bankruptcy trustee for Bonneville Pacific Corporation ("Bonneville"), captioned Roger G. Segal, as the Chapter 11 Trustee for Bonneville Pacific Corporation v. Portland General Corporation, et al., in the United States District Court for the District of Utah (the "Court"). This complaint alleges that, in conjunction with top executives of Bonneville and with the alleged assistance of the other 100 defendants, the Company engaged in a broad conspiracy and fraud. The complaint has been amended a number of times. The Company has answered each version of the complaint by denying all claims. In August 1994, the Company successfully moved for an order severing the trustee's claims against the Company from the claims against the other defendants. Although the case involves over 25 separate financial transactions entered into by Bonneville, the severed case concerns the Company in respect of only one of these transactions. In 1988, the Company invested $2.0 million in a partnership formed with Bonneville to develop four hydroelectric projects in the State of Hawaii. The projects were not successfully developed by the partnership and, subsequent to Bonneville's Chapter 11 filing, the Company filed a claim as a creditor against Bonneville's bankruptcy estate. The trustee alleges that the investment was actually a loan and was designed to inflate Bonneville's earnings. The trustee initially alleged that Calpine is one of many defendants in this case responsible for Bonneville's "deepening insolvency" and the amount of damages attributable to the Company based on the $2.0 million partnership investment was alleged to be $577.2 million. Based upon statements made by the Court and the trustee at a pre-trial hearing in September 1996, the Company believes that the maximum compensatory damages which the trustee may seek will not exceed $2.0 million. There can be no assurance, however, of the actual amount of damages to be sought by the trustee. The Company believes the claims against it are without merit and will continue to defend the action vigorously. The Company further believes that the resolution of this matter will not have a material adverse effect on its financial position or results of operations.
In connection with the Company's unsuccessful attempt to acquire O'Brien Environmental Energy, Inc. ("O'Brien") in 1995 through the U.S. Bankruptcy Court proceedings, the Company incurred approximately $3.6 million of third-party expenses, all of which have been capitalized by the Company. Pursuant to the terms of a contract with O'Brien, the Company is seeking the reimbursement of $2.3 million of such expenses and a $2.0 million break-up fee, each of which is subject to the approval of the Bankruptcy Court. On June 6, 1996, the Bankruptcy Court ruled that the Company had the right to seek reimbursement of its fees and expenses and conducted an evidentiary hearing on August 28, 1996 to determine the amount to be awarded. The Bankruptcy Court is scheduled to decide this matter on September 30, 1996. Although the Company believes it will be awarded all or a substantial part of the fees and expenses which it is seeking, there can be no assurance as to the ultimate resolution of this claim.
The Company is involved in various other claims and legal actions arising out of the normal course of business. Management does not expect that the outcome of these cases will have a material adverse effect on the Company's financial position or results of operations.
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MANAGEMENT
BOARD OF DIRECTORS AND EXECUTIVE OFFICERS
The following table sets forth certain information with respect to each person who is a Director, a nominee for Director or an executive officer of the Company.

                   NAME                      AGE                      POSITION
------------------------------------------   ----   ---------------------------------------------
Peter Cartwright..........................    66    President, Chief Executive Officer, Director
                                                    and Chairman of the Board Nominee
Pierre Krafft.............................    66    Chairman of the Board
Hans-Peter Aebi...........................    48    Director
Rudolf Boesch.............................    59    Director
Ann B. Curtis.............................    45    Senior Vice President and Director Nominee
George J. Stathakis.......................    66    Director Nominee
Rodney M. Boucher.........................    53    Senior Vice President
Lynn A. Kerby.............................    58    Senior Vice President
Kenneth J. Kerr...........................    52    Senior Vice President
Peter W. Camp.............................    57    Vice President
Robert D. Kelly...........................    38    Vice President
Larry R. Krumland.........................    56    Vice President
Alicia N. Noyola..........................    46    Vice President
John P. Rocchio...........................    58    Vice President
Ron A. Walter.............................    47    Vice President	

Set forth below is certain information with respect to each current Director, nominee for Director and executive officer of the Company. Upon completion of the Common Stock Offering, Mr. Krafft, Mr. Aebi and Mr. Boesch will resign from the Board of Directors of the Company and Ms. Curtis and Mr. Stathakis will be appointed to fill two of the vacancies. Accordingly, following the Common Stock Offering, the Board of Directors will be comprised of Mr. Cartwright, Ms. Curtis and Mr. Stathakis and Mr. Cartwright will serve as Chairman of the Board. The Company is actively seeking to add up to four additional independent Directors who are not directors, officers or employees of the Company, Electrowatt or an affiliate of Electrowatt. The Company anticipates that at least one additional independent Director will be appointed within six months of the completion of the Common Stock Offering.
Peter Cartwright founded the Company in 1984 and has since served as a Director and as the Company's President and Chief Executive Officer. Mr. Cartwright will become Chairman of the Board of Directors of the Company effective upon completion of the Common Stock Offering. From 1979 to 1984, Mr. Cartwright was Vice President and General Manager of Gibbs & Hill, Inc.'s Western Regional Office, an office which he established. Gibbs & Hill, Inc. is an architect-engineering firm which specializes in power engineering projects. From 1960 to 1979, Mr. Cartwright worked for General Electric's Nuclear Energy Division. His responsibilities included plant construction, project management and new business development. He served on the Board of Directors of nuclear fuel manufacturing companies in Germany, Italy and Japan. Mr. Cartwright was responsible for General Electric's technology development and licensing programs in Europe and Japan. Mr. Cartwright obtained a Master of Science Degree in Civil Engineering from Columbia University in 1953 and a Bachelor of Science Degree in Geological Engineering from Princeton University in 1952. Mr. Cartwright is a Professional Engineer licensed in the states of New York and California.
Pierre Krafft has been the Company's Chairman of the Board since March 1991. Mr. Krafft served as Executive Vice President of Electrowatt from 1971 until his retirement in April 1995. He also serves as a director of several electric utility companies in Switzerland, Germany and France and as Chairman of the Swiss National Committee of the World Energy Council. Mr. Krafft obtained a Master of Science Degree in Electrical Engineering from the Georgia Institute of Technology in 1956 and an undergraduate degree in Electrical Engineering from the Federal Institute of Technology in 1953.
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Hans-Peter Aebi has been a Director of the Company since June 1994. Mr. Aebi has served as the President of Elektrizitats-Gesellschaft Laufenburg AG, Executive Vice President of the Electric Power Operations Division and a member of Electrowatt's executive management since October 1994. He was also named Executive Vice President for Landis & Gyr AG in March 1996. He served as the Senior Vice President of the Energy Division of Electrowatt from 1993 to 1994. Mr. Aebi's prior experience includes 14 years with an Electrowatt affiliate, CKW, in various capacities including Executive Vice President from 1991 to 1992, and as the First Vice President from 1988 to 1990. Mr. Aebi obtained a Master of Science Degree in Engineering from the Federal Institute of Technology in 1972.
Rudolf Boesch has been a Director of the Company since its inception in 1984. Dr. Boesch serves as a member of the Executive Committee of Electrowatt, and as Executive Vice President of Electrowatt's Services Division. His prior experience with Electrowatt includes over ten years in the areas of marketing and sales and technical development. Dr. Boesch obtained a Ph.D. in Physics from the Federal Institute of Technology in 1965.
Ann B. Curtis has served as the Company's Senior Vice President since September 1992 and has been employed by the Company since its inception in 1984. Ms. Curtis will become a Director of the Company effective upon the completion of the Common Stock Offering. She is responsible for the Company's financial and administrative functions, including the functions of general counsel, corporate and project finance, accounting, human resources, public relations and investor relations. Ms. Curtis also serves as Corporate Secretary for the Company, and serves as an officer of each of the Company's subsidiaries. Ms. Curtis also represents the Company on partnership management committees. From the Company's inception in 1984 through 1992, she served as the Company's Vice President for Management and Financial Services. Prior to joining Calpine, Ms. Curtis was Manager of Administration for Gibbs & Hill, Inc.
George J. Stathakis has been a Senior Advisor to the Company since 1994 and will be a Director of the Company effective upon completion of the Common Stock Offering. Mr. Stathakis has been providing financial, business and management advisory services to numerous international investment banks since 1985. He also served as Chairman of the Board and Chief Executive Officer of Ramtron International Corporation, an advanced technology semiconductor company, from 1990 to 1994. From 1986 to 1989, he served as Chairman of the Board and Chief Executive Officer of International Capital Corporation, a subsidiary of American Express. Prior to 1986, Mr. Stathakis served thirty-two years with General Electric Corporation in various management and executive positions. During his service with General Electric Corporation, Mr. Stathakis founded the General Electric Trading Company and was appointed its first President and Chief Executive Officer. Mr. Stathakis obtained a Bachelor of Science Degree in Engineering from the University of California at Berkeley in 1952 and a Master of Science Degree in Engineering from the University of California at Berkeley in 1953.
Rodney M. Boucher joined the Company in June 1995 as Senior Vice President, and as President and Chief Executive Officer of the Company's subsidiary, Calpine Power Services Company. He is responsible for the purchase, sale and marketing of electric power, as well as the restructuring of contract, transmission and generation rights. Prior to joining the Company, Mr. Boucher served as Chief Operating Officer of Citizens Power & Light Company from 1992 to 1995 and as Senior Vice President of Citizens Lehman Power L.P., in Boston, Massachusetts from 1994 to 1995. Prior to joining Citizens he served as President for Electrical Interconnections-International from 1991 to 1992. Mr. Boucher also served as Vice President and Chief Information Officer with PacifiCorp from 1984 to 1991, and held various other positions with PacifiCorp since 1975. Mr. Boucher holds a Master of Science Degree in Power Systems from Rensselaer Polytechnic Institute and a Bachelor of Science Degree in Electrical Engineering from Oregon State University.
Lynn A. Kerby joined the Company in January 1991 and served as Vice President of Operations through January 1993, at which time he became a Senior Vice President for the Company. Prior to joining the Company, Mr. Kerby served as Senior Vice President-Operations of Guy F. Atkinson Company, an engineering and construction company, from 1989 to 1990, and served in various other positions within Guy F. Atkinson since 1961. Mr. Kerby served on Calpine's Board of Directors from 1984 to 1988 as a Guy F. Atkinson representative. He obtained a Bachelor of Science Degree in Civil Engineering and Business from the University of Idaho in 1961. Mr. Kerby holds a Class A Contractors License in the states of California, Arizona and Hawaii.
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Kenneth J. Kerr joined the Company in March 1996 as Senior Vice President-International. Prior to joining the Company, he served as Senior Vice President-Commercial Development for Magma Power Company from 1993 to 1995. From 1989 to 1993 he served as Business Vice President-Plastics, Pacific Area with The Dow Chemical Company. From 1966 to 1989, he served in various marketing and management positions also with The Dow Chemical Company. Mr. Kerr obtained a Bachelor of Science Degree in Chemical Engineering from the University of Delaware in 1966.
Peter W. Camp joined the Company in November 1993 and served as Director of Project Development through January 1995, at which time he became a Vice President of Project Development. From 1992 to 1993 he served as a full-time consultant with the Company. From 1988 to 1992, he served as President for Altran Corporation, a nuclear waste technology company. From 1975 to 1987, Mr. Camp worked for General Electric Company as General Manager, Nuclear Fuel Marketing and Projects Department, and as Manager, Nuclear Energy Strategic Planning. He obtained a Master of Business Administration Degree from Stanford University in 1970 and a Bachelor of Science Degree in Mechanical Engineering from Yale University in 1962.
Robert D. Kelly has served as the Company's Vice President, Finance since 1994. Mr. Kelly's responsibilities include all project and corporate finance activities. From 1991 to 1992, Mr. Kelly served as Project Finance Manager, and from 1992 to 1994, he served as Director-Project Finance for the Company. Prior to joining the Company, he was the Marketing Manager of Westinghouse Credit Corporation from 1990 to 1991. From 1989 to 1990, Mr. Kelly was Vice President of Lloyds Bank PLC. From 1982 to 1989, Mr. Kelly was employed in various positions with The Bank of Nova Scotia. He obtained a Master of Business Administration Degree from Dalhousie University, Canada in 1980 and a Bachelor of Commerce Degree from Memorial University, Canada, in 1979.
Larry R. Krumland has served as the Company's Vice President of Asset Management since January 1993. From 1990 to 1993, Mr. Krumland served as Director-Asset Management. From 1984 to 1990, Mr. Krumland served as Manager-Geothermal Development. Prior to joining the Company, he served as Director of Sales and Manager of Geothermal Projects for Gibbs & Hill, Inc. Mr. Krumland obtained a Master of Business Administration Degree in Business Economics and Finance from the University of California, Los Angeles in 1972; a Master of Science Degree in Engineering, Energy Systems, from the University of California, Los Angeles in 1967; and a Bachelor of Science Degree in Mechanical Engineering from the University of California at Berkeley in 1964.
Alicia N. Noyola joined the Company in March 1991 and served as a full-time consultant through March 1992, at which time she became employed by the Company as Special Counsel. Ms. Noyola became a Vice President of Project Development in January 1993. From 1987 to 1991, Ms. Noyola was a partner in the San Francisco, California-based law firm Thelen, Marrin, Johnson and Bridges, where she concentrated on commercial and corporate finance. Ms. Noyola obtained a Juris Doctor Degree in 1973 from Hastings College of the Law, University of California and obtained a Bachelor of Arts Degree in Architecture in 1970 from the University of California, Berkeley.
John P. Rocchio joined the Company at inception in 1984 as Vice President of Project Development. Prior to joining the Company, he served as Manager of Business Development for Gibbs & Hill, Inc. from 1979 to 1984. Prior to 1979, Mr. Rocchio served for 17 years with General Electric in various positions, including Manager International Sales for the Nuclear Energy Group from 1970 to 1979 and various engineering and marketing positions from 1962 to 1979. He obtained a Bachelor of Science Degree in Marine Engineering from the U.S. Merchant Marine Academy in 1959.
Ron A. Walter has served as the Company's Vice President of Project Development since July 1990. From 1984 to 1990, Mr. Walter served as the Company's Manager-Geothermal Projects. Prior to joining the Company, he served as Director of Sales-Geothermal for the San Jose-based architect-engineering firm, Gibbs & Hill, Inc. from 1983 to 1984 and Senior Engineer from 1982 to 1983. From 1981 to 1982 he served as Project Manager Geothermal Projects with Rogers Engineering Co. and from 1972 to 1981 he served in engineering and management positions with Batelle Northwest Laboratories. Mr. Walter obtained a Master of Science Degree in Mechanical Engineering from Oregon State University in 1976 and a Bachelor of Science Degree in Mechanical Engineering from the University of Nebraska in 1971.
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CLASSIFIED BOARD OF DIRECTORS
The Company's Amended and Restated By-laws, which will become effective upon the completion of the Common Stock Offering, will provide that the number of directors shall be between three and nine, with the actual number of directors to be established from time to time by resolution of the Board of Directors. Following the Common Stock Offering, the Company's Board of Directors will be divided into three classes, designated Class I, Class II and Class III, with each class having a three-year term. Initially, Mr. Stathakis will serve in Class I, Ms. Curtis will serve in Class II and Mr. Cartwright will serve in Class III. The initial Directors in each class will hold office for terms of one year, two years and three years, respectively. Thereafter each class will serve a three-year term. The Company's Directors are elected by the stockholders at the annual meeting of stockholders and will serve until their successors are elected and qualified, or until their earlier resignation or removal. Additional Directors will be designated to serve as Class I, Class II or Class III Directors upon their appointment to the Board of Directors following the Common Stock Offering.
COMMITTEES OF THE BOARD OF DIRECTORS
The Board of Directors will establish an Audit Committee and a Compensation Committee upon completion of the Common Stock Offering. The Audit Committee will review internal auditing procedures, the adequacy of internal controls and the results and scope of the audit and other services provided by the Company's independent auditors. The Compensation Committee will administer salaries, incentives and other forms of compensation for officers and other employees of the Company, as well as the incentive compensation and benefit plans of the Company. Initially, Mr. Stathakis will serve as the sole Director on the Audit Committee and the Compensation Committee. Thereafter, the Board of Directors will designate one or more additional non-employee Directors to serve on the Audit Committee and the Compensation Committee upon appointment to the Board of Directors.
DIRECTOR COMPENSATION
Directors currently do not receive any compensation or other services as members of the Board of Directors. The Company has determined that, following the completion of the Common Stock Offering, non-employee Directors will receive an annual fee of $25,000 and will be reimbursed for expenses incurred in attending meetings of the Board of Directors or any committee thereof. The chairman of the Compensation Committee and the chairman of the Audit Committee will receive an additional annual fee of $5,000. In addition, Directors will be eligible to participate in the Company's 1996 Stock Incentive Plan. See "-- 1996 Stock Incentive Plan."
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EXECUTIVE COMPENSATION
The following table provides certain summary information concerning the compensation earned, paid or awarded for services rendered to the Company in all capacities during each of the three years ended December 31, 1995 to the Company's Chief Executive Officer and each of the five other most highly compensated executive officers of the Company serving in that capacity as of December 31, 1995.
SUMMARY COMPENSATION TABLE

                                                                        LONG-TERM
                                                                       COMPENSATION
                                                                       ------------
                                           ANNUAL COMPENSATION            SHARES
                                       ----------------------------     UNDERLYING        ALL OTHER
     NAME AND PRINCIPAL POSITION       YEAR     SALARY      BONUS        OPTIONS       COMPENSATION(1)
- -------------------------------------  ----    --------    --------    ------------    ---------------
Peter                                  1995    $341,000    $255,750       178,668          $21,420
Cartwright...........................  1994     300,000     292,500       155,815           11,934
  President and Chief Executive        1993     220,055     176,000            --            7,722
Officer
Lynn A.                                1995     195,000      72,000        53,600            4,815
Kerby................................  1994     180,000      72,000        38,954            4,275
  Senior Vice President                1993     173,250      90,000        41,551            4,228
Ann B.                                 1995     160,000      60,000        53,600              877
Curtis...............................  1994     130,000      75,000        38,954              694
  Senior Vice President                1993     122,500      70,000            --              648
Alicia N.                              1995     140,000      45,000        13,400            1,288
Noyola...............................  1994     133,875      40,162            --            1,134
  Vice President                       1993     124,417      40,000        31,163              660
Ron A.                                 1995     135,000      45,000        13,400            1,235
Walter...............................  1994     120,000      40,000            --            1,027
  Vice President                       1993     112,500      30,000            --              587
Robert D.                              1995     126,684      42,000        22,334              436
Kelly................................  1994     115,208      60,000        31,163              389
  Vice President                       1993     103,347      50,000        23,372              343	

(1) Represents the taxable value of an employer-sponsored life insurance policy. The amount is calculated based on the age of the employee and the life insurance coverage in excess of $50,000.
EMPLOYMENT AGREEMENTS, CONSULTING AGREEMENT AND CHANGE OF CONTROL ARRANGEMENTS
The Company has entered into employment agreements with Mr. Peter Cartwright, Mr. Lynn Kerby, Ms. Ann Curtis, Mr. Ron Walter and Mr. Robert Kelly. Each of the employment agreements expires during 1999 unless earlier terminated or subsequently extended. The employment agreements provide for the payment of a base salary, subject to periodic adjustment by the Board of Directors, and provide for annual bonuses and participation in all benefit and equity plans. The employment agreements also provide for other employee benefits such as life insurance and health care, in addition to certain disability and death benefits. Severance benefits, including the acceleration of outstanding options, are also payable upon an involuntary termination or a termination following a change of control in the Company. Severance benefits would not be payable in the event that termination was for cause.
On December 1, 1994, the Company entered into a Consulting Agreement with Mr. George J. Stathakis, a Director nominee. The Consulting Agreement was amended and restated effective June 3, 1996. Pursuant to the Consulting Agreement, Mr. Stathakis has been retained to provide, among other things, advice to the Company with regard to domestic and international business, to identify project investment opportunities, and to provide advisory support to the Company's management in identifying potential buyers for, and negotiating the sale of, Electrowatt's equity interest in the Company. The Consulting Agreement provides for a monthly retainer of $5,000. In addition, for services rendered in connection with the Common Stock Offering, the Company will pay Mr. Stathakis $250,000 plus 0.25% of all payments received by Electrowatt in excess of $200 million. The Consulting Agreement terminates on January 1, 1997 unless otherwise earlier terminated or extended by mutual agreement of the parties.
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Should the Company be acquired by merger or asset sale, then all outstanding options held by the Chief Executive Officer and the other executive officers under the Company's Stock Option Program or the 1996 Stock Incentive Plan will automatically accelerate and vest in full, except to the extent those options are to be assumed by the successor corporation. In addition, the Compensation Committee as Plan Administrator of the 1996 Stock Incentive Plan will have the authority to provide for the accelerated vesting of the shares of Common Stock subject to outstanding options held by the Chief Executive Officer or any other executive officer or any unvested shares of Common Stock subject to direct issuances held by such individual, in connection with the termination of that individual's employment following: (i) a merger or asset sale in which these options are assumed or are assigned or (ii) certain hostile changes in control of the Company. However, certain executive officers have existing employment agreements that provide for the acceleration of their options upon a termination of their employment following certain changes in control or ownership of the Company.
STOCK OPTION PROGRAM
The following table sets forth certain information concerning grants of stock options during the fiscal year ended December 31, 1995 to each of the executive officers named in the Summary Compensation Table above. The table also sets forth hypothetical gains or "option spreads" for the options at the end of their respective ten-year terms. These gains are based on the assumed rates of annual compound stock price appreciation of 5% and 10% from the date the option was granted over the full option term.
OPTION GRANTS IN LAST FISCAL YEAR

                                              INDIVIDUAL GRANTS(1)                        POTENTIAL REALIZABLE
                          -------------------------------------------------------------     VALUE AT ASSUMED
                                               PERCENTAGE OF                                ANNUAL RATES OF
                                               TOTAL OPTIONS                                     STOCK
                                                GRANTED TO                                 PRICE APPRECIATION
                               OPTIONS           EMPLOYEES      EXERCISE                   FOR OPTION TERM(4)
                               GRANTED           IN FISCAL      PRICE PER    EXPIRATION   --------------------
          NAME            (NO. OF SHARES)(2)      YEAR(3)         SHARE         DATE         5%         10%
- ------------------------  ------------------   -------------   -----------   ----------   --------   ---------
Peter Cartwright........        178,668              40%          $4.91       1/1/05      $551,704   $1,398,126
Lynn A. Kerby...........         53,600              12            4.91       1/1/05       165,510     419,435
Ann B. Curtis...........         53,600              12            4.91       1/1/05       165,510     419,435
Alicia N. Noyola........         13,400               3            4.91       1/1/05        41,377     104,859
Ron A. Walter...........         13,400               3            4.91       1/1/05        41,377     104,859
Robert D. Kelly.........         22,334               5            4.91       1/1/05        68,965     174,770	

(1) The exercise price may be paid in cash, in shares of the Company's Common Stock valued at fair market value on the exercise date or through a cashless exercise procedure involving a same-day sale of the purchased shares. The Company may also finance the option exercise by loaning the optionee sufficient funds to pay the exercise price for the purchased shares, together with any federal and state income tax liability incurred by the optionee in connection with such exercise. The Compensation Committee of the Board of Directors, as the Plan Administrator of the Company's 1996 Stock Incentive Plan, will have the discretionary authority to reprice the options through the cancellation of those options and the grant of replacement options with an exercise price based on the fair market value of the option shares on the grant date.
(2) Each option set forth in the table above was granted on January 1, 1995 and has a maximum term of ten years measured from the grant date, subject to earlier termination upon the executive officer's termination of service with the Company. Each option is immediately exercisable, but the underlying shares are subject to repurchase by the Company at the original exercise price paid per share should the executive officer's service with the Company cease prior to vesting in such shares. The Company's repurchase right will lapse with respect to, and the executive officer will vest in, four equal annual installments over the four-year period of service measured from the grant date. The Company's right to repurchase with respect to the option shares will terminate immediately upon an acquisition of the Company by merger or asset sale if the options are not assumed by the successor corporation.
(3) The Company granted options to purchase 446,930 shares of Common Stock during the year ended December 31, 1995.
(4) The 5% and 10% assumed annual rates of compound stock price appreciation are mandated by the rules of the Securities and Exchange Commission (the "Commission") and do not represent the Company's estimate or a projection by the Company of future stock prices.
In addition to the options described above, in March 1996 the Board of Directors granted options to purchase shares of Common Stock under the Company's Stock Option Program to the following individuals in the designated amounts; Mr. Cartwright, an option for 181,785 shares; Mr. Kerby, an option for 41,551 shares; Ms. Curtis, an option for 51,938 shares; Ms. Noyola, an option for 20,775 shares; Mr. Walter, an option for
75

20,775 shares; and Mr. Kelly, an option for 36,357 shares. The exercise price for each option is $8.57 per share. Each option has a maximum term of ten (10) years measured from the date of grant, subject to earlier termination in the event of the optionee's cessation of service with the Company. The Company's right of repurchase will lapse with respect to, and the optionee will vest in, the option shares in a series of four equal annual installments over the four-year period of service measured from January 1, 1996. The Company's right to repurchase with respect to the option shares will terminate immediately upon an acquisition of the Company by merger or asset sale if the options are not assumed by the successor corporation.
No executive officer named in the Summary Compensation Table above exercised stock options during the year ended December 31, 1995. The following table sets forth certain information concerning the number of shares subject to exercisable and unexercisable stock options held by the executive officers named in the Summary Compensation Table above as of December 31, 1995. Also reported are values for "in-the-money" options that represent the positive spread between the respective exercise prices of outstanding stock options and the fair market value of the Company's Common Stock.
AGGREGATE OPTION EXERCISES IN LAST FISCAL YEAR AND YEAR-END OPTION VALUES

                                           NUMBER OF UNEXERCISED OPTIONS     VALUE OF UNEXERCISED IN-THE-
                                           AT DECEMBER 31, 1995 (NO. OF            MONEY OPTIONS AT
                                                     OPTIONS)                    DECEMBER 31, 1995(1)
                                           -----------------------------     -----------------------------
                 NAME                      EXERCISABLE     UNEXERCISABLE     EXERCISABLE     UNEXERCISABLE
- ---------------------------------------    -----------     -------------     -----------     -------------
Peter Cartwright.......................      597,292          256,576        $11,049,902      $ 4,746,656
Lynn A. Kerby..........................       50,640           83,465            936,840        1,544,103
Ann B. Curtis..........................      144,129           73,077          2,666,387        1,351,925
Alicia N. Noyola.......................       23,372           21,191            432,382          392,034
Ron A. Walter..........................      114,265           13,400          2,113,903          247,900
Robert D. Kelly........................       33,111           43,758            612,554          809,523	

(1) For purposes of the computation of the value of unexercised in-the-money options at December 31, 1995, the table above assumes that the value of the underlying shares is the initial public offering price of the shares offered hereby, which is assumed to be $18.50 per share.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
For 1995, the members of the Board of Directors, other than Mr. Cartwright, acted as the Compensation Committee for the purposes of establishing the compensation for Mr. Cartwright, the Company's President and Chief Executive Officer. All decisions regarding the compensation of the Company's other executive officers were made by Mr. Cartwright. Upon the consummation of the Common Stock Offering, there will be established a Compensation Committee of the Board of Directors. Following the Common Stock Offering, no member of the Compensation Committee of the Board of Directors of the Company will serve as a member of the board of directors or compensation committee of any entity that has one or more executive officers serving as a member of the Company's Board of Directors or Compensation Committee.
1996 STOCK INCENTIVE PLAN
The Company's 1996 Stock Incentive Plan (the "1996 Plan") is intended to serve as the successor equity incentive program to the Company's Stock Option Program (the "Predecessor Plan"). See "-- Stock Option Program." The 1996 Plan was adopted by the Board of Directors and approved by the Company's stockholder on July 17, 1996. The 1996 Plan will become effective on the date of this Prospectus. The Company has initially authorized 4,041,858 shares of Common Stock for issuance under the 1996 Plan. This initial share reserve is comprised of (i) the 2,596,923 shares which remained available for issuance under the Predecessor Plan, including the 2,392,026 shares subject to outstanding options thereunder, plus (ii) an additional increase of 1,444,935 shares. In addition, the share reserve will automatically be increased on the first trading day of January each calendar year, beginning in January 1997, by a number of shares equal to one percent (1%) of
76

the number of shares of Common Stock outstanding on the last trading day of the immediately preceding calendar year. However, in no event may any one participant in the 1996 Plan receive option grants or direct stock issuances for more than 500,000 shares in the aggregate per calendar year.
Outstanding options under the Predecessor Plan will be incorporated into the 1996 Plan upon the consummation of the Common Stock Offering, and no further option grants will be made under the Predecessor Plan. The incorporated options will continue to be governed by their existing terms, unless the Plan Administrator elects to extend one or more features of the 1996 Plan to those options. However, except as otherwise noted below, the outstanding options under the Predecessor Plan contain substantially the same terms and conditions summarized below for the Discretionary Option Grant Program in effect under the 1996 Plan.
The 1996 Plan is divided into five separate components: (i) the Discretionary Option Grant Program under which eligible individuals in the Company's employ or service (including officers and other employees, non-employee Board members and independent consultants) may, at the discretion of the Plan Administrator, be granted options to purchase shares of Common Stock at an exercise price not less than 85% of their fair market value on the grant date, (ii) the Stock Issuance Program under which such individuals may, in the Plan Administrator's discretion, be issued shares of Common Stock directly, through the purchase of such shares at a price not less than 100% of their fair market value at the time of issuance or as a bonus tied to the performance of services, (iii) the Salary Investment Option Grant Program under which executive officers and other highly compensated employees may elect to apply a portion of their base salary to the acquisition of special stock option grants, (iv) the Automatic Option Grant Program under which option grants will automatically be made at periodic intervals to eligible non-employee Directors to purchase shares of Common Stock at an exercise price equal to 100% of their fair market value on the grant date and (v) the Director Fee Option Grant Program pursuant to which the non-employee Directors may apply a portion of the annual retainer fee, if any, otherwise payable to them in cash each year to the acquisition of special stock option grants.
The Discretionary Option Grant, Stock Issuance and Salary Investment Option Grant Programs will be administered by the Compensation Committee. The Compensation Committee as Plan Administrator will have complete discretion to determine which eligible individuals are to receive option grants or stock issuances, the time or times when such option grants or stock issuance are to be made, the number of shares subject to each such grant or issuance, the vesting schedule to be in effect for the option grant or stock issuance, the maximum term for which any granted option is to remain outstanding and the status of any granted option as either an incentive stock option or a non-statutory stock option under the Federal tax laws, except that all options granted under the Salary Investment Option Grant Program will be non-statutory stock options. The administration of the Automatic Option Grant and Director Fee Option Grant Programs will be self-executing in accordance with the express provisions of each such program.
The exercise price for the shares of Common Stock subject to option grants made under the 1996 Plan may be paid in cash or in shares of Common Stock valued at fair market value on the exercise date. The option may also be exercised through a same-day sale program without any cash outlay by the optionee. In addition, the Plan Administrator may provide financing to one or more optionees in the exercise of their outstanding options by allowing such individuals to deliver a full-recourse, interest-bearing promissory note in payment of the exercise price and any associated withholding taxes incurred in connection with such exercise.
In the event that the Company is acquired by merger or asset sale, each outstanding option under the Discretionary Option Grant Program which is not to be assumed by the successor corporation will automatically accelerate in full, and all unvested shares under the Stock Issuance Program will immediately vest, except to the extent the Company's repurchase rights with respect to those shares are to be assigned to the successor corporation. The Plan Administrator will have the authority under the Discretionary Option Grant and Stock Issuance Programs to grant options and to structure repurchase rights so that the shares subject to those options or repurchase rights will automatically vest in the event the individual's service is terminated, whether involuntarily or through a resignation for good reason, within a specified period (not to exceed 18 months) following (i) a merger or asset sale in which those options are assumed or (ii) a hostile
77

change in control of the Company effected by a successful tender offer for more than 50% of the outstanding voting stock or by proxy contest for the election of Directors. Options currently outstanding under the Predecessor Plan will accelerate upon an acquisition of the Company by merger or asset sale, unless those options are assumed by the acquiring entity. However, such options under the Predecessor Plan are not subject to acceleration upon the termination of the optionee's service following an acquisition in which those options are assumed or following a hostile change in control, except to the extent provided in any employment contract or severance agreement in effect between the optionee and the Company.
Stock appreciation rights may be issued in tandem with option grants made under the Discretionary Option Grant Program. The holders of such rights will have the opportunity to elect between the exercise of their outstanding stock options for shares of Common Stock or the surrender of those options for an appreciation distribution from the Company equal to the excess of (i) the fair market value of the vested shares of Common Stock subject to the surrendered option over (ii) the aggregate exercise price payable for such shares. Such appreciation distribution may be made in cash or in shares of Common Stock. There are currently no outstanding stock appreciation rights under the Predecessor Plan.
The Plan Administrator has the authority to effect the cancellation of outstanding options under the Discretionary Option Grant Program (including options incorporated from the Predecessor Plan) in return for the grant of new options for the same or different number of option shares with an exercise price per share based upon the fair market value of the Common Stock on the new grant date.
In the event the Plan Administrator elects to activate the Salary Investment Option Grant Program for one or more calendar years, each executive officer and other highly compensated employee of the Company selected for participation may elect, prior to the start of the calendar year, to reduce his or her base salary for that calendar year by a specified dollar amount not less than $10,000 nor more than $50,000. If such election is approved by the Plan Administrator, the officer will be granted, on or before the last trading day in January in the calendar year for which the salary reduction is to be in effect, a non-statutory option to purchase that number of shares of Common Stock determined by dividing the salary reduction amount by two-thirds of the fair market value per share of Common Stock on the grant date. The option will be exercisable at a price per share equal to one-third of the fair market value of the option shares on the grant date. As a result, the total spread on the option shares at the time of grant will be equal to the amount of salary invested in that option. The option will vest in a series of 12 equal monthly installments over the calendar year for which the salary reduction is in effect and will be subject to full and immediate vesting upon certain changes in the ownership or control of the Company.
Under the Automatic Option Grant Program, each individual who is serving as a non-employee Director on the date the Underwriting Agreement for the Common Stock Offering is executed will receive at that time a stock option for 10,000 shares of Common Stock, provided that individual has not previously received an option grant from the Company in connection with his or her service on the Board of Directors. Each individual who becomes a non-employee Director after such date will receive an option grant for 10,000 shares of Common Stock at the time of his or her commencement of service on the Board of Directors, provided such individual has not otherwise been in the prior employment of the Company. In addition, at each Annual Stockholders Meeting, beginning with the 1997 Annual Stockholders Meeting, each individual who is to continue to serve as a non-employee Director will receive an option grant to purchase 1,500 shares of Common Stock, whether or not such individual has been in the prior employment of the Company or has previously received a stock option grant from the Company.
Each automatic grant will have an exercise price equal to the fair market value per share of Common Stock on the grant date and will have a maximum term of 10 years, subject to earlier termination following the optionee's cessation of service on the Board of Directors. Each automatic option will be immediately exercisable; however, any shares purchased upon exercise of the option will be subject to repurchase, at the option exercise price paid per share, should the optionee's service as a non-employee Director cease prior to vesting in the shares. The 10,000-share grant will vest in four successive equal annual installments over the optionee's period of service on the Board of Directors measured from the grant date. Each annual 1,500-share grant will vest upon the optionee's completion of one year of service on the Board of Directors measured from
78

the grant date. However, each outstanding option will immediately vest upon (i) certain changes in the ownership or control of the Company or (ii) the death or disability of the optionee while serving as a Director.
Should the Director Fee Option Grant Program be activated in the future, each non-employee Director would have the opportunity to apply all or a portion of his or her annual retainer fee otherwise payable in cash to the acquisition of a below-market option grant. The option grant would automatically be made on the first trading day in January in the year for which the retainer fee would otherwise be payable in cash. The option will have an exercise price per share equal to one-third of the fair market value of the shares of Common Stock on the grant date, and the number of shares subject to the option will be determined by dividing the amount of the retainer fee applied to the program by two-thirds of the fair market value per share of Common Stock on the grant date. As a result, the total spread on the option (the fair market value of the option shares on the grant date less the aggregate exercise price payable for those shares) will be equal to the portion of the retainer fee invested in that option. The option will become exercisable for the option shares in a series of installments over the optionee's period of service on the Board of Directors as follows: one half of the option shares will become exercisable upon the optionee's completion of six months of service on the Board of Directors during the calendar year of the option grant and the balance will become exercisable in six successive equal monthly installments upon his or her completion of each additional month of service on the Board of Directors in such calendar year. However, the option will become immediately exercisable for all the option shares upon (i) certain changes in the ownership or control of the Company or (ii) the death or disability of the optionee while serving as a Director.
The Board of Directors may amend or modify the 1996 Plan at any time. The 1996 Plan will terminate on July 16, 2006, unless sooner terminated by the Board of Directors.
EMPLOYEE STOCK PURCHASE PLAN
The Company's Employee Stock Purchase Plan (the "Purchase Plan") was adopted by the Board of Directors on July 17, 1996. The Purchase Plan is designed to allow eligible employees of the Company and participating subsidiaries to purchase shares of Common Stock, at semi-annual intervals, through their periodic payroll deductions under the Purchase Plan, and a reserve of 275,000 shares of Common Stock has been established for this purpose.
The Purchase Plan will be implemented in a series of successive offering periods, each with a maximum duration of 24 months. However, the initial offering period will begin on the day the Underwriting Agreement is executed in connection with the Common Stock Offering and will end on the last business day in August 1998.
Individuals who are eligible employees on the start date of any offering period may enter the Purchase Plan on that start date or on any subsequent semi-annual entry date (March 1 or September 1 each year). Individuals who become eligible employees after the start date of the offering period may join the Purchase Plan on any subsequent semi-annual entry date within that period.
Payroll deductions may not exceed 15% of the participant's cash compensation for each semi-annual period of participation, and the accumulated payroll deductions will be applied to the purchase of shares on the participant's behalf on each semi-annual purchase date (February 28 and August 31 each year, with the first such purchase date to occur on February 28, 1997) at a purchase price per share not less than eighty-five percent (85%) of the lower of (i) the fair market value of the Common Stock on the participant's entry date into the offering period or (ii) the fair market value on the semi-annual purchase date. In no event, however, may any participant purchase more than 300 shares on any one semi-annual purchase date. Should the fair market value of the Common Stock on any semi-annual purchase date be less than the fair market value of the Common Stock on the first day of the offering period, then the current offering period will automatically end and a new 24-month offering period will begin, based on the lower fair market value.
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LIMITATION OF LIABILITY AND INDEMNIFICATION MATTERS
The Company's Certificate of Incorporation limits the liability of directors to the maximum extent permitted by Delaware law. Delaware law provides that a director of a corporation will not be personally liable for monetary damages for breach of such individual's fiduciary duties as a director except for liability (i) for any breach of such director's duty of loyalty to the corporation, (ii) for acts or omissions not in good faith or that involve intentional misconduct or a knowing violation of law, (iii) for unlawful payments of dividends or unlawful stock repurchases or redemptions as provided in Section 174 of the Delaware General Corporation Law, or (iv) for any transaction from which a director derives an improper personal benefit.
The Company's Bylaws provide that the Company will indemnify its directors and may indemnify its officers, employees and other agents to the full extent permitted by law. The Company believes that indemnification under its Bylaws covers at least negligence and gross negligence on the part of an indemnified party and permits the Company to advance expenses incurred by an indemnified party in connection with the defense of any action or proceeding arising out of such party's status or service as a director, officer, employee or other agent of the Company upon an undertaking by such party to repay such advances if it is ultimately determined that such party is not entitled to indemnification.
The Company has entered into separate indemnification agreements with each of its directors and officers. These agreements require the Company, among other things, to indemnify such director or officer against expenses (including attorneys' fees), judgments, fines and settlements (collectively, "Liabilities") paid by such individual in connection with any action, suit or proceeding arising out of such individual's status or service as a director or officer of the Company (other than Liabilities arising from willful misconduct or conduct that is knowingly fraudulent or deliberately dishonest) and to advance expenses incurred by such individual in connection with any proceeding against such individual with respect to which such individual may be entitled to indemnification by the Company. The Company believes that its Certificate of Incorporation and Bylaw provisions and indemnification agreements are necessary to attract and retain qualified persons as directors and officers.
At present the Company is not aware of any pending litigation or proceeding involving any director, officer, employee or agent of the Company where indemnification will be required or permitted. The Company is not aware of any threatened litigation or proceeding that might result in a claim for such indemnification.
CERTAIN TRANSACTIONS
CS Holding, a Swiss corporation, holds approximately 44.9% of the outstanding shares of Electrowatt, which indirectly holds all of the outstanding capital stock of the Company. CS Holding also holds (i) approximately 100% of the outstanding shares of Credit Suisse and (ii) approximately 69.3% of the outstanding common stock of CS First Boston, Inc., which holds all of the outstanding common stock of CS First Boston Corporation. CS First Boston Corporation was one of the underwriters of the Company's 9 1/4% Senior Notes issued in February 1994 and was one of the placement agents in the sale of the 10 1/2% Senior Notes in May 1996. CS First Boston Corporation is acting as an Underwriter in the Common Stock Offering.
In January 1990, O.L.S. Energy-Agnews entered into a credit agreement with Credit Suisse providing for a $28 million loan to finance the construction of the Agnews Facility. The Company holds a 20% interest in O.L.S. Energy-Agnews. The loan is collateralized by all of the assets of the Agnews Facility and bears interest on the unpaid principal balance based on LIBOR plus a margin rate varying between .50% and 1.50%. After commencement of commercial operation of the Agnews Facility, the Facility was sold to Nynex Credit Corporation under a sale leaseback arrangement with O.L.S. Energy-Agnews and Credit Suisse. Under the sale leaseback, O.L.S. Energy-Agnews entered into a 22-year lease, commencing February 1991, providing for the payment of a fixed base rental, as well as renewal options and a purchase option at the termination of the lease. As of December 31, 1995, O.L.S. Energy-Agnews's outstanding obligation of its sale leaseback arrangement was $37.6 million.
In September 1990, the Company obtained a $25.3 million Credit Facility from Credit Suisse. In April 1993, the Credit Suisse Credit Facility was amended to increase the amount of credit available to the
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Company to $54.0 million. The Credit Suisse Credit Facility is unsecured and bears interest on the amounts outstanding from time to time, if any, at LIBOR plus .50% per annum. During 1994, the Company completed a $105.0 million public debt offering of the 9 1/4% Senior Notes. A portion of the net proceeds were used to repay $52.6 million indebtedness outstanding under the Credit Suisse Credit Facility. On April 21, 1995, the Company entered into the Credit Suisse Credit Facility providing for advances of $50.0 million. On April 29, 1996, the amount of advances available under the Credit Suisse Credit Facility was increased to $58.0 million. A portion of the proceeds of the sale of the 10 1/2% Senior Notes was used to repay outstanding borrowings under the Credit Suisse Credit Facility of approximately $53.7 million on May 16, 1996. The amount of advances available under the Credit Suisse Credit Facility was subsequently reduced to $50.0 million. Borrowings of approximately $13.0 million are outstanding under the Credit Suisse Credit Facility as of the date of this Prospectus. All of such borrowings will be repaid with a portion of the net proceeds to the Company from the Common Stock Offering. Upon the completion of the Common Stock Offering, the Credit Suisse Credit Facility will terminate.
In January 1992, Sumas and its wholly owned subsidiary, ENCO, entered into loan agreements with Prudential and Credit Suisse providing for a $120.0 million loan to finance the construction of the Sumas Facility and acquisition of associated gas reserves. See "Business -- Description of Facilities -- Power Generation Facilities -- Sumas Facility." As of December 31, 1995, the outstanding indebtedness of Sumas and ENCO under the term loan was $119.0 million.
In January 1995, the Company and Electrowatt entered into a management services agreement, which replaced a prior similar agreement, under which Electrowatt agreed to provide the Company with advisory services in connection with the construction, financing, acquisition and development of power projects, as well as any other advisory services as may be required by the company in connection with the operation of the Company. The Company has agreed to pay Electrowatt $200,000 per year for all services rendered under the management services agreement. Pursuant to this agreement, $200,000 was paid in 1995. Upon the completion of the Common Stock Offering, the management services agreement will terminate.
In 1995, the Company paid $106,000 to Electrowatt pursuant to a guarantee fee agreement whereby Electrowatt agreed to guarantee the payment when due of any and all indebtedness of the Company to Credit Suisse in accordance with the terms and conditions of the Credit Suisse Credit Facility. Under the guarantee fee agreement, the Company has agreed to pay to Electrowatt an annual fee equal to 1% of the average outstanding balance of the Company's indebtedness to Credit Suisse during each quarter as compensation for all services rendered under the guarantee fee agreement. Upon the completion of the Common Stock Offering, the guarantee fee agreement will terminate.
In June 1995, Calpine repaid $57.5 million of non-recourse financing to Credit Suisse which was outstanding indebtedness related to the Greenleaf 1 and 2 Facilities at the time of the acquisition of such facilities.
In December 1994, the Company entered into a Consulting Agreement with Mr. Stathakis, a Director nominee, which was amended and restated effective June 3, 1996. See "Management--Employment Agreements, Consulting Agreement and Change of Control Agreements."
In March 1996, Electrowatt invested $50.0 million in the Company in the form of shares of Preferred Stock, all of which have been converted into shares of Common Stock in connection with the Common Stock Offering.
The Company believes that all transactions between the Company and its officers, Directors, principal shareholders and affiliates have been and will be on terms no less favorable to the Company than could be obtained from unaffiliated parties.
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PRINCIPAL AND SELLING STOCKHOLDERS
The following table sets forth certain information regarding beneficial ownership of the Company's Common Stock as of June 30, 1996 and as adjusted to reflect the Common Stock Offering by: (i) each person known by the Company to be the beneficial owner of more than five percent of the outstanding shares of the Company's Common Stock, (ii) each Director and nominee for Director of the Company, (iii) each executive officer of the Company listed in the Summary Compensation Table, (iv) Electrowatt (the "Selling Stockholder"), and (v) all executive officers and Directors and nominees for Director of the Company as a group.

                                    SHARES BENEFICIALLY                             SHARES BENEFICIALLY
                                           OWNED                                           OWNED
                                       PRIOR TO THE                                      AFTER THE
                                       COMMON STOCK                                     COMMON STOCK
                                        OFFERING(1)                                     OFFERING(1)
        NAME AND ADDRESS          -----------------------     NUMBER OF SHARES     ----------------------
      OF BENEFICIAL OWNER           NUMBER        PERCENT     BEING OFFERED(2)      NUMBER        PERCENT
- --------------------------------  ----------      -------     ----------------     ---------      -------
Electrowatt Ltd.(2).............  12,567,180        100%(2)      12,567,180               --         --
Pierre Krafft...................          --          --                 --               --         --
Hans-Peter Aebi.................          --          --                 --               --         --
Rudolf Boesch...................          --          --                 --               --         --
Peter Cartwright(3).............     641,959        4.9%                 --          641,959        3.4%
Ann B. Curtis(3)................     157,529        1.2%                 --          157,529          *
George J. Stathakis.............          --          --                 --               --         --
Lynn A. Kerby(3)................      74,428           *                 --           74,428          *
Ron A. Walter(3)................     117,615           *                 --          117,615          *
Alicia N. Noyola(3).............      34,513           *                 --           34,513          *
Robert D. Kelly(3)..............      44,537           *                 --           44,537          *
All executive officers and
  Directors and nominees for
  Director as a group (15
  persons)(3)...................   1,366,696        9.8%                 --        1,366,696        7.0%	

* Less than one percent
(1) Beneficial ownership is determined in accordance with the rules of the Commission and generally includes voting or investment power with respect to securities. Shares of Common Stock subject to options, warrants and convertible notes currently exercisable or convertible, or exercisable or convertible within 60 days, are deemed outstanding for computing the percentage of the person holding such options but are not deemed outstanding for computing the percentage of any other person. Subject to community property laws where applicable, the persons named in the table have sole voting and investment power with respect to all shares of Common Stock shown as beneficially owned by them.
(2) Electrowatt's address is: Bellerivestrasse 36, P.O. Box CH-8022, Zurich, Switzerland.
(3) Represents shares of the Company's Common Stock issuable upon exercise of options that are currently exercisable or will become exercisable within 60 days after June 30, 1996.
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DESCRIPTION OF CAPITAL STOCK
The authorized capital stock of the Company consists of 100,000,000 shares of Common Stock, $.001 par value, and 10,000,000 shares of Preferred Stock, $.001 par value. The following summary is qualified in its entirety by the provisions of the Certificate of Incorporation and Bylaws of the Company, which have been filed as exhibits to the Registration Statement of which this Prospectus constitutes a part.
COMMON STOCK
There will be 18,045,000 shares of Common Stock outstanding upon the completion of the Common Stock Offering. The holders of Common Stock are entitled to one vote per share on all matters to be voted upon by the stockholders. Subject to preferences that may be applicable to any outstanding Preferred Stock, the holders of Common Stock are entitled to receive ratably such dividends, if any, as may be declared from time to time by the Board of Directors out of funds legally available therefor. See "Dividend Policy." In the event of the liquidation, dissolution or winding up of the Company, the holders of Common Stock are entitled to share ratably in all assets remaining after payment of liabilities, subject to prior liquidation rights of Preferred Stock, if any, then outstanding. The Common Stock has no preemptive or conversion rights or other subscription rights. There are no redemption or sinking fund provisions applicable to the Common Stock. All outstanding shares of Common Stock to be outstanding upon the completion of the Common Stock Offering will be fully paid and non-assessable.
PREFERRED STOCK
The Board of Directors has the authority to issue the Preferred Stock in one or more series and to fix the rights, preferences, privileges and restrictions granted to or imposed upon any wholly unissued shares of undesignated preferred stock and to fix the number of shares constituting any series and the designations of such series, without any further vote or action by the stockholders. The Board of Directors, without stockholder approval, can issue Preferred Stock with voting and conversion rights which could adversely affect the voting power of the holders of Common Stock. The issuance of Preferred Stock may have the effect of delaying, deferring or preventing a change in control of the Company, or could delay or prevent a transaction that might otherwise give stockholders of the Company an opportunity to realize a premium over the then prevailing market price of the Common Stock. There will be no shares of Preferred Stock outstanding upon the completion of the Common Stock Offering.
ANTI-TAKEOVER EFFECTS OF PROVISIONS OF THE CERTIFICATE OF INCORPORATION, BYLAWS AND DELAWARE LAW
Certificate of Incorporation and Bylaws
The Company's Certificate of Incorporation and Bylaws provide that the Company's Board of Directors is classified into three classes of Directors serving staggered, three-year terms. The Certificate of Incorporation also provides that Directors may be removed only by the affirmative vote of the holders of two-thirds of the shares of capital stock of the Company entitled to vote. Any vacancy on the Board of Directors may be filled only by vote of the majority of Directors then in office. Further, the Certificate of Incorporation provides that any "Business Combination" (as therein defined) requires the affirmative vote of the holders of two-thirds of the shares of capital stock of the Company entitled to vote, voting together as a single class. The Certificate of Incorporation also provides that all stockholder actions must be effected at a duly called meeting and not by a consent in writing. The Bylaws provide that the Company's stockholders may call a special meeting of stockholders only upon a request of stockholders owning at least 50% of the Company's capital stock. These provisions of the Certificate of Incorporation and Bylaws could discourage potential acquisition proposals and could delay or prevent a change in control of the Company. These provisions are intended to enhance the likelihood of continuity and stability in the composition of the Board of Directors and in the policies formulated by the Board of Directors and to discourage certain types of transactions that may involve an actual or threatened change of control of the Company. These provisions are designed to reduce the vulnerability of the Company to an unsolicited acquisition proposal. The provisions also are intended to discourage certain tactics that may be used in proxy fights. However, such provisions could have the effect of
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discouraging others from making tender offers for the Company's shares and, as a consequence, they also may inhibit fluctuations in the market price of the Company's shares that could result from actual or rumored takeover attempts. Such provisions also may have the effect of preventing changes in the management of the Company. See "Risk Factors -- Anti-Takeover Provisions" and "Management -- Classified Board of Directors."
Delaware Anti-Takeover Statute
The Company is subject to Section 203 of the Delaware General Corporation Law ("Section 203"), which, subject to certain exceptions, prohibits a Delaware corporation from engaging in any business combination with any interested stockholder for a period of three years following the date that such stockholder became an interested stockholder, unless: (i) prior to such date, the board of directors of the corporation approved either the business combination or the transaction that resulted in the stockholder becoming an interested stockholder;
(ii) upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced, excluding for purposes of determining the number of shares outstanding those shares owned (x) by persons who are directors and also officers and (y) by employee stock plans in which employee participants do not have the right to determine confidentially whether shares held subject to the plan will be tendered in a tender or exchange offer; or (iii) on or subsequent to such date, the business combination is approved by the board of directors and authorized at an annual or special meeting of stockholders, and not by written consent, by the affirmative vote of at least 66 2/3% of the outstanding voting stock that is not owned by the interested stockholder.
Section 203 defines business combination to include: (i) any merger or consolidation involving the corporation and the interested stockholder; (ii) any sale, transfer, pledge or other disposition of 10% or more of the assets of the corporation involving the interested stockholder; (iii) subject to certain exceptions, any transaction that results in the issuance or transfer by the corporation of any stock of the corporation to the interested stockholder; (iv) any transaction involving the corporation that has the effect of increasing the proportionate share of the stock of any class or series of the corporation beneficially owned by the interested stockholder; or (v) the receipt by the interested stockholder of the benefit of any loans, advances, guarantees, pledges or other financial benefits provided by or through the corporation. In general, Section 203 defines an interested stockholder as any entity or person beneficially owning 15% or more of the outstanding voting stock of the corporation and any entity or person affiliated with or controlling or controlled by such entity or person.
TRANSFER AGENT AND REGISTRAR
The Transfer Agent and Registrar for the Company's Common Stock is First Chicago Trust Company of New York. Its address is 525 Washington Boulevard, Jersey City, New Jersey 07310 and its telephone number is (201) 222-4114.
LISTING
The Common Stock has been approved for listing on the New York Stock Exchange under the trading symbol "CPN," subject to notice of issuance.
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SHARES ELIGIBLE FOR FUTURE SALE
Upon the completion of the Common Stock Offering, the Company will have 18,045,000 shares of Common Stock outstanding (assuming no exercise of the Underwriters' over-allotment option and assuming no exercise of outstanding options). All of the shares sold in the Common Stock Offering will be freely tradeable without restriction or further registration under the Securities Act, except that any shares purchased by "affiliates" of the Company, as that term is defined under the Securities Act ("Affiliates"), may generally only be sold in compliance with the limitations of Rule 144 described below.
SALES OF RESTRICTED SHARES
Shares of Common Stock not freely tradeable without restriction or further registration under the Securities Act are deemed "restricted" under Rule 144 of the Securities Act. The number of shares of Common Stock available for sale in the public market is limited by restrictions under the Securities Act and lock-up agreements under which the holders of such shares have agreed with the Underwriters not to sell or otherwise dispose of any of their shares for a period of 180 days after the date of this Prospectus without the prior written consent of CS First Boston. The Company intends to register with the Commission on a registration statement on Form S-8 a total of 4,041,858 shares of Common Stock issuable pursuant to the Company's 1996 Plan, including the 2,392,026 shares of Common Stock subject to outstanding options previously granted under the Predecessor Plan. Upon the effectiveness of such registration statement, the shares issuable upon the exercise of outstanding options or otherwise under the 1996 Plan will become freely tradeable upon issuance thereof, subject to the restrictions on Affiliates under the Securities Act.
In general, under Rule 144 of the Securities Act as currently in effect, beginning 90 days after the Common Stock Offering, a person (or persons whose shares are aggregated) who has beneficially owned "restricted" shares for at least two years, including a person who may be deemed an Affiliate of the Company, is entitled to sell within any three-month period a number of shares of Common Stock that does not exceed the greater of 1% of the then-outstanding shares of Common Stock of the Company (approximately 180,450 shares after giving effect to the Common Stock Offering) or the average weekly trading volume of the Common Stock on the New York Stock Exchange during the four calendar weeks preceding such sale. Sales under Rule 144 are subject to certain restrictions relating to manner of sale, notice and the availability of current public information about the Company. A person (or persons whose shares are aggregated) who is not an Affiliate of the Company at any time during the ninety days preceding a sale, and who has beneficially owned shares for at least three years, would be entitled to sell such shares immediately following the Common Stock Offering without regard to the volume limitations, manner of sale provisions or notice or other requirements of Rule 144 of the Securities Act pursuant to Rule 144(k). However, the transfer agent may require an opinion of counsel that a proposed sale of shares comes within the terms of Rule 144(k) prior to effecting a transfer of such shares.
Prior to the Common Stock Offering, there has been no public market for the Common Stock of the Company and no predictions can be made of the effect, if any, that the sale or availability for sale of shares of additional Common Stock will have on the market price of the Common Stock. Nevertheless, sales of substantial amounts of such shares in the public market, or the perception that such sales could occur, could adversely affect the market price of the Common Stock and could impair the Company's future ability to raise capital through an offering of its equity securities.
OPTIONS
As of the date of this Prospectus, options to purchase a total of 2,392,026 shares of Common Stock were outstanding under the Company's 1996 Plan. Of such amount, options to purchase 1,366,696 shares were exercisable, all of which will become eligible for sale 180 days after the date of this Prospectus upon expiration of certain lock-up agreements with the Underwriters and pursuant to Rule 701, subject in some cases to certain volume and other resale restrictions. Rule 701 under the Securities Act provides that shares of Common Stock acquired on the exercise of outstanding options may be resold (i) by persons other than Affiliates, beginning 90 days after the date of this Prospectus, subject only to the manner of sale provisions of
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Rule 144 and (ii) by Affiliates, beginning 90 days after the date of this Prospectus, subject to all provisions of Rule 144 except its two-year minimum holding period.
LOCK-UP AGREEMENTS
All holders of options to purchase shares of Common Stock have agreed with the Underwriters that they will not, without the prior written consent of CS First Boston, offer, sell, contract to sell or otherwise dispose of any shares of Common Stock beneficially owned by them or any shares issuable upon exercise of stock options for a period of 180 days from the date of this Prospectus. See "Underwriting."
CERTAIN UNITED STATES FEDERAL TAX CONSEQUENCES
TO NON-U.S. HOLDERS
The following is a general discussion of certain United States federal income and estate tax consequences of an investment in Common Stock by a holder that, for United States federal income tax purposes, is not a "United States person" (a "Non-U.S. Holder"). For purposes of this discussion, a "United States person" means a citizen or resident (as defined for United States federal income and estate tax purposes, as the case may be) of the United States, a corporation or partnership created or organized in the United States or under the laws of the United States or of any State thereof or an estate or trust whose income is includible in gross income for United States federal income tax purposes regardless of its source. The discussion is based on the United States Internal Revenue Code of 1986, as amended (the "Code"). Treasury regulations promulgated thereunder, and judicial and administrative interpretations thereof, all as in effect on the date hereof and all of which are subject to change, possibly retroactively, and is for general information only. The discussion does not address aspects of United States federal taxation other than income and estate taxation and does not address all aspects of United States federal income and estate taxation. The discussion does not consider any specific facts or circumstances that may apply to a particular Non-U.S. Holder. PROSPECTIVE INVESTORS ARE URGED TO CONSULT THEIR TAX ADVISORS WITH RESPECT TO THE UNITED STATES FEDERAL, STATE, LOCAL AND NON-U.S. INCOME AND OTHER TAX CONSEQUENCES TO THEM OF AN INVESTMENT IN COMMON STOCK.
DIVIDENDS
Dividends paid to a Non-U.S. Holder will generally be subject to withholding of United States federal income tax at a rate equal to 30% of the gross amount of the distribution (or at a lower rate prescribed by an applicable tax treaty) unless the dividends are effectively connected with the conduct of a trade or business within the United States by the Non-U.S. Holder, in which case the dividends generally will not be subject to withholding (if the Non-U.S. Holder files certain forms with the payor of the dividend) and generally will be subject to the United States federal income tax on net income that applies to United States persons generally (and, in the case of corporate holders, effectively connected dividends may also, under certain circumstances, be subject to the branch profits tax at a 30% rate or such lower rate as may be specified by an applicable income tax treaty). An applicable income tax treaty may, however, change these rules. To determine the applicability of a tax treaty providing for a lower rate of withholding, dividends paid to an address in a foreign country are presumed under current interpretation of existing Treasury regulations to be paid to a resident of that country. Treasury regulations proposed to be effective for payments made after December 31, 1997, which have not been finally adopted, however, would require Non-U.S. Holders to file certain new forms to obtain the benefit of any applicable tax treaty providing for a lower rate of withholding tax on dividends. Such forms would contain the holder's name and address and certain other information.
The gross amount of a distribution with respect to Common stock will be treated as a dividend to the extent of the Company's current and accumulated earnings and profits as determined for U.S. federal income tax purposes. In the event that such a distribution exceeds the amount of the Company's earnings and profits, it will be treated first as a non-taxable return of capital to the extent of the Non-U.S. Holder's basis in Common Stock (but not below zero), and thereafter as capital gain. A Non-U.S. Holder will have to file a refund claim to obtain a refund of tax withheld on distributions in excess of the dividend portion of any distribution.
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GAIN ON DISPOSITION
A Non-U.S. Holder generally will not be subject to United States federal income tax on gain recognized upon a sale or other disposition of shares of Common Stock unless (i) the gain is effectively connected with the conduct of a trade or business within the United States by the Non-U.S. Holder, (ii) the Non-U.S. Holder is an individual who has a tax home (as specifically defined under the United States federal income tax laws) in the United States (or maintains an office or other fixed place of business in the United States to which the gain from the sale of the stock is attributable), holds the shares of Common Stock as a capital asset, and is present in the United States for 183 days or more in the taxable year of the disposition or (iii) except as discussed below, the Company is or has been a "United States real property holding corporation" ("USRPHC") within the meaning of section 897(c)(2) of the Code at any time within the shorter of the five year period preceding such disposition or such holder's holding period.
Gain that is (or is treated as being) effectively connected with the conduct of a trade or business within the United States by the Non-U.S. Holder will be subject to the United States federal income tax on net income that applies to United States persons generally (and, with respect to corporate holders and under certain circumstances, the branch profits tax) but will not be subject to withholding. If the Company is a USRPHC, a Non-U.S. Holder may be subject to taxation under certain provisions of the Codes enacted pursuant to the Foreign Investors Real Property Tax Act ("FIRPTA"). The determination of whether the Company is a USRPHC depends in part upon unresolved issues of what constitutes real property for purposes of the FIRPTA provisions and upon difficult and uncertain questions of valuation. If the Company were or were to become a USRPHC, gains realized upon a disposition of Common Stock by a Non-U.S. Holder that is not deemed to own more than 5% of the Common Stock would not be subject to tax under the FIRPTA provisions provided that the Common Stock is "regularly traded" on an established securities market. Since the Common Stock will trade on the New York Stock Exchange, the Company believes the Common Stock will be "regularly traded" on an established securities market.
Non-U.S. Holders should consult applicable treaties, which may provide for different rules (including possibly the exemption of certain capital gains from tax).
FEDERAL ESTATE TAXES
Common stock owned or treated as owned by an individual who is not a citizen or resident (as specially defined for United States federal estate tax purposes) of the United States at the time of death will be includible in the individual's gross estate for United States federal estate tax purposes, unless an applicable estate tax treaty provides otherwise. Such individual's estate may be subject to the United States federal estate tax on the property includible in the estate for United States federal estate tax purposes.
BACKUP WITHHOLDING AND INFORMATION REPORTING
The Company or its designated paying agent (the "payor") must report annually to the Internal Revenue Service (the "Service") and to each Non-U.S. Holder the amount of dividends paid to, and the tax, if any, withheld with respect to, such holder. That information may also be made available to the tax authorities of the country in which the Non-U.S. Holder resides.
United States federal backup withholding (imposed at a 31% rate on certain payments to nonexempt persons) and information reporting with respect to such withholding will generally not apply to dividends paid to a Non-U.S. Holder that are otherwise subject to withholding or taxed as effectively connected income as described above under "Dividends."
The backup withholding and information reporting requirements also apply to the payment of gross proceeds to a Non-U.S. Holder upon the disposition of Common Stock by or through a United States office of a United States or foreign broker, unless the holder certifies to the broker under penalties of perjury as to its name, address, and status as a Non-U.S. Holder or the holder otherwise establishes an exemption. Information reporting requirements (but not backup withholding if the payor does not have actual knowledge that the payee is a United States person) will apply to a payment of the proceeds of a disposition of Common
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Stock by or through a foreign office of (i) a United States broker, (ii) a foreign broker 50% or more of whose gross income for certain periods is effectively connected with the conduct of a trade or business in the United States or (iii) a foreign broker that is a "controlled foreign corporation" for United States federal income tax purposes, unless the broker has documentary evidence in its records that the holder is a Non-U.S. Holder and certain other conditions are met, or the holder otherwise establishes an exemption. Neither backup withholding nor information reporting will generally apply to a payment of the proceeds of a disposition of Common Stock by or through a foreign office of a foreign broker not subject to the preceding sentence.
Backup withholding is not an additional tax. Any amounts withheld under the backup withholding rules will be refunded (or credited against the Non-U.S. Holder's United States federal income tax liability, if any), provided that the required information is furnished to the Service.
These information reporting and backup withholding rules are under review by the United States Treasury and their application to the Common Stock could be changed by future regulations. The Service recently issued proposed Treasury regulations concerning the withholding of tax and reporting for certain amounts paid to non-resident individuals and foreign corporations. The proposed Treasury regulations, if adopted in their present form, would be effective for payments made after December 31, 1997. Prospective investors should consult their tax advisors concerning the potential adoption of such proposed Treasury regulations and the potential effect on their ownership of the Common Stock.
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UNDERWRITING
Under the terms and subject to the conditions contained in an Underwriting Agreement dated , 1996 (the "U.S. Underwriting Agreement"), the underwriters named below (the "U.S. Underwriters"), for whom CS First Boston Corporation, Morgan Stanley & Co. Incorporated, PaineWebber Incorporated and Salomon Brothers Inc are acting as representatives (the "Representatives"), have severally but not jointly agreed to purchase from Calpine and the Selling Stockholder the following respective number of U.S. Shares:

                                                                    NUMBER OF
                           UNDERWRITER                             U.S. SHARES
-----------------------------------------------------------------  -----------
CS First Boston Corporation......................................
Morgan Stanley & Co. Incorporated................................
PaineWebber Incorporated.........................................
Salomon Brothers Inc ............................................
                                                                   -----------
          Total..................................................   14,436,000
                                                                     =========	

The U.S. Underwriting Agreement provides that the obligations of the U.S. Underwriters are subject to certain conditions precedent and that the U.S. Underwriters will be obligated to purchase all of the U.S. Shares offered hereby
(other than those shares covered by the over-allotment option described below)
if any are purchased. The U.S. Underwriting Agreement provides that, in the event of a default by a U.S. Underwriter, in certain circumstances the purchase commitments of non-defaulting U.S. Underwriters may be increased or the U.S. Underwriting Agreement may be terminated.
Calpine has entered into a Subscription Agreement (the "Subscription Agreement") with the Managers of the International Offering (the "Managers" and, together with the U.S. Underwriters, the "Underwriters") providing for the concurrent offer and sale of the International Shares outside the United States and Canada. The closing of the U.S. Offering is a condition to the closing of the International Offering and vice versa.
Calpine has granted to the U.S. Underwriters and the Managers an option, exercisable by CS First Boston Corporation, expiring at the close of business on the 30th day after the date of this Prospectus, to purchase up to 2,706,750 additional shares at the initial public offering price, less the underwriting discounts and commissions, all as set forth on the cover page of this Prospectus. Such option may be exercised only to cover over-allotments in the sale of the shares of Common Stock offered hereby. To the extent that this option to purchase is exercised, each U.S. Underwriter and each Manager will become obligated, subject to certain conditions, to purchase approximately the same percentage of additional shares being sold to the U.S. Underwriters and the Managers as the number of U.S. Shares set forth next to such U.S. Underwriter's name in the preceding table and as the number set forth next to such Manager's name in the corresponding table in the Prospectus relating to the International Offering bears to the sum of the total number of shares of Common Stock in such tables.
Calpine has been advised by the Representatives that the U.S. Underwriters propose to offer the U.S. Shares in the United States and Canada to the public initially at the public offering price set forth on the cover page of this Prospectus and, through the Representatives, to certain dealers at such price less a concession of $ per share, and the U.S. Underwriters and such dealers may allow a discount of $ per share on sales to certain other dealers. After the initial public offering, the public offering price and concession and discount to dealers may be changed by the Representatives.
The public offering price, the aggregate underwriting discounts and commissions per share and per share concession and discount to dealers for the U.S. Offering and the concurrent International Offering will be identical. Pursuant to an Agreement between the U.S. Underwriters and Managers (the "Intersyndicate Agreement") relating to the Common Stock Offering, changes in the public offering price, concession and discount to dealers will be made only upon the mutual agreement of CS First Boston Corporation, as
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representative of the U.S. Underwriters, and CS First Boston Limited ("CSFBL"), on behalf of the Managers.
Pursuant to the Intersyndicate Agreement, each of the U.S. Underwriters has agreed that, as part of the distribution of the U.S. Shares and subject to certain exceptions, it has not offered or sold, and will not offer or sell, directly or indirectly, any shares of Common Stock or distribute any prospectus relating to the Common Stock to any person outside the United States or Canada or to any other dealer who does not so agree. Each of the Managers has agreed or will agree that, as part of the distribution of the International Shares and subject to certain exceptions, it has not offered or sold, and will not offer or sell, directly or indirectly, any shares of Common Stock or distribute any prospectus relating to the Common Stock in the United States or Canada or to any other dealer who does not so agree. The foregoing limitations do not apply to stabilization transactions or to transactions between the U.S. Underwriters and the Managers pursuant to the Intersyndicate Agreement. As used herein, "United States" means the United States of America (including the States and District of Columbia), its territories, possessions and other areas subject to its jurisdiction, "Canada" means Canada, its provinces, territories, possessions and other areas subject to its jurisdiction, and an offer or sale shall be in the United States or Canada if it is made to (i) any individual resident in the United States or Canada or (ii) any corporation, partnership, pension, profit-sharing or other trust or other entity (including any such entity acting as an investment adviser with discretionary authority) whose office most directly involved with the purchase is located in the United States or Canada.
Pursuant to the Intersyndicate Agreement, sales may be made between the U.S. Underwriters and the Managers of such number of shares of Common Stock as may be mutually agreed upon. The price of any shares so sold will be the public offering price, less such amount as may be mutually agreed upon by CS First Boston Corporation, as representative of the U.S. Underwriters, and CSFBL, on behalf of the Managers, but not exceeding the selling concession applicable to such shares. To the extent there are sales between the U.S. Underwriters and the Managers pursuant to the Intersyndicate Agreement, the number of shares of Common Stock initially available for sale by the U.S. Underwriters or by the Managers may be more or less than the amount appearing on the cover page of the Prospectus. Neither the U.S. Underwriters nor the Managers are obligated to purchase from the other any unsold shares of Common Stock.
Calpine has agreed that it will not offer, sell, contract to sell, announce its intention to sell, pledge or otherwise dispose of, directly or indirectly, or file with the Securities and Exchange Commission a registration statement under the Securities Act (other than a registration statement on Form S-8) relating to, any additional shares of its Common Stock or securities convertible into or exchangeable or exercisable for any shares of its Common Stock without the prior written consent of CS First Boston Corporation for a period of 180 days after the date of this Prospectus, except issuances pursuant to the exercise of employee stock options outstanding on the date hereof. In addition, all holders of options to purchase shares of Common Stock have agreed that they will not, without the prior written consent of CS First Boston Corporation, offer, sell, contract to sell or otherwise dispose of any shares of Common Stock beneficially owned by them or any shares issuable upon exercise of stock options for a period of 180 days after the date of this Prospectus.
Calpine has agreed to indemnify the U.S. Underwriters and the Managers against certain liabilities, including civil liabilities under the Securities Act, or to contribute to payments that the U.S. Underwriters and the Managers may be required to make in respect thereof.
CS First Boston Corporation, one of the Underwriters, is an affiliate of the Company. The Common Stock Offering therefore is being conducted in accordance with the applicable provisions of Rule 2720 to the Conduct Rules of the National Association of Securities Dealers, Inc. Rule 2720 requires that the initial public offering price of the Common Stock not be higher than that recommended by a "qualified independent underwriter" meeting certain standards. Accordingly, PaineWebber Incorporated is assuming the responsibilities of acting as the qualified independent underwriter in pricing the Common Stock Offering and conducting due diligence. The initial public offering price of the Common Stock set forth on the cover page of this Prospectus is no higher than the price recommended by PaineWebber Incorporated.
In connection with the Common Stock Offering, PaineWebber Incorporated in its role as qualified independent underwriter has performed due diligence investigations and reviewed and participated in the
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preparation of this Prospectus and the Registration Statement of which this Prospectus forms a part. In addition, the Underwriters may not confirm sales to any discretionary account without the prior specific written approval of the customer.
The decision made by CS First Boston Corporation and CSFBL to underwrite the Common Stock Offering was made independently of the Company, CS Holding and Electrowatt. The net proceeds from the Common Stock Offering will not be applied for the benefit of CS First Boston Corporation or CSFBL. CS First Boston Corporation and CSFBL will not receive any benefit from the Common Stock Offering other than their respective portion of the underwriting discounts and commissions.
The Common Stock has been approved for listing on the New York Stock Exchange, subject to notice of issuance, under the symbol "CPN." In connection with the listing of the Common Stock on the New York Stock Exchange, the Underwriters have undertaken to sell round lots of 100 shares or more to a minimum of 2,000 beneficial holders.
Prior to the Common Stock Offering, there has been no public market for the shares of Common Stock offered hereby. The initial public offering price for the shares was determined by negotiations among the Company, the Selling Stockholder and CS First Boston Corporation, as one of the Representatives of the U.S. Underwriters, and by CSFBL, on behalf of the Managers, and does not necessarily reflect the secondary market prices for the Common Stock following the initial offering hereby. Among the principal factors considered in determining the initial public offering price were prevailing economic prospects, the sales, earnings and financial and operating performance of the Company in recent periods, the future prospects of the Company, market valuations of companies in related businesses and the history and prospects for the industries in which the Company competes. Additionally, consideration has been given to the general condition of the securities markets, the market for new issues of securities and the demand for securities of comparable companies.
In the ordinary course of their business, CS First Boston Corporation and certain of the other Underwriters and their affiliates have engaged and may in the future engage in investment banking transactions with Calpine, including the provision of certain advisory services to Calpine. CS Holding, a Swiss corporation, holds approximately 44.9% of the outstanding shares of Electrowatt, which indirectly holds all of the outstanding capital stock of the Company. CS Holding also holds (i) approximately 100% of the outstanding shares of Credit Suisse and (ii) approximately 69.3% of the outstanding common stock of CS First Boston, Inc., which holds all of the outstanding common stock of CS First Boston Corporation and of CSFBL. CS First Boston Corporation was one of the Underwriters in connection with the public offering of the Company's 9 1/4% Senior Notes in February 1994, one of the placement agents in connection with the sale of the 10 1/2% Senior Notes in May 1996 and is one of the Representatives of the U.S. Underwriters in the U.S. Offering, and CSFBL is one of the Managers in the International Offering. See "Certain Transactions."
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NOTICE TO CANADIAN RESIDENTS
RESALE RESTRICTIONS
The distribution of the Common Stock in Canada is being made only on a private placement basis exempt from the requirement that the Company prepare and file a prospectus with the securities regulatory authorities in each province where trades of Common Stock are effected. Accordingly, any resale of the Common Stock in Canada must be made in accordance with applicable securities laws which will vary depending on the relevant jurisdiction, and which may require resales to be made in accordance with available statutory exemptions or pursuant to a discretionary exemption granted by the applicable Canadian securities regulatory authority. Purchasers are advised to seek legal advice prior to any resale of the Common Stock.
REPRESENTATIONS OF PURCHASERS
Each purchaser of Common Stock in Canada who receives a purchase confirmation will be deemed to represent to the Company and the dealer from whom such purchase confirmation is received that (i) such purchaser is entitled under applicable provincial securities laws to purchase such Common Stock without the benefit of a prospectus qualified under such securities laws, (ii) where required by law, that such purchaser is purchasing as principal and not as agent, and (iii) such purchaser has reviewed the text above under "Resale Restrictions."
RIGHTS OF ACTION AND ENFORCEMENT
The securities being offered are those of a foreign issuer and Ontario purchasers will not receive the contractual right of action prescribed by section 32 of the Regulation under the Securities Act (Ontario). As a result, Ontario purchasers must rely on other remedies that may be available, including common law rights of action for damages or rescission or rights of action under the civil liability provisions of the U.S. federal securities laws.
All of the issuer's directors and officers as well as the experts named herein may be located outside of Canada and, as a result, it may not be possible for Ontario purchasers to effect service of process within Canada upon the issuer or such persons. All or a substantial portion of the assets of the issuer and such persons may be located outside of Canada and, as a result, it may not be possible to satisfy a judgment against the issuer or such persons in Canada or to enforce a judgment obtained in Canadian courts against such issuer or persons outside of Canada.
NOTICE TO BRITISH COLUMBIA RESIDENTS
A purchaser of Common Stock to whom the Securities Act (British Columbia) applies is advised that such purchaser is required to file with the British Columbia Securities Commission a report within ten days of the sale of any Common Stock acquired by such purchaser pursuant to this offering. Such report must be in the form attached to British Columbia Securities Commission Blanket Order BOR #95/17, a copy of which may be obtained from the Company. Only one such report must be filed in respect of Common Stock acquired on the same date and under the same prospectus exemption.
LEGAL MATTERS
The validity of the Common Stock will be passed upon for the Company by Brobeck, Phleger & Harrison LLP, San Francisco, California and for the Underwriters by Skadden, Arps, Slate, Meagher & Flom, New York, New York.
92

EXPERTS
The consolidated financial statements and schedules of the Company as of December 31, 1995 and 1994 and for the three years ended December 31, 1995, 1994 and 1993, the financial statements of Calpine Geysers Company, L.P. for the period ended April 18, 1993 and the financial statements of BAF Energy, A California Limited Partnership as of October 31, 1995 and 1994 and for the three years ended October 31, 1995, 1994 and 1993 included in this Prospectus and elsewhere in the Registration Statement have been audited by Arthur Andersen LLP, independent public accountants, as indicated in their reports with respect thereto, and are included herein in reliance upon authority of said firm as experts in giving said reports. In the reports for the Company, that firm states that with respect to Sumas Cogeneration Company, L.P., its opinion is based on the reports of other independent public accountants, namely Moss Adams LLP.
The consolidated financial statements of Sumas Cogeneration Company, L.P. and Subsidiary as of December 31, 1995 and 1994 and for the three years ended December 31, 1995, 1994 and 1993 appearing in this Prospectus have been audited by Moss Adams LLP, independent public accountants, as indicated in their reports with respect thereto, and are included herein in reliance upon authority of said firm as experts in giving said reports.
The combined financial statements of LFC No. 38 Corp. and Portsmouth Leasing Corporation and Subsidiaries and the consolidated financial statements of LFC No. 60 Corp. and Subsidiary as of December 31, 1994 and 1993 and for the years then ended appearing in this Prospectus have been audited by Coopers & Lybrand L.L.P., independent accountants, as indicated in their reports with respect thereto, and are included herein in reliance upon authority of said firm as experts in giving said reports.
The financial statements of Gilroy Energy Company, a wholly owned subsidiary of Gilroy Foods, Inc. which in turn is a wholly owned subsidiary of McCormick & Company, Inc., at November 30, 1995 and 1994, and for each of the two years in the period ended November 30, 1995, appearing in this Prospectus and Registration Statement have been audited by Ernst & Young LLP, independent auditors, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given upon the authority of such firm as experts in accounting and auditing.
AVAILABLE INFORMATION
The Company has filed with the Commission a Registration Statement on Form S-1 under the Securities Act with respect to the Common Stock offered hereby. As permitted by the rules and regulations of the Commission, this Prospectus omits certain information, exhibits and undertakings contained in the Registration Statement. The Company is subject to the informational requirements of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), and, in accordance therewith, files periodic reports and other information with the Commission. For further information with respect to the Company and the Common Stock offered hereby, reference is made to the Registration Statement, including the exhibits thereto and the financial statements, notes and schedules filed as a part thereof, as well as the periodic reports and other information filed by the Company with the Commission, which may be inspected and copied at the Public Reference Section of the Commission at Room 1024, Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C. 20549 and at the regional offices of the Commission located at 7 World Trade Center, 13th Floor, New York, New York 10048 and Suite 1400, Northwestern Atrium Center, 500 West Madison Street, Chicago, Illinois 60661-2511. Copies of such materials may be obtained from the Public Reference Section of the Commission, Room 1024, Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C. 20549, and its public reference facilities in New York, New York and Chicago, Illinois, at the prescribed rates. The Commission maintains a Web site that contains reports, proxy and information statements and other information regarding registrants, such as the Company, that file electronically with the Commission and the address of such site is http://www.sec.gov. Statements contained in this Prospectus as to the contents of any contract or other document are not necessarily complete, and in each instance reference is made to the copy of such contract or document filed as an exhibit to the Registration Statement, each such statement being qualified in all respects by such reference.
93

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

                                                                                        PAGE
                                                                                        ----
CALPINE CORPORATION
Report of Independent Public Accountants..............................................   F-3
Consolidated Balance Sheets, December 31, 1995 and 1994...............................   F-4
Consolidated Statements of Operations for the Years Ended December 31, 1995, 1994 and
  1993................................................................................   F-5
Consolidated Statements of Stockholder's Equity for the Years Ended December 31, 1995,
  1994 and 1993.......................................................................   F-6
Consolidated Statements of Cash Flows for the Years Ended December 31, 1995, 1994 and
  1993................................................................................   F-7
Notes to Consolidated Financial Statements for the Years Ended December 31, 1995, 1994
  and 1993............................................................................   F-8
Condensed Consolidated Balance Sheets, June 30, 1996 (unaudited) and December 31,
  1995................................................................................  F-30
Condensed Consolidated Statements of Operations for the Six Months Ended June 30, 1996
  and 1995 (unaudited)................................................................  F-31
Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 1996
  and 1995 (unaudited)................................................................  F-32
Notes to Condensed Consolidated Financial Statements for the Six Months Ended June 30,
  1996 and 1995 (unaudited)...........................................................  F-33
SUMAS COGENERATION COMPANY, L.P. AND SUBSIDIARY
Report of Independent Public Accountants..............................................  F-38
Consolidated Balance Sheets, December 31, 1995 and 1994...............................  F-39
Consolidated Statement of Operations for the Years Ended December 31, 1995, 1994 and
  1993................................................................................  F-40
Consolidated Statement of Changes in Partners' Deficit for the Years Ended December
  31, 1995, 1994 and 1993.............................................................  F-41
Consolidated Statement of Cash Flows for the Years Ended December 31, 1995, 1994 and
  1993................................................................................  F-42
Notes to Consolidated Financial Statements for the Years Ended December 31, 1995, 1994
  and 1993............................................................................  F-43
CALPINE GEYSERS COMPANY, L.P.
Report of Independent Public Accountants..............................................  F-52
Statement of Operations for the Period from January 1, 1993 to April 18, 1993.........  F-53	

Statement of Cash Flows for the Period from January 1, 1993 to April 18, 1993.........  F-54
Notes to Financial Statements for the Period from January 1, 1993 to April 18, 1993...  F-55
LFC NO. 38 CORP. AND PORTSMOUTH LEASING CORPORATION AND SUBSIDIARIES
Report of Independent Accountants.....................................................  F-60
Combined Balance Sheets, December 31, 1994 and 1993...................................  F-61
Combined Statement of Operations for the Years Ended December 31, 1994 and 1993.......  F-62
Combined Statements of Changes in Shareholder's Deficiency for the Years Ended
  December 31, 1994 and 1993..........................................................  F-63
Combined Statements of Cash Flows for the Years Ended December 31, 1994 and 1993......  F-64
Notes to Combined Financial Statements for the Years Ended December 31, 1994 and
  1993................................................................................  F-65
LFC NO. 60 CORP. AND SUBSIDIARY
Report of Independent Accountants.....................................................  F-69
Consolidated Balance Sheets, December 31, 1994 and 1993...............................  F-70
Consolidated Statements of Operations for the Years Ended December 31, 1994 and
  1993................................................................................  F-71
Consolidated Statements of Changes in Shareholder's Deficiency for the Years Ended
  December 31, 1994 and 1993..........................................................  F-72
Consolidated Statements of Cash Flows for the Years Ended December 31, 1994 and
  1993................................................................................  F-73
Notes to Consolidated Financial Statements for the Years Ended December 31, 1994 and
  1993................................................................................  F-74	

F-1

                                                                                        PAGE
                                                                                        ----
BAF ENERGY, A CALIFORNIA LIMITED PARTNERSHIP
Report of Independent Public Accountants..............................................  F-77
Balance Sheets, October 31, 1995 and 1994.............................................  F-78
Statements of Income for the Years Ended October 31, 1995, 1994 and 1993..............  F-79
Statements of Partners' Equity for the Years Ended October 31, 1995, 1994 and 1993....  F-80
Statements of Cash Flows for the Years Ended October 31, 1995, 1994 and 1993..........  F-81
Notes to Financial Statements for the Years Ended October 31, 1995, 1994 and 1993.....  F-82
Condensed Balance Sheets as of January 31, 1996 (unaudited) and October 31, 1995......  F-86
Condensed Statements of Income for the Three Months Ended January 31, 1996 and 1995
  (unaudited).........................................................................  F-87
Condensed Statements of Cash Flows for the Three Months Ended January 31, 1996 and
  1995 (unaudited)....................................................................  F-88
Notes to Condensed Financial Statements as of January 31, 1996........................  F-89
GILROY ENERGY COMPANY
Report of Independent Auditors........................................................  F-91
Balance Sheets, November 30, 1995 and 1994 and May 31, 1996 (unaudited)...............  F-92
Statements of Income for the Years Ended November 30, 1995 and 1994 and for the Six
  Months Ended May 31, 1996 and 1995 (unaudited)......................................  F-93
Statement of Shareholder's Equity for the Years Ended November 30, 1995 and 1994 and
  for the Six Months Ended May 31, 1996 (unaudited)...................................  F-94
Statements of Cash Flows for the Years Ended November 30, 1995 and 1994 and for the
  Six Months Ended May 31, 1996 and 1995 (unaudited)..................................  F-95
Notes to Financial Statements for the Years Ended November 30, 1995 and 1994 and for
  the Six Months Ended May 31, 1996 and 1995 (unaudited)..............................  F-96	

F-2

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To The Board of Directors
of Calpine Corporation:
We have audited the accompanying consolidated balance sheets of Calpine Corporation (a Delaware corporation) and subsidiaries as of December 31, 1995 and 1994, and the related consolidated statements of operations, stockholder's equity and cash flows for each of the three years in the period ended December 31, 1995. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We did not audit the financial statements of Sumas Cogeneration Company, L.P. (Sumas), the investment in which is reflected in the accompanying financial statements using the equity method of accounting. The investment in Sumas represents approximately 1% and 2% of the Company's total assets at December 31, 1995 and 1994, respectively. The Company has recorded a loss of $3.0 million, $2.9 million and $1.9 million representing its share of the net loss of Sumas for the years ended December 31, 1995, 1994 and 1993, respectively. The financial statements of Sumas were audited by other auditors whose report has been furnished to us and our opinion, insofar as it relates to the amounts included for Sumas, is based solely on the report of other auditors.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and the report of other auditors, the financial statements referred to above present fairly, in all material respects, the financial position of Calpine Corporation and subsidiaries as of December 31, 1995 and 1994, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1995 in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
San Jose, California
March 15, 1996 (except with respect to
the matter discussed in Note 26, as to
which the date is September 13, 1996)
F-3

CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 1995 AND 1994
 (IN THOUSANDS)

                                                                                    1995         1994
                                                                                  --------     --------
                                                ASSETS
Current assets
  Cash and cash equivalents.....................................................  $ 21,810     $ 22,527
  Accounts receivable
     from related parties.......................................................     2,177        1,864
     from others................................................................    17,947       12,723
  Acquisition project receivables...............................................     8,805           --
  Prepaid expenses and other current assets.....................................     5,491        4,256
                                                                                  --------     --------
          Total current assets..................................................    56,230       41,370
Property, plant and equipment, net..............................................   447,751      335,453
Investments in power projects...................................................     8,218       11,114
Capitalized project costs.......................................................     1,123          645
Notes receivable from related parties...........................................    19,391       16,882
Notes receivable from Coperlasa.................................................     6,394           --
Restricted cash.................................................................     9,627       10,813
Deferred charges and other assets...............................................     5,797        5,095
                                                                                  --------     --------
          Total assets..........................................................  $554,531     $421,372
                                                                                  ========     ========
                                 LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities
  Current non-recourse project financing........................................  $ 84,708     $ 22,800
  Notes payable to bank and short-term borrowings...............................     1,177        4,500
  Accounts payable..............................................................     6,876        1,869
  Accrued payroll and related expenses..........................................     2,789        2,624
  Accrued interest payable......................................................     7,050        5,622
  Other accrued expenses........................................................     2,657        2,517
                                                                                  --------     --------
          Total current liabilities.............................................   105,257       39,932
Long-term line of credit........................................................    19,851           --
Non-recourse long-term project financing, less current portion..................   190,642      196,806
Notes payable...................................................................     6,348        5,296
Senior Notes Due 2004...........................................................   105,000      105,000
Deferred income taxes, net......................................................    97,621       50,928
Deferred revenue................................................................     4,585        4,761
                                                                                  --------     --------
          Total liabilities.....................................................   529,304      402,723
                                                                                  --------     --------
Commitments and contingencies (Note 25)
Stockholder's equity
  Common stock, authorized 33,760 shares, issued and
     outstanding -- 10,388 shares in 1995 and 1994..............................        10           10
  Additional paid-in capital....................................................     6,214        6,214
  Retained earnings.............................................................    19,034       12,456
  Cumulative translation adjustment.............................................       (31)         (31)
                                                                                  --------     --------
          Total stockholder's equity............................................    25,227       18,649
                                                                                  --------     --------
          Total liabilities and stockholder's equity............................  $554,531     $421,372
                                                                                  ========     ========	

The accompanying notes are an integral part of these consolidated financial statements.
F-4

CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
 (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

                                                               1995         1994         1993
                                                             --------     --------     --------
Revenue
  Electricity and steam sales..............................  $127,799     $ 90,295     $ 53,000
  Service contract revenue from related parties............     7,153        7,221       16,896
  Income (loss) from unconsolidated investments in power
     projects..............................................    (2,854)      (2,754)          19
                                                             --------      -------      -------
          Total revenue....................................   132,098       94,762       69,915
                                                             --------      -------      -------
Cost of revenue
  Plant operating expenses.................................    33,162       14,944        9,078
  Depreciation.............................................    26,264       21,202       12,272
  Production royalties.....................................    10,574       11,153        6,814
  Operating lease expense..................................     1,542           --           --
  Service contract expenses................................     5,846        5,546       14,337
                                                             --------      -------      -------
          Total cost of revenue............................    77,388       52,845       42,501
                                                             --------      -------      -------
Gross profit...............................................    54,710       41,917       27,414
  Project development expenses.............................     3,087        1,784        1,280
  General and administrative expenses......................     8,937        7,323        5,080
  Provision for write-off of project development costs.....        --        1,038           --
                                                             --------      -------      -------
          Income from operations...........................    42,686       31,772       21,054
Other (income) expense
  Interest expense
     Related party.........................................     1,663          375        2,613
     Other.................................................    30,491       23,511       11,212
  Other income, net........................................    (1,895)      (1,988)      (1,133)
                                                             --------      -------      -------
     Income before provision for income taxes and
       cumulative effect of change in accounting
       principle...........................................    12,427        9,874        8,362
  Provision for income taxes...............................     5,049        3,853        4,195
                                                             --------      -------      -------
     Income before cumulative effect of change in
       accounting principle................................     7,378        6,021        4,167
  Cumulative effect of adoption of SFAS No. 109............        --           --         (413)
                                                             --------      -------      -------
          Net income.......................................  $  7,378     $  6,021     $  3,754
                                                             ========      =======      =======
As adjusted earnings per share assuming conversion of
  preferred stock:
                                                               14,187
  As adjusted weighted average shares outstanding..........  ========
                                                             $   0.52
  Net income per share.....................................  ========	

The accompanying notes are an integral part of these consolidated financial statements.
F-5

CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
 (IN THOUSANDS)

                                                    COMMON STOCK     ADDITIONAL              CUMULATIVE
                                                   ---------------    PAID-IN     RETAINED   TRANSLATION
                                                   SHARES   AMOUNT    CAPITAL     EARNINGS   ADJUSTMENT    TOTAL
                                                   ------   ------   ----------   --------   ----------   -------
Balance, December 31, 1992.......................  10,388    $ 10      $6,214     $ 4,281       $ --      $10,505
  Dividend ($0.08 per share).....................      --      --          --        (800 )       --         (800)
  Net income.....................................      --      --          --       3,754         --        3,754
  Cumulative translation adjustment..............      --      --          --          --        (31)         (31)
                                                    -----     ---     -------        ----    -------
Balance, December 31, 1993.......................  10,388      10       6,214       7,235        (31)      13,428
  Dividend ($0.08 per share).....................      --      --          --        (800 )       --         (800)
  Net income.....................................      --      --          --       6,021         --        6,021
                                                    -----     ---     -------        ----    -------
Balance, December 31, 1994.......................  10,388      10       6,214      12,456        (31)      18,649
  Dividend ($0.08 per share).....................      --      --          --        (800 )       --         (800)
  Net income.....................................      --      --          --       7,378         --        7,378
                                                    -----     ---     -------        ----    -------
Balance, December 31, 1995.......................  10,388    $ 10      $6,214     $19,034       $(31)     $25,227
                                                    =====     ===     =======        ====    =======	

The accompanying notes are an integral part of these consolidated financial statements.
F-6

CALPLNE CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
 (IN THOUSANDS)

                                                                 1995        1994        1993
                                                               --------     -------     -------
Cash flows from operating activities
  Net income.................................................  $  7,378     $ 6,021     $ 3,754
  Adjustments to reconcile net income to net cash provided by
     operating activities:
     Depreciation and amortization, net......................    25,931      20,342      11,318
     Deferred income taxes, net..............................    (1,027)      3,180       4,619
     (Income) loss from unconsolidated investments in power
       projects..............................................     2,854       2,754         (19)
     Distributions from investments in power projects........        --          --       7,352
     Provision for write-off of project development costs....        --       1,038          --
       Change in operating assets and liabilities:
       Accounts receivable...................................    (3,354)     (2,578)       (615)
       Acquisition project receivables.......................    (8,805)         --          --
       Other current assets..................................      (737)         79        (956)
       Accounts payable and accrued expenses.................     6,847       6,218      (3,040)
       Deferred revenue......................................    (2,434)     (2,858)      1,897
                                                               --------     --------    --------
          Net cash provided by operating activities..........    26,653      34,196      24,310
                                                               --------     --------    --------
Cash flows from investing activities
  Acquisition of property, plant and equipment...............   (17,434)     (7,023)     (8,445)
  Acquisition of Greenleaf, net of cash on hand..............   (14,830)         --          --
  Investment in Watsonville, net of cash on hand.............       494          --          --
  Acquisition of TPC, net of cash on hand....................        --     (62,770)         --
  Acquisition of CGC, net of CGC cash on hand................        --          --     (20,296)
  Increase in notes receivable...............................    (6,348)    (13,556)         --
  Investments in power projects..............................        --        (118)       (627)
  Capitalized project costs..................................    (1,258)       (175)       (952)
  Decrease (increase) in restricted cash.....................     1,186        (900)      2,968
  Other, net.................................................      (307)         98         270
                                                               --------     --------    --------
          Net cash used in investing activities..............   (38,497)    (84,444)    (27,082)
                                                               --------     --------    --------
Cash flows from financing activities
  Payment of dividends.......................................      (800)       (800)       (800)
  Borrowings from line of credit.............................    34,851          --      23,000
  Repayments of line of credit...............................   (15,000)    (52,595)     (5,873)
  Borrowings from non-recourse project financing.............    76,026      60,000          --
  Repayments of non-recourse project financing...............   (79,388)    (12,735)     (8,800)
  Short-term borrowings......................................     2,683       4,500          --
  Repayments of short-term borrowings........................    (6,006)         --          --
  Senior Notes Due 2004......................................        --     105,000          --
  Financing costs............................................    (1,239)     (3,921)       (749)
  Repayment of note payable to shareholder...................        --      (1,200)         --
  Proceeds from note payable.................................        --       5,167          --
  Repayment of notes payable -- FMRP.........................        --     (36,807)         --
                                                               --------     --------    --------
          Net cash provided by financing activities..........    11,127      66,609       6,778
                                                               --------     --------    --------
Net increase (decrease) in cash and cash equivalents.........      (717)     16,361       4,006
Cash and cash equivalents, beginning of period...............    22,527       6,166       2,160
                                                               --------     --------    --------
Cash and cash equivalents, end of period.....................  $ 21,810     $22,527     $ 6,166
                                                               ========     ========    ========
Supplementary information -- cash paid during the year for:
  Interest...................................................  $ 32,162     $19,890     $15,084
  Income taxes...............................................     4,294         683          13	

The accompanying notes are an integral part of these consolidated financial statements.
F-7

CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
1. ORGANIZATION AND OPERATIONS OF THE COMPANY
Calpine Corporation (Calpine) and subsidiaries (collectively, the Company) are engaged in the development, acquisition, ownership and operation of power generation facilities in the United States. The Company has ownership interests in and operates geothermal steam fields, geothermal power generation facilities, and natural gas-fired cogeneration facilities in Northern California and Washington. Each of the generation facilities produces electricity for sale to utilities. Thermal energy produced by the gas-fired cogeneration facilities is sold to governmental and industrial users, and steam produced by the geothermal steam fields is sold to utility-owned power plants. For the year ended December 31, 1995, primarily all electricity and steam sales revenue from consolidated subsidiaries was derived from sales to two customers in Northern California (see Note 24), of which 73% related to geothermal activities.
Founded in 1984, the Company is wholly owned by Electrowatt Services, Inc., which is wholly owned by Electrowatt Ltd. (Electrowatt), a Swiss company. The Company has expertise in the areas of engineering, finance, construction and plant operations and maintenance.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation -- The consolidated financial statements include the accounts of Calpine Corporation and its wholly owned and majority owned subsidiaries. All significant intercompany accounts and transactions are eliminated in consolidation. During 1993, the Company acquired the remaining interests in Calpine Geysers Company, L.P. (CGC) (see Note 3). Prior to the acquisition, the Company recognized its share of the net income of CGC under the equity method of accounting. During 1994, the Company formed Calpine Thermal Power, Inc. (Calpine Thermal) and Calpine Siskiyou Geothermal Partners, L.P. (see Notes 4 and 7, respectively). Calpine Thermal acquired Thermal Power Company (TPC) during 1994. During 1995, the Company formed Calpine Greenleaf Corporation (Calpine Greenleaf), Calpine Monterey Cogeneration, Inc. (CMCI) and Calpine Vapor, Inc. (Calpine Vapor). Calpine Greenleaf indirectly acquired two operating gas-fired cogeneration plants (see Note 5) and CMCI acquired an operating lease for a gas-fired cogeneration facility (see Note 6). Calpine Vapor made loans to fund construction of new geothermal wells in Mexico (see Note 8).
Accounting for Jointly Owned Geothermal Properties -- The Company uses the proportionate consolidation method to account for TPC's 25% interest in jointly owned geothermal properties. TPC has a steam sales agreement with Pacific Gas and Electric Company (PG&E) pursuant to which the steam derived from its interest in the properties is sold. See Note 4 for further information regarding TPC.
Use of Estimates in Preparation of Financial Statements -- The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The most significant estimates with regard to these financial statements relate to future development costs and total productive resources of the geothermal facilities (see Property, Plant and Equipment and Note 4), the estimated "free steam" liability (see Revenue Recognition and Deferred Revenue), receivables which the Company believes to be collectible (see Note 10), and the realization of deferred income taxes (see Note 19).
Revenue Recognition and Deferred Revenue -- Revenue from electricity and steam sales is recognized upon transmission to the customer. Revenues from contracts entered into or acquired since May 21, 1992 are recognized at the lesser of amounts billable under the contract or amounts recognizable at an average rate over the term of the contract. The Company's power sales agreements related to CGC were entered into prior to
F-8

CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
May 1992. Had the Company applied this principle, the revenues of the Company recorded for the years ended December 31, 1995 and 1994, and for the period from April 19, 1993 to December 31, 1993, would have been approximately $12.6 million, $11.9 million and $6.5 million less, respectively.
CGC revenues from sales of steam were calculated considering a future period when steam would be delivered without receiving corresponding revenue. The estimated "free steam" obligation was recorded at an average rate over future steam production as deferred revenue in 1993. As of December 31, 1993, the Company had deferred revenue of $8.6 million. During 1994, based on estimates and analyses performed, the Company determined that these deliveries would no longer be required for a customer. In May 1994, the Company reversed approximately $5.9 million of its deferred revenue liability. This reversal was recorded as a $1.9 million purchase price reduction to property, plant and equipment, with the remaining $4.0 million as an increase in revenue. Concurrently, $800,000 of the revenue increase was reserved for future construction of gathering systems required for future production of the steam fields, with the offset recorded in property, plant and equipment.
In October 1994, PG&E agreed to the termination of the free steam provision for one of the geothermal steam fields. During 1995, CGC took additional measures regarding future capital commitments and other actions which will increase steam production and, based on additional analyses and estimates performed, the Company recognized the remaining $2.7 million of previously deferred revenue.
The Company performs operations and maintenance services for projects in which it has an interest. Revenue from investees is recognized on these contracts when the services are performed. Revenue from consolidated subsidiaries are eliminated in consolidation.
Cash and Cash Equivalents -- The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents. The carrying amount of these instruments approximates fair value because of their short maturity.
Restricted Cash -- The Company is required to maintain cash balances that are restricted by provisions of its debt agreements and by regulatory agencies. The Company's debt agreements specify restrictions based on debt service payments and drilling costs for the following year. Regulatory agencies require cash to be restricted to ensure that funds will be available to restore property to its original condition. Restricted cash is invested in accounts earning market rates; therefore, their carrying value approximates fair value. Such cash is excluded from cash and cash equivalents for the purposes of the statements of cash flows.
Concentration of Credit Risk -- Financial instruments which potentially subject the Company to concentrations of credit risk consist primarily of cash and accounts/notes receivable. The Company's cash accounts are held by five major financial institutions. The Company's accounts/notes receivable are concentrated within entities engaged in the energy industry, mainly within the United States, some of which are related parties. Certain of the Company's notes receivable are with a company in Mexico (see Note 8).
Property, Plant and Equipment -- Property, plant and equipment are stated at cost less accumulated depreciation and amortization.
The Company capitalizes costs incurred in connection with the development of geothermal properties, including costs of drilling wells and overhead directly related to development activities, together with the costs of production equipment, the related facilities and the operating power plants. Geothermal properties include the value attributable to the geothermal resources of CGC and all of the property, plant and equipment of Calpine Thermal. Proceeds from the sale of geothermal properties are applied against capitalized costs, with no gain or loss recognized.
Geothermal costs, including an estimate of future development costs to be incurred and the estimated costs to dismantle, are amortized by the units of production method based on the estimated total productive output over the estimated useful lives of the related steam fields. Depreciation of the buildings and roads is
F-9

CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
computed using the straight-line method over their estimated useful lives. It is reasonably possible that the estimate of useful lives, total units of production or total capital costs to be amortized using the units of production method could differ materially in the near term from the amounts assumed in arriving at current depreciation expense. These estimates are affected by such factors as the ability of the Company to continue selling steam and electricity to customers at estimated prices, changes in prices of alternative sources of energy such as hydro-generation and gas, and changes in the regulatory environment.
Gas-fired power production facilities include the cogeneration plants and related equipment and are stated at cost. Depreciation is recorded utilizing the straight-line method over the estimated original useful life of up to thirty years. Depreciation of office equipment is provided on the straight-line method over useful lives of three to five years. Amortization of leasehold improvements is provided based on the straight-line method over the lesser of the useful life of the asset or the life of the lease. When assets are disposed of, the cost and related accumulated depreciation are removed from the accounts, and the resulting gains or losses are included in the results of operations.
As of December 31, 1995 and 1994, the components of property, plant and equipment are (in thousands):

                                                                   1995         1994
                                                                 --------     --------
Geothermal properties..........................................  $216,042     $209,243
Buildings......................................................   147,532       29,149
Machinery and equipment........................................    50,826       47,125
Wells and well pads............................................    44,706       43,982
Steam gathering and control systems............................    28,363       28,296
Roads..........................................................     7,384        7,384
Miscellaneous assets...........................................     2,425        1,694
                                                                 --------     --------
                                                                  497,278      366,873
Less accumulated depreciation and amortization.................    60,511       34,020
                                                                 --------     --------
                                                                  436,767      332,853
Land...........................................................       754          413
Construction in progress.......................................    10,230        2,187
                                                                 --------     --------
  Property, plant and equipment, net...........................  $447,751     $335,453
                                                                 ========     ========	

Investments in Power Projects -- The Company accounts for its unconsolidated investments in power projects under the equity method. The Company's share of income from these investments is calculated according to the Company's equity ownership or in accordance with the terms of the appropriate partnership agreement (see Note 11).
Capitalized Project Costs -- The Company capitalizes project development costs upon the execution of a memorandum of understanding or a letter of intent for a power or steam sales agreement. These costs include professional services, salaries, permits and other costs directly related to the development of a new project. Outside services and other third-party costs are capitalized for acquisition projects. Upon the start-up of plant operations or the completion of an acquisition, these costs are generally transferred to property, plant and equipment and amortized over the estimated useful life of the project. Capitalized project costs are charged to expense when the Company determines that the project will not be consummated or is impaired.
As Adjusted Earnings Per Share -- Net income per share is computed using weighted average shares outstanding, which includes the net additional number of shares which would be issuable upon the exercise of outstanding stock options, assuming that the Company used the proceeds received to purchase additional shares at an assumed public offering price. Net income per share also gives effect, even if antidilutive, to common equivalent shares from preferred stock that will automatically convert upon the closing of the
F-10

CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Company's initial public offering (using the as-if-converted method). If the offering contemplated by the Company is consummated, all of the convertible preferred stock outstanding as of the closing date will automatically be converted into shares of common stock based on the shares of convertible preferred stock outstanding at June 30, 1996.
Reclassifications -- Prior years' amounts in the consolidated financial statements have been reclassified where necessary to conform to the 1995 presentation.
3. CALPINE GEYSERS COMPANY, L.P.
CGC, an indirect wholly owned subsidiary of the Company, is the owner of two operating geothermal power plants and their respective steam fields, Bear Canyon and West Ford Flat, and three geothermal steam fields, which provide steam to PG&E's Unit 13 and Unit 16 power plants and to Sacramento Municipal Utility District's (SMUD) geothermal power plant. The power plants and steam fields are located in The Geysers area of Northern California. Electricity from CGC's two operating geothermal power plants is sold to PG&E under 20-year agreements. Under the terms of the agreements which began in 1989, CGC is paid for energy delivered based upon a fixed price which escalates annually through December 1998, and upon PG&E's full short-run avoided operating costs for the subsequent ten years. CGC also receives capacity payments from PG&E. Under certain circumstances, if CGC is unable to deliver firm capacity, then CGC may owe PG&E certain minimum damages as specified in the agreements.
Under the steam sales agreements with PG&E and SMUD, the price paid for the steam is determined annually and semiannually, respectively, based on contract price formulas and steam delivery terms.
Under the PG&E Unit 16 and the SMUD agreements, if the quantity of steam delivered is less than 50% of the units' capacities, then neither PG&E nor SMUD is required to make payment for steam delivered during such month until the cost of the affected power plant has been completely amortized (see Note 2). Further, both PG&E and SMUD can terminate their agreements with written notice under conditions specified in the agreement if further operation of the plants becomes uneconomical. In the event that CGC terminates the agreements, PG&E or SMUD may require CGC to assign them all rights, title and interest to the wells, lands and related facilities. In consideration for such an assignment to SMUD, SMUD shall reimburse CGC for its original costs net of depreciation for any associated materials or facilities.
Prior to April 19, 1993 the Company owned a minority interest in CGC and recognized its share of CGC's net income under the equity method. On April 19, 1993, the Company acquired Freeport-McMoRan Resource Partners, L.P.'s (FMRP) interest in CGC for $23.0 million in cash and non-recourse notes payable to FMRP totaling $40.5 million. On February 17, 1994, the Company exercised its option to prepay the notes utilizing a discount rate of 10% by paying $36.9 million including interest in full satisfaction of its obligations under the FMRP notes. The difference between the original carrying amount of the notes and the prepayment was recorded as an adjustment to the purchase price.
4. CALPINE THERMAL POWER, INC.
On September 9, 1994, Calpine Thermal acquired the outstanding capital stock of TPC from Natomas Energy Company (Natomas), a wholly owned subsidiary of Maxus Energy Company, pursuant to a Stock Purchase Agreement dated June 27, 1994. Under the terms of the Stock Purchase Agreement, Calpine Thermal acquired the stock of TPC for a total purchase price of $66.5 million, consisting of a $60.0 million cash payment and the issuance by Calpine of a non-interest bearing promissory note to Natomas in the amount of $6.5 million (discounted to $5.2 million), which is due September 9, 1997. At or subsequent to the closing of the acquisition, Calpine received payments of $3.0 million from Natomas, which represented cash from TPC's operations for the period from July 1, 1994 to September 8, 1994. These payments were treated as purchase price adjustments. The Company funded the cash portion of the purchase price in the acquisition
F-11

CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
through a two-year non-recourse secured financing provided by The Bank of Nova Scotia pursuant to a Credit Agreement dated September 9, 1994 (see Note 16).
Calpine Thermal owns a 25% undivided interest in certain producing geothermal steam fields located at The Geysers area of Northern California. Union Oil Company of California, a wholly owned subsidiary of Unocal Corporation, owns the remaining 75% interest in the steam fields, which deliver geothermal steam to twelve operating plants owned by PG&E. The steam fields currently provide the twelve operating plants with sufficient steam to generate approximately 604 megawatts of electricity.
Steam from Calpine Thermal's steam field is sold to PG&E under a steam sales agreement. In addition, Calpine Thermal receives a monthly capacity maintenance fee, which provides for effluent disposal costs and facilities support costs, and a monthly fee for PG&E's right to curtail its power plants. The steam price, capacity maintenance and curtailment fees are adjusted annually. Calpine Thermal is required to compensate PG&E for the unused capacity of its geothermal power plants due to insufficient field capacities of its steam supply (offset payment).
In accordance with the steam sales agreement, PG&E may curtail the power plants which receive steam from the Union Oil/Calpine Thermal Steam Fields in order to produce energy from lower cost sources. However, PG&E is constrained by its contractual obligation to operate all the power plants at a minimum of 40% of the field capacity during any given year. During 1995, Calpine Thermal experienced extensive curtailments of steam production due to low gas prices and abundant hydro power.
In March 1995, PG&E notified Union Oil and TPC of its plan to accelerate the retirement of the geothermal power plants to which steam is supplied. Calpine Thermal had considered plant retirements in its analysis leading to the acquisition of TPC in September 1994. Calpine Thermal had no assurance that PG&E would follow the accelerated schedule which was not in accordance with the terms and conditions of the steam sales agreement, and, with Union Oil, entered into intensive discussions with PG&E regarding alternatives. As a result of those discussions, the March 1995 accelerated closure schedule has been reevaluated in accordance with expected steam supply projections, curtailment levels, and actual contract terms and conditions to result in estimates of future project output and revised closure schedules. Closure schedules will continue to be modified throughout the life of the power sales agreement to be consistent with actual production levels based on competitive energy prices and weather.
On August 9, 1995, the Company, Union Oil and PG&E executed a letter agreement on alternative steam pricing for the calendar year 1995. Under this agreement, all steam delivered up to 40% of field capacity remained at the original contract rate, and all other steam was sold at a 33% reduction to the contract rate, thus lowering the cost to PG&E and enhancing production and revenue from The Geysers to Union Oil and Calpine Thermal. On February 1, 1996, the Company and Union Oil entered into an alternative steam pricing agreement with PG&E for the month of February 1996, which was subsequently extended through at least March 15, 1996. The parties to this agreement are currently in the process of negotiating a longer term alternative pricing agreement. The Company is unable to predict the sales and prices that may result from such an alternative pricing program.
The steam sales agreement between Calpine Thermal and PG&E terminates two years after the closing of the last PG&E operating unit. PG&E may terminate the agreement upon a one-year written notice to Calpine Thermal. In the event the agreement is terminated by PG&E, Calpine Thermal has the right to purchase PG&E's facilities at PG&E's unamortized cost. Calpine Thermal will provide capacity maintenance services for five years after termination by PG&E or closure of the last PG&E operating unit. Alternatively, Calpine Thermal may terminate the agreement upon two years written notice to PG&E. PG&E has the right to take assignment of Calpine Thermal's facilities on the date of termination. In such a case, Calpine Thermal would generally continue to pay offset payments for 36 months following the date of termination.
F-12

CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
5. CALPINE GREENLEAF CORPORATION
On April 21, 1995, Calpine Greenleaf acquired the outstanding capital stock of Portsmouth Leasing Corporation, LFC No. 38 Corp. and LFC No. 60 Corp.
(collectively, the Acquired Companies) from Radnor Power Corporation (Radnor)
for $80.5 million pursuant to a Share Purchase Agreement dated March 30, 1995.
The Acquired Companies own 100% of the assets of two 49.5 megawatt natural gas-fired cogeneration facilities (collectively, the Greenleaf facilities), Greenleaf Unit One and Greenleaf Unit Two, located in Yuba City in Northern California. The Greenleaf facilities burn natural gas in the cogeneration of electrical and thermal energy. The Greenleaf facilities produce electrical power for sale to PG&E pursuant to two long-term power sales agreements that provide for electricity payments over an original thirty-year period (expiring in 2019) at prices equal to PG&E's full short-run avoided operating costs, adjusted annually. In addition, the Company receives firm capacity payments through 2019 for up to 49.2 megawatts on each unit and as-delivered capacity on excess deliveries. PG&E, at its discretion, may curtail purchases of electricity from the Greenleaf facilities due to hydro-spill or uneconomic cost conditions. The thermal energy generated is used by thermal hosts adjacent to the Greenleaf facilities. The Greenleaf facilities are qualifying facilities, as defined by the Public Utility Regulatory Policies Act of 1978, as amended (PURPA).
Natural gas for the Greenleaf facilities is supplied by Montis Niger, Inc. (MNI) pursuant to a long-term gas purchase agreement, and by Chevron USA Production Company (Chevron). MNI is a wholly owned subsidiary of LFC Financial Corporation, the parent company of Radnor. See Note 25 for further information regarding these agreements.
The acquisition was accounted for as a purchase and the purchase price has been allocated to the acquired assets and liabilities based on the estimated fair values of the acquired assets and liabilities as shown below. The allocation may be adjusted as additional information becomes available (in thousands):

Current assets....................................................  $  6,572
Property, plant and equipment.....................................   120,752
                                                                    --------
  Total assets....................................................   127,324
                                                                    --------
Current liabilities...............................................      (944)
Deferred income taxes, net........................................   (45,844)
                                                                    --------
  Total liabilities...............................................   (46,788)
                                                                    --------
Net purchase price................................................  $ 80,536
                                                                    ========	

The purchase price included a cash payment of $20.3 million and the assumption of project debt totalling $60.2 million. The final purchase price, which is to be adjusted after the determination of the final net working capital amount, was determined upon an arms-length transaction between Calpine and Radnor. The parties are currently in dispute regarding certain provisions of the Share Purchase Agreement, and the outcome of the dispute may affect the purchase price.
The $20.3 million cash payment was funded by borrowings from the Credit Suisse lines of credit described in Note 13 below. The $60.2 million debt assumed by the Company in the acquisition of the Greenleaf facilities consisted of $57.6 million of non-recourse long-term project financing payable to Credit Suisse and $2.6 million of installment payments to individuals. On June 30, 1995, the Company refinanced the Greenleaf project by borrowing $76.0 million from banks (described in Note 16 below). Net proceeds of $74.9 million were used to repay $57.5 million of Credit Suisse debt including interest, and $2.9 million of installment and premium payments to individuals. The remaining $14.5 million of net proceeds and $500,000 of internal funds were used to repay the Credit Suisse line of credit borrowings related to the Greenleaf project.
F-13

CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Pro forma consolidated results for the Company as if the Greenleaf acquisition had been consummated on January 1, 1995 and as if the Greenleaf and TPC acquisitions had been consummated on January 1, 1994, respectively, are (in thousands, except per share amounts):

                                                                      YEAR ENDED
                                                             -----------------------------
                                                             DECEMBER 31,     DECEMBER 31,
                                                                 1995             1994
                                                             ------------     ------------
                                                                      (UNAUDITED)
Revenue....................................................    $137,412         $143,137
Net income.................................................    $  4,868         $ 11,708
Earnings per share (assuming stock split and conversion of
  preferred stock; see Note 2).............................    $   0.34	

The pro forma information does not purport to be indicative of results that actually would have occurred had the acquisition been made on the dates indicated or of results which may occur in the future.
Also in connection with the Greenleaf acquisition, the Company borrowed $1.9 million on April 21, 1995 against an uncommitted demand loan facility with The Bank of Nova Scotia to finance the prepayment for natural gas to be delivered to the Greenleaf facilities from MNI (see Note 13 for further information).
6. CALPINE MONTEREY COGENERATION, INC.
On June 29, 1995, CMCI acquired a 14.5 year operating lease (through December 2009) for a 28.5 megawatt natural gas-fired cogeneration power plant located in Watsonville in Northern California. The Company acquired the operating lease from Ford Motor Credit Company, acting through its agent, USL Capital Corporation, for $900,000. The Watsonville plant sells electricity to PG&E under the terms of a 20-year power sales agreement, generally at prices equal to PG&E's full short-run avoided operating costs. Basic and contingent lease rental payments are described in Note 25. As a cogenerator, the plant provides steam to two local food processing plants, and is a qualifying facility as defined by PURPA. The Company also provides project and fuels management services.
In connection with this acquisition, the Company obtained a $5.0 million uncommitted line of credit with The Bank of Nova Scotia for letters of credit. On December 31, 1995, the Company had $2.9 million of letters of credit outstanding (see Note 13 for further information).
7. CALPINE SISKIYOU GEOTHERMAL PARTNERS, L.P.
On August 24, 1994, the Company formed a partnership with Trans-Pacific Geothermal Glass Mountain, Ltd. (TGGM), an affiliate of Trans-Pacific Geothermal Corporation of Oakland, California, and is planning to build a geothermal power generation facility. The power generation facility will be located at Glass Mountain in Northern California near the Oregon border. The partnership is consolidated as the Company owns a controlling interest.
8. CALPINE VAPOR, INC.
In November 1995, Calpine Vapor entered into agreements with Constructora y Perforadora Latina, S.A. de C.V. (Coperlasa) and certain Mexican bank lenders to Coperlasa in connection with a geothermal steam production contract at the Cerro Prieto geothermal resource in Baja California, Mexico. The resource currently produces electricity from geothermal power plants owned and operated by Comision Federal de Electricidad (CFE), Mexico's national utility. The steam field contract is between Coperlasa and CFE. Calpine will loan up to $18.5 million to Coperlasa, and will receive fees for technical services provided to the project. At December 31, 1995, notes receivable (see Note 12) totaled $4.9 million. In February 1996, the Company loaned an additional $3.4 million to Coperlasa.
F-14

CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In December 1995, Calpine Vapor also paid $1.5 million for an option to purchase an equity interest in Coperlasa. The option expires in May 1997 and is being amortized over the estimated repayment period of the Coperlasa loan (through the year 1999) using the interest method, as the Company views the option as a loan acquisition fee. The unamortized balance of the option is also included in notes receivable from Coperlasa.
9. ACCOUNTS RECEIVABLE
The Company has both billed and unbilled receivables. The components of accounts receivable as of December 31, 1995 and 1994 are as follows (in thousands):

                                                                    1995        1994
                                                                   -------     -------
Billed...........................................................  $18,341     $13,809
Unbilled.........................................................      525         768
Other............................................................    1,258          10
                                                                   -------     -------
                                                                   $20,124     $14,587
                                                                   =======     =======	

Other accounts receivable consist primarily of disputed amounts related to the Greenleaf facilities purchase price (see Note 5).
Accounts receivable from related parties at December 31, 1995 and 1994 include the following (in thousands):

                                                                      1995       1994
                                                                     ------     ------
O.L.S. Energy-Agnews, Inc..........................................  $  806     $  538
Geothermal Energy Partners, Ltd....................................     462        793
Sumas Cogeneration Company, L.P....................................     908        528
Electrowatt and subsidiaries.......................................       1          5
                                                                     ------     ------
                                                                     $2,177     $1,864
                                                                     ======     ======	

10. ACQUISITION PROJECT RECEIVABLES
On October 17, 1995, in connection with the Company's unsuccessful bid to acquire O'Brien Environmental Energy, Inc. (OEE) through the U.S. Bankruptcy Court -- District of New Jersey proceedings, the Company purchased accounts receivable of $1.9 million, and two notes receivable totaling $3.7 million. The remaining balance of $3.2 million represents capitalized project acquisition costs. The recovery of these costs is subject to approval by the U.S. Bankruptcy Court in 1996.
The Company purchased $1.9 million of accounts receivable from two cogeneration facilities owned by subsidiaries of OEE. Payments are made to the Company based on cash availability for each project. In February 1996, the Company received approximately $1.1 million against these receivables. The Company currently expects repayment of the balance of these accounts receivable during 1996.
The Company purchased for $900,000 from Stewart & Stevenson, Inc. (S&S) a 90% participation interest in a $1.0 million note issued by OEE (the O'Brien Note). Calpine and S&S entered into an agreement in February 1996 whereby S&S assigned 100% of its interest in the O'Brien Note to Calpine, without any additional consideration. Interest accrues at approximately 5% after January 20, 1996. The Company currently expects repayment of the note receivable during 1996.
The Company entered into a purchase agreement for all of S&S's rights and obligations in a Subordinated Loan Agreement dated March 11, 1994 between S&S and O'Brien (Newark) Cogeneration, Inc. (O'Brien Newark), the Subordinated Note relating thereto and any related documents and agreements. The purchase price was $2.8 million and the notes bear interest at prime plus 2.0%. The Company receives
F-15

CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
$80,000 per month until the note is fully amortized. As of December 31, 1995, $2.7 million of principal was receivable bearing interest at 10.5%. Through February 1996, the Company received $160,000 in payment of this note. The Company currently expects repayment of the note receivable upon restructuring of O'Brien Newark debt during 1996.
11. INVESTMENTS IN POWER PROJECTS
As of December 31, 1995, 1994 and 1993, the Company had unconsolidated investments in power projects which are accounted for under the equity method. Financial information related to these investments is as follows (in thousands):

                                             SUMAS         O.L.S.      GEOTHERMAL
                                          COGENERATION     ENERGY-       ENERGY
                                            COMPANY,       AGNEWS,     PARTNERS,
                  1995                      L.P.(A)         INC.          LTD.
----------------------------------------  ------------     -------     ----------
Operating revenue.......................    $ 31,526       $10,779      $ 21,676
Net income (loss).......................      (6,098)         (483)        5,538
Assets..................................     122,802        40,330        76,017
Liabilities.............................     123,377        39,034        51,439
Company's percentage ownership..........          (b)          20%            5%
Equity investments in power projects....       5,763           314         1,229
Project development costs...............         912            --            --
                                            --------       -------       -------
Total investments in power projects.....    $  6,675       $   314      $  1,229
Company's share of net income (loss)....      (3,049)          (82)          277
                                            --------       -------       -------	

                                             SUMAS         O.L.S.      GEOTHERMAL
                                          COGENERATION     ENERGY-       ENERGY
                                            COMPANY,       AGNEWS,     PARTNERS,
                  1994                      L.P.(A)         INC.          LTD.
----------------------------------------  ------------     -------     ----------
Operating revenue.......................    $ 32,060       $11,985      $ 21,721
Net income (loss).......................      (5,777)         (415)        5,548
Assets..................................     130,148        42,596        77,081
Liabilities.............................     124,625        40,864        58,041
Company's percentage ownership..........          (b)          20%            5%
Equity investments in power projects....       8,812           396           952
Project development costs...............         946             8            --
                                            --------       -------       -------
Total investments in power projects.....    $  9,758       $   404      $    952
Company's share of net income (loss)....      (2,888)         (143)          277
                                            --------       -------       -------	

F-16

CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

                                             SUMAS         O.L.S.      GEOTHERMAL     CALPINE
                                          COGENERATION     ENERGY-       ENERGY       GEYSERS
                                            COMPANY,       AGNEWS,     PARTNERS,      COMPANY,
                  1993                      L.P.(A)         INC.          LTD.        L.P.(C)
----------------------------------------  ------------     -------     ----------     -------
Operating revenue.......................    $ 23,671       $12,485      $ 18,451      $20,759
Net income (loss).......................      (3,739)         (931)        1,090        2,689
Assets..................................     134,579        44,249        74,994           --
Liabilities.............................     123,279        42,249        61,503           --
Company's percentage ownership..........          (b)          20%            5%           --
Equity investments in power projects....      11,700           515           674           --
Project development costs...............         981            17             7           --
                                            --------       -------       -------      -------
Total investments in power projects.....    $ 12,681       $   532      $    681      $    --
Company's share of net income (loss)....      (1,870)         (127)           55        1,961
                                            --------       -------       -------      -------	

(a) Commercial operations commenced April 1993 and dry kiln operations commenced in May 1993.
(b) Distributions will be made out of operating income after certain required deposits are made and certain minimum balances are met. After receiving certain preferential distributions, the Company will have a 50% interest in the profits and losses of Sumas until earning a 24.5% pre-tax cumulative return on its investment, at which time the Company's interest in Sumas will be reduced to 11.33%.
(c) 1993 CGC information is for the period from January 1, 1993 to April 19, 1993, the date of the acquisition. Subsequent to April 19, 1993, the operating results of CGC are included in the accounts of the Company.
Sumas Cogeneration Company, L.P. -- Sumas Cogeneration Company, L P. (Sumas) is a Delaware limited partnership formed between Sumas Energy, Inc. (SEI), a Washington State Subchapter S corporation, and Whatcom Cogeneration Partners, L.P. (Whatcom), a wholly owned partnership of the Company. SEI is the general partner and Whatcom is the limited partner. Sumas has a wholly owned Canadian subsidiary, ENCO Gas, Ltd. (ENCO), which is incorporated in New Brunswick, Canada.
Sumas is the owner and operator of a power generation facility (the Generation Facility) in Sumas, Washington. The Generation Facility is a natural gas-fired combined cycle electrical generation plant with a production capacity of approximately 125 megawatts. In connection with the Generation Facility, there is a lumber dry kiln facility and a 3.5 mile private natural gas pipeline. ENCO acquired, developed and is operating a portfolio of proven natural gas reserves in British Columbia and Alberta, Canada to provide a dedicated fuel supply for the Generation Facility.
Sumas produces and sells electrical energy to Puget Sound Power & Light Company (Puget) under a 20-year agreement for approximately 110 megawatts of power, which was subsequently increased to an average 123 megawatts in 1994. Sumas leases the dry kiln facility and sells steam to Socco, Inc. (Socco), a custom lumber drying operation owned by an affiliated individual. Under the kiln lease and steam sale agreements with Socco, both of which are for 20 years, the Generating Facility is a qualifying facility as defined by PURPA.
Construction financing was provided through a $95.2 million construction and term loan agreement with The Prudential Insurance Company of America (Prudential) and Credit Suisse, an affiliate of the Company. In addition, ENCO has a $24.8 million loan agreement with Prudential and Credit Suisse. On May 25, 1993, the entire $120.0 million was converted to a term loan. Sumas established and funded all reserve accounts as required under the terms of the loan agreements with Prudential and Credit Suisse.
In addition to its interest stated above, the Company has been contracted by Sumas to provide operations and maintenance services. For these services, the Company receives a fixed fee of $1.1 million per year
F-17

CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
adjusted annually based on the Consumer Price Index, an annual base fee of $150,000 per year also adjusted based on the Consumer Price Index and certain other reimbursable expenses. In addition, the Company is entitled to an annual performance bonus of up to $400,000 based upon the achievement of certain performance levels. This arrangement will expire upon the date Whatcom receives its 24.5% pre-tax return or 10 years, subject to renewal terms, whichever is later. The Company recorded revenue of approximately $2.0 million, $1.9 million and $1.4 million associated with this arrangement during the years ended December 31, 1995, 1994 and 1993, respectively.
The Company has also provided construction management services to the Sumas project. The Company recorded revenue of approximately $72,300 and $934,000 related to construction management services during the years ended December 31, 1994 and 1993, respectively. The Company defers the profit on these contracts, to the extent of their ultimate ownership percentage, and amortizes it over the life of the project.
Calpine Geysers Company, L.P. -- In addition to its interest as stated above, the Company had been contracted by CGC to provide operations and maintenance services at cost plus overhead and fees. The Company recorded revenue of approximately $6.8 million associated with this service agreement and for other services provided to CGC for the period from January 1, 1993 to April 19, 1993.
O.L.S. Energy-Agnews, Inc. -- The Company has a 20% interest in O.L.S. Energy-Agnews, Inc., a joint venture with GATX Capital Corporation, which owns and operates a 29 megawatt gas-fired combined-cycle cogeneration facility at the State-owned Agnews Developmental Center (Center) in San Jose, California. The cogeneration plant, which commenced operations in December 1990, provides the Center with all of its thermal and electric requirements. Excess electricity is sold to PG&E under a Standard Offer No. 4 contract. The Company's original investment was $1.8 million.
In addition to its interest as stated above, the Company has been contracted by the joint venture to provide operations and maintenance services at cost plus overhead and fees, as specified. The Company recorded revenue of $1.5 million, $1.4 million and $2.3 million associated with this service agreement and for other services provided to the joint venture for the years ended December 31, 1995, 1994 and 1993, respectively.
In January 1990, O.L.S Energy-Agnews, Inc. entered into a credit agreement with Credit Suisse providing for a $28.0 million loan. The loan is secured by all of the assets of the Agnews Facility and bears interest on the unpaid principal balance based on the London Interbank Offered Rate (LIBOR) plus a margin rate varying between 0.05% and 1.5%
Geothermal Energy Partners, Ltd. -- During 1989, the Company acquired a 5% interest in Geothermal Energy Partners Ltd. (GEP). GEP was established in 1988 to develop, finance and construct a 20 megawatt geothermal power production facility located in The Geysers area of Northern California. The facility began operations on June 6, 1989.
In addition to its interest as stated above, the Company has been contracted by GEP to provide operations and maintenance services at cost plus overhead and fees, as specified. The Company recorded revenue of $3.5 million, $3.7 million and $4.5 million associated with this service agreement to GEP for the years ended December 31, 1995, 1994 and 1993, respectively.
The Company accounts for its investment in GEP under the equity methods because control of the project is deemed to be shared under the terms of the partnership agreement and the Company has significant influence over the operation of the venture.
12. NOTES RECEIVABLE
On May 25, 1993, in accordance with certain provisions of the Sumas partnership agreement, the Company was entitled to receive a distribution of $1.5 million. In addition, in accordance with provisions of
F-18

CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
the Sumas partnership agreement, SEI was required to make a capital contribution of $1.5 million. In order to meet SEI's $1.5 million capital contribution requirement, the Company loaned $1.5 million to the sole shareholder of SEI, who in turn loaned the funds to SEI, who in turn contributed the capital to Sumas. The loan bears interest at 20% and is secured by a security interest in the loan between SEI and its sole shareholder. The Company will receive payments of 50% of SEI's cash distributions from Sumas. The payments will first reduce any accrued and unpaid interest and then reduce the principal balance. On May 25, 2003, all unpaid principal and interest is due. The Company is deferring the recognition of interest income from this note until Sumas generates net income.
On March 15, 1994, the Company completed a $10.0 million loan to the sole shareholder of SEI, the Company's partner in Sumas. The loan matures in 10 years and bears interest at 16.25%. The loan is secured by a pledge to Calpine of the partner's interest in Sumas. In order to provide for the payment of principal and interest on the loan, an additional 25% of the cash flow generated by Sumas, estimated to begin in 1996, has been assigned to Calpine. The Company is deferring the recognition of interest income from this note until Sumas generates net income.
On August 25, 1994, the Company entered into a loan agreement providing for loans up to $4.8 million to TGGM (see Note 7). The loan bears interest at 10% and has a maturity date which is based on certain future events. Based on current forecasts, the maturity date will be in the year 2022. The loan is secured by a pledge to Calpine of the partner's interest in the project. The Company is deferring the recognition of income from this note until the Glass Mountain project generates sufficient income to support collectibility of interest earned. As of December 31, 1995, $3.8 million was outstanding.
As of December 31, 1995, Calpine Vapor had notes receivable of $4.9 million and unamortized loan acquisition fees of $1.5 million from Coperlasa (see Note
8). Interest accrues on the $4.9 million of outstanding notes receivable at approximately 18.8% and is due semi-annually. Principal payments in six equal installments are due beginning in May 1997 through November 1999. In January 1996, the Company loaned an additional $3.4 million to Coperlasa. The fair value of the notes receivable approximates its carrying value since the loan was entered into near the end of 1995.
13. REVOLVING CREDIT FACILITY AND LINES OF CREDIT
At December 31, 1995, the line of credit with Credit Suisse (whose parent company owns approximately 44.9% of Electrowatt) provided for advances of $50.0 million. Interest may be paid at either LIBOR or the Credit Suisse base rate, plus applicable margins in both cases. At December 31, 1995, the Company had $19.9 million of borrowings outstanding, bearing interest at LIBOR plus 0.5% (6.4% at December 31, 1995). At the Company's discretion, the debt outstanding can be held for various maturity periods of up to six months. Interest is paid on the last day of each interest period for such loans, but not less often than quarterly, based on the principal amount outstanding during the period. No stated amortization exists for this indebtedness. From January 1 to March 13, 1996, the Company borrowed an additional $8.8 million and issued a letter of credit for $3.0 million to fund an additional loan to Coperlasa (see Note 8) and other developmental project and working capital requirements. No borrowings were outstanding at December 31, 1994. The credit agreement specifies that the Company maintain certain covenants with which the Company was in compliance.
At December 31, 1995, the Company had three loan facilities with available borrowings totaling $10.2 million. Borrowings and letters of credit outstanding were $1.2 million and $3.8 million as of December 31, 1995, respectively, with interest payable at variable interest rates based on bank base rates, LIBOR or prime plus applicable margins in all cases (approximately 7.6% at December 31, 1995 on borrowings). At December 31, 1994, no borrowings and $900,000 of letters of credit were outstanding on these facilities. The credit agreements specify that the Company maintain certain covenants with which the Company was in compliance.
F-19

CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
14. WORKING CAPITAL LOAN
The Company has a $5.0 million working capital loan agreement with a bank providing for advances and letters of credit. The aggregate unpaid principal of the working capital loan is payable in full at least once a year, with the final payment of principal, interest and fees due June 30, 1998. Interest on borrowings accrues at the option of the Company at either a base rate, LIBOR, or a certificate of deposit rate (plus applicable margins in all cases) over the term of the loan. No borrowings were outstanding at December 31, 1995. At December 31, 1994, $4.5 million was outstanding under the working capital agreement, with interest at 7.625%. The Company had letters of credit outstanding of $459,000 at December 31, 1995 and 1994. Outstanding letters of credit bear interest at 0.625% payable quarterly.
15. NOTE PAYABLE TO STOCKHOLDER
On December 31, 1991, the Company declared a dividend of $1.2 million to its parent company, Electrowatt Services, Inc. On the same date, the Company issued a note payable to Electrowatt Services, Inc. for $1.2 million. Interest was paid quarterly at a rate of 4.25%, which approximated market. The note was paid on June 30, 1994, the maturity date.
16. NON-RECOURSE PROJECT FINANCING
The components of non-recourse project financing as of December 31, 1995 and 1994 are (in thousands):

                                                                     1995       1994
                                                                   --------   --------
Senior-term loans
  Fixed rate portion.............................................  $ 99,400   $116,800
  Variable rate portion..........................................    20,000     20,000
  Premium on debt................................................     2,959      4,341
                                                                   --------   --------
          Total senior-term loans................................   122,359    141,141
Junior-term loans................................................    19,965     19,965
Notes payable to banks...........................................   133,026     58,500
                                                                   --------   --------
          Total long-term debt...................................   275,350    219,606
          Less current portion...................................    84,708     22,800
                                                                   --------   --------
          Long-term debt, less current portion...................  $190,642   $196,806
                                                                   ========   ========	

Senior-Term Loans -- Principal and interest are payable in quarterly installments at variable amounts with the final payment of principal, interest and fees due June 30, 2002. A portion of the senior-term loans bears interest fixed at 9.93% (see discussion on swap agreement below) with the remainder accruing interest at LIBOR plus 0.75% to 1.25% (6.69% and 7.25% at December 31, 1995 and 1994, respectively) over the term of the loan, collateralized by all of CGC's assets and the Company's interest in CGC. In connection with the acquisition of CGC's assets in 1993, the Company recorded a premium on the fixed rate portion of the senior-term loans reflecting the fixed rate in excess of market. The premium is amortized over the life of the fixed rate portion of the loan using the interest method, and the unamortized balance is included in long-term debt outstanding.
On January 2, 1996, $5.4 million of principal was repaid, and $2.5 million of interest calculated through January 1, 1996 was paid.
Junior-Term Loans -- Principal and interest are payable in quarterly installments at variable amounts beginning September 30, 2002 with the final payment of principal, interest and fees due June 30, 2005; interest accrues at LIBOR plus 1.5% to 2.75% (7.69% and 8.5% at December 31, 1995 and 1994, respectively) over the term of the loan, collateralized by all of CGC's assets and the Company's interest in CGC.
F-20

CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Company entered into two interest rate swap agreements to minimize the impact of changes in interest rates on a portion of its senior-term loans. These agreements, with a commercial bank and a financing company, effectively fix the interest on this portion at 9.93%. The Company records the fixed rate interest as interest expense. At December 31, 1995, the swap agreements were applicable to debt with a principal balance total of $99.4 million. The interest rate swap agreements mature through December 31, 2000. The premium on debt was recorded in conjunction with the acquisition as discussed above. The premium effectively adjusts the recognized interest rate on the fixed-rate debt to 7.05% per annum. The floating interest rate associated with this portion of the senior-term loans was LIBOR plus 1.0% (6.99%) at December 31, 1995 and LIBOR plus 0.75% (7.25%) at December 31, 1994. The Company is exposed to credit risk in the event of non- performance by the other parties to the agreements.
Notes Payable to Banks -- On September 9, 1994, the Company entered into a two-year agreement with The Bank of Nova Scotia to finance the acquisition of TPC. As of December 31, 1995, the Company had $57.0 million of non-recourse project financing outstanding under this agreement. This indebtedness is secured by TPC's interest in The Geysers steam field assets. Among other restrictions, TPC is required to maintain an interest coverage ratio of at least 2.5 to 1.0, and to maintain a loan to value ratio (as defined) of no more than 0.7 to 1.0. At the Company's discretion, the debt outstanding can be held for various maturity periods of at least 30 days up to the final maturity date, September 9, 1996. The entire outstanding balance bears interest at variable rates currently based on LIBOR plus 1% (averaging 6.9% as of December 31, 1995). Interest is paid on each maturity date, but not less often than quarterly, based on the principal amount outstanding during the period. No stated principal amortization exists for this indebtedness. The Company may elect to repay principal at any time. All unpaid principal is due and payable on September 9, 1996. The Company currently intends to refinance the $57.0 million of debt before September 9, 1996.
On June 26, 1995, the Company entered into an agreement with Sumitomo Bank to finance the acquisition of the Greenleaf facilities. Of the $76.0 million debt outstanding at December 31, 1995, $60.0 million bears interest fixed at 7.4%, with the remaining floating rate portion accruing interest at LIBOR plus an applicable margin (6.5% as of December 31, 1995). This debt is secured by all of the assets of Greenleaf Unit One and Greenleaf Unit Two. Interest on the floating rate portion may be at Sumitomo's base rate plus an applicable margin or at LIBOR plus an applicable margin. Interest on base rate loans is paid at the end of each calendar quarter, and interest on LIBOR based loans is paid on each maturity date, but not less often than quarterly, based on the principal amount outstanding during the period. At the Company's discretion, the LIBOR based loans may be held for various maturity periods of at least 1 month up to 12 months. The $76.0 million debt will be repaid quarterly, with a final maturity date of December 31, 2010.
The annual principal maturities of the non-recourse long-term debt outstanding at December 31, 1995 are as follows (in thousands):

1996..............................................................  $ 84,708
1997..............................................................    24,772
1998..............................................................    25,993
1999..............................................................    18,733
2000..............................................................    17,991
Thereafter........................................................   100,194
                                                                    --------
                                                                     272,391
Unamortized premium on fixed portion of senior loan...............     2,959
                                                                    --------
          Total...................................................  $275,350
                                                                    ========	

The carrying value of $99.4 million and $116.8 million of the senior-term loan as of December 31, 1995 and 1994, respectively, has an effective rate of 9.93% under the Company's interest rate swap agreements
F-21

CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(7.05% after consideration of the debt premium). Based on the borrowing rates currently available to the Company for bank loans with similar terms and maturities, the fair value of the debt as of December 31, 1995 and 1994 is approximately $107.3 million and $120.0 million, respectively. The carrying value of the remaining $20.0 million of the senior and the $20.0 million junior-term loans and the long-term notes payable to banks approximates the debt's fair market value as the rates are variable and based on the current LIBOR rate.
The non-recourse long-term debt is held by subsidiaries of Calpine. The debt agreements of the Company's subsidiaries and other affiliates governing the non-recourse project financing generally restrict their ability to pay dividends, make distributions or otherwise transfer funds to the Company. The dividend restrictions in such agreements generally require that, prior to the payment of dividends, distributions or other transfers, the subsidiary or other affiliate must provide for the payment of other obligations, including operating expenses, debt service and reserves.
17. LONG-TERM NOTES PAYABLE
At December 31, 1995, the Company had a non-interest bearing promissory note for $6.5 million payable to Natomas Energy Company, a wholly owned subsidiary of Maxus Energy Company. This note has been discounted to yield 8.0% per annum, due September 9, 1997. The carrying amount of $5.7 million at December 31, 1995 approximates fair market value.
In January 1995, the Company purchased the working interest covering certain properties in its geothermal properties at CGC from Santa Fe Geothermal, Inc. The purchase price included $6.0 million cash, and a $750,000 non-interest bearing note discounted to yield 9% per annum and due on December 26, 1997. The Company may repay all or any part of the note at any time without penalty. The carrying value of $627,000 of the discounted non-interest bearing note at December 31, 1995 approximates fair market value.
18. SENIOR NOTES DUE 2004
On February 17, 1994, the Company completed a $105.0 million public debt offering of 9 1/4% Senior Notes Due 2004 (Senior Notes). The net proceeds of $100.9 million were used to repay all of the indebtedness outstanding under the Company's existing line of credit, and to repay the non-recourse notes payable to FMRP plus accrued interest (see Note 3). The remaining proceeds were used for general corporate purposes, including the loan to the sole shareholder of SEI discussed in Note 12. The transaction costs of $4.1 million incurred in connection with the public debt offering were recorded as a deferred charge and are amortized over the ten-year life of the Senior Notes using the interest method.
The Senior Notes will mature on February 1, 2004 and bear interest at 9 1/4% payable semiannually on February 1 and August 1 of each year, commencing August 1, 1994, to holders of record. Based on the traded yield to maturity, the approximate fair market value of the Senior Notes was $97.0 million as of December 31, 1995. The agreement specifies that the Company maintain certain covenants with which the Company was in compliance.
Under provisions of the indenture applicable to the Senior Notes, the Company may, under certain circumstances, be limited in its ability to make restricted payments, as defined, which include dividends and certain purchases and investments, incur additional indebtedness and engage in certain transactions.
19. PROVISION FOR INCOME TAXES
Effective January 1, 1993, the Company adopted Statement of Financial Accounting Standard No. 109 Accounting for Income Taxes (SFAS No. 109) and recorded $413,000 as the cumulative effect of adoption in the accompanying financial statements. SFAS No. 109 requires that the Company follow the liability method of accounting for income taxes whereby deferred income taxes are recognized for the tax consequences of
F-22

CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
"temporary differences" to the extent they are not reduced by net operating loss and tax credit carryforwards by applying enacted statutory rates.
The components of the deferred tax liability as of December 31, 1995 and 1994 are (in thousands):

                                                                  1995          1994
                                                                ---------     --------
Deferred state income taxes...................................  $     256     $  1,389
Expenses deductible in a future period........................      1,865        1,536
Net operating loss and credit carryforwards...................     19,797       15,566
Other differences.............................................      2,034        1,129
                                                                ---------     --------
  Deferred tax asset, before valuation allowance..............     23,952       19,620
Valuation allowance...........................................       (749)        (749)
                                                                ---------     --------
  Deferred tax asset..........................................     23,203       18,871
                                                                ---------     --------
Property differences..........................................   (116,763)     (66,552)
Difference in taxable income and income from investments
  recorded on the equity method...............................     (2,311)      (2,119)
Other differences.............................................     (1,750)      (1,128)
                                                                ---------     --------
  Deferred tax liabilities....................................   (120,824)     (69,799)
                                                                ---------     --------
     Net deferred tax liability...............................  $ (97,621)    $(50,928)
                                                                =========     ========	

The net operating loss and credit carryforwards consist of Federal and State net operating loss carryforwards which expire 2005 through 2010 and 1999, respectively, and Federal and State alternative minimum tax credit carryforwards which can be carried forward indefinitely. During 1991, the State of California suspended the usage of net operating loss carryforwards available to reduce taxable income for 1992 and 1991. In September 1993, the State of California removed the suspension on utilization of net operating loss carryforwards, although they can only be carried forward five years. Fifty percent of the State net operating loss carryforwards are available to reduce future taxable income. During 1993, the Company increased the tax provision by approximately $700,000 as a result of the change in the California State Tax regulations. At December 31, 1995, Federal and State net operating loss carryforwards were approximately $41.8 million and $7.2 million, respectively. At December 31, 1995 the State net operating losses have been fully reserved for in the valuation allowance due to the limited carryforward period allowed by the State of California. At December 31, 1995, Federal and State alternative minimum tax carryforwards were approximately $3.2 million and $1.6 million, respectively.
Realization of the deferred tax assets and federal net operating loss carryforwards is dependent on generating sufficient taxable income prior to expiration of the loss carryforwards. Although realization is not assured, management believes it is more likely than not that all of the deferred tax asset will be realized based on estimates of future taxable income. The amount of the deferred tax asset considered realizable, however, could be reduced in the near term if estimates of future taxable income during the carryforward period are reduced.
F-23

CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The provision for income taxes for the years ended December 31, 1995, 1994 and 1993 consists of the following (in thousands):

                                                            1995       1994       1993
                                                           ------     ------     ------
Current
  Federal................................................  $3,085     $   96     $   --
  State..................................................   1,163        365         11
Deferred
  Federal, excluding items listed below..................     816      2,546      2,581
     Adjustment in federal tax rate......................      --         --         88
  State, excluding items listed below....................     (15)       547      1,250
     Utilization of net operating loss carryforwards.....      --         --       (192)
     Increase in valuation allowance.....................      --        299        457
                                                           ------     ------     ------
          Total provision................................  $5,049     $3,853     $4,195
                                                           ======     ======     ======	

The Company's effective rate for income taxes for the years ended December 31, 1995, 1994 and 1993 differs from the U.S. statutory rate for the same periods due to state income taxes, depletion allowances and the limitation on use of state net operating loss carryforwards discussed above, as reflected in the following reconciliation.

                                                                 1995     1994     1993
                                                                 ----     ----     ----
U.S. statutory tax rate........................................  35.0%    35.0%    35.0%
State income tax, net of Federal benefit.......................   6.0      6.0      8.1
Depletion allowance............................................  (0.3)    (8.6)      --
Adjustment to deferred for change in tax rates.................    --       --      1.0
Utilization of state net operating loss carryforward...........    --       --     (2.3)
Other, net.....................................................  (0.1)    (1.2)     2.9
Increase in valuation allowance................................    --      7.8      5.5
                                                                 ----     ----     ----
     Effective income tax rate.................................  40.6%    39.0%    50.2%
                                                                 ====     ====     ====	

20. RETIREMENT SAVINGS PLAN
The Company has a defined contribution savings plan under Section 401(a) and 501(a) of the Internal Revenue Code. The plan provides for tax deferred salary deductions and after-tax employee contributions. Employees automatically become participants on the first quarterly entry date after completion of three months of service. Contributions include employee salary deferral contributions and a 3% employer profit-sharing contribution. Employer profit-sharing contributions in 1995, 1994 and 1993 totaled $350,000, $311,000 and $293,000, respectively.
21. COMMON STOCK
Prior to the merger and the stock split discussed in Note 26, the Company had Class A and Class B common stock. Each class of common stock fully participated in any dividends declared. Although Class A shareholders were precluded from receiving stock dividends of Class B common stock, Class B shares were convertible into Class A shares on a share-for-share basis at the option of the holder. Each share of Class A common stock was entitled to one vote per share, and each share of Class B common stock was entitled to ten votes per share -- see Note 26.
F-24

CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
22. STOCK OPTION PROGRAM
The Company adopted a Stock Option Program effective December 31, 1992. Under the plan, the Board of Directors may grant non-qualified stock options to officers and other senior employees of the Company, not to exceed 35 participants, to purchase Class A common stock of the Company. The plan is administered by a committee of the Board of Directors. The committee determines the timing of awards, individuals to be granted awards, the number of options to be awarded, and the price, term, vesting schedule and other conditions of the options. The Company has reserved a total of 2,596,923 Class A common shares for issuance under the plan.
Options outstanding to officers and other senior employees are:

                   GRANT                        OPTIONS        PER         EXPIRATION
                    DATE                      OUTSTANDING     SHARE           DATE
--------------------------------------------  -----------     -----     -----------------
December 31, 1992...........................     934,893      $ .50     December 31, 2002
April 1, 1993...............................     179,188      $1.85     April 1, 2003
October 1, 1994.............................     296,049      $4.57     October 1, 2004
January 1, 1995.............................     418,364      $4.91     January 1, 2005
June 16, 1995...............................      25,969      $4.91     June 16, 2005
                                                 -------
                                               1,854,463
                                                 =======	

The options were granted at fair value as determined by the Board of Directors based, in part or in whole, on the most recent applicable independent appraisal. The options granted on December 31, 1992 were fully exercisable on the date of grant. The options granted in 1993 and 1994 were vested 25% at the date of issuance with the balance vesting equally over a three-year period. The options granted on January 1, 1995 vest equally over a four-year period beginning on January 1, 1996. The options granted on June 16, 1995 vest 50% on June 16, 1997 and 50% on June 16, 1999. The number of options exercisable at December 31, 1995 totaled 1,217,308. No options have been exercised to date.
23. RELATED PARTY TRANSACTIONS
In January 1995, the Company and Electrowatt entered into a management services agreement whereby Electrowatt agreed to provide the Company with advisory services in connection with the construction, financing, acquisition and development of power projects, as well as any other advisory services as may be required by the Company in connection with the operation of the Company. The Company currently pays Electrowatt $200,000 per year for all services rendered under the management services agreement. The management services agreement terminates in January 1998.
During 1995, 1994 and 1993, the Company paid $106,000, $69,000 and $474,000, respectively, to Electrowatt pursuant to a guarantee fee agreement whereby Electrowatt agreed to guarantee the payment, when due, of any and all indebtedness of the Company to Credit Suisse in accordance with the terms and conditions of the line of credit. Under the guarantee fee agreement, the Company has agreed to pay to Electrowatt an annual fee equal to 1% of the average outstanding balance of the Company's indebtedness to Credit Suisse during each quarter as compensation for all services rendered under the guarantee fee agreement. The guarantee fee agreement terminates in January 1998.
24. SIGNIFICANT CUSTOMERS
The Company's electricity and steam sales revenue is primarily from two sources -- PG&E and SMUD. During 1994, the Company entered into a three-year agreement to sell 5 megawatts of electricity to Northern California Power Agency (NCPA). The Company terminated this agreement on December 31, 1994.
F-25

CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Revenues earned from these sources for the years ended December 31, 1995 and 1994 and for the period from April 19, 1993 to December 31, 1993 were (in thousands):

                                                         1995        1994        1993
                                                       --------     -------     -------
PG&E.................................................  $112,522     $77,010     $45,819
SMUD.................................................    12,345       9,296       9,014
NCPA.................................................        --         804          --
Other................................................       173          --          --
                                                       --------     -------     -------
                                                        125,040      87,110      54,833
Revenues recognized (deferred) (see Note 2)..........     2,759       3,185      (1,833)
                                                       --------     -------     -------
Total electricity and steam sales....................  $127,799     $90,295     $53,000
                                                       ========     =======     =======	

See Note 25 regarding CPUC Restructuring.
25. COMMITMENTS AND CONTINGENCIES
Capital Projects -- The Company has 1996 commitments for capital expenditures totaling $6.8 million related to various projects at its geothermal facilities. In March 1996, the Company entered into an energy development agreement with Phillips Petroleum Company to develop, construct, own and operate a 240 megawatt gas-fired cogeneration facility at Phillips Houston Chemical Complex in Pasadena, Texas. The initial permitting process is underway, with construction of the facility planned to begin in late 1996 and to be completed in 1998. The Company is currently evaluating options to finance the construction of this facility. The Company issued a $3.0 million letter of credit and has a 1996 capital commitment of $3.0 million in connection with this facility. In a separate transaction, as of March 15, 1996, the Company was negotiating the potential acquisition of an operating lease for a 120 megawatt gas-fired cogeneration facility located in Northern California.
Royalties and Leases -- The Company is committed under several geothermal leases and right-of-way, easement and surface agreements. The geothermal leases generally provide for royalties based on production revenue, with reductions for property taxes paid, and the right-of-way, easement and surface agreements are based on flat rates and are not material. Under the terms of certain geothermal leases, royalties accrue at rates ranging from 7% to 12.5% of steam and effluent revenue. Certain properties also have net profits and overriding royalty interests ranging from approximately 1.45% to 28%, which are in addition to the land royalties. Most lease agreements contain clauses providing for minimum lease payments to lessors if production temporarily ceases or if production falls below a specified level.
The Company also has working interest agreements with third parties providing for the sharing of approximately 25% to 30% of drilling and other well costs, various percentages of other operating costs and 25% to 30% of revenues on specified wells.
F-26

CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Expenses under these agreements for the years ended December 31, 1995 and 1994 and for the period from April 19,1993 to December 31, 1993, are (in thousands):

                                                          1995        1994        1993
                                                         -------     -------     ------
Production royalties...................................  $10,574     $11,153     $6,814
Lease payments.........................................  $   225     $   252     $  172	

Natural Gas Purchases -- Natural gas for the Greenleaf facilities is supplied by MNI pursuant to a long-term gas purchase agreement. Under the terms of the gas purchase agreement, MNI may nominate on a monthly basis to provide firm gas deliveries from certain specified wells. If MNI is unable to deliver the nominated quantity of gas from its reserves, MNI must purchase and deliver sufficient gas at no additional cost to the Company. The Company is committed to purchase gas at the forecasted weighted average incremental cost per decatherm of gas procured by PG&E at the California border, adjusted annually to actual cost. The fuel purchase agreement may be terminated by the Company under specified contract conditions, or upon disbursement of contract suspension payments.
The Company is committed to purchase and receive natural gas from Chevron in an amount sufficient to satisfy the requirements of the Greenleaf facilities, in excess of the nominated quantity supplied by MNI. If MNI supplies less than the nominated quantity, Chevron shall supply the volumes of natural gas constituting the difference between the volumes of gas delivered by MNI and the nominated volumes (make-up gas). Chevron will have the option to be the exclusive provider of make-up gas if Chevron agrees to sell at a price less than or equal to 100% of the average gas rate at the burner tip for utility electric generation as posted by PG&E for the month of delivery. If MNI supplies volumes of gas greater than its nomination, Chevron will reduce its deliveries in a corresponding amount. The gas supply agreement is effective through June 30, 1996, continuing month to month thereafter unless either party terminates the agreement upon sixty days written notice.
Watsonville Operating Lease -- The Company is committed under an operating lease (through December 2009) for a 28.5 megawatt natural gas-fired cogeneration power plant located in Watsonville, California (see Note 6). Under the terms of the lease, basic and contingent rents are payable each month during the period from July through December. As of December 31, 1995, future basic rent payments are $2.9 million for each year from 1996 to 2000, and $27.3 million thereafter through December 2009. Contingent rent payments are based on the net of revenues less all operating expenses, fees, reserve requirements, basic rent and supplemental rent payments. Of the remaining balance, 60% is payable to the lessor and 40% is payable to the Company.
Office and Equipment Leases -- The Company leases its corporate office, Santa Rosa office facilities and certain office equipment under noncancellable operating leases expiring through 2000. Future minimum lease payments under these leases are (in thousands):

1996................................................................  $  899
1997................................................................     905
1998................................................................     907
1999................................................................     776
2000................................................................     745
thereafter..........................................................     286
                                                                       -----
Total future minimum lease commitments..............................  $4,518
                                                                       =====	

Lease payments are subject to adjustment for the Company's pro rata portion of annual increases or decreases in building operating costs. In 1995, 1994 and 1993, rent expense for noncancellable operating leases amounted to $733,000, $663,000 and $636,000, respectively.
F-27

CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
CPUC Restructuring -- Electricity and steam sales agreements with PG&E are regulated by the California Public Utilities Commission (CPUC). In December 1995, the CPUC proposed the transition of the electric generation market to a competitive market beginning January 1, 1998, with all consumers participating by 2003. The proposed restructuring provides for phased-in customer choice, development of non-discriminatory market structure, recovery of utilities' stranded costs, sanctity of existing contracts, and continuation of existing public policy programs including the promotion of fuel diversity through a renewable energy purchase requirement.
As the proposed restructuring has widespread impact and the market structure requires the participation and oversight of the Federal Energy Regulatory Commission (FERC), the CPUC will seek to build a California consensus involving the legislature, the Governor, public and municipal utilities, and customers. The consensus would then be placed before the FERC so that both the CPUC and FERC would implement the new market structure no later than January 1, 1998. There can be no assurance that the proposed restructuring will be enacted in substantially the same form as discussed above. The Company is unable to predict the ultimate outcome of the restructuring.
Litigation -- The Company, together with over 100 other parties, was named as a defendant in the second amended complaint in an action brought in August 1993 by the bankruptcy trustee for Bonneville Pacific Corporation (Bonneville), captioned Roger G. Segal, as the Chapter 11 Trustee for Bonneville Pacific Corporation v. Portland General Corporation, et al., in the United States District Court for the District of Utah. This complaint alleges that, in conjunction with top executives of Bonneville and with the alleged assistance of the other 100 defendants, the Company engaged in a broad conspiracy and fraud. The complaint has been amended a number of times. The Company has answered each version of the complaint by denying all claims and is in the process of conducting discovery. In August 1994, the Company successfully moved for an order severing the trustee's claim against the Company from the claims against the other defendants. Although the case involves over 25 separate financial transactions entered into by Bonneville, the severed case concerns the Company in respect of only one of these transactions. In 1988, the Company invested $2.0 million in a partnership formed with Bonneville to develop four hydroelectric projects in the State of Hawaii. The projects were not successfully developed by the partnership, and, subsequent to Bonneville's Chapter 11 filing, the Company filed a claim as a creditor against Bonneville's bankruptcy estate. The trustee alleges that the equity investment was actually a "sham" loan designed to inflate Bonneville's earnings. The trustee further alleges that Calpine is one of many defendants in this case responsible for Bonneville's insolvency and the amount of damages attributable to the Company based on the $2.0 million partnership investment is alleged to be $577.2 million. The trustee is seeking to hold each of the other defendants liable for a portion, all or, in certain cases, more than this amount. The Company expects the matter will be set for trial in 1996. The Company believes the claims against it are without merit and will continue to defend the action vigorously. The Company further believes that the resolution of this matter will not have a material adverse effect on its financial position or results of operations.
ENCO terminated protracted contract negotiations with two Canadian natural gas suppliers in January 1995. One of the suppliers notified ENCO it considered a draft contract to be effective although it had not been executed by ENCO. The supplier indicated it may pursue legal action if ENCO would not execute the contract. As of March 15, 1996, no legal action has been served on ENCO. Management believes if legal action is commenced, ENCO has significant defenses and believes such action will not result in any material adverse impact to the Company's financial condition or results of operations.
The Company is involved in various other claims and legal actions arising out of the normal course of business. Management does not expect that the outcome of these cases will have a material adverse effect on the Company's financial position or results of operations.
F-28

CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
26. SUBSEQUENT EVENT
In July 1996, the Company's Board of Directors authorized the reincorporation of the Company into Delaware in connection with the Company's initial public equity offering. Also, the Board of Directors approved a stock split at a ratio of approximately 5.194 to 1. On September 13, 1996, the reincorporation of the Company and the stock split became effective. The accompanying financial statements reflect the reincorporation and the stock split as if such transactions had been effective for all periods.
F-29

CALPINE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
 (IN THOUSANDS)

                                                                       AS ADJUSTED
                                                                        JUNE 30,
                                                                          1996
                                                                      STOCKHOLDER'S
                                                                         EQUITY
                                                                        ASSUMING
                                                                       CONVERSION
                                                                      OF PREFERRED
                                                                       STOCK (NOTE      DECEMBER 31,
                                                                           12)              1995
                                                         JUNE 30,     -------------     ------------
                                                           1996                         (UNAUDITED)
                                                         --------
                                                         (UNAUDITED)
                                      ASSETS
Current assets:
  Cash and cash equivalents............................  $ 38,403                         $ 21,810
  Accounts receivable..................................    38,691                           20,124
  Acquisition project receivables......................     4,536                            8,805
  Collateral securities, current portion...............     9,745                               --
  Prepaid expenses.....................................     6,978                            3,447
  Inventory............................................     3,444                            1,377
  Other current assets.................................     2,947                              677
                                                         --------
          Total current assets.........................   104,744                           56,230
Property, plant and equipment, net.....................   530,203                          447,751
Investments in power projects..........................    12,693                            8,218
Collateral securities, net of current portion..........    88,669                               --
Notes receivable from related parties..................    20,894                           19,391
Notes receivable from Coperlasa........................    16,492                            6,094
Restricted cash........................................     8,477                            9,627
Deferred charges and other assets......................    10,640                            7,220
                                                         --------
          Total assets.................................  $792,812                         $554,531
                                                         ========
                       LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
  Current non-recourse long-term project financing.....  $ 27,178                         $ 84,708
  Notes payable to bank and short-term borrowings......        --                            1,177
  Accounts payable.....................................     9,530                            6,876
  Accrued payroll and related expenses.................     2,336                            2,789
  Accrued interest payable.............................     8,693                            7,050
  Other accrued expenses...............................     5,121                            2,657
                                                         --------
          Total current liabilities....................    52,858                          105,257
Long-term line of credit...............................        --                           19,851
Non-recourse long-term project financing, less current
  portion..............................................   180,974                          190,642
Notes payable..........................................     6,598                            6,348
Senior Notes...........................................   285,000                          105,000
Deferred income taxes, net.............................   100,068                           97,621
Deferred lease incentive...............................    81,495                               --
Other liabilities......................................     6,163                            4,585
                                                         --------
          Total liabilities............................   713,156                          529,304
                                                         --------
Stockholder's equity
  Preferred stock......................................         5              --               --
  Common stock.........................................        10              18               10
  Additional paid-in capital...........................    56,209          56,206            6,214
  Retained earnings....................................    23,432          23,432           19,003
                                                         --------        --------
          Total stockholder's equity...................    79,656          79,656           25,227
                                                         --------        --------
          Total liabilities and stockholder's equity...  $792,812       $ 792,812         $554,531
                                                         ========        ========	

The accompanying notes are an integral part of these condensed consolidated financial statements.
F-30

CALPINE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
 (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

(UNAUDITED)

                                                                          SIX MONTHS ENDED
                                                                              JUNE 30,
                                                                       -----------------------
                                                                         1996           1995
                                                                       --------       --------
Revenue:
  Electricity and steam sales........................................  $ 72,030       $ 49,014
  Service contract revenue from related parties......................     4,616          3,129
  Service revenue from others........................................       818             --
  Income (loss) from unconsolidated investments in power projects....     1,713         (1,791)
  Interest income on loans to power projects.........................     2,817             --
                                                                       --------       --------
          Total revenue..............................................    81,994         50,352
                                                                       --------       --------
Cost of revenue:
  Plant operating expenses, depreciation, operating lease expense and
     production royalties............................................    46,835         28,344
  Service contract expenses and other................................     4,484          2,274
                                                                       --------       --------
          Total cost of revenue......................................    51,319         30,618
                                                                       --------       --------
Gross profit.........................................................    30,675         19,734
Project development expenses.........................................     1,410          1,308
General and administrative expenses..................................     5,874          3,659
                                                                       --------       --------
          Income from operations.....................................    23,391         14,767
Other (income) expense:
  Interest expense...................................................    18,665         15,116
  Other income, net..................................................    (2,777)          (855)
                                                                       --------       --------
          Income before provision for income taxes...................     7,503            506
Provision for income taxes...........................................     3,080            208
                                                                       --------       --------
          Net income.................................................  $  4,423       $    298
                                                                       ========       ========
As adjusted earnings per share assuming conversion of preferred
  stock:
                                                                         14,476
  As adjusted weighted average shares outstanding....................  ========
                                                                       $   0.31
  Net income per share...............................................  ========	

The accompanying notes are an integral part of these condensed consolidated financial statements.
F-31

CALPINE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 (IN THOUSANDS)

(UNAUDITED)

                                                                        SIX MONTHS ENDED JUNE
                                                                                 30,
                                                                        ----------------------
                                                                          1996          1995
                                                                        ---------     --------
Net cash provided by operating activities.............................  $   5,035     $  5,126
                                                                        ---------     --------
Cash flows from investing activities:
  Acquisition of property, plant and equipment........................     (8,061)      (9,324)
  Investment in Greenleaf, net of cash on hand........................         --      (16,958)
  Investment in Watsonville, net of cash on hand......................         --          494
  Investment in King City, net of cash on hand........................     (4,877)          --
  Investment in King City collateral securities.......................    (98,414)          --
  Investments in power projects and capitalized costs.................     (2,983)        (579)
  Loans to Coperlasa..................................................    (12,104)          --
  Increase in notes receivable from related party.....................       (250)        (250)
  Decrease in restricted cash.........................................      1,150        2,766
  Other, net..........................................................       (512)         (23)
                                                                        ---------     --------
     Net cash used in investing activities............................   (126,051)     (23,874)
                                                                        ---------     --------
Cash flows from financing activities:
  Proceeds from issuance of Senior Notes Due 2006.....................    180,000           --
  Proceeds from issuance of preferred stock...........................     50,000           --
  Borrowings from line of credit......................................     33,800       20,851
  Repayment of line of credit.........................................    (53,651)     (15,000)
  Borrowing from Bank.................................................     45,000           --
  Repayments to Bank..................................................    (46,177)          --
  Borrowings of non-recourse project financing........................         --       77,925
  Repayment of non-recourse project financing.........................    (66,600)     (73,988)
  Repayment of working capital loan...................................         --       (4,500)
  Financing costs.....................................................     (4,763)      (1,546)
                                                                        ---------     --------
     Net cash provided by (used for) financing activities.............    137,609        3,742
                                                                        ---------     --------
Net increase (decrease) in cash and cash equivalents..................     16,593      (15,006)
Cash and cash equivalents, beginning of period........................     21,810       22,527
                                                                        ---------     --------
Cash and cash equivalents, end of period..............................  $  38,403     $  7,521
                                                                        =========     ========
Supplementary information:
  Cash paid during the period for:
     Interest.........................................................  $  16,517     $ 17,530
     Income taxes.....................................................  $     955     $    125	

The accompanying notes are an integral part of these consolidated financial statements.
F-32

CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 JUNE 30, 1996
1. ORGANIZATION AND OPERATION OF THE COMPANY
Calpine Corporation (Calpine) and subsidiaries (collectively, the Company) are engaged in the development, acquisition, ownership and operation of power generation facilities in the United States. The Company has ownership interests in or operates geothermal steam fields, geothermal power generation facilities, and natural gas-fired cogeneration facilities in Northern California, Washington and Mexico. Each of the generation facilities produces electricity for sale to utilities. Thermal energy produced by the gas-fired cogeneration facilities is sold to governmental and industrial users, and steam produced by the geothermal steam fields is sold to utility-owned power plants. Founded in 1984, the Company is wholly owned by Electrowatt Services, Inc., which is wholly owned by Electrowatt Ltd (Electrowatt), a Swiss company. The Company has expertise in the areas of engineering, finance, construction and plant operations and maintenance.
In July 1996, the Company filed a registration statement with the United States Securities and Exchange Commission relating to the initial public offering of shares of the Company's Common Stock. In the offering, the Company will sell newly issued shares of Common Stock and Electrowatt will sell shares of Common Stock representing its entire ownership interest in Calpine. If the offering is completed, Electrowatt will no longer own any interest in the Company.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Interim Presentation
The accompanying interim condensed consolidated financial statements of the Company have been prepared by the Company, without audit by independent public accountants, pursuant to the rules and regulations of the Securities and Exchange Commission. In the opinion of management, the condensed consolidated financial statements include all and only normal recurring adjustments necessary to present fairly the information required to be set forth therein. Certain information and note disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted from these statements pursuant to such rules and regulations and, accordingly, should be read in conjunction with the audited consolidated financial statements of the Company included in the Company's annual report on Form 10-K for the year ended December 31, 1995. The results for interim periods are not necessarily indicative of the results for the entire year.
As Adjusted Earnings Per Share and As Adjusted Stockholder's Equity
Net income per share is computed using weighted average shares outstanding, which includes the net additional number of shares which would be issuable upon the exercise of outstanding stock options, assuming that the Company used the proceeds received to purchase additional shares at an assumed public offering price. Net income per share also gives effect, even if antidilutive, to common equivalent shares from preferred stock that will automatically convert upon the closing of the Company's initial public offering (using the as-if-converted method). If the offering contemplated by the Company is consummated, all of the convertible preferred stock outstanding as of the closing date will automatically be converted into shares of common stock based on the shares of convertible preferred stock outstanding at June 30, 1996. Unaudited as adjusted stockholder's equity at June 30, 1996, as adjusted for the conversion of preferred stock, is disclosed on the balance sheet.
Impact of Recent Accounting Pronouncements
In March 1995, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards (SFAS) No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets
F-33

CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
to be Disposed Of. This pronouncement requires that long-lived assets and certain identifiable intangible assets be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. An impairment loss is to be recognized when the sum of undiscounted cash flows is less than the carrying amount of the asset. Measurement of the loss for assets that the entity expects to hold and use are to be based on the fair market value of the asset. SFAS No. 121 must be adopted for fiscal years beginning in 1996. The Company adopted SFAS No. 121 effective January 1, 1996, and determined that adoption of this pronouncement had no material impact on the results of operations or financial condition as of January 1, 1996.
In October 1995, the Financial Accounting Standards Board issued SFAS No. 123, Accounting for Stock Based Compensation. The disclosure requirements of SFAS No. 123 are effective for the Company's 1996 fiscal year. The new pronouncement did not have an impact on its results of operations since the intrinsic value-based method prescribed by Accounting Principles Board Opinion No. 25 and also allowed by SFAS No. 123 will continue to be used by the Company to account for its stock-based compensation plans.
3. ACCOUNTS RECEIVABLE
The Company has both billed and unbilled receivables. The components of accounts receivable as of June 30, 1996 and December 31, 1995 are as follows (in thousands):

                                                                      DECEMBER 31,
                                                                          1995
                                                       JUNE 30,       ------------
                                                         1996
                                                      -----------
                                                      (UNAUDITED)
Projects:
  Billed............................................    $37,622         $ 18,341
  Unbilled..........................................        845              525
  Other.............................................        224            1,258
                                                        -------          -------
                                                        $38,691         $ 20,124
                                                        =======          =======	

Other accounts receivable consist primarily of disputed amounts related to the Greenleaf facilities purchase price. In May 1996, the Company reclassified such accounts receivable to property, plant and equipment as an adjustment to the purchase price of the Greenleaf facilities (see Note 6).
Accounts receivable from related parties as of June 30, 1996 and December 31, 1995 are comprised of the following (in thousands):

                                                                      DECEMBER 31,
                                                                          1995
                                                       JUNE 30,       ------------
                                                         1996
                                                      -----------
                                                      (UNAUDITED)
O.L.S. Energy-Agnews, Inc. .........................    $   589         $    806
Geothermal Energy Partners, Ltd. ...................        979              462
Sumas Cogeneration Company, L.P. ...................      1,206              908
Electrowatt and subsidiaries........................          2                1
                                                        -------          -------
                                                        $ 2,776         $  2,177
                                                        =======          =======	

F-34

CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
4. INVESTMENTS IN POWER PROJECTS
The Company has unconsolidated investments in power projects which are accounted for under the equity method. Unaudited financial information for the six months ended June 30, 1996 and 1995 related to these investments is as follows (in thousands):

                                                                1996                                  1995
                                                 -----------------------------------   ----------------------------------
                                                    SUMAS       O.L.S.    GEOTHERMAL      SUMAS       O.L.S.   GEOTHERMAL
                                                 COGENERATION   ENERGY-     ENERGY     COGENERATION   ENERGY-    ENERGY
                                                   COMPANY,     AGNEWS,   PARTNERS,      COMPANY,     AGNEWS,  PARTNERS,
                                                     L.P.        INC.        LTD.          L.P.        INC.       LTD.
                                                 ------------   -------   ----------   ------------   ------   ----------
Revenue........................................    $ 21,561     $4,604      $9,576       $ 15,265     $4,612     $9,847
Operating expenses.............................      12,752      4,349       6,219         13,530     4,300       5,064
                                                    -------     ------      ------         ------     ------     ------
Income (loss) from operations..................       8,809        255       3,357          1,735       312       4,783
Other expenses, net............................       5,098      1,040       2,444          5,283     1,034       2,865
                                                    -------     ------      ------         ------     ------     ------
    Net income (loss)..........................    $  3,711     $ (785 )    $  913       $ (3,548)    $(722 )    $1,918
                                                    =======     ======      ======         ======     ======     ======
Company's share of net income (loss)...........    $  1,855     $ (179 )    $   37       $ (1,774)    $(130 )    $  113
                                                    =======     ======      ======         ======     ======     ======	

5. THERMAL POWER COMPANY
In March 1996, Thermal Power Company (TPC) a wholly owned subsidiary of the company, and Union Oil Company of California (Union Oil) entered into an alternative pricing agreement with Pacific Gas and Electric Company (PG&E) for any steam produced in excess of 40% of average field capacity. The alternative pricing strategy is effective through December 31, 2000. Under the agreement, PG&E would purchase a portion of the steam that PG&E would likely curtail under TPC's existing steam sales agreement. The price for this portion of steam will be set by TPC and Union Oil with the intent that it be at competitive market prices. TPC and Union Oil will solely determine the price and duration of these alternative price offers.
6. GREENLEAF TRANSACTION
In April 1995, the Company purchased the capital stock of the companies which owned 100% of the assets of two 49.5 megawatt natural gas-fired cogeneration facilities (collectively, the Greenleaf facilities) located in Yuba City in Northern California. The initial purchase price included a cash payment of $20.3 million and the assumption of project debt totalling $60.2 million. In April 1996, the Company finalized the purchase price in accordance with the Share Purchase Agreement dated March 30, 1995.
The acquisition was accounted for as a purchase and the purchase price has been allocated to the acquired assets and liabilities based on the estimated fair values of the acquired assets and liabilities as shown below. The adjusted allocation of the purchase price is as follows (in thousands):

Current assets....................................................  $  6,572
Property, plant and equipment.....................................   122,545
                                                                    --------
     Total assets.................................................   129,117
                                                                    --------
Current liabilities...............................................    (1,079)
Deferred income taxes, net........................................   (46,580)
                                                                    --------
     Total liabilities............................................   (47,659)
                                                                    --------
Net purchase price................................................  $ 81,458
                                                                    ========	

F-35

CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
7. KING CITY TRANSACTION
In April 1996, the Company entered into a long-term operating lease with BAF Energy, A California Limited Partnership (BAF), for a 120 megawatt natural gas-fired combined cycle facility located in King City, California. The facility generates electricity for sale to PG&E pursuant to a long-term power sales agreement through 2019. Natural gas for the facility is supplied by Chevron USA Inc. pursuant to a contract which expires June 30, 1997.
Under the terms of the operating lease, the Company makes semi-annual lease payments to BAF on each February 15 and August 15, a portion of which is supported by a $98.4 million collateral fund owned by the Company. The collateral fund consists of a portfolio of investment grade and U.S. Treasury Securities that will mature serially in amounts equal to a portion of the lease payments. The collateral fund securities are accounted for as held-to-maturity investments under SFAS No. 115, Accounting for Certain Investments in Debt and Equity Securities. As of June 30, 1996, future rent payments are $11.8 million for the remainder of 1996, $24.4 million for 1997, $23.8 million for 1998, $19.4 million for 1999, $20.1 million for 2000 and $204.1 million thereafter.
The Company has recorded the value of the above-market pricing provided in the power sales agreement (PSA) as an asset which is included in property, plant and equipment, since the Company has, in substance, assumed the rights of the PSA. The Company has also recorded a deferred lease incentive equal to the value of the above-market payments to be received. The asset and liability are being amortized over the life of the power sales agreement and lease, respectively.
The Company financed the collateral fund and other transaction costs with $50.0 million of proceeds from the issuance of preferred stock to Electrowatt by Calpine (see Note 10) and other short-term borrowings, which included $13.3 million of borrowings under the Credit Suisse Credit Facility (see Note 8) below and a $45.0 million loan from The Bank of Nova Scotia. The Company repaid the short-term borrowings from a portion of the net proceeds of the Senior Notes Due 2006 issued in May 1996 (see Note 9).
8. LINES OF CREDIT
At June 30, 1996, the Company had borrowings under its $50.0 million Credit Facility with Credit Suisse (whose parent company owns 44.9% of Electrowatt) and had a letter of credit outstanding thereunder for $3,025,000. Borrowings under the Credit Facility bear interest at the London Interbank Offered Rate (LIBOR) plus 0.5%. Interest is paid on the last day of each interest period for such loan, but not less often than quarterly, based on the principal amount outstanding during the period. No stated principal amortization exists for this indebtedness. Upon completion of the Company's proposed initial public offering, the Credit Facility will terminate and is expected to be replaced by a comparable facility. On July 20, 1996, the Company entered into a commitment letter with The Bank of Nova Scotia to provide a $50 million three-year Revolving Credit Facility. Such Revolving Credit Facility will become effective upon the completion of the Company's initial public offering.
9. SENIOR NOTES DUE 2006
On May 16, 1996, the Company issued $180.0 million aggregate principal amount of 10 1/2% Senior Notes Due 2006. The net proceeds of $175.2 million were used to repay $53.7 million of borrowings under the Credit Suisse Credit Facility, $57.0 million of non-recourse project financing, and $45.0 million of borrowing from The Bank of Nova Scotia. The remaining $19.5 million was available for general corporate purposes. Transaction costs of $4.8 million incurred in connection with the public debt offering were recorded as a
F-36

CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
deferred charge and are amortized over the ten-year life of the Senior Notes Due 2006 using the straight line method.
The Senior Notes Due 2006 will mature on May 15, 2006. The Company has no sinking fund or mandatory redemption obligations with respect to the Senior Notes Due 2006. Interest is payable semi-annually on May 15 and November 15 of each year while the Senior Notes Due 2006 are outstanding, commencing on November 15, 1996.
10. PREFERRED STOCK
The Company has 5,000,000 authorized shares of Series A Preferred Stock, all of which were issued on March 21, 1996 and outstanding as of June 30, 1996. All of the shares of Series A Preferred Stock are held by Electrowatt. The shares of Series A Preferred Stock are not publicly traded. No dividends are payable on the Series A Preferred Stock. The Series A Preferred Stock contains provisions regarding liquidation and conversion rights. Upon the consummation of the Company's proposed initial public offering, the Series A Preferred Stock will be converted into Common Stock and sold to the public in the offering.
11. CONTINGENCIES
The Company, together with over 100 other parties, was named as a defendant in the second amended complaint in an action brought in August 1993 by the bankruptcy trustee for Bonneville Pacific Corporation (Bonneville), captioned Roger G. Segal, as the Chapter 11 Trustee for Bonneville Pacific Corporation v. Portland General Corporation, et al., in the United States District Court for the District of Utah (the "Court"). This complaint alleges that, in conjunction with top executives of Bonneville and with the alleged assistance of the other 100 defendants, the Company engaged in a broad conspiracy and fraud. The complaint has been amended a number of times. The Company has answered each version of the complaint by denying all claims and is in the process of conducting discovery. In August 1994, the Company successfully moved for an order severing the trustee's claim against the Company from the claims against the other defendants. Although the case involves over 25 separate financial transactions entered into by Bonneville, the severed case concerns the Company in respect of only one of these transactions. In 1988, the Company invested $2.0 million in a partnership formed with Bonneville to develop four hydroelectric projects in the State of Hawaii. The projects were not successfully developed by the partnership, and, subsequent to Bonneville's Chapter 11 filing, the Company filed a claim as a creditor against Bonneville's bankruptcy estate. The trustee alleges that the equity investment was actually a "sham" loan designed to inflate Bonneville's earnings. The trustee initially alleged that Calpine is one of many defendants in this case responsible for Bonneville's "deepening insolvency" and the amount of damages attributable to the Company based on the $2.0 million partnership investment was alleged to be $577.2 million. Based upon statements made by the Court and the trustee in July 1996, the Company believes that the maximum compensatory damages which the trustee may seek will not exceed $5 million. There can be no assurance, however, of the actual amount of damages to be sought by the Trustee. The Company believes the claims against it are without merit and will continue to defend the action vigorously. The Company further believes that the resolution of this matter will not have a material adverse effect on its financial position or results of operations.
The Company is involved in various other claims and legal actions arising out of the normal course of business. Management does not expect that the outcome of these cases will have a material adverse effect on the Company's financial position or results of operations.
12. SUBSEQUENT EVENT
In July 1996, the Company's Board of Directors authorized the reincorporation of the Company into Delaware in connection with the Company's initial public equity offering. Also, the Board of Directors approved a stock split at a ratio of approximately 5.194 to 1. On September 13, 1996, the reincorporation of the Company and the stock split became effective. The accompanying financial statements reflect the reincorporation and the stock split as if such transactions had been effective for all periods.
F-37

INDEPENDENT AUDITOR'S REPORT
To the Partners
Sumas Cogeneration Company, L.P. and Subsidiary
We have audited the accompanying consolidated balance sheet of Sumas Cogeneration Company, L.P. and Subsidiary as of December 31, 1995 and 1994, and the related consolidated statements of operations, changes in partners' deficit, and cash flows for each of the three years ended December 31, 1995. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Sumas Cogeneration Company, L.P. and Subsidiary as of December 31, 1995 and 1994 and the results of their operations and cash flows for each of the three years ended December 31, 1995, in conformity with generally accepted accounting principles.
MOSS ADAMS LLP
Everett, Washington
January 19, 1996
F-38

SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS

                                                                          DECEMBER 31,
                                                                  -----------------------------
                                                                      1995             1994
                                                                  ------------     ------------
                                            ASSETS
Current assets
  Cash and cash equivalents.....................................  $    199,169     $    353,936
  Current portion of restricted cash and cash equivalents.......     2,937,884        6,409,185
  Accounts receivable...........................................     3,090,213        4,108,206
  Prepaid expenses..............................................       222,828          232,325
                                                                  ------------     ------------
     Total current assets.......................................     6,450,094       11,103,652
Restricted cash and cash equivalents, net of current portion....     8,017,758        7,454,923
Property, plant and equipment, at cost, net.....................    95,589,737       97,039,459
Other assets....................................................    12,744,480       14,550,228
                                                                  ------------     ------------
                                                                  $122,802,069     $130,148,262
                                                                  ============     ============
                               LIABILITIES AND PARTNERS' DEFICIT
Current liabilities
  Accounts payable and accrued liabilities......................  $  2,051,178     $  3,651,799
  Current portion of related party payables
     Calpine Corporation........................................         4,864           41,871
     National Energy Systems Company............................         1,861            1,430
  Current portion of long-term debt.............................     2,000,000          400,000
                                                                  ------------     ------------
     Total current liabilities..................................     4,057,903        4,095,100
Related party payable -- Calpine Corporation, net of current
  portion.......................................................       908,679          446,624
Long-term debt, net of current portion..........................   117,000,003      119,000,002
Future removal and site restoration costs.......................       502,600          309,600
Deferred income taxes...........................................       907,800          773,800
Commitments and contingency (Notes 6 and 8)
Partners' (deficit) equity......................................      (574,916)       5,523,136
                                                                  ------------     ------------
                                                                  $122,802,069     $130,148,262
                                                                  ============     ============	

The accompanying notes are an integral part of these consolidated financial statements.
F-39

SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
CONSOLIDATED STATEMENT OF OPERATIONS

                                                                 YEAR ENDED DECEMBER 31,
                                                        -----------------------------------------
                                                            1995           1994          1993
                                                        ------------   ------------   -----------
Revenues
  Power sales.........................................  $ 30,603,018   $ 29,206,469   $19,525,098
  Natural gas sales, net..............................       893,690      2,832,668     2,104,407
  Other...............................................        29,146         20,490       116,895
                                                        ------------   ------------   -----------
          Total revenues..............................    31,525,854     32,059,627    21,746,400
                                                        ------------   ------------   -----------
Costs and expenses
  Operating and production costs......................    18,493,245     19,032,754    11,779,505
  Depletion, depreciation and amortization............     6,965,496      6,715,156     4,986,300
  General and administrative..........................     1,400,129      1,412,326     1,563,509
                                                        ------------   ------------   -----------
          Total costs and expenses....................    26,858,870     27,160,236    18,329,314
                                                        ------------   ------------   -----------
Income from operations................................     4,666,984      4,899,391     3,417,086
                                                        ------------   ------------   -----------
Other income (expense)
  Interest income.....................................       490,071        436,741       250,675
  Interest expense....................................   (11,006,056)   (10,172,959)   (6,707,183)
  Other expense.......................................       (60,664)      (359,000)           --
                                                        ------------   ------------   -----------
          Total other expense.........................   (10,576,649)   (10,095,218)   (6,456,508)
                                                        ------------   ------------   -----------
Loss before provision for income taxes................    (5,909,665)    (5,195,827)   (3,039,422)
Provision for income taxes............................      (188,387)      (581,190)     (337,431)
                                                        ------------   ------------   -----------
Net loss..............................................  $ (6,098,052)  $ (5,777,017)  $(3,376,853)
                                                        ============   ============   ===========	

The accompanying notes are an integral part of these consolidated financial statements.
F-40

SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
CONSOLIDATED STATEMENT OF CHANGES IN PARTNERS' DEFICIT
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993

Partners' equity, December 31, 1992.............................................  $14,688,436
Capital contributions...........................................................    1,500,000
Capital distributions...........................................................   (1,500,000)
Net loss........................................................................   (3,376,853)
Cumulative foreign exchange translation adjustment..............................      (11,430)
                                                                                  -----------
Partners' equity, December 31, 1993.............................................   11,300,153
Net loss........................................................................   (5,777,017)
                                                                                  -----------
Partners' equity, December 31, 1994.............................................    5,523,136
Net loss........................................................................   (6,098,052)
                                                                                  -----------
Partners' deficit, December 31, 1995............................................  $  (574,916)
                                                                                  ===========	

The accompanying notes are an integral part of these consolidated financial statements.
F-41

SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
CONSOLIDATED STATEMENT OF CASH FLOWS

                                                                YEAR ENDED DECEMBER 31,
                                                      -------------------------------------------
                                                         1995            1994            1993
                                                      -----------     -----------     -----------
Cash flows from operating activities
  Net loss..........................................  $(6,098,052)    $(5,777,017)    $(3,376,853)
  Adjustments to reconcile net loss to net cash from
     operating activities
     Depletion, depreciation and amortization.......    6,965,496       6,715,156       4,986,300
     Deferred income taxes..........................      134,000         532,400         241,400
     Changes in operating assets and liabilities
       Accounts receivable..........................    1,017,993      (1,254,639)     (2,064,616)
       Prepaid expenses.............................        9,497         (30,342)        203,904
       Accounts payable and accrued liabilities.....   (1,407,621)      1,081,431       1,168,892
       Related party payables.......................      425,479         132,296              --
                                                      -----------     -----------     -----------
          Net cash from operating activities........    1,046,792       1,399,285       1,159,027
                                                      -----------     -----------     -----------
Cash flows from investing activities
  Decrease (increase) in restricted cash and cash
     equivalents....................................    2,908,466       2,922,819     (13,286,927)
  Acquisition of property, plant and equipment......   (3,710,025)     (3,690,399)    (16,558,101)
  Other assets......................................           --        (167,483)     (5,700,537)
  Accounts payable and accrued liabilities..........           --              --      (3,847,743)
                                                      -----------     -----------     -----------
          Net cash from investing activities........     (801,559)       (935,063)    (39,393,308)
                                                      -----------     -----------     -----------
Cash flows from financing activities
  Proceeds from long-term debt......................           --              --      38,710,000
  Repayment of long-term debt.......................     (400,000)       (400,025)       (199,973)
  Capital contributions.............................           --              --       1,500,000
  Capital distributions.............................           --              --      (1,500,000)
  Payments to related parties.......................           --              --        (864,890)
                                                      -----------     -----------     -----------
          Net cash from financing activities........     (400,000)       (400,025)     37,645,137
                                                      -----------     -----------     -----------
Effect of exchange rate changes on cash.............           --              --         (11,430)
                                                      -----------     -----------     -----------
Net increase (decrease) in cash and cash
  equivalents.......................................     (154,767)         64,197        (600,574)
Cash and cash equivalents, beginning of year........      353,936         289,739         890,313
                                                      -----------     -----------     -----------
Cash and cash equivalents, end of year..............  $   199,169     $   353,936     $   289,739
                                                      ===========     ===========     ===========
Supplementary disclosure of cash flow information
  Cash paid for interest during the year............  $11,006,056     $10,172,959     $ 8,868,183
                                                      ===========     ===========     ===========	

The accompanying notes are an integral part of these consolidated financial statements.
F-42

SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1995, 1994 AND 1993
NOTE 1 -- ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(a) GENERAL -- Sumas Cogeneration Company, L.P. (the Partnership) is a Delaware limited partnership formed on August 28, 1991 between Sumas Energy, Inc. (SEI), the general partner which currently holds a 50% interest in the profits and losses of the Partnership and Whatcom Cogeneration Partners, L.P. (Whatcom), the sole limited partner which holds the remaining 50% Partnership interest. Whatcom is owned through affiliated companies by Calpine Corporation (Calpine). The Partnership has a wholly owned Canadian subsidiary, ENCO Gas, Ltd. (ENCO), which is incorporated in New Brunswick, Canada. The consolidated financial statements include the accounts of the Partnership and ENCO (collectively, the Company). All intercompany profits, transactions and balances have been eliminated in consolidation.
Prior to the commencement of commercial operation as discussed below, the Partnership was considered to be a development stage company in the process of developing, constructing and owning an electrical generation facility (the Generation Facility) in Sumas, Washington. The Generation Facility is a natural gas-fired combined cycle electrical generation plant which has a nameplate capacity of approximately 125 megawatts. Commercial operation of the Generation Facility commenced on April 16, 1993. In addition, the Generation Facility includes a lumber dry kiln facility and a 3.5 mile private natural gas pipeline. The lumber dry kiln commenced commercial operation in May 1993.
ENCO has acquired and is operating and developing a portfolio of proven natural gas reserves in British Columbia and Alberta, Canada which provide a dedicated fuel supply for the Generation Facility (collectively, the Project). ENCO produces and supplies natural gas production to the Generation Facility, with incidental off-sales to third parties. The Generation Facility also receives a portion of its fuel under contracts with third parties.
The Partnership produces and sells its entire electricity capacity to Puget Sound Power & Light Company (Puget) under a 20-year electricity sales contract. Under the electricity sales contract, the Partnership is required to be certified as a qualifying cogeneration facility as established by the Public Utility Regulatory Policy Act of 1978, as amended, and as administered by the Federal Energy Regulatory Commission.
The Generation Facility produced and sold megawatt hours of electricity to Puget as follows:

                     YEAR ENDED
                    DECEMBER 31,                      MEGAWATTS       REVENUE
----------------------------------------------------  ---------     -----------
1995................................................  1,026,000     $30,603,000
1994................................................  1,000,400     $29,206,000
1993................................................    696,400     $19,525,000	

The Partnership leases a kiln facility and sells steam under a 20-year agreement for the purchase and sale of steam and lease of the kiln (Note 6) to Socco, Inc. (Socco), a custom lumber drying operation owned by an affiliate of the Partnership. Steam use requirements under the agreement with Socco were established to maintain the qualifying cogeneration facility status of the Generation Facility.
(b) THE PARTNERSHIP -- SEI assigned all its rights, title, and interest in the Project, including the Puget contract, to the Partnership in exchange for its Partnership interest. SEI and Whatcom are both currently entitled to a 50% interest in the profits and losses of the Partnership, after the payment of certain preferential distributions to Whatcom of approximately $6,239,000 and $5,619,000 at December 31, 1995 and 1994, respectively, and to SEI of approximately $441,000 and $363,000 at December 31, 1995 and 1994, respectively. A portion of these preferential distributions compound at 20% per annum. After Whatcom has received cumulative distributions representing a fixed rate of return of 24.5% on its equity investment,
F-43

SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
exclusive of the preferential distributions referred to above, SEI's share of operating distributions will increase to 88.67% and Whatcom's share of operating distributions will decrease to 11.33%.
(c) DISTRIBUTIONS -- Distributions of operating cash flows are permitted quarterly after required deposits are made and minimum cash balances are met, and subject to certain other restrictions. During 1995 and 1994, there were no distributions of operating cash flow. In 1993 Whatcom received a distribution of $1,500,000, reducing its equity investment in the Partnership. Whatcom loaned the sole shareholder of SEI $1,500,000, and the sole shareholder of SEI loaned $1,500,000 to SEI. SEI then contributed $1,500,000 in additional equity to the Partnership.
(d) REVENUE RECOGNITION -- Revenue from the sale of electricity is recognized based on kilowatt hours generated and delivered to Puget at contractual rates. Revenue from the sale of natural gas is recognized based on volumes delivered to customers at contractual delivery points and rates. The costs associated with the generation of electricity and the delivery of gas, including operating and maintenance costs, gas transportation and royalties, are recognized in the same period in which the related revenue is earned and recorded.
(e) GAS ACQUISITION AND DEVELOPMENT COSTS -- ENCO follows the full cost method of accounting for gas acquisition and development expenditures, wherein all costs related to the development of gas reserves in Canada are initially capitalized. Costs capitalized include land acquisition costs, geological and geophysical expenditures, rentals on undeveloped properties, cost of drilling productive and nonproductive wells, and well equipment. Gains or losses are not recognized upon disposition or abandonment of natural gas properties unless a disposition or abandonment would significantly alter the relationship between capitalized costs and proven reserves.
All capitalized costs of gas properties, including the estimated future costs to develop proven reserves, are depleted using the unit-of-production method based on estimated proven gas reserves as determined by independent engineers. ENCO has not assigned any value to its investment in unproven gas properties and, accordingly, no costs have been excluded from capitalized costs subject to depletion.
Costs subject to depletion under the full cost method include estimated future costs of dismantlement and abandonments of $3,748,000 in 1995, $3,630,000 in 1994 and $3,026,400 in 1993. This includes the cost of production equipment removal and environmental cleanup based upon current regulations and economic circumstances. The provisions for future removal and site restoration costs of $193,000 in 1995, $169,000 in 1994 and $110,000 in 1993, are included in depletion expense.
Capitalized costs are subject to a ceiling test which limits such costs to the aggregate of the net present value of the estimated future cash flows from the related proven gas reserves. The ceiling test calculation is made by estimating the future net cash flows, based on current economic operating conditions, plus the lower of cost or fair market value of unproven reserves, and discounting those cash flows at an annual rate of 10%.
(f) JOINT VENTURE ACCOUNTING -- Substantially all of ENCO's natural gas production activities are conducted jointly with others and, accordingly, these consolidated financial statements reflect only ENCO's proportionate interest in such activities.
(g) FOREIGN EXCHANGE GAINS AND LOSSES -- During 1995 and 1994, foreign exchange gains and losses as a result of translating Canadian dollar transactions and Canadian dollar denominated cash, accounts receivable and accounts payable transactions are recognized in the statement of operations. During 1993, ENCO's functional currency was Canadian dollars. As a result, translation adjustments were reported separately and accumulated as separate components of partners' equity.
(h) CASH AND CASH EQUIVALENTS -- For purposes of the statement of cash flows, cash and cash equivalents consist of cash and short-term investments in highly liquid instruments such as certificates of deposit, money
F-44

SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
market accounts and U.S. treasury bills with an original maturity of three months or less, excluding restricted cash and cash equivalents.
(i) CONCENTRATION OF CREDIT RISK -- Financial instruments, which potentially subject the Company to concentrations of credit risk, consist primarily of cash and short-term investments in highly liquid instruments such as certificates of deposit, money market accounts and U.S. treasury bills with maturities of three months or less, and accounts receivable. The Company's cash and cash equivalents are primarily held with two financial institutions. Accounts receivable are primarily due from Puget.
(j) DEPRECIATION -- The Company provides for depreciation of property, plant and equipment using the straight-line method over estimated useful lives which range from 7 to 40 years for plant and equipment and 3 to 7 years for furniture and fixtures.
(k) AMORTIZATION OF OTHER ASSETS -- The Company provides for amortization of other assets using the straight-line method as follows:

Organization, start-up and development costs.....................   5-30 years
Financing costs..................................................     15 years
Gas contract costs...............................................     20 years	

(l) INCOME TAXES -- Profits or losses of the Partnership are passed directly to the partners for income tax purposes.
ENCO is subject to Canadian income taxes and accounts for income taxes on the liability method. The liability method recognizes the amount of tax payable at the date of the consolidated financial statements as a result of all events that have been recognized in the consolidated financial statements, as measured by currently enacted tax laws and rates. Deferred income taxes are provided for temporary differences in recognition of revenues and expenses for financial and income tax reporting purposes.
(m) USE OF ESTIMATES -- The preparation of the consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the consolidated financial statements and accompanying notes. Actual results could differ from those estimates.
NOTE 2 -- PROPERTY, PLANT AND EQUIPMENT

                                                                  DECEMBER 31,
                                                          -----------------------------
                                                              1995             1994
                                                          ------------     ------------
Land and land improvements..............................  $    381,071     $    381,071
Plant and equipment.....................................    84,061,359       82,759,005
Acquisition of gas properties, including development
  thereon...............................................    25,030,165       22,815,964
Furniture and fixtures..................................       195,914          188,444
                                                          ------------     ------------
                                                           109,668,509      106,144,484
Less accumulated depreciation and depletion.............    14,078,772        9,105,025
                                                          ------------     ------------
                                                          $ 95,589,737     $ 97,039,459
                                                          ============     ============	

Depreciation expense was $3,316,748 in 1995, $3,069,446 in 1994 and $2,133,711 in 1993. Depletion expense was $1,843,000 in 1995, $1,671,000 in 1994 and $1,332,000 in 1993.
F-45

SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 3 -- OTHER ASSETS

                                                                   DECEMBER 31,
                                                            ---------------------------
                                                               1995            1994
                                                            -----------     -----------
Organization, start-up and development costs..............  $ 6,165,574     $ 7,487,943
Financing costs...........................................    4,254,719       4,598,746
Gas contract costs........................................    2,324,187       2,463,539
                                                            -----------     -----------
                                                            $12,744,480     $14,550,228
                                                            ===========     ===========	

NOTE 4 -- LONG-TERM DEBT
The Partnership and ENCO have loan agreements with The Prudential Insurance Company of America (Prudential) and Credit Suisse (collectively, the Lenders). Credit Suisse is an affiliate of Whatcom. At December 31, 1995 and 1994, amounts outstanding under the term loan agreements, by entity, were as follows:

                                                                  DECEMBER 31,
                                                          -----------------------------
                                                              1995             1994
                                                          ------------     ------------
Sumas Cogeneration Company, L.P.........................  $ 94,367,003     $ 94,684,202
ENCO Gas, Ltd...........................................    24,633,000       24,715,800
                                                          ------------     ------------
                                                           119,000,003      119,400,002
Less current portion....................................     2,000,000          400,000
                                                          ------------     ------------
                                                          $117,000,003     $119,000,002
                                                          ============     ============	

Scheduled annual principal payments under the loan agreements as of December 31, 1995 are as follows:

                          YEAR ENDING
                         DECEMBER 31,                               AMOUNT
---------------------------------------------------------------  ------------
1996...........................................................  $  2,000,000
1997...........................................................     3,600,000
1998...........................................................     4,200,000
1999...........................................................     5,400,000
2000...........................................................     7,200,000
Thereafter.....................................................    96,600,003
                                                                 ------------
                                                                 $119,000,003
                                                                 ============	

The Partnership's loan is comprised of a fixed rate loan in the original amount of $55,510,000 and a variable rate loan in the original amount of $39,650,000. Interest is payable quarterly on the fixed rate loan at a rate of 10.35%. Interest on the variable rate loan is payable quarterly at either the London Interbank Offered Rate (LIBOR), certificate of deposit rate or Credit Suisse's base rate, plus an applicable margin which ranges from 2.25% prior to Loan Conversion to .875% after Loan Conversion as stated in the loan agreement. During the year ended December 31, 1995, interest rates on the variable rate loan ranged from 7.47% to 7.76%. The loans mature in May 2008.
ENCO's loan is comprised of a fixed rate loan in the original amount of $14,490,000 and a variable rate loan in the original amount of $10,350,000. Interest is payable quarterly on the fixed rate loan at a rate of 9.99%. Interest on the variable rate loan is payable quarterly at either the LIBOR, certificate of deposit rate or Credit Suisse's base rate, plus an applicable margin as stated in the loan agreement. During the year ended
F-46

SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
December 31, 1995, interest rates on the variable rate loan ranged from 7.47% to 7.76%. The loans mature in May 2008.
The Partnership pays Prudential an agency fee of $50,000 per year, adjusted annually by an inflation index, until the loan matures. The Partnership pays Credit Suisse an agency fee of $40,000 per year, adjusted annually by an inflation index, until the loan matures. The loans are collateralized by substantially all the Company's assets and interests in the Project. Additionally, the Company's rights under all contractual agreements are assigned as collateral. The Partnership and ENCO loans are cross-collateralized and contain cross-default provisions.
Under the terms of the loan agreements and the deposit and disbursement agreements with the Lenders, the Partnership is required to establish and fund certain accounts held by Credit Suisse and Royal Trust as security agents. The accounts require specified minimum deposits and funding levels to meet current and future operating, maintenance and capital costs, and to provide certain other reserves for payment of principal, interest and other contingencies. These accounts are presented as restricted cash and cash equivalents and include cash, certificates of deposit, money market accounts and U.S. treasury bills, all with maturities of 3 months or less. The current portion of restricted cash and cash equivalents is based on the amount of current liabilities for obligations which may be funded from the restricted accounts. The balance of restricted cash and cash equivalents has been classified as a noncurrent asset.
During 1993, the Company incurred and paid $8,868,183 of interest, including $6,707,183, which was charged to operations and $2,161,000, which was capitalized.
NOTE 5 -- INCOME TAXES
The provision for income taxes represents Canadian taxes which consist of the following:

                                                          YEAR ENDED DECEMBER 31,
                                                     ----------------------------------
                                                       1995         1994         1993
                                                     --------     --------     --------
Current
  Federal large corporation tax....................  $ 34,625     $ 31,314     $ 45,262
  British Columbia capital taxes...................    19,762       17,476       50,769
                                                     --------     --------     --------
                                                       54,387       48,790       96,031
Deferred...........................................   135,400      178,400      241,400
                                                     --------     --------     --------
                                                      189,787      227,190      337,431
Utilization of loss carryforwards for Canadian
  income
  tax purposes.....................................    47,700      259,000           --
Reduction of (increase in) Canadian loss
  carryforwards
  due to foreign exchange and other adjustments....   (49,100)      95,000           --
                                                     --------     --------     --------
                                                     $188,387     $581,190     $337,431
                                                     ========     ========     ========	

F-47

SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The principal sources of temporary differences resulting in deferred tax assets and liabilities are as follows:

                                                                    DECEMBER 31,
                                                              -------------------------
                                                                 1995           1994
                                                              ----------     ----------
Deferred tax asset
  Canadian net operating loss carryforwards.................  $ (840,900)    $ (829,400)
Deferred tax liabilities
  Acquisition and development costs of gas deducted for tax
     purposes in excess of amounts deducted for financial
     reporting purposes.....................................   1,748,700      1,603,200
                                                              ----------     ----------
          Net deferred tax liability........................  $  907,800     $  773,800
                                                              ==========     ==========	

The provision for income taxes differs from the Canadian statutory rate principally due to the following:

                                                          YEAR ENDED DECEMBER 31,
                                                     ----------------------------------
                                                       1995         1994         1993
                                                     --------     --------     --------
Canadian statutory rate............................     44.62%       44.34%        44.3%
Income taxes based on statutory rate...............  $(33,852)    $ 82,909     $165,100
Capital taxes, net of deductible portion...........    47,028       36,678       75,587
Non-deductible provincial royalties, net of
  resource allowance...............................    95,671       39,836       50,267
Depletion on gas properties with no tax basis......    44,641       38,420       41,778
Other foreign exchange adjustments.................    36,299       29,347        4,699
                                                     --------     --------     --------
                                                     $189,787     $227,190     $337,431
                                                     ========     ========     ========	

As of December 31, 1995, ENCO has non-capital loss carryforwards of approximately $1,885,000 which may be applied against taxable income of future periods which expire as follows:

1999.............................................................  $1,625,000
2000.............................................................  $  260,000	

NOTE 6 -- RELATED PARTY TRANSACTIONS AND COMMITMENTS
(a) ADMINISTRATIVE SERVICES -- As managing partner of the Partnership, SEI receives a fee of $250,000 per year from June 1993 through December 1995 and $300,000 per year for periods after December 1995. The fee is subject to annual adjustment based upon an inflation index. Approximately $258,000 in 1995, $253,000 in 1994 and $151,000 in 1993 was paid to SEI under this agreement.
(b) OPERATING AND MAINTENANCE SERVICES -- The Partnership has an operating and maintenance agreement with a related party to operate, repair and maintain the Project. For these services, the Partnership pays a fixed fee of $1,140,000 per year adjustable based on the Consumer Price Index, an annual base fee of $150,000 per year also adjustable based on the Consumer Price Index, and certain other reimbursable expenses as defined in the agreement. In addition, the agreement provides for an annual performance bonus of up to $400,000, adjustable based on the Consumer Price Index, based on the achievement of certain annual performance levels. Payment of the performance bonus is subordinated to the payment of operating expenses, debt service and required deposits, and minimum balances under the loan agreements, and deposit and disbursement agreements. Accordingly, the performance bonuses earned in 1995 and 1994 are included as a non-current liability in the consolidated balance sheet. This agreement expires on the date Whatcom receives its 24.5% cumulative return or the tenth anniversary of the Project completion date, subject to renewal terms.
F-48

SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Approximately $2,031,000 in 1995, $1,946,000 in 1994 and $1,260,000 in 1993 was earned under this agreement.
(c) THERMAL ENERGY AND KILN LEASE -- The Partnership has a 20-year thermal energy and kiln lease agreement with Socco. Under this agreement, Socco leases the premises and the kiln and purchases certain amounts of thermal energy delivered to dry lumber. Income recorded from Socco was approximately $19,000 in 1995, $61,000 in 1994 and $6,000 in 1993.
(d) CONSULTING SERVICES -- ENCO has an agreement with National Energy Systems Company (NESCO), an affiliate of SEI, to provide consulting services for $8,000 per month, adjustable based upon an inflation index. The agreement automatically renews for one-year periods unless written notice of termination is served by either party. Approximately $100,000 in 1995, $101,000 in 1994 and $96,000 in 1993 was paid under this agreement
(e) FUEL SUPPLY AND PURCHASE AGREEMENTS -- The Partnership has a fixed price natural gas sale and purchase agreement with ENCO. The agreement requires ENCO to deliver up to a maximum daily contract quantity of 12,000 MMBtu's of natural gas per day which may be increased to 24,000 MMBtu's in accordance with the agreement. The Partnership paid ENCO $2.26 per delivered MMBtu through October 1995 and pays $2.43 per delivered MMBtu through 1996. Prices under the agreement then escalate at an annual rate of 7.5% until October 31, 2000, and at 4% per annum thereafter. Partnership payments to ENCO under the agreement are eliminated in consolidation. The agreement expires on the twentieth anniversary of the date of commercial operation.
The Partnership has a gas supply agreement with Westcoast Gas Services, Inc. (WGSI) to provide the Partnership with quantities of firm gas. Commencing April 1, 1993, WGSI must provide the Partnership with quantities of gas ranging from 10,000 MMBtu's per day up to 12,900 MMBtu's per day at a firm price, as provided under the agreement. The agreement is expected to terminate on October 31, 1996.
The Partnership and ENCO have a gas management agreement with WGSI. WGSI is paid a gas management fee for each MMBtu of gas delivered to the Generation Facility. The gas management fee is adjusted annually based on the British Columbia Consumer Price Index. The gas management agreement expires October 31, 2008 unless terminated earlier as provided for in the agreement.
ENCO is committed to the utilization of pipeline capacity on the Westcoast Energy Inc. System. These firm capacity commitments are predominantly under one-year renewable contracts. Firm capacity has been accepted at an annual cost of approximately $2,569,000 in 1995, $2,776,000 in 1994 and $1,347,000 in 1993.
As collateral for the obligations of the Company under the gas supply and gas management agreements with WGSI, the Partnership secured an irrevocable standby letter of credit with Credit Suisse in favor of WGSI. As of December 31, 1995 and 1994, the letter of credit had a face amount of $2,500,000 and the Partnership had a cash deposit of $2,500,000 held in a restricted money market account as collateral for the letter of credit. As of December 31, 1995 and 1994, $2,500,000 held in a restricted money market account is included in the current portion of restricted cash and cash equivalents. In January 1996, the letter of credit was reduced in accordance with its terms to a face amount of $500,000.
(f) UTILITY SERVICES -- The Partnership entered into an agreement for utility services with the City of Sumas, Washington. The City of Sumas has agreed to provide a guaranteed annual supply of water at its wholesale rate charged to external association customers. Should the Partnership fail to purchase the daily average minimum of 550 gallons per minute from the City of Sumas during the first 10 years of commercial operation, except for uncontrollable forces or reasonable and necessary shutdowns, the Partnership shall make up the lost revenue to the City of Sumas in accordance with the agreement.
F-49

SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Partnership entered into an agreement for waste water disposal with the City of Bellingham, Washington. The City of Bellingham has agreed to accept up to 70,000 gallons of waste water daily at a rate of one cent per gallon. The agreement expires on December 31, 1998.
(g) LEASE COMMITMENTS -- In December 1990, the Partnership entered into a 23.5-year land lease which may be renewed for five consecutive five-year periods. Rental expense was approximately $48,400 in 1995 and 1994, and $45,300 in 1993.
In April 1992, ENCO signed an operating lease for office space which expires in March 1997. Monthly rental expense is approximately $1,700. Rental expense was approximately $17,700 in 1995, $17,000 in 1994 and $16,000 in 1993.
Future minimum land and office lease commitments as of December 31, 1995 are as follows:

                           YEAR ENDING
                          DECEMBER 31,                               AMOUNT
-----------------------------------------------------------------  ----------
1996.............................................................  $   66,800
1997.............................................................      51,000
1998.............................................................      49,300
1999.............................................................      49,300
2000.............................................................      52,500
Thereafter.......................................................     868,200
                                                                   ----------
                                                                   $1,137,100
                                                                   ==========	

(h) PROJECT MANAGEMENT SERVICES -- NESCO entered into a project management agreement with the Partnership for which it received $45,000 per month through June 1993. Approximately $264,000 was paid to NESCO in 1993, under this agreement.
(i) CONSTRUCTION MANAGEMENT SERVICES -- Calpine entered into a construction management agreement with the Partnership for which it received $40,000 per month through June 1993. Approximately $235,000 was paid to Calpine in 1993, under this agreement.
(j) PARTNER LOAN -- In March 1994, the sole shareholder of SEI borrowed $10,000,000 from Calpine. The loan bears interest at 16.25%, compounded quarterly, and is collateralized by a subordinated assignment in SEI's interest in the Partnership and a subordinated pledge of SEI's stock. The loan requires payments of interest and principal to be made from 50% of SEI's cash distributions from the Partnership, less amounts due to Whatcom under a previous note made in connection with Loan Conversion (Note 1). On March 15, 2004, all unpaid principal and interest on the loan is due.
NOTE 7 -- FAIR VALUES OF FINANCIAL INSTRUMENTS
The carrying amount of all cash and cash equivalents reported in the consolidated balance sheet is estimated by the Company to approximate their fair value.
The Company is not able to estimate the fair value of its long-term debt with a carrying amount of $119,000,003 at December 31, 1995. There is no ability to assess current market interest rates of similar borrowing arrangements for similar projects because the terms of each such financing arrangement is the result of substantial negotiations among several parties.
F-50

SUMAS COGENERATION COMPANY, L.P.
AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 8 -- CONTINGENCY
ENCO terminated protracted contract negotiations with two Canadian natural gas suppliers in January 1995. One of the suppliers notified ENCO it considered a draft contract to be effective although it had not been executed by ENCO. The supplier indicated it may pursue legal action if ENCO would not execute the contract. As of January 19, 1996, no legal action has been served on ENCO. Management believes if legal action is commenced, it has significant defenses and believes such action will not result in any material adverse impact to the Company's financial condition or results of operations.
F-51

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Partners of Calpine Geysers Company, L.P.:
We have audited the accompanying statements of operations and cash flows for the period from January 1, 1993 to April 18, 1993 of Calpine Geysers Company, L.P., a Delaware limited partnership. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these statements based on our audit.
We conducted our audit in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the results of operations and cash flows of Calpine Geysers Company, L.P. for the period from January 1, 1993 through April 18, 1993 in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
San Jose, California
March 18, 1994
F-52

CALPINE GEYSERS COMPANY, L.P.
STATEMENT OF OPERATIONS
FOR THE PERIOD FROM JANUARY 1, 1993 TO APRIL 18, 1993

Revenue from power contracts....................................................  $20,759,116
                                                                                  -----------
Costs and expenses:
  Production royalties..........................................................    3,150,076
  Operating expenses............................................................    4,893,878
  Depreciation and amortization.................................................    5,153,239
  General and administrative....................................................      787,005
                                                                                  -----------
          Total costs and expenses..............................................   13,984,198
                                                                                  -----------
          Income from operations................................................    6,774,918
Other (income) expense
  Interest expense..............................................................    4,794,952
  Other income..................................................................     (193,179)
                                                                                  -----------
          Net income............................................................  $ 2,173,145
                                                                                  ===========	

The accompanying notes are an integral part of these financial statements.
F-53

CALPINE GEYSERS COMPANY, L.P.
STATEMENT OF CASH FLOWS
FOR THE PERIOD FROM JANUARY 1, 1993 TO APRIL 18, 1993

Cash flows from operating activities:
  Net income...................................................................  $  2,173,145
  Adjustments to reconcile net income to net cash provided by operating
     activities:
     Depreciation and amortization.............................................     5,153,239
     Amortization of deferred costs............................................       146,277
     Changes in operating assets and liabilities:
       Accounts receivable.....................................................     2,157,353
       Supplies inventory......................................................        81,061
       Prepaid expenses........................................................       837,841
       Accounts payable and accrued liabilities................................     2,634,254
       Deferred revenue........................................................       395,100
       Payment on note payable.................................................      (543,778)
                                                                                 ------------
          Net cash provided by operating activities............................    13,034,492
                                                                                 ------------
Cash flows from investing activities:
  Acquisition of property, plant and equipment.................................    (3,401,378)
  Increase in restricted cash requirements.....................................       (12,862)
                                                                                 ------------
          Net cash used for investing activities...............................    (3,414,240)
                                                                                 ------------
Cash flows from financing activities:
  Repayment of debt............................................................    (2,200,000)
  Partner distributions........................................................    (7,416,018)
                                                                                 ------------
          Net cash used for financing activities...............................    (9,616,018)
                                                                                 ------------
Net increase in cash and cash equivalents......................................         4,234
Cash and cash equivalents at beginning of period...............................     2,700,135
                                                                                 ------------
Cash and cash equivalents at end of period.....................................  $  2,704,369
                                                                                 ============
Supplementary information:
  Cash paid during the period for interest.....................................  $  3,914,710
                                                                                 ============	

The accompanying notes are an integral part of these financial statements.
F-54

CALPINE GEYSERS COMPANY, L.P.
NOTES TO FINANCIAL STATEMENTS
FOR THE PERIOD FROM JANUARY 1, 1993 TO APRIL 18, 1993
1. BUSINESS AND FORMATION OF THE PARTNERSHIP
Business
Calpine Geysers Company, L.P. ("CGC"), a Delaware limited partnership, was formed on April 5, 1990. CGC is the owner of two operating geothermal power plants and their respective steam fields, and three geothermal steam fields located in The Geysers area of northern California. Electricity and steam generated by CGC is sold to two utilities under long-term power sales contracts (see Note 9).
Formation of the Partnership
CGC was formed by Sonoma Geothermal Partners, L.P. ("SGP"), wholly owned by Calpine Corporation ("Calpine"), and Freeport-McMoRan Resource Partners, Limited Partnership ("FMRP") for the purpose of acquiring from FMRP the assets constituting the geothermal business described above. On July 2, 1990, FMRP contributed an undivided 15.93 percent interest in the existing assets and geothermal business and $1,178,567 in cash for financing costs. SGP contributed $22,165,718 in cash, including financing and closing costs of $2,008,000.
Concurrent with the formation of CGC, an agreement was entered into between CGC and FMRP to purchase the remaining undivided 84.07 percent interest in the existing assets and geothermal business for $227.0 million in cash plus the assumption of the liabilities, not including existing project debt. The amount was funded by SGP's contribution and a new nonrecourse credit arrangement with a consortium of banks (see Note 5).
Under the CGC partnership agreement, profits are allocated first to SGP to the extent necessary to achieve a target return, as defined. Thereafter, profits are allocated 22.5 percent to SGP and 77.5 percent to FMRP.
Upon liquidation, equity is allocated first to SGP to the extent necessary to achieve a target return as defined; second, equity is allocated to achieve the target capital account ratios (22.5 percent to SGP and 77.5 percent to FMRP); and third, equity is allocated 22.5 percent to SGP and 77.5 percent to FMRP.
Cash distributions are allocated 99 percent to SGP and 1 percent to FMRP until the target return is reached. Distributions made during the period from January 1, 1993 to April 18, 1993 were $7,352,017 to SGP and $64,001 to FMRP.
Acquisition of FMRP Interest in CGC
On April 19, 1993, Calpine purchased all of FMRP's interest in CGC for $59.8 million, terminating the partnership with FMRP. The purchase price includes a $23.0 million cash payment by Calpine and a $36.8 million note payable to FMRP.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Cash and Cash Equivalents
CGC's cash, cash equivalents and restricted cash are primarily held by one major international financial institution. CGC considers all highly liquid instruments purchased with an original maturity of three months or less to be cash equivalents. The carrying amount of these instruments approximates fair value because of their short maturity.
F-55

CALPINE GEYSERS COMPANY, L.P.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Restricted Cash
CGC is required to maintain cash balances that are restricted by provisions of its debt agreements and by regulatory agencies. CGC's debt agreements specify restrictions based on debt service payments and drilling costs for the following year. Regulatory agencies require cash to be restricted to ensure that funds will be available to restore property to its original condition. Restricted cash is invested in accounts earning market rates. Therefore, their carrying value approximates fair value.
Supplies Inventory
Supplies are valued at the lower of cost or market. Cost for large replacement parts is determined using the specific identification method. For the remaining supplies, cost is determined using the weighted average cost method.
Property, Plant and Equipment
CGC uses the full cost method of accounting for costs incurred in connection with the exploration and development of geothermal properties. All such costs, including geological and geophysical expenses, costs of drilling productive, nonproductive and reinjection wells and overhead directly related to development activities, together with the costs of production equipment, the related facilities and the operating power plants, are capitalized.
Geothermal costs, including an estimate of future development costs to be incurred and the estimated costs to dismantle, are amortized by the units of production method based on the estimated total productive output over the estimated useful lives of the related steam fields. Depreciation of the buildings and roads is computed using the straight line method over the estimated remaining useful lives of the buildings and roads.
Proceeds from the sale of assets are applied against capitalized costs, with no gain or loss recognized.
Deferred Costs
Deferred costs consist of financing costs, a commitment fee and Partnership closing costs. These costs are amortized over the following periods:

Financing costs.................................................       15 years
Partnership closing costs.......................................   5 to 7 years	

Revenue Recognition
Revenues from sales of electricity are recognized as service is delivered. Revenues from sales of steam are calculated considering a future period when steam will be delivered without receiving corresponding revenue. This free steam is being recorded at an average rate over future steam production as deferred revenue.
A recent accounting principle requires companies to recognize revenue on power sales agreements entered into after May 1992 using the lower of the actual cash received or the average rate measured on a cumulative basis. CGC's power sales agreements were entered into prior to May 1992. Had CGC applied this principle, the revenues CGC recorded for the period from January 1, 1993 to April 18, 1993 would have been approximately $488,000 less.
Income Taxes
Income taxes are the responsibility of the individual partners; therefore, there is no provision for Federal and state income taxes in the financial statements.
F-56

CALPINE GEYSERS COMPANY, L.P.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
3. WORKING CAPITAL LOAN
CGC has a working capital agreement with a bank providing for advances not to exceed $5.0 million less any outstanding letters of credit. The aggregate unpaid principal of the working capital loan is payable in full at least once a year commencing in 1991, with the final payment of principal, interest and fees due June 30, 1995; interest accrues at the London Interbank Offered Rate (LIBOR) plus .625 percent over the term of the loan.
4. NOTE PAYABLE
During 1992, CGC entered into a note payable with a financing company for $543,778. The note bears interest at 3.79 percent annually and was repaid in two installments in January and April 1993.
5. LONG-TERM DEBT
CGC has a $200.0 million ($176.8 million outstanding at April 18, 1993) loan agreement with a bank, the components of which are as follows:
Senior term loans: $156.8 million outstanding at April 18, 1993 with principal and interest payable in quarterly installments at variable amounts beginning September 30, 1990 and the final payment of principal, interest and fees due June 30, 2002; interest on $136.8 million is fixed at 9.93 percent with the remainder accruing at LIBOR plus .75 percent to 1.25 percent over the term of the loan; collateralized by all of CGC's assets and the partners' interest.
Junior term loans: $20.0 million outstanding at April 18, 1993 with principal and interest payable in quarterly installments at variable amounts beginning September 30, 2002 and the final payment of principal, interest and fees due June 30, 2005; interest accrues at LIBOR plus 1.5 percent to 2.75 percent over the term of the loan; the loan is collateralized by all of CGC's assets and the partners' interest.
The annual principal maturities of the long-term debt outstanding at April 18, 1993 are as follows:

1993...........................................................  $  8,800,000
1994...........................................................    16,000,000
1995...........................................................    18,000,000
1996...........................................................    21,000,000
1997...........................................................    22,000,000
Thereafter.....................................................    91,000,000
                                                                 ------------
                                                                 $176,800,000
                                                                 ============	

The senior and junior term loan agreements contain a number of covenants. Two of these covenants require that CGC maintain restricted cash balances as defined in the agreements, and that CGC maintain certain insurance coverages. During the period from January 1, 1993 to April 18, 1993, CGC did not meet the insurance covenant and has obtained a waiver for this violation.
The carrying value of the $136.8 million portion of the senior term notes has an effective rate of 9.93 percent under CGC's interest rate swap agreements (see Note 6). Based on the borrowing rates currently available to CGC for bank loans with similar terms and maturities, the fair value of the debt as of April 18, 1993 is approximately $150.2 million.
The carrying value of the remaining $20.0 million of the senior and the $20.0 million junior term loans approximates the debt's fair market value as the rates are variable and are based on current LIBOR.
F-57

CALPINE GEYSERS COMPANY, L.P.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
6. INTEREST RATE SWAP AGREEMENTS:
CGC entered into two interest rate swap agreements to minimize the impact of changes in interest rates by effectively fixing its interest rate at 9.93 percent on a portion of its senior term note. The interest rate swap agreements mature through December 31, 2000. CGC is exposed to credit loss in the event of nonperformance by the other parties to the interest rate swap agreements.
7. COMMITMENTS AND CONTINGENCIES
Royalties and Leases
CGC is committed under several geothermal and right of way leases. The geothermal leases generally provide for royalties based on production revenue, with reductions for property taxes paid and the right of way leases are based on flat rates and are not material. Under the terms of certain geothermal land leases, royalties accrue at rates ranging from 7 percent to 12.5 percent of electricity, steam and effluent revenue, net of property taxes. Certain properties also have net profits and overriding royalty interests ranging from approximately 1.7 percent to 23.5 percent, which are in addition to the land lease royalties. CGC also has a working interest agreement with a third party providing for the sharing of approximately 30 percent of drilling and other well costs, various percentages of other operating costs and 30 percent of revenues on specified wells of Unit 13 and Unit 16.
Most lease agreements contain clauses providing for minimum lease payments to leaseholders if production temporarily ceases or if production falls below a specified level.
Expenses under these agreements for the period from January 1, 1993 to April 18, 1993 are as follows:

Production royalties.............................................  $3,150,076
Lease payments...................................................     119,081	

Litigation
CGC is a party to lawsuits and claims arising out of the normal course of business, principally related to royalty interests on geothermal property sites. Management believes that the outcome of these claims and lawsuits will not have a material adverse effect on CGC's financial position and results of operations.
8. RELATED PARTY TRANSACTIONS
The power plants and steam fields of CGC are operated by Calpine Operating Plant Services, Inc. ("COPS"), wholly owned by Calpine Corporation, under an Operating and Maintenance Agreement. Under the agreement, COPS is obligated to perform all operation and maintenance services in connection with the business, including operation, repair and maintenance of the power plants and steam fields, arranging for new well drilling, providing administrative and billing services, and performing technical analyses and contract administration.
For performance of these services, COPS is reimbursed for its direct costs plus a general and administrative recovery rate of 12 percent for direct labor costs, 10 percent for specific costs, and 5 percent for capital expenditures up to $5.0 million per year, then 2 percent for additional capital expenditures. In addition, the contract also includes an annual operating fee of $1.0 million, escalating in relation to the Consumer Price Index. During the period from January 1, 1993 to April 18, 1993, total charges under the Operating and Maintenance Agreement amounted to approximately $7.1 million, including approximately $3.7 million for capital expenditures.
F-58

CALPINE GEYSERS COMPANY, L.P.
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Calpine also charges CGC directly for expenses in connection with its duties as general partner, and for technical and administrative services. During the period from January 1, 1993 to April 18, 1993, charges amounted to approximately $185,000.
FMRP has a royalty interest in one of the properties in production. During the period from January 1, 1993 to April 18, 1993, production royalty expense related to FMRP amounted to approximately $397,000.
9. SIGNIFICANT CUSTOMERS AND SUMMARY OF OPERATIONS:
CGC's revenue is derived primarily from two sources -- Pacific Gas and Electric ("PG&E") and Sacramento Municipal Utility District ("SMUD"). Revenue for the period from January 1, 1993 to April 18, 1993 is as follows:

PG&E............................................................  $17,323,683
SMUD............................................................    3,830,533
                                                                  -----------
                                                                   21,154,216
Less revenues deferred..........................................     (395,100)
                                                                  -----------
          Total.................................................  $20,759,116
                                                                  ===========	

Operating Geothermal Power Plants
Electricity from CGC's two operating geothermal power plants, Bear Canyon and West Ford Flat, is sold to PG&E under the terms of twenty-year contracts which began in 1989.
Under the terms of the contracts, CGC is paid for energy delivered based upon a fixed price which escalates annually for the first ten years of the contract and upon PG&E's full short-run avoided operating costs for the second ten years.
CGC also receives capacity payments from PG&E. Under certain circumstances, if CGC is unable to deliver firm capacity, then CGC may owe PG&E certain minimum damages, as specified in the contracts.
Geothermal Steam Fields
Steam from CGC's three geothermal steam fields is sold to PG&E and SMUD under contracts. PG&E is obligated to operate the plants (Unit 13 and Unit 16) as close to full capacity and as continuously as possible. SMUD is obligated to make its best effort to continuously accept steam generated by the plant, except during outages.
Under the terms of the PG&E contract, the price paid for steam is adjusted annually based upon prices paid by PG&E for fossil fuels (oil and natural gas) and nuclear fuel. Under the terms of the SMUD contract, the price paid for steam is adjusted bi-annually based upon inflation and price indices reflecting the economy and the cost of fuel.
The contracts with both PG&E and SMUD also provide that CGC receive an additional amount per mwh of net output as compensation for the cost of disposing of liquid effluents, primarily steam condensate.
In the event the quantity of steam delivered at any of the plants is less than 50 percent of the units rated capacity during any given month, PG&E or SMUD is not required to pay for steam delivered during such month until the cost of the power plants has been completely amortized.
The contracts may be terminated upon written notice under conditions specified in the contract if further operation of the plants becomes uneconomical. In the event that the contract is terminated by CGC, and if requested by either PG&E or SMUD, CGC must assign to PG&E (Unit 13 and Unit 16) or SMUD (SMUDGEO #1) all rights, title and interest to the wells, lands and related facilities.
F-59

REPORT OF INDEPENDENT ACCOUNTANTS
To the Shareholder of LFC No. 38 Corp. and Portsmouth Leasing Corporation:
We have audited the accompanying combined balance sheets of LFC No. 38 Corp. and Portsmouth Leasing Corporation and Subsidiaries as of December 31, 1994 and 1993, and the related combined statements of operations, changes in shareholder's deficiency and cash flows for the years then ended. These financial statements are the responsibility of the Companies' management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the combined financial position of LFC No. 38 Corp. and Portsmouth Leasing Corporation and Subsidiaries as of December 31, 1994 and 1993, and the combined results of their operations and their cash flows for the years then ended in conformity with generally accepted accounting principles.
As discussed in Note 4 to the financial statements, the Companies changed their method of accounting for income taxes in 1993.
COOPERS & LYBRAND L.L.P.
2400 Eleven Penn Center
Philadelphia, Pennsylvania
February 3, 1995, except
as to the information presented
in Note 7 for which the date is
March 30, 1995
F-60

LFC NO. 38 CORP. AND PORTSMOUTH LEASING CORPORATION AND SUBSIDIARIES
COMBINED BALANCE SHEETS

                                                                           DECEMBER 31,
                                                                    ---------------------------
                                                                       1994            1993
                                                                    -----------     -----------
                                            ASSETS
Current assets
  Cash and equivalents............................................  $ 2,986,606     $ 3,911,692
  Accounts receivable.............................................    1,888,467       1,774,335
  Other current assets............................................       74,729         145,754
                                                                    -----------     -----------
          Total current assets....................................    4,949,802       5,831,781
Power production facility, less accumulated depreciation of
  $6,086,660 and $5,057,568, respectively.........................   24,228,646      25,239,115
Project development rights, less accumulated amortization of
  $1,093,026 and $915,778, respectively...........................    4,287,918       4,465,166
Deferred costs, less accumulated amortization of $1,335,381 and
  $1,215,708, respectively........................................      712,224         831,898
Land..............................................................      340,938         340,938
                                                                    -----------     -----------
          Total assets............................................  $34,519,528     $36,708,898
                                                                    ===========     ===========
                           LIABILITIES AND SHAREHOLDER'S DEFICIENCY
Current liabilities
  Accounts payable and accrued liabilities........................  $ 1,372,360     $ 1,606,528
  Accrued interest payable........................................      136,294         245,135
  Notes payable...................................................    1,819,071       1,633,676
  Due to affiliates...............................................      224,413         555,185
                                                                    -----------     -----------
          Total current liabilities...............................    3,552,138       4,040,524
Notes payable.....................................................   26,767,423      28,553,740
Liability for major maintenance...................................    1,850,728       1,266,518
Deferred income taxes.............................................    9,233,673       8,613,266
                                                                    -----------     -----------
          Total liabilities.......................................   41,403,962      42,474,048
                                                                    -----------     -----------
Shareholder's deficiency
  Common stock $1 par value, 2,000 shares authorized,
     2,000 shares issued..........................................        2,000           2,000
  Capital in excess of par value..................................        1,279           1,279
  Accumulated deficit.............................................     (565,743)     (1,668,429)
                                                                    -----------     -----------
                                                                       (562,464)     (1,665,150)
  Advances to affiliates..........................................   (6,321,970)     (4,100,000)
                                                                    -----------     -----------
          Total shareholder's deficiency..........................   (6,884,434)     (5,765,150)
                                                                    -----------     -----------
          Total liabilities and shareholder's deficiency..........  $34,519,528     $36,708,898
                                                                    ===========     ===========	

See Accompanying Notes to Combined Financial Statements
F-61

LFC NO. 38 CORP. AND PORTSMOUTH LEASING CORPORATION AND SUBSIDIARIES
COMBINED STATEMENT OF OPERATIONS

                                                                       YEAR ENDED DECEMBER 31,
                                                                      -------------------------
                                                                         1994          1993
                                                                      -----------   -----------
Revenues
  Power sales.......................................................  $17,431,700   $18,134,824
  Interest income...................................................      234,154        89,318
                                                                      -----------   -----------
                                                                       17,665,854    18,224,142
                                                                      -----------   -----------
Expenses
  Operating costs...................................................   12,702,761     9,271,110
  Depreciation and amortization.....................................    1,338,734     1,515,297
  Interest expense..................................................    1,738,152     1,740,675
                                                                      -----------   -----------
                                                                       15,779,647    12,527,082
                                                                      -----------   -----------
Income before income taxes..........................................    1,886,207     5,697,060
Income tax provision................................................      783,521     2,307,233
                                                                      -----------   -----------
Income before cumulative effect of change in accounting principle...    1,102,686     3,389,827
Cumulative effect of change in accounting for income taxes..........           --    (5,108,294)
                                                                      -----------   -----------
          Net income (loss).........................................  $ 1,102,686   $(1,718,467)
                                                                      ===========   ===========	

See Accompanying Notes to Combined Financial Statements
F-62

LFC NO. 38 CORP. AND PORTSMOUTH LEASING CORPORATION AND SUBSIDIARIES
COMBINED STATEMENTS OF CHANGES IN SHAREHOLDER'S DEFICIENCY
 (FOR THE YEARS ENDED DECEMBER 31, 1994 AND 1993)

                                                                 RETAINED
                                                  CAPITAL IN     EARNINGS                   SHAREHOLDER'S
                                         COMMON   EXCESS OF    (ACCUMULATED   ADVANCES TO      EQUITY
                                         STOCK    PAR VALUE      DEFICIT)     AFFILIATES    (DEFICIENCY)
                                         ------   ----------   ------------   -----------   -------------
Balance, December 31, 1992.............  $2,000     $1,279     $     50,038            --    $     53,317
Advance to affiliates..................     --          --               --   $(4,100,000)     (4,100,000)
Net loss...............................     --          --       (1,718,467)           --      (1,718,467)
                                         ------     ------        ---------    ----------      ----------
Balance, December 31, 1993.............  2,000       1,279       (1,668,429)   (4,100,000)     (5,765,150)
Advance to affiliates..................     --          --               --    (2,221,970)     (2,221,970)
Net income.............................     --          --        1,102,686            --       1,102,686
                                         ------     ------        ---------    ----------      ----------
Balance, December 31, 1994.............  $2,000     $1,279     $   (565,743)  $(6,321,970)   $ (6,884,434)
                                         ======     ======        =========    ==========      ==========	

See Accompanying Notes to Combined Financial Statements
F-63

LFC NO. 38 CORP. AND PORTSMOUTH LEASING CORPORATION AND SUBSIDIARIES
COMBINED STATEMENTS OF CASH FLOWS

                                                                      YEAR ENDED DECEMBER 31,
                                                                    ---------------------------
                                                                       1994            1993
                                                                    -----------     -----------
Cash flows from operating activities
  Net income (loss)...............................................  $ 1,102,686     $(1,718,467)
  Adjustments to reconcile net income (loss) to net cash provided
     by operating activities
     Depreciation and amortization................................    1,338,734       1,515,297
     Provision for major maintenance..............................      584,210         710,872
     Payments for major maintenance...............................           --        (814,244)
     Cumulative effect of change in accounting for income taxes...           --       5,108,294
     Deferred income taxes........................................      620,408       2,306,433
     Changes in operating assets and liabilities
       Accounts receivable........................................     (114,132)        476,265
       Due to affiliates..........................................     (330,771)       (161,838)
       Accounts payable and accrued liabilities...................     (234,169)     (1,862,005)
       Other current assets.......................................       71,025         (20,955)
       Accrued interest payable...................................     (108,842)        (23,990)
                                                                    -----------     -----------
  Net cash provided by operating activities.......................    2,929,149       5,515,662
                                                                    -----------     -----------
Cash flows used in investing activities
  Investment in power production facility.........................      (31,343)        (10,433)
                                                                    -----------     -----------
Cash flows used in financing activities
  Repayment of financing..........................................   (1,600,922)     (1,416,935)
  Advances to affiliates..........................................   (2,221,970)     (4,100,000)
                                                                    -----------     -----------
  Net cash used in financing activities...........................   (3,822,892)     (5,516,935)
                                                                    -----------     -----------
Net decrease in cash and equivalents..............................     (925,086)        (11,706)
Cash and equivalents -- beginning of period.......................    3,911,692       3,923,398
                                                                    -----------     -----------
Cash and equivalents -- end of period.............................  $ 2,986,606     $ 3,911,692
                                                                    ===========     ===========	

See Accompanying Notes to Combined Financial Statements
F-64

LFC NO. 38 CORP. AND PORTSMOUTH LEASING CORPORATION AND SUBSIDIARIES
NOTES TO COMBINED FINANCIAL STATEMENTS
NOTE 1 -- THE PARTNERSHIP AND THE PROJECT
LFC No. 38 Corp. (the "Limited Partner"), a Delaware corporation, is the sole Limited Partner and Greenleaf Unit One Associates, Inc. (the "General Partner"), a California corporation, is the sole General Partner (collectively the "Partners") of Greenleaf Unit One Associates, L.P. (the "Partnership"), a California Limited Partnership. Portsmouth Leasing Corporation ("Portsmouth"), a Delaware corporation, is the sole owner of the General Partner. Portsmouth and the Partners are wholly owned subsidiaries of Radnor Energy Partners, L.P. ("L.P."). L.P. is, in turn, a majority-owned subsidiary of LFC Financial Corp ("Financial"). The combined financial statements include the accounts of the Partners, the Partnership, and Portsmouth (collectively the "Company") after elimination of all material intercompany balances and transactions.
The Partnership owns and operates a 49.5 megawatt natural gas fired cogeneration facility located in Yuba City, California (the "Project"). The facility, which was completed in March 1989, produces electrical power which it sells to Pacific Gas and Electric Company ("PG&E") pursuant to a power purchase agreement that provides for electricity and capacity payments over a thirty-year period. The exhaust gas generated by the Project is used to dry wood chips. The wood drying facility is operated by Wood Fuel Processing, Inc. ("WFP") pursuant to a processing facilities agreement. The agreement provides that WFP will pay certain royalties to the Partnership in the future based on the profitability of the wood drying operation. Operations and maintenance of the Project is performed by Stockmar Energy Inc., which does business as LFC Power Systems Corporation ("Power Systems"), an affiliate. Power Systems is a wholly owned subsidiary of LFC Energy Corporation ("Energy"), which, in turn, is a majority-owned subsidiary of Financial.
NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Power Production Facility -- The power production facility, which was constructed by Power Systems, includes the cogeneration plant (including the wood drying facility) and the related equipment and is stated at cost. Depreciation is recorded utilizing the straight-line method over the estimated useful life of the Project of thirty years. Upon disposition, the cost and related accumulated depreciation of equipment removed from the accounts and the resulting gain (loss) is included in gains (losses) on equipment sales for the period.
Project Development Rights -- The Project development rights include all of the essential contracts, agreements, permits, licenses and other agreements which were required to construct and operate the Project, as well as the preliminary design of the Project, the power purchase agreement, the FERC certification and other contracts and agreements. These Project development rights are being amortized by the Partnership over a thirty-year period.
Deferred Costs -- Deferred costs include lender, legal, and other professional fees incurred in connection with the acquisition and construction of the Project and pre-operating expenses which were capitalized. Capitalized fees are amortized over their estimated useful lives and pre-operating expenses are amortized over sixty months.
Major Maintenance -- Major maintenance costs are accrued ratably over the scheduled maintenance period and are included in operating costs. Costs anticipated to be incurred within the next twelve months are classified as a current liability.
Income Taxes -- Effective January 1, 1993, the Company adopted Statement of Financial Accounting Standards No. 109 -- "Accounting For Income Taxes" ("SFAS109"). SFAS109 requires the recognition of deferred income tax liabilities and assets for the future tax consequences of transactions that have been recognized for financial reporting or income tax purposes and includes a requirement for adjustment of deferred tax balances for tax rate changes. The Company joins with L.P. and affiliated companies in the filing of a consolidated U.S. federal income tax return. The Company's policy is to provide for federal and state
F-65

LFC NO. 38 CORP. AND PORTSMOUTH LEASING CORPORATION AND SUBSIDIARIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
income taxes on a separate return basis. In addition, the Company has a tax sharing arrangement with L.P. that provides to the extent that net operating loss or investment tax credit carryforwards are not utilized by the Company on a separate return basis, but are utilized in the consolidated tax return of L.P., the Company will receive a portion of these tax benefits. These payments will be classified as capital in excess of par value.
Statements of Cash Flows -- The Company considers all highly liquid investments with a maturity of three months or less to be cash equivalents for purposes of the statement of cash flows. Net cash provided by operating activities includes cash payments for interest of $1,846,993 and $1,764,666 in 1994 and 1993, respectively.
NOTE 3 -- NOTES PAYABLE
Notes payable at December 31, 1994 and 1993 consist of the following:

                                                               1994            1993
                                                            -----------     -----------
Note payable -- Bank......................................  $25,996,000     $27,507,000
Note payable -- Individuals...............................    2,590,494       2,680,416
                                                            -----------     -----------
          Total...........................................   28,586,494      30,187,416
Less current portion......................................    1,819,071       1,633,676
                                                            -----------     -----------
Noncurrent portion........................................  $26,767,423     $28,553,740
                                                            ===========     ===========	

The Partnership's note payable is payable pursuant to a credit agreement with the New York branch of Credit Suisse ("Credit Suisse") and is collateralized by substantially all of the Partnership's assets. The credit agreement contains certain restrictive covenants including the maintenance of certain debt service coverage ratios, working capital requirements, and limitations on distributions. In addition, all cash and equivalents are maintained in accounts at Credit Suisse. The loan bears interest at variable rates or fixed rates at the option of the Partnership. The effective interest rate on the loan was 8.05% at December 31, 1994. The loan is being repaid over ten years, commencing in 1990, in level quarterly debt service payments on a fourteen-year amortization schedule with a balloon payment at the end of the tenth year.
The note payable-individuals is payable pursuant to a sale/purchase agreement with the former owners of the General Partner. The loan bears interest at a fixed rate of 8.25%. The loan is scheduled to be repaid in twenty (20) annual installments plus interest, with each payment being based upon 1.59% of power sales. If the obligation is repaid prior to maturity, the Company must continue the payments as defined until the payment period ends, 2010.
The required principal payments by year are as follows:

1995.......................................................  $ 1,819,071
1996.......................................................    2,016,092
1997.......................................................    2,231,533
1998.......................................................    2,529,127
1999.......................................................    2,794,776
2000.......................................................   16,092,618
Thereafter.................................................    1,103,277
                                                             -----------
          Total............................................  $28,586,494
                                                             ===========	

F-66

LFC NO. 38 CORP. AND PORTSMOUTH LEASING CORPORATION AND SUBSIDIARIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
NOTE 4 -- INCOME TAXES
Effective January 1, 1993, the Company adopted SFAS109, which requires the liability method of accounting for income taxes. The cumulative effect of the change in method of accounting for income taxes of $5,108,294 was reported in the 1993 statement of operations and as an increase in the net deferred tax liability at January 1, 1993.
The income tax provision is comprised of the following:

                                                                 1994          1993
                                                               --------     ----------
Current
  State......................................................  $ 26,944     $      800
  Federal....................................................   136,169             --
Deferred
  State......................................................   175,417        529,827
  Federal....................................................   444,991      1,776,606
                                                               --------     ----------
Total                                                          $783,521     $2,307,233
                                                               ========     ==========	

The provision for income taxes as a percentage of income before income tax can be reconciled to the federal statutory rate as follows:

                                                                         1994     1993
                                                                         ----     ----
Federal statutory tax rate.............................................   34%      34%
State tax, net of federal benefit......................................    6%       6%
Other..................................................................    2%      --
                                                                                  -- -
                                                                         ---
Provision for income taxes.............................................   42%      40%
                                                                         ===      ===	

The net deferred tax liability (determined in accordance with SFAS109) consists of:

                                                                   DECEMBER 31,
                                                            ---------------------------
                                                               1994            1993
                                                            -----------     -----------
Deferred tax liabilities:
  Accumulated depreciation................................  $10,872,804     $11,353,409
                                                            -----------     -----------
Deferred tax assets:
  Liability for major maintenance.........................      742,845         508,355
  Investment tax credit carryforward......................      821,862       1,254,862
  Net operating loss carryforward.........................       74,424         976,926
                                                            -----------     -----------
                                                              1,639,131       2,740,143
                                                            -----------     -----------
Net deferred tax liability................................  $ 9,233,673     $ 8,613,266
                                                            ===========     ===========	

As of December 31, 1994, the Company had, on a separate company basis, a state net operating loss carryforward of $800,260 which expires in 1996 through 1999 and investment tax credit carryforwards of $821,862 which expires in 2003.
NOTE 5 -- RELATED PARTIES AND OPERATING COSTS
The Partnership incurred operating costs through Power Systems of $1,976,599 and $1,910,189 in 1994 and 1993, respectively. The Partnership's 1994 and 1993 operating costs include $3,264,328 and $2,680,216, respectively, for the purchase of natural gas from affiliates. Affiliates also provided gathering, transportation and fuel management services at a cost of $2,328,028 and $725,000 to the Partnership in 1994 and 1993,
F-67

LFC NO. 38 CORP. AND PORTSMOUTH LEASING CORPORATION AND SUBSIDIARIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
respectively. The Partnership incurred $1,307,649 and $104,114 in 1994 and 1993, respectively, for management services provided by L.P.
NOTE 6 -- COMMON STOCK
The combined common stock of the Company as of December 31, 1994 and 1993 consists of the following:

                                                                                   CAPITAL
                                                          SHARES                     IN
                                                        AUTHORIZED     $1 PAR     EXCESS OF
                                                        AND ISSUED     VALUE      PAR VALUE
                                                        ----------     ------     ---------
LFC No. 38 Corp.......................................     1,000       $1,000           --
Portsmouth Leasing Corporation........................     1,000        1,000      $ 1,279
                                                           -----       ------       ------
          Total.......................................     2,000       $2,000      $ 1,279
                                                           =====       ======       ======	

NOTE 7 -- SUBSEQUENT EVENTS
On March 30, 1995, Financial entered into a stock purchase agreement to sell the stock of the Company to Calpine Corporation. The transaction is scheduled to close by April 28, 1995. No effect of the proposed sale has been recognized in the accompanying financial statements.
F-68

REPORT OF INDEPENDENT ACCOUNTANTS
To the Shareholder of LFC No. 60 Corp.:
We have audited the accompanying consolidated balance sheets of LFC No. 60 Corp. and Subsidiary as of December 31, 1994 and 1993, and the related consolidated statements of operations, changes in shareholder's deficiency and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of LFC No. 60 Corp. and Subsidiary as of December 31, 1994 and 1993, and the consolidated results of their operations and their cash flows for the years then ended in conformity with generally accepted accounting principles.
As discussed in Note 4 to the financial statements, the Company changed its method of accounting for income taxes in 1993.
COOPERS & LYBRAND L.L.P.
2400 Eleven Penn Center
Philadelphia, Pennsylvania
February 3, 1995, except
as to the information presented
in Note 6 for which the date is
March 30, 1995
F-69

LFC NO. 60 CORP. AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS

                                                                           DECEMBER 31,
                                                                    ---------------------------
                                                                       1994            1993
                                                                    -----------     -----------
ASSETS
Current assets
  Cash and equivalents............................................  $ 2,088,588     $ 2,491,825
  Accounts receivable, net of allowance for doubtful accounts of
     $200,000 in 1993.............................................    2,076,594       1,967,998
  Due from affiliates.............................................      776,253              --
  Prepaid assets..................................................      513,954         266,690
                                                                    -----------     -----------
          Total current assets....................................    5,455,389       4,726,513
Power production facility, less accumulated depreciation of
  $5,430,948 and $4,339,447, respectively.........................   26,636,147      27,711,561
Project development rights, less accumulated amortization of
  $330,417 and $265,417, respectively.............................    1,619,583       1,684,583
Deferred costs, less accumulated amortization of $1,410,676 and
  $1,148,992, respectively........................................      580,706         842,390
                                                                    -----------     -----------
          Total assets............................................  $34,291,825     $34,965,047
                                                                    ===========     ===========
LIABILITIES AND SHAREHOLDER'S DEFICIENCY
Current liabilities
  Accounts payable and accrued liabilities........................  $ 1,785,800     $   882,746
  Due to affiliates...............................................           --         634,451
  Accrued interest payable........................................       13,972         131,200
  Note payable....................................................      600,000         600,000
  Liability for major maintenance.................................           --         969,996
                                                                    -----------     -----------
          Total current liabilities...............................    2,399,772       3,218,393
Note payable......................................................   31,600,000      32,200,000
Liability for major maintenance...................................    1,737,908       1,273,328
Deferred income taxes.............................................    6,368,319       5,764,303
                                                                    -----------     -----------
          Total liabilities.......................................   42,105,999      42,456,024
                                                                    -----------     -----------
Shareholder's deficiency
  Common stock $1 par value, authorized, issued and outstanding --
     1,000 shares.................................................        1,000           1,000
  Capital in excess of par value..................................    1,199,000       1,199,000
  Deficit.........................................................     (395,931)     (1,290,977)
                                                                    -----------     -----------
                                                                        804,069         (90,977)
  Advances to affiliates..........................................   (8,618,243)     (7,400,000)
                                                                    -----------     -----------
          Total shareholder's deficiency..........................   (7,814,174)     (7,490,977)
                                                                    -----------     -----------
          Total liabilities and shareholder's deficiency..........  $34,291,825     $34,965,047
                                                                    ===========     ===========	

See Accompanying Notes to Consolidated Financial Statements
F-70

LFC NO. 60 CORP. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF OPERATIONS

                                                                      YEAR ENDED DECEMBER 31,
                                                                    ---------------------------
                                                                       1994            1993
                                                                    -----------     -----------
Revenues
  Power sales.....................................................  $18,495,832     $19,223,155
  Steam sales.....................................................       61,780          62,496
  Interest income.................................................      155,715          68,247
                                                                    -----------     -----------
                                                                     18,713,327      19,353,898
                                                                    -----------     -----------
Expenses
  Operating costs.................................................   13,961,525      12,620,397
  Depreciation and amortization...................................    1,418,185       1,436,668
  Interest expense................................................    1,773,839       1,702,354
                                                                    -----------     -----------
                                                                     17,153,549      15,759,419
                                                                    -----------     -----------
Income before income taxes........................................    1,559,778       3,594,479
Income tax provision..............................................     (664,732)     (1,616,815)
                                                                    -----------     -----------
Income before cumulative effect of change in accounting
  principle.......................................................      895,046       1,977,664
Cumulative effect of change in accounting for income taxes........           --      (2,773,609)
                                                                    -----------     -----------
Net income (loss).................................................  $   895,046     $  (795,945)
                                                                    ===========     ===========	

See Accompanying Notes to Consolidated Financial Statements
F-71

LFC NO. 60 CORP. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S DEFICIENCY
 (FOR THE YEARS ENDED DECEMBER 31, 1994 AND 1993)

                                          CAPITAL IN
                               COMMON     EXCESS OF                      ADVANCES TO
                               STOCK      PAR VALUE        DEFICIT       AFFILIATES         TOTAL
                               ------     ----------     -----------     -----------     -----------
Balance December 31, 1992....  $1,000     $1,199,000     $  (495,032)    $(3,600,000)    $(2,895,032)
Net loss.....................     --              --        (795,945)             --        (795,945)
Advance to affiliates........     --              --              --      (3,800,000)     (3,800,000)
                               ------     ----------     -----------     -----------     -----------
Balance December 31, 1993....  1,000       1,199,000      (1,290,977)     (7,400,000)     (7,490,977)
Net income...................     --              --         895,046              --         895,046
Advance to affiliates........     --              --              --      (1,218,243)     (1,218,243)
                               ------     ----------     -----------     -----------     -----------
Balance, December 31, 1994...  $1,000     $1,199,000     $  (395,931)    $(8,618,243)    $(7,814,174)
                               ======      =========      ==========      ==========      ==========	

See Accompanying Notes to Consolidated Financial Statements
F-72

LFC NO. 60 CORP. AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS

                                                                           DECEMBER 31,
                                                                    ---------------------------
                                                                       1994            1993
                                                                    -----------     -----------
Cash flows from operating expenses
  Net income (loss)...............................................  $   895,046     $  (795,945)
  Adjustments to reconcile net income (loss) to net cash provided
     by operating activities
     Depreciation and amortization................................    1,418,185       1,436,668
     Provision for major maintenance..............................      331,134         818,329
     Payments for major maintenance...............................     (836,550)             --
     Provision for doubtful accounts..............................           --         200,000
     Cumulative effect of change in accounting principle..........           --       2,773,609
     Deferred income tax provision................................      604,016       1,364,083
     Changes in operating assets and liabilities
       Accounts receivable........................................     (108,595)         41,995
       Due from affiliates........................................   (1,410,704)       (112,443)
       Accounts payable and accrued liabilities...................      903,054      (1,184,769)
       Prepaid assets.............................................     (247,264)        (19,510)
       Accrued interest payable...................................     (117,228)        (20,866)
                                                                    -----------     -----------
  Net cash provided by operating activities.......................    1,431,094       4,501,151
                                                                    -----------     -----------
Cash flows used in investing activities
  Investment in power production facility.........................      (16,088)        (21,968)
                                                                    -----------     -----------
Cash flows used in financing activities
  Repayment of financing..........................................     (600,000)       (600,000)
  Advances to affiliates..........................................   (1,218,243)     (3,800,000)
                                                                    -----------     -----------
  Net cash used in financing activities...........................   (1,818,243)     (4,400,000)
                                                                    -----------     -----------
Net increase (decrease) in cash and equivalents...................     (403,237)         79,183
Cash and equivalents -- beginning of period.......................    2,491,825       2,412,642
                                                                    -----------     -----------
Cash and equivalents -- end of period.............................  $ 2,088,588     $ 2,491,825
                                                                    ===========     ===========	

See Accompanying Notes to Consolidated Financial Statements
F-73

LFC NO. 60 CORP. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 -- THE COMPANY AND THE PROJECT
LFC No. 60 Corp., a Delaware corporation, is a wholly-owned subsidiary of Radnor Energy Partners, L.P. ("L.P."). L.P. is, in turn, a majority-owned subsidiary of LFC Financial Corp ("Financial"). LFC No. 60 Corp. owns 100% of the Greenleaf Unit Two Associates, Inc. ("GUTA"). The consolidated financial statements include the accounts of LFC No. 60 Corp. and GUTA (the "Company") after elimination of all material intercompany balances and transactions.
GUTA is a California corporation which owns and operates a 49.5 megawatt natural gas fired cogeneration plant located in Yuba City, California (the "Project"). The facility, which was completed in December 1989, produces electrical power which it sells to Pacific Gas and Electric Company ("PG&E") pursuant to a power purchase agreement that provides for electricity and capacity payments over a thirty year period. The steam produced by the Project is sold to Sunsweet Growers, Inc. under a long-term steam purchase agreement. Operations and maintenance of the Project is performed by Stockmar Energy Inc., which does business as LFC Power Systems Corporation ("Power Systems"), an affiliate. Power Systems is a wholly-owned subsidiary of LFC Energy Corporation ("Energy"), which, in turn, is a majority-owned subsidiary of Financial.
NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Power Production Facility -- The power production facility, which was constructed by Power Systems, includes the cogeneration plant and the related equipment and is stated at cost. Depreciation is recorded utilizing the straight-line method over the estimated useful life of the Project of thirty years. Upon disposition, the cost and related accumulated depreciation of equipment is removed from the accounts and the resulting gain (loss) is included in gains (losses) on equipment sales for the period.
Project Development Rights -- The Project development rights include all of the essential contracts, agreements, permits, licenses and other agreements which were required to construct and operate the Project as well as the preliminary design of the Project, the power purchase agreement, the FERC certification and other contracts and agreements. These Project development rights are being amortized by the Company over a thirty-year period.
Deferred Costs -- Deferred costs include lender, legal, and other professional fees incurred in connection with the acquisition and construction of the Project and pre-operating expenses which were capitalized. Capitalized fees are amortized over their estimated useful lives and pre-operating expenses are amortized over sixty months.
Major Maintenance -- Major maintenance costs are accrued ratably over the scheduled maintenance period and are included in operating costs. Costs anticipated to be incurred within the next twelve months are classified as a current liability.
Income Taxes -- Effective January 1, 1993, the Company adopted Statement of Financial Accounting Standards No. 109 -- "Accounting For Income Taxes" ("SFAS 109"). SFAS109 requires the recognition of deferred income tax liabilities and assets for the future tax consequences of transactions that have been recognized for financial reporting or income tax purposes and includes a requirement for adjustment of deferred tax balances for tax rate changes. The Company joins with L.P. and affiliated companies in the filing of a consolidated U.S. federal income tax return. The Company's policy is to provide for federal and state income taxes on a separate return basis. In addition, the Company has a tax sharing arrangement with L.P. that provides to the extent that net operating loss or investment tax credit carryforwards are not utilized by the Company on a separate return basis, but are utilized in the consolidated tax return of L.P., the Company will receive a portion of these tax benefits. These payments will be classified as capital in excess of par value.
F-74

LFC NO. 60 CORP. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Statements of Cash Flows -- The Company considers all highly liquid investments purchased with a maturity of three months or less to be cash equivalents for purposes of the statement of cash flows. Net cash provided by operating activities includes cash payments for interest of $1,891,067 and $1,723,220 in 1994 and 1993, respectively.
NOTE 3 -- NOTE PAYABLE
The Company's note payable is payable pursuant to a credit agreement with the New York branch of Credit Suisse ("Credit Suisse") and is collateralized by substantially all of the Company's assets. The credit agreement contains certain restrictive covenants including the maintenance of certain debt service coverage ratios, working capital requirements, and limitations on distributions. In addition, all cash and equivalents are maintained in accounts at Credit Suisse. The note bears interest at variable or fixed rates at the option of the Company. The effective interest rate on the note was 7.81% at December 31, 1994. The note is being repaid in quarterly payments through 2005.
The required principal payments by year are as follows:

1995.......................................................  $   600,000
1996.......................................................      600,000
1997.......................................................      600,000
1998.......................................................    2,000,000
1999.......................................................    2,500,000
Thereafter.................................................   25,900,000
                                                             -----------
     Total.................................................  $32,200,000
                                                             ===========	

NOTE 4 -- INCOME TAXES
Effective January 1, 1993, the Company adopted SFAS 109, which requires the liability method of accounting for income taxes. The cumulative effect of the change in method of accounting for income taxes of $2,773,609 was reported in the 1993 statement of operations and as an increase in the net deferred tax liability at January 1, 1993.
The income tax provision is comprised of the following:

                                                                 1994          1993
                                                               --------     ----------
Deferred
  Federal....................................................  $490,009     $1,293,236
  State......................................................   114,007         70,847
Current -- State.............................................    60,716        252,732
                                                               --------     ----------
          Total..............................................  $664,732     $1,616,815
                                                               ========     ==========	

The provision for income taxes as a percentage of income before income taxes can be reconciled to the federal statutory rate as follows:

                                                                         1994     1993
                                                                         ----     ----
Federal statutory tax rate.............................................   34%      34%
State Tax..............................................................    8%       6%
Other..................................................................    1%       5%
                                                                          --       --
  Provision for income taxes...........................................   43%      45%
                                                                          ==       ==	

F-75

LFC NO. 60 CORP. AND SUBSIDIARY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The net deferred tax liability (determined in accordance with SFAS109) consists of:

                                                                    DECEMBER 31,
                                                              -------------------------
                                                                 1994           1993
                                                              ----------     ----------
Deferred tax liabilities:
  Accumulated depreciation..................................  $9,123,465     $8,509,818
                                                              ----------     ----------
Deferred tax assets:
  Liability for major maintenance...........................     713,324        922,858
  Investment tax credit carryforward........................   1,333,448      1,333,448
  Net operating loss carryforward...........................     708,374        418,977
  Other.....................................................          --         70,232
                                                              ----------     ----------
                                                               2,755,146      2,745,515
                                                              ----------     ----------
Net deferred tax liability..................................  $6,368,319     $5,764,303
                                                              ==========     ==========	

As of December 31, 1994, the Company had a tax net operating loss carry forward determined on a separate company basis of $2,023,928 which expires in 2007 through 2009. As of December 31, 1994, the Company had ITC carryforwards determined on a separate company basis of $1,333,448 which expire in 2004.
NOTE 5 -- RELATED PARTIES AND OPERATING COSTS
The Company incurred operating costs of $1,610,780 and $2,330,001 through Power Systems in 1994 and 1993, respectively. The Company's 1994 and 1993 operating costs include $1,088,550 and $1,421,558, respectively, for the purchase of natural gas from affiliates. Affiliates provided gathering, transportation and fuel management services at a cost of $2,181,758 and $400,000 in 1994 and 1993, respectively. The Company incurred $1,307,465 and $104,106 in 1994 and 1993, respectively, for management services provided by L.P.
NOTE 6 -- SUBSEQUENT EVENT
On March 30, 1995, Financial entered into a stock purchase agreement to sell the stock of the Company and certain affiliates to Calpine Corporation. The transaction is scheduled to close by April 28, 1995. No effect of the proposed sale has been recognized in the accompanying financial statements.
F-76

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the General Partner of
BAF Energy, A California Limited Partnership:
We have audited the accompanying balance sheets of BAF Energy, A California Limited Partnership, as of October 31, 1995 and 1994, and the related statements of income, partners' equity and cash flows for each of the three years ended October 31, 1995, 1994 and 1993. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of BAF Energy, A California Limited Partnership, as of October 31, 1995 and 1994, and the results of its operations and its cash flows for each of the three years ended October 31, 1995, 1994 and 1993 in conformity with generally accepted accounting principles.
As explained in Note 1 to the financial statements, effective November 1, 1994, the Company changed its method of accounting for investments.
As discussed in Note 8 to the financial statements, subsequent to October 31, 1995, the Partnership signed a letter agreement with a third party to lease substantially all of its property, plant and equipment and assign all related contracts to a third party.
ARTHUR ANDERSEN LLP
San Francisco, California
December 6, 1995
F-77

BAF ENERGY,
A CALIFORNIA LIMITED PARTNERSHIP
BALANCE SHEETS
OCTOBER 31, 1995 AND 1994

                                                                      1995             1994
                                                                  ------------     ------------
ASSETS
Current assets:
  Cash and cash equivalents.....................................  $  3,757,921     $  5,363,057
  Available for sale securities.................................     1,919,184               --
  Restricted available-for-sale securities......................     7,241,305       12,332,244
  Accounts receivable -- trade..................................    10,916,919        5,277,413
  Supplies inventory............................................     2,153,129        2,060,935
  Prepaid insurance.............................................       288,383          251,375
                                                                  ------------     ------------
          Total current assets..................................    26,276,841       25,285,024
                                                                  ------------     ------------
Property, plant and equipment...................................   100,258,434      100,210,960
  Accumulated depreciation and amortization.....................   (24,387,912)     (20,854,389)
                                                                  ------------     ------------
                                                                    75,870,522       79,356,571
                                                                  ------------     ------------
          Total assets..........................................  $102,147,363     $104,641,595
                                                                  ============     ============
LIABILITIES AND PARTNERS' EQUITY
Current liabilities
  Accounts payable..............................................  $  1,598,177     $  2,824,110
  Interest payable..............................................     1,309,566        1,396,495
  Payable to affiliate..........................................       166,569          615,881
  Current portion of long-term liabilities......................     5,444,386        5,283,785
                                                                  ------------     ------------
          Total current liabilities.............................     8,518,698       10,120,271
                                                                  ------------     ------------
Long-term liabilities...........................................    66,804,704       71,157,714
                                                                  ------------     ------------
Commitments and contingencies (Note 6)
Partners' equity:
  Contributed equity............................................     9,901,600        9,901,600
  Undistributed earnings........................................    16,922,361       13,462,010
                                                                  ------------     ------------
          Total partners' equity................................    26,823,961       23,363,610
                                                                  ------------     ------------
          Total liabilities and partners' equity................  $102,147,363     $104,641,595
                                                                  ============     ============	

The accompanying notes are an integral part of these statements.
F-78

BAF ENERGY,
A CALIFORNIA LIMITED PARTNERSHIP
STATEMENTS OF INCOME
FOR THE YEARS ENDED OCTOBER 31, 1995, 1994 AND 1993

                                                         1995            1994            1993
                                                      -----------     -----------     -----------
Operating Revenues..................................  $43,835,619     $47,955,622     $49,738,504
Operating Expenses:
  Fuel..............................................    9,193,490      14,079,684      16,449,118
  Depreciation and amortization.....................    3,578,572       3,575,442       3,576,710
  Labor, supplies and other.........................    6,614,543       6,959,891       6,343,755
                                                      -----------     -----------     -----------
          Total operating expenses..................   19,386,605      24,615,017      26,369,583
                                                      -----------     -----------     -----------
          Operating income..........................   24,449,014      23,340,605      23,368,921
                                                      -----------     -----------     -----------
Other Income and Expense:
  Interest income and other.........................      955,299         477,666         448,961
  General and administrative........................     (773,610)       (784,401)       (653,373)
  Interest expense..................................   (8,165,273)     (8,654,453)     (9,091,695)
                                                      -----------     -----------     -----------
          Total other income and expense............   (7,983,584)     (8,961,188)     (9,296,107)
                                                      -----------     -----------     -----------
Partnership Income..................................  $16,465,430     $14,379,417     $14,072,814
                                                      ===========     ===========     ===========	

The accompanying notes are an integral part of these statements.
F-79

BAF ENERGY,
A CALIFORNIA LIMITED PARTNERSHIP
STATEMENTS OF PARTNERS' EQUITY
FOR THE YEARS ENDED OCTOBER 31, 1995, 1994 AND 1993

                                      GENERAL     LIMITED                     UNREALIZED       TOTAL
                                     PARTNERS'   PARTNERS'    UNDISTRIBUTED    LOSSES ON     PARTNERS'
                                      EQUITY       EQUITY       EARNINGS      SECURITIES       EQUITY
                                     ---------   ----------   -------------   -----------   ------------
Balance, October 31, 1992..........    $ 100     $9,901,500   $  13,509,779   $        --   $ 23,411,379
  Net income.......................       --             --      14,072,814            --     14,072,814
  Cash distributions...............       --             --     (15,000,000)           --    (15,000,000)
                                        ----     ----------    ------------       -------           ----
Balance, October 31, 1993..........      100      9,901,500      12,582,593            --     22,484,193
  Net income.......................       --             --      14,379,417            --     14,379,417
  Cash distributions...............       --             --     (13,500,000)           --    (13,500,000)
                                        ----     ----------    ------------       -------           ----
Balance, October 31, 1994..........      100      9,901,500      13,462,010            --     23,363,610
  Net income.......................       --             --      16,465,430            --     16,465,430
  Cash distributions...............       --             --     (13,000,000)           --    (13,000,000)
  Change in unrealized losses on
     available-for-sale
     securities....................       --             --              --        (5,079)        (5,079)
                                        ----     ----------    ------------       -------           ----
Balance, October 31, 1995..........    $ 100     $9,901,500   $  16,927,440   $    (5,079)  $ 26,823,961
                                        ====     ==========    ============       =======           ====	

The accompanying notes are an integral part of these statements.
F-80

BAF ENERGY,
A CALIFORNIA LIMITED PARTNERSHIP
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED OCTOBER 31, 1995, 1994 AND 1993

                                                       1995             1994             1993
                                                   ------------     ------------     ------------
Cash flows from operating activities:
  Partnership income.............................  $ 16,465,430     $ 14,379,417     $ 14,072,814
  Adjustments to reconcile partnership income to
     net cash provided from operating
     activities --
       Depreciation and amortization.............     3,578,572        3,575,442        3,576,710
       Realized (gains) losses on sales of
          available-for-sale securities, net.....          (465)          10,189          (22,701)
       Change in operating assets &
          liabilities --
          Accounts receivable -- trade...........    (5,639,506)       7,560,768       (6,403,581)
          Supplies inventory.....................       (92,194)        (301,309)         (11,406)
          Prepaid insurance......................       (37,008)         (69,663)           4,270
          Accounts payable.......................    (1,225,933)      (1,375,739)       1,516,130
          Interest payable.......................       (86,929)         (77,740)         (69,540)
          Payable to affiliate...................      (449,312)         463,194       (1,130,695)
          Other, net.............................       (45,049)              --               --
                                                     ----------       ----------       ----------
            Net cash provided by operating
               activities........................    12,467,606       24,164,559       11,532,001
                                                     ----------       ----------       ----------
Cash flows from investing activities:
  Purchases of available-for-sale securities.....   (34,628,300)     (25,334,642)     (16,319,709)
  Proceeds from sales and maturities of
     available-for-sale securities...............    37,795,441       20,232,824       20,074,603
  Additions to property, plant and equipment,
     net.........................................       (47,474)         (21,066)        (131,924)
                                                     ----------       ----------       ----------
            Net cash provided by (used in)
               investing activities..............     3,119,667       (5,122,884)       3,622,970
                                                     ----------       ----------       ----------
Cash flows from financing activities:
  Reductions of long-term liabilities, net.......    (4,192,409)      (3,587,576)      (3,250,397)
  Cash distributions to partners.................   (13,000,000)     (13,500,000)     (15,000,000)
                                                     ----------       ----------       ----------
            Net cash used in financing
               activities........................   (17,192,409)     (17,087,576)     (18,250,397)
                                                     ----------       ----------       ----------
Net (decrease) increase in cash and cash
  equivalents....................................    (1,605,136)       1,954,099       (3,095,426)
Cash and cash equivalents, beginning of year.....     5,363,057        3,408,958        6,504,384
                                                     ----------       ----------       ----------
Cash and cash equivalents, end of year...........  $  3,757,921     $  5,363,057     $  3,408,958
                                                     ==========       ==========       ==========
Supplemental disclosure of noncash investing and
  financing activities
  Unrealized holding losses, net, on
     available-for-sale securities, recorded as
     additions to undistributed earnings.........  $     (5,079)    $         --     $         --	

The accompanying notes are an integral part of these statements.
F-81

BAF ENERGY,
A CALIFORNIA LIMITED PARTNERSHIP
NOTES TO FINANCIAL STATEMENTS
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Organization
Basic American, Inc. (BAI) formed BAF Energy, A California Limited Partnership (BAF Energy or the Partnership) on March 25, 1986, for the purpose of developing, constructing and operating a cogeneration facility. The term of the Partnership is through December 2020 unless terminated earlier in accordance with the Partnership Agreement. The facility produces and sells electricity and steam. On December 6, 1995, the Partnership signed a letter agreement with a third party to lease substantially all of the Partnership's property, plant and equipment and to assign all related contracts. The third party lessee will operate the cogeneration facility through April, 2019 (see Note 8).
BAF Energy, Inc. (BEI) is the general partner of the Partnership and has an ownership interest of 1 percent. BEI is a wholly owned subsidiary of Basic Vegetable Products, Inc. (BVP). BVP is a wholly owned subsidiary of BAI. As of October 31, 1995, BAI also owned approximately 51 percent of the Limited Partnership units of BAF Energy then outstanding.
Distributions and profit and loss are allocated 99 percent to the limited partners, based on their proportionate share of limited partnership units, and 1 percent to the general partner.
Reclassifications
Certain reclassifications have been made to the 1994 and 1993 financial statements to be consistent with the current year presentation.
Cash and Cash Equivalents
For purposes of reporting cash flows, cash and cash equivalents include cash on deposit with banks, money market funds, and commercial paper. Cash paid for interest during the years ended October 31, 1995, 1994 and 1993 was $8,252,202, $8,732,052 and $9,161,241, respectively.
Available-for-Sale Securities
Effective November 1, 1994, the Partnership adopted Statement of Financial Accounting Standards No. 115, "Accounting for Certain Investments in Debt and Equity Securities" (SFAS 115). The Partnership has classified its investments as available-for-sale securities and as restricted available-for-sale securities and has recorded all securities holdings at fair value. Unrealized gains and losses are reported as a separate component of partners' equity until realized.
Premiums and discounts are amortized over the life of the related security as an adjustment to interest income using the effective interest method. Interest income is recognized when earned. Realized gains and losses on securities transactions are included in net income and are derived using the specific identification method for determining the cost of securities sold.
Prior to the November 1, 1994 adoption of SFAS 115, the Partnership's short-term investments were included in cash and short-term investments and were valued at the lower of aggregate cost or market. Such securities have been reclassified as available-for-sale securities to conform with SFAS 115 presentation requirements.
The effect of adopting SFAS 115 was to recognize net unrealized holding losses of $32,599 as a decrease in partners' equity as of November 1, 1994. At October 31, 1995, net unrealized holding losses were $5,079.
Restricted securities are required under the term loans described in Note 4.
F-82

BAF ENERGY,
A CALIFORNIA LIMITED PARTNERSHIP
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Property, Plant and Equipment
Property, plant and equipment are stated at cost less accumulated depreciation and amortization. Depreciation and amortization of property, plant and equipment are computed on a straight-line method principally over the following estimated useful lives:

                                                                       YEARS
                                                                      --------
Buildings and improvements..........................................     30
Machinery and equipment.............................................  5 to 30	

Major Maintenance Accruals
The Partnership accrues for the estimated future costs of major overhauls and equipment replacement based upon engineering studies.
Income Taxes
Federal and state income tax regulations provide that no income taxes are levied on a partnership. Instead, each partners' share of partnership profit or loss is reported on his or her separate income tax return. Accordingly, no partnership income taxes are provided for in the accompanying financial statements.
(2) AVAILABLE-FOR-SALE SECURITIES
As of October 31, 1995, the amortized cost and estimated fair values of the Partnership's investments in tax-exempt municipal securities are summarized as follows:

                                                        RESTRICTED
                                         AVAILABLE-     AVAILABLE-
                                          FOR-SALE       FOR-SALE
                                         SECURITIES     SECURITIES       TOTAL
                                         ----------     ----------     ----------
Amortized cost.........................  $1,919,184     $7,246,384     $9,165,568
Gross unrealized losses................          --         (5,079)        (5,079)
                                         ----------     ----------     ----------
Estimated fair value...................  $1,919,184     $7,241,305     $9,160,489
                                         ==========     ==========     ==========	

The amortized cost and estimated fair value of tax-exempt municipal securities by contractual maturity are shown below.

                                                      AMORTIZED      ESTIMATED
       DUE IN FISCAL YEAR ENDING OCTOBER 31,             COST        FAIR VALUE
----------------------------------------------------  ----------     ----------
1996................................................  $2,137,292     $2,134,000
1997-2000...........................................   7,028,276      7,026,489
                                                      ----------     ----------
          Total.....................................  $9,165,568     $9,160,489
                                                      ==========     ==========	

Proceeds from sales of investments for the year ended October 31, 1995 are as follow:

Gross proceeds..................................................  $26,099,037
Gross gains.....................................................  $     4,404
Gross losses....................................................  $     3,939	

F-83

BAF ENERGY,
A CALIFORNIA LIMITED PARTNERSHIP
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
(3) PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment and accumulated depreciation and amortization consist of:

                                                              1995             1994
                                                          ------------     ------------
Cost
  Buildings and improvements............................  $  1,410,873     $  1,313,304
  Machinery and equipment...............................    98,847,561       98,897,656
                                                          ------------     ------------
                                                           100,258,434      100,210,960
Accumulated depreciation and amortization...............   (24,387,912)     (20,854,389)
                                                          ------------     ------------
                                                          $ 75,870,522     $ 79,356,571
                                                          ============     ============	

On December 6, 1995, the Partnership signed a letter agreement with a third party to lease substantially all of the Partnership's property, plant and equipment (see Note 8).
(4) LONG-TERM LIABILITIES
Long-term liabilities are summarized as follows:

                                                               1995            1994
                                                            -----------     -----------
Term loan at 10.88%, due in equal installments through
  March 2004, non-recourse to the Partnership, secured by
  the facility and associated contracts...................  $60,514,066     $64,678,085
Term loan at 15.65%, due in equal installments through
  March 2004, with recourse to BEI, secured by the
  facility and associated contracts.......................    8,137,159       8,575,025
Major maintenance accruals................................    3,597,865       3,188,389
                                                            -----------     -----------
                                                             72,249,090      76,441,499
Less -- Current maturities................................    5,444,386       5,283,785
                                                            -----------     -----------
                                                            $66,804,704     $71,157,714
                                                            ===========     ===========	

Annual Maturities,
Annual maturities of long-term liabilities at October 31, 1995 are summarized as follows:

                    YEAR ENDING OCTOBER 31,                         AMOUNT
----------------------------------------------------------------  -----------
1996............................................................  $ 5,444,386
1997............................................................    6,121,107
1998............................................................    6,716,700
1999............................................................    7,224,887
2000............................................................   10,541,918
Thereafter......................................................   36,200,092
                                                                  -----------
                                                                  $72,249,090
                                                                  ===========	

(5) RELATED PARTY TRANSACTIONS
The Partnership Agreement requires that the Partnership pay BEI a monthly administrative fee. This fee amounted to $146,596, $139,613 and $132,966 for the years ended October 31, 1995, 1994 and 1993, respectively.
F-84

BAF ENERGY,
A CALIFORNIA LIMITED PARTNERSHIP
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
The Partnership has entered into a ground lease with a remaining term of 23 years with BAI for the land on which the facility is located. The lease includes options to extend the lease term up to an additional 30 years. Rent was $146,572, $139,593 and $132,946 for the years ended October 31, 1995, 1994 and 1993, respectively. Rents will escalate at the rate of 5% each year. In fiscal 1996, this lease will be assigned to a third party lessee pursuant to a letter agreement discussed at Note 8.
The Partnership negotiated a steam sales contract with a remaining term of 23 years with Basic Vegetable Products, LP (BVP, LP). The General Partner of BVP, LP is BVP. Under the contract, the Partnership supplies steam to BVP, LP's King City, California food processing plant. Revenues recorded under the contract totaled $669,341, $840,959 and $1,068,141 in 1995, 1994 and 1993, respectively. In fiscal 1996, this contract will also be assigned (see Note 8).
(6) COMMITMENTS AND CONTINGENCIES
Facilities
The Partnership executed an Operations and Maintenance (O & M) Agreement with Bechtel North American Power Corporation (Bechtel) in which Bechtel is required to operate and maintain the facility for a term of five years from May 1989. The Partnership reimburses Bechtel for all costs incurred in the performance of the service. O & M expenses paid totaled $3,665,168, $3,884,943 and $4,556,321 in 1995, 1994 and 1993, respectively, including a payment of base fees of $275,000, $387,456 and $500,000 per year, respectively, and a payment of earned fees of $380,000, $306,803 and $902,430 per year, respectively. The agreement also provided for a "high performance" bonus fee dependent on meeting certain performance standards. In April 1994, the O & M Agreement was renegotiated and extended through October 1998. The renegotiated terms include payment of base fees of $275,000 and elimination of the high performance bonus fee. The bonus paid in 1994 and 1995 totaled $3,107 and $175,327, respectively. In connection with the anticipated transaction described at Note 8, the Partnership will sever its O & M Agreement with Bechtel. The severance payment will be made with funds directly contributed by the third party lessee.
Financing
Calcorp Group, Inc. (CGI), a limited partner, has a put option to sell its 23 percent investment in the Partnership back to the Partnership at fair market value in certain circumstances. The put is subject to a subordination agreement with the Partnership's lenders. CGI has entered into a technical support agreement with the Partnership, wherein CGI is reimbursed for services rendered based upon time and expenses incurred.
(7) REVENUE RECOGNITION
BEI has an exclusive Power Purchase Agreement with Pacific Gas and Electric (PG&E) under which PG&E pays capacity payments, as defined in the agreement, and purchases all available energy, except for amounts sold to BVP, LP (see Note 5). The Partnership receives substantially all of its capacity payments from PG&E during May through October, and receives payment for energy sales to PG&E during May through January. In fiscal 1996, this agreement will be assigned to a third party lessee pursuant to a letter agreement discussed at Note 8.
(8) SIGNIFICANT LEASE TRANSACTION
On December 6, 1995, BAF Energy signed a letter agreement with a third party to enter into a 23-year lease of the cogeneration property, plant and equipment and to assign all related contracts. Under the terms of the lease, the lessee will assume all rights and responsibilities related to the ground lease (see Note 5), the BVP, LP steam sales contract (see Note 5), and the PG&E Power Purchase Agreement (see Note 7). BAF Energy expects to sign the lease in early 1996.
F-85

BAF ENERGY,
A CALIFORNIA LIMITED PARTNERSHIP
CONDENSED BALANCE SHEETS

                                                                                   OCTOBER 31,
                                                                                      1995
                                                                  JANUARY 31,     -------------
                                                                     1996
                                                                  -----------
                                                                  (UNAUDITED)
ASSETS
Current Assets:
  Cash and cash equivalents.....................................  $ 2,211,511     $   3,757,921
  Available for sale securities.................................           --         1,919,184
  Restricted available-for-sale securities......................   10,953,152         7,241,305
  Accounts receivable -- trade..................................    2,703,251        10,916,919
  Supplies inventory............................................    2,128,361         2,153,129
  Prepaid insurance.............................................      144,633           288,383
                                                                  ------------     ------------
          Total current assets..................................   18,140,908        26,276,841
                                                                  ------------     ------------
Property, Plant and Equipment...................................  100,258,434       100,258,434
  Accumulated depreciation and amortization.....................  (25,280,413)      (24,387,912)
                                                                  ------------     ------------
                                                                   74,978,021        75,870,522
                                                                  ------------     ------------
                                                                  $93,118,929     $ 102,147,363
                                                                  ============     ============
LIABILITIES AND PARTNERS' EQUITY
Current Liabilities:
  Accounts payable..............................................  $   811,919     $   1,598,177
  Interest payable..............................................    3,273,915         1,309,566
  Payable to affiliate..........................................       38,428           166,569
  Current portion of long-term liabilities......................    5,546,361         5,444,386
                                                                  ------------     ------------
          Total current liabilities.............................    9,670,623         8,518,698
                                                                  ------------     ------------
Long-Term Liabilities...........................................   66,702,729        66,804,704
                                                                  ------------     ------------
Commitments and Contingencies...................................           --                --
Partners' Equity:
  Contributed equity............................................    9,901,600         9,901,600
  Undistributed earnings........................................    6,843,977        16,922,361
                                                                  ------------     ------------
          Total partners' equity................................   16,745,577        26,823,961
                                                                  ------------     ------------
                                                                  $93,118,929     $ 102,147,363
                                                                  ============     ============	

The accompanying notes are an integral part of these statements.
F-86

BAF ENERGY,
A CALIFORNIA LIMITED PARTNERSHIP
CONDENSED STATEMENTS OF INCOME
 (UNAUDITED)

                                                                        THREE MONTHS ENDED
                                                                            JANUARY 31,
                                                                    ---------------------------
                                                                       1996            1995
                                                                    -----------     -----------
OPERATING REVENUES................................................  $ 4,957,368     $ 7,941,577
OPERATING EXPENSES:
  Fuel............................................................    1,479,116       3,408,912
  Depreciation and amortization...................................      892,500       1,072,028
  Labor, supplies and other.......................................    1,066,580       1,431,321
                                                                    -----------     -----------
          Total operating expenses................................    3,438,196       5,912,261
                                                                    -----------     -----------
            Operating income......................................    1,519,172       2,029,316
                                                                    -----------     -----------
OTHER INCOME AND EXPENSE:
  Interest income and other.......................................      154,073         130,313
  General and administrative......................................     (290,763)       (201,340)
  Interest expense................................................   (1,965,945)     (2,094,761)
                                                                    -----------     -----------
          Total other income and expense..........................   (2,102,635)     (2,165,788)
                                                                    -----------     -----------
PARTNERSHIP LOSS..................................................  $  (583,463)    $  (136,472)
                                                                    ===========     ===========	

The accompanying notes are an integral part of these statements.
F-87

BAF ENERGY,
A CALIFORNIA LIMITED PARTNERSHIP
CONDENSED STATEMENTS OF CASH FLOWS
 (UNAUDITED)

                                                                       THREE MONTHS ENDED
                                                                           JANUARY 31,
                                                                  -----------------------------
                                                                      1996             1995
                                                                  ------------     ------------
Net Cash Provided by Operating Activities.......................  $  9,779,417     $  2,298,789
                                                                  ------------     ------------
Cash Flows from Investing Activities:
  Purchases of available-for-sale securities....................   (25,170,795)     (12,290,102)
  Proceeds from sales and redemptions of available-for-sale
     securities.................................................    23,344,968       12,841,335
  Additions to property, plant and equipment, net...............            --          (20,189)
                                                                  ------------     ------------
          Net cash (used in) provided by investing activities...    (1,825,827)         531,044
                                                                  ------------     ------------
Cash Flows From Financing Activities:
  Increase in long-term liabilities, net........................            --          307,110
  Cash distributions to partners................................    (9,500,000)      (8,500,000)
                                                                  ------------     ------------
          Net cash used in financing activities.................    (9,500,000)      (8,192,890)
                                                                  ------------     ------------
Net Decrease in Cash and Cash Equivalents.......................    (1,546,410)      (5,363,057)
Cash and Cash Equivalents, beginning of period..................     3,757,921        5,363,057
                                                                  ------------     ------------
Cash and Cash Equivalents, end of period........................  $  2,211,511     $         --
                                                                  ============     ============
Supplementary Information:
  Unrealized holding gains/losses, net, on available-for-sale
     securities, recorded as additions to undistributed
     earnings...................................................  $      5,079     $         --
  Cash paid during the period for interest......................  $         --     $         --	

The accompanying notes are an integral part of these statements.
F-88

BAF ENERGY,
A CALIFORNIA LIMITED PARTNERSHIP
NOTES TO CONDENSED FINANCIAL STATEMENTS
 JANUARY 31, 1996
(UNAUDITED)
(1) GENERAL
Organization
BAF Energy, A California Limited Partnership (BAF Energy or the Partnership) was founded in 1986 and is engaged in the development, construction and operation of a cogeneration facility. The term of the Partnership is through December 2020 unless terminated earlier in accordance with the Partnership Agreement. The facility produces and sells electricity and steam.
BAF Energy, Inc. (BEI) is the general partner of the Partnership and has an ownership interest of 1 percent. BEI is a wholly owned subsidiary of Basic Vegetable Products, Inc. (BVP). BVP is a wholly owned subsidiary of Basic American, Inc. (BAI). As of January 31, 1996, BAI also owned approximately 51 percent of the limited partnership units of BAF Energy then outstanding.
Distributions and profit and loss are allocated 99 percent to the limited partners, based on their proportionate share of limited partnership units, and 1 percent to the general partner.
Basis of Interim Presentation
The accompanying interim condensed financial statements of the Partnership have been prepared by the Partnership, without audit by independent public accountants, pursuant to the rules and regulations of the Securities and Exchange Commission. In the opinion of management, the condensed consolidated financial statements include all normal recurring adjustments necessary to present fairly the information required to be set forth therein. Certain information and note disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted from these statements pursuant to such rules and regulations and, accordingly, should be read in conjunction with the audited financial statements of the Partnership for the year ended October 31, 1995. Consistent with the operating schedule of the cogeneration facility, the Partnership receives a majority of its operating revenue between May and September. Therefore, the results of operations for the three months ended January 31, 1996 and 1995 are not indicative of the results for the entire year.
(2) RELATED PARTY TRANSACTIONS
The Partnership Agreement requires that the Partnership pay BEI a monthly administrative fee. This fee amounted to $37,558 and $35,770 for the quarters ended January 31, 1996 and 1995, respectively.
The Partnership has entered into a ground lease with BAI for the land on which the facility is located. Rent was $37,554 and $35,764 for the quarters ended January 31, 1996 and 1995, respectively.
The Partnership negotiated a steam sales contract with Basic Vegetable Products, LP (BVP, LP). The General Partner of BVP, LP is BVP. Under the contract, the Partnership supplies steam to BVP, LP's food processing plant. Revenues recorded under the contract totaled $38,333 and $55,788 for the quarters ended January 31, 1996 and 1995, respectively.
(3) PARTNERS' EQUITY:
The Partnership made distributions of $9,500,000 and $8,500,000 for the quarters ended January 31, 1996 and 1995, respectively.
F-89

BAF ENERGY,
A CALIFORNIA LIMITED PARTNERSHIP
NOTES TO CONDENSED FINANCIAL STATEMENTS -- (CONTINUED)
 JANUARY 31, 1996
(UNAUDITED)
(4) SIGNIFICANT LEASE TRANSACTION:
In April 1996, the Partnership signed an agreement with a third party to enter into a 23-year lease of the cogeneration property, plant and equipment and to assign all related contracts. Under the terms of the lease, the lessee will assume all rights and responsibilities related to the ground lease with BAI (see Note 2), the BVP, LP steam sales contract (see Note 2) and a Pacific Gas & Electric (PG&E) Power Purchase Agreement. The ground lease has a remaining term of 23 years with BAI for the land on which the facility is located. This lease includes options to extend the lease term up to an additional 30 years. The BVP, LP steam sales contract has a remaining term of 23 years. The PG&E Power Purchase Agreement states that PG&E pays capacity payments, as defined in the agreement, and purchases all available energy, except for amounts sold to BVP, LP.
F-90

REPORT OF INDEPENDENT AUDITORS
The Shareholder
Gilroy Energy Company
We have audited the accompanying balance sheets of Gilroy Energy Company (the Company), a wholly owned subsidiary of Gilroy Foods, Inc. which in turn is a wholly owned subsidiary of McCormick & Company, Inc., as of November 30, 1995 and 1994 and the related statements of income, shareholder's equity, and cash flows for the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Gilroy Energy Company at November 30, 1995 and 1994 and the results of its operations and its cash flows for the years then ended in conformity with generally accepted accounting principles.
ERNST & YOUNG LLP
Baltimore, Maryland
July 18, 1996
F-91

GILROY ENERGY COMPANY
 (A WHOLLY OWNED SUBSIDIARY)
BALANCE SHEETS
 (DOLLARS IN THOUSANDS)
ASSETS

                                                                                 NOVEMBER 30
                                                                            ---------------------
                                                                              1995         1994
                                                              MAY 31,       --------     --------
                                                               1996
                                                            -----------
                                                            (UNAUDITED)
Current assets:
  Accounts receivable.....................................   $   4,428      $  1,615     $  1,503
  Prepaid expenses........................................         462           725          776
                                                              --------      --------     --------
          Total current assets............................       4,890         2,340        2,279
Property and equipment, at cost:
  Buildings...............................................       2,720         2,720        2,720
  Machinery and equipment.................................      93,421        93,349       93,098
  Furniture and fixtures..................................          64            64           62
  Software................................................          65            65           58
                                                              --------      --------     --------
                                                                96,270        96,198       95,938
Less accumulated depreciation and amortization............      39,202        36,712       31,701
                                                              --------      --------     --------
                                                                57,068        59,486       64,237
Due from parent and affiliates............................      64,780        69,422       61,522
                                                              --------      --------     --------
Total assets..............................................   $ 126,738      $131,248     $128,038
                                                              ========      ========     ========
                                           LIABILITIES
Current liabilities:
  Bank overdraft..........................................          --      $     58     $    618
  Accounts payable........................................   $   1,653         2,678        1,767
  Accrued interest........................................       3,093         3,238        3,363
  Other liabilities.......................................         336           993          241
  Current portion of long-term debt.......................       2,848         2,468        2,152
                                                              --------      --------     --------
          Total current liabilities.......................       7,930         9,435        8,141
Long-term debt, due after one year........................      50,120        52,968       55,436
Other liabilities.........................................         399            49        1,083
                                                              --------      --------     --------
                                                                50,519        53,017       56,519
Shareholder's equity:
  Common stock, no par value:
     Authorized shares -- 10,000
     Issued and outstanding shares -- 1,000...............          10            10           10
  Additional paid-in capital..............................      16,946        16,946       16,946
  Retained earnings.......................................      51,333        51,840       46,422
                                                              --------      --------     --------
          Total shareholder's equity......................      68,289        68,796       63,378
                                                              --------      --------     --------
Total liabilities and shareholder's equity................   $ 126,738      $131,248     $128,038
                                                              ========      ========     ========	

See accompanying notes.
F-92

GILROY ENERGY COMPANY
 (A WHOLLY OWNED SUBSIDIARY)
STATEMENTS OF INCOME
 (DOLLARS IN THOUSANDS)

                                                         SIX MONTHS ENDED         YEARS ENDED
                                                             MAY 31,             NOVEMBER 30,
                                                         ----------------     -------------------
                                                          1996     1995        1995        1994
                                                         ------   -------     -------     -------
                                                           (UNAUDITED)
Net revenues:
  Electricity revenue................................    $9,306   $11,158     $35,132     $40,037
  Steam revenue from Gilroy Foods, Inc...............       185       260       1,089       1,367
                                                         ------   -------     -------     -------
                                                          9,491    11,418      36,221      41,404
Cost of sales........................................     6,525     8,125      18,825      23,766
                                                         ------   -------     -------     -------
Gross margin.........................................     2,966     3,293      17,396      17,638
Operating expenses;
  Selling, general and administrative................       720       946       1,888       1,885
                                                         ------   -------     -------     -------
Operating income.....................................     2,246     2,347      15,508      15,753
Interest expense.....................................     3,093     3,237       6,477       6,731
                                                         ------   -------     -------     -------
(Loss) Income before income taxes....................      (847)     (890)      9,031       9,022
Provision for income tax (benefit) expense...........      (340)     (356)      3,613       3,622
                                                         ------   -------     -------     -------
Net (loss) income....................................    $ (507)  $  (534)    $ 5,418     $ 5,400
                                                         ======   =======     =======     =======	

See accompanying notes.
F-93

GILROY ENERGY COMPANY
 (A WHOLLY OWNED SUBSIDIARY)
STATEMENT OF SHAREHOLDER'S EQUITY
 (DOLLARS IN THOUSANDS)

                                             COMMON STOCK        ADDITIONAL                      TOTAL
                                           -----------------      PAID-IN       RETAINED     SHAREHOLDER'S
                                           SHARES     AMOUNT      CAPITAL       EARNINGS        EQUITY
                                           ------     ------     ----------     --------     -------------
Balance at November 30, 1993.............  1,000       $ 10       $ 16,946      $ 41,022        $57,978
Net income...............................     --         --             --         5,400          5,400
                                           ------     ------     ----------     --------     -------------
Balance at November 30, 1994.............  1,000         10         16,946        46,422         63,378
Net income...............................     --         --             --         5,418          5,418
                                           ------     ------     ----------     --------     -------------
Balance at November 30, 1995.............  1,000         10         16,946        51,840         68,796
Net (loss) (unaudited)...................     --         --             --          (507)          (507)
                                           ------     ------     ----------     --------     -------------
Balance at May 31, 1996
  (unaudited)............................  1,000       $ 10       $ 16,946      $ 51,333        $68,289
                                           =====      ======       =======       =======     ==========	

See accompanying notes.
F-94

GILROY ENERGY COMPANY
 (A WHOLLY OWNED SUBSIDIARY)
STATEMENTS OF CASH FLOWS
 (DOLLARS IN THOUSANDS)

                                                       SIX MONTHS ENDED           YEARS ENDED
                                                            MAY 31,              NOVEMBER 30,
                                                      -------------------     -------------------
                                                       1996        1995        1995        1994
                                                      -------     -------     -------     -------
                                                          (UNAUDITED)
OPERATING ACTIVITIES:
  Net income (loss).................................  $  (507)    $  (534)    $ 5,418     $ 5,400
  Adjustments to reconcile net (loss) income to net
     cash (used in) provided by operating
     activities:
     Depreciation and amortization..................    2,490       2,482       5,011       4,880
     Changes in operating assets and liabilities:
       Accounts receivable..........................   (2,813)     (3,577)       (113)         51
       Prepaid expenses.............................      263         325          52          49
       Accounts payable.............................   (1,025)       (360)        912      (1,221)
       Accrued expenses and other liabilities.......     (452)       (644)       (408)        364
                                                      -------     -------     -------     -------
Net cash (used in) provided by operating
  activities........................................   (2,044)     (2,308)     10,872       9,523
                                                      -------     -------     -------     -------
INVESTING ACTIVITIES:
Due from parent and affiliates......................    4,642       5,071      (7,900)     (4,610)
Purchase of property and equipment..................      (72)       (117)       (260)     (3,376)
                                                      -------     -------     -------     -------
Net cash provided by (used in) investing
  activities........................................    4,570       4,954      (8,160)     (7,986)
                                                      -------     -------     -------     -------
FINANCING ACTIVITIES:
Principal payments on long-term debt................   (2,468)     (2,152)     (2,152)     (2,152)
                                                      -------     -------     -------     -------
Net cash (used in) financing activities.............   (2,468)     (2,152)     (2,152)     (2,152)
                                                      -------     -------     -------     -------
Net decrease (increase) in bank overdraft...........       58         494         560        (615)
Bank overdraft at beginning of period...............      (58)       (618)       (618)         (3)
                                                      -------     -------     -------     -------
Bank overdraft at end of period.....................  $    --     $  (124)    $   (58)    $  (618)
                                                      =======     =======     =======     =======
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Interest paid.......................................  $ 3,238     $ 3,359     $ 6,602     $ 6,602	

See accompanying notes.
F-95

GILROY ENERGY COMPANY
 (A WHOLLY OWNED SUBSIDIARY)
NOTES TO FINANCIAL STATEMENTS
 (DOLLARS IN THOUSANDS)
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Organization
Gilroy Energy Company (the Company) was incorporated in the State of California in July 1984. The Company is a wholly owned subsidiary of Gilroy Foods, Inc. which in turn is a wholly owned subsidiary of McCormick & Company, Inc. (McCormick). The Company runs a cogeneration facility in Gilroy, California which uses natural gas and steam turbine engines to generate steam for sale to Gilroy Foods, Inc. and electricity for sale to Pacific Gas and Electric Company.
Sales to Pacific Gas and Electric Company represented approximately 97% of total revenues for each of the years ended November 30, 1995 and 1994 and 98% for the six months ended May 31, 1996 and 1995.
Approximately 80% of the Company's net revenues are recognized during the months of May through October of each year. As such, the results of operations for the six month periods ended May 31, 1996 and 1995 are not indicative of the results of operations that may be realized for the full year.
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements as well as the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Bank Overdrafts
The Company maintains a zero balance bank account. Amounts sufficient to cover checks presented to the bank are deposited into the account by McCormick & Company, Inc. The bank overdrafts represent checks that have been written but have not cleared the bank as of the balance sheet date.
Property and Equipment
Property and equipment are recorded at cost. Depreciation and amortization are computed using the straight-line method over the estimated useful lives of the assets, ranging from five to forty years.
In 1995, the Financial Accounting Standards Board released Statement of Financial Accounting Standards No. 121, "Accounting for Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of " (FAS 121). FAS 121 requires recognition of impairment of long-lived assets in the event that the net book value of such assets exceeds the future undiscounted cash flows attributable to such assets. The Company will be required to adopt FAS 121 in its 1997 fiscal year. Management does not believe that the initial adoption of FAS 121 will have a significant impact on the Company.
Repairs and Maintenance
The cogeneration plant requires a periodic shutdown for major overhauls of its primary components every several years. The Company's policy is to accrue the anticipated cost of these overhauls during the operating periods prior to the scheduled overhaul dates. The amounts and period of accruals for overhaul costs are revised annually based on management's estimate of time remaining before the next scheduled overhaul and the estimated cost of the overhaul.
Repairs and maintenance expenditures that are not a part of major overhauls or do not extend the useful life of the related equipment are charged to expense when incurred.
F-96

GILROY ENERGY COMPANY
 (A WHOLLY OWNED SUBSIDIARY)
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
 (DOLLARS IN THOUSANDS)
Due from Parent and Affiliates
The due from parent and affiliates included in the balance sheet represents a net balance as the result of various transactions between the Company and Gilroy Foods, Inc. and McCormick & Company, Inc. There are no terms of settlement, or interest charges associated with the account balance. The balance is primarily the result of the Company's participation in McCormick's central cash management program, wherein all the Company's cash receipts are remitted to McCormick and all cash disbursements are funded by McCormick. Other transactions include steam sales to Gilroy Foods, Inc., the Company's estimated income tax payable or receivable resulting from the current and prior years estimated provisions, and miscellaneous other administrative expenses incurred by Gilroy Foods, Inc. or McCormick & Company, Inc. on behalf of the Company.
An analysis of transactions in the due from parent and affiliates balance for the six months ended May 31, 1996 and 1995 (unaudited) and each of the two years in the period ended November 30, 1995 follows:

                                                       SIX MONTHS ENDED           YEARS ENDED
                                                            MAY 31,              NOVEMBER 30,
                                                      -------------------     -------------------
                                                       1996        1995        1995        1994
                                                      -------     -------     -------     -------
                                                          (UNAUDITED)
Balance in due from parent and affiliates at
  beginning of period...............................  $69,422     $61,522     $61,522     $56,912
Net cash remitted (from) to Gilroy Foods, Inc. or
  McCormick.........................................   (4,616)     (5,578)     10,671       7,729
Net intercompany sales..............................      196         275       1,146       1,438
Net intercompany purchases for cost of sales........     (532)         (3)       (218)         (6)
Net intercompany purchases for selling, general and
  administrative expenses...........................      (30)       (121)        (87)       (929)
Benefit (provision) for income taxes................      340         356      (3,612)     (3,622)
                                                      -------     -------     -------     -------
Balance in due from parent and affiliated at end of
  period............................................  $64,780     $56,451     $69,422     $61,522
                                                      =======     =======     =======     =======
Average balance during the period...................  $66,384     $58,373     $61,811     $56,828
                                                      =======     =======     =======     =======	

Gilroy Foods, Inc. provides certain administrative services to the Company including the services of the President of Gilroy Energy Company, Inc., accounting, and other administrative services. It is the policy of Gilroy Foods, Inc. to charge these expenses and all other central operating costs on the basis of direct usage. In the opinion of management, no other costs of Gilroy Foods, Inc. should be allocated to the Company.
McCormick provides various administrative services to the Company including legal assistance and treasury services. McCormick does not charge the Company for these services. In the opinion of management, the cost of the services rendered by McCormick in these areas during each of the two years ended November 30, 1995 and 1994 and the six months ended May 31, 1996 and 1995 are nominal.
Concentration of Credit Risk
The Company sells electricity to Pacific Gas and Electric Company under a long-term contract. All accounts receivable at May 31, 1996 (unaudited) and November 30, 1995 and 1994 are due from this customer. No collateral is required for accounts receivable. Management believes that no reserves are required for potential credit losses at May 31, 1996 and November 30, 1995 and 1994.
F-97

GILROY ENERGY COMPANY
 (A WHOLLY OWNED SUBSIDIARY)
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
 (DOLLARS IN THOUSANDS)
Sources of Supply
The Company purchases natural gas for the operation of the cogeneration facility under a supply contract with one supplier. The supply contract requires the Company to purchase substantially all of its natural gas needs from the supplier at a price based on the market value determined in accordance with the contract through July 31, 1997. Management believes that in the event that this supplier is not able to meet its obligations under the contract, alternative sources of supply for natural gas are readily available at comparable prices.
2. LONG-TERM DEBT
The Company's outstanding indebtedness is as follows:

                                                                 NOVEMBER 30,
                                                              -------------------
                                                               1995        1994
                                                MAY 31,       -------     -------
                                                 1996
                                              -----------
                                              (UNAUDITED)
Note payable in annual installments through     $52,968       $55,436     $57,588
  2006 with interest at 11.68% per annum....
Less current portion........................      2,848         2,468       2,152
                                                -------       -------     -------
                                                $50,120       $52,968     $55,436
                                                =======       =======     =======	

The note payable requires the maintenance of a $5,000 maintenance fund and a $10,000 debt service fund. The note holder has agreed to accept a guarantee of up to $15,000 by McCormick & Company, Inc. in lieu of establishing these funds. The terms of the note payable require the Company to comply with certain nonfinancial covenants. Management believes that the Company was in compliance with all applicable covenants at November 30, 1995 and 1994. The note payable is secured by the cogeneration facility.
The note payable agreement provides for the payment of a prepayment penalty in the event of early retirement. The amount of the prepayment penalty approximates the present value of the differential between current market interest rates and the stated rate over the remaining life of the debt as defined by the agreement.
Aggregate maturities of long-term debt over the next five fiscal years ending November 30 and thereafter are as follows:

1996.......................................................  $ 2,468
1997.......................................................    2,848
1998.......................................................    3,101
1999.......................................................    3,481
2000.......................................................    3,797
Thereafter.................................................   39,741
                                                             -------
                                                             $55,436
                                                             =======	

3. INCOME TAXES
The Company is included in the consolidated federal and state income tax returns of McCormick. McCormick does not have a formal tax sharing arrangement with its subsidiaries. The income tax provisions included in the statements of income has been provided under the liability method assuming that Gilroy Energy Company had prepared separate income tax returns for the years ended November 30, 1995 and 1994 and the six months ended May 31, 1996 and 1995 (unaudited). Any income taxes receivable or payable as a
F-98

GILROY ENERGY COMPANY
 (A WHOLLY OWNED SUBSIDIARY)
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
 (DOLLARS IN THOUSANDS)
result of the income tax provisions, including any deferred amounts due or payable resulting from the current or prior years provisions are included in due from parent and affiliates.
The (benefit) provision for income taxes is summarized as follows:

                                           SIX MONTHS
                                              ENDED              YEARS ENDED
                                             MAY 31,            NOVEMBER 30,
                                         ---------------     -------------------
                                         1996      1995       1995        1994
                                         -----     -----     -------     -------
                                           (UNAUDITED)
Current:
  Federal..............................  $(288)    $(303)    $ 3,877     $ 4,061
  State................................    (52)      (53)      1,169       1,225
                                         -----     -----     -------     -------
                                          (340)     (356)      5,046       5,286
                                         -----     -----     -------     -------
Deferred:
  Federal..............................     --        --      (1,095)     (1,278)
  State................................     --        --        (338)       (386)
                                         -----     -----     -------     -------
                                            --        --      (1,433)     (1,664)
                                         -----     -----     -------     -------
                                         $(340)    $(356)    $ 3,613     $ 3,622
                                         =====     =====     =======     =======	

The reconciliation between income tax computed at the United States federal statutory rate and income taxes actually provided follows:

                               SIX MONTHS ENDED MAY 31,            YEARS ENDED NOVEMBER 30,
                            -------------------------------     -------------------------------
                                1996              1995              1995              1994
                            -------------     -------------     -------------     -------------
                            AMOUNT    %       AMOUNT    %       AMOUNT    %       AMOUNT    %
                            ------   ----     ------   ----     ------   ----     ------   ----
                            (UNAUDITED)
Tax at federal rate.......  $ (288)  34.0%    $ (303)  34.0%    $3,071   34.0%     3,067   34.0%
State income taxes, net of
  federal benefit.........     (52)   6.1%       (53)   6.0%       542    6.0%       555    6.1%
                            ------            ------            ------
Actual income taxes
  (benefit) provided......  $ (340)  40.1%    $ (356)  40.0%    $3,613   40.0%    $3,622   40.1%
                            ======            ======            ======	

The temporary differences that give rise to significant portions of the deferred tax assets and liabilities that have been netted in due from parent and affiliates consist of the following:

                                                              NOVEMBER 30,
                                                           -------------------
                                                            1995        1994
                                                           -------     -------
Temporary differences resulting in deferred tax assets:
  Repairs and maintenance expenditures...................  $   986     $ 1,082
                                                           -------     -------
Temporary differences resulting in deferred tax
  liabilities:
  Depreciation...........................................   50,897      54,587
  Prepaid expenses.......................................      810         758
  Other..................................................      357         357
                                                           -------     -------
                                                            52,064      55,702
                                                           -------     -------
                                                           $51,078     $54,620
                                                           =======     =======	

No valuation allowance is provided for deferred tax assets.
F-99

GILROY ENERGY COMPANY
 (A WHOLLY OWNED SUBSIDIARY)
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
 (DOLLARS IN THOUSANDS)
4. RELATED PARTY TRANSACTIONS
The Company sells substantially all of the steam, which is a byproduct of the cogeneration process to Gilroy Foods, Inc. During the years ended November 30, 1995 and 1994, the amount of revenue recognized by the Company from steam sales to Gilroy Foods, Inc. was $1,089 and $1,367, respectively. During the six months ended May 31, 1996 and 1995, the amount of revenue recognized by the Company from steam sales to Gilroy Foods, Inc. was $185 and $261, respectively.
Gilroy Foods, Inc. provides certain accounting and administrative services to Gilroy Energy Company, Inc. A portion of the cost of these services is billed directly to Gilroy Energy Company, Inc.
The Company leases the land where the cogeneration facility is located under an operating lease with Gilroy Foods, Inc. The lease agreement runs through 2018 and provides for minimum annual rental payments with provisions for the escalation of costs every three years based on the average increase in the Consumer Price Index. The future minimum lease payments under this lease, excluding any future increases, are as follows:

1996..................................................................................  $ 40
1997..................................................................................    40
1998..................................................................................    40
1999..................................................................................    40
2000..................................................................................    40
2001 through 2018.....................................................................   715
                                                                                        ----
                                                                                        $915
                                                                                        ====	

Rent expense recognized under this lease was $38 and $37 in the years ended November 30, 1995 and 1994, respectively, and $20 and $19 in the six months ended May 31, 1996 and 1995, respectively.
5. COMMITMENTS AND CONTINGENCIES
The Company has an agreement with the Pacific Gas and Electric Company (PG&E) to sell all electricity generated by the cogeneration facility to PG&E. The agreement establishes the methodology used to calculate the purchase price of the electricity, establishes the operating hours of the cogeneration facility, and provides for the payment to the Company of additional capacity payments if certain operating targets as defined are achieved. The current provisions of this agreement extend through December 31, 1998. Subsequent to December 31, 1998 and continuing through the expiration of the base agreement on December 31, 2017, the pricing and operating provisions of the agreement will be established by negotiation between PG&E and Gilroy Energy Company.
The Company has an agreement with Gilroy Foods, Inc. whereby Gilroy Foods, Inc. has agreed to purchase substantially all of the steam produced by the Company. The terms of the agreement, which extends through 2017, provide for the establishment of the purchase price for steam based on the current cost of alternative sources of energy available to Gilroy Foods, Inc.
The Company has an operating and maintenance agreement with an outside party for the daily operation and maintenance of the cogeneration facility. This agreement, which extends through November 1996, provides for all operating and routine maintenance of the cogeneration facility at direct costs plus a minimum annual fee of $100,000. The contract also provides for the payment of bonuses, as defined, if certain operating targets are met.
F-100

GILROY ENERGY COMPANY
 (A WHOLLY OWNED SUBSIDIARY)
NOTES TO FINANCIAL STATEMENTS--(CONTINUED)
 (DOLLARS IN THOUSANDS)
6. FAIR VALUE
The following methods and assumptions were used by the Company in estimating fair value disclosures for financial instruments:
Accounts receivable, due from parent and affiliates, bank overdrafts, current portion of long-term debt, accounts payable, and accrued liabilities -- The amounts reported in the balance sheet approximate fair value.
Long-term debt. The fair value of long-term debt, based on a discounted cash flow analysis using current interest rates for debt with similar characteristics and maturities is as follows:

                                              NOVEMBER 30
                                              ---------------------------------------------
                                                      1995                     1994
                                               FAIR       CARRYING      FAIR       CARRYING
                                               VALUE       VALUE        VALUE       VALUE
                                              -------     --------     -------     --------
Long-term debt............................    $68,100     $ 52,968     $63,000     $ 55,436	

7. SUBSEQUENT EVENT
In May 1996, McCormick & Company, Inc. announced its intention to sell the assets and liabilities, excluding the due from parent and affiliates, the current portion of long-term debt and the long-term debt of the Company to Calpine Corporation. At the time of the closing of the sale, McCormick & Company, Inc. will assume the due from parent and affiliates and will be required to retire the current portion of the long-term debt and the long-term debt. In addition to all remaining assets and liabilities of Gilroy Energy Company, Calpine Corporation will assume all rights and obligations under the following agreements to which Gilroy Energy Company is currently a party:
- Long-term contract to sell electricity to Pacific Gas and Electric Company.
- Natural gas supply contract through July 31, 1997.
- Lease for the land with Gilroy Foods, Inc. upon which the cogeneration facility is located.
- Steam sale contract with Gilroy Foods, Inc.
Upon closing of the sale, the management contract with the current operator of the cogeneration facility will be terminated by McCormick & Company, Inc.
It is currently anticipated that the closing date for the sale of the applicable assets and liabilities of Gilroy Energy Company to Calpine Corporation will take place in the third quarter of 1996.
F-101

NO DEALER, SALESPERSON OR OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY INFORMATION OR TO MAKE ANY REPRESENTATION NOT CONTAINED IN THIS PROSPECTUS, AND, IF GIVEN OR MADE, SUCH INFORMATION OR REPRESENTATION MUST NOT BE RELIED UPON AS HAVING BEEN AUTHORIZED BY THE COMPANY OR ANY UNDERWRITER. THIS PROSPECTUS DOES NOT CONSTITUTE AN OFFER TO SELL OR A SOLICITATION OF AN OFFER TO BUY ANY OF THE SECURITIES OFFERED HEREBY IN ANY JURISDICTION TO ANY PERSON TO WHICH IT IS UNLAWFUL TO MAKE SUCH OFFER IN SUCH JURISDICTION. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR ANY SALE MADE HEREUNDER SHALL, UNDER ANY CIRCUMSTANCES, CREATE ANY IMPLICATION THAT THE INFORMATION CONTAINED HEREIN IS CORRECT AS OF ANY TIME SUBSEQUENT TO THE DATE HEREOF OR THAT THERE HAS BEEN NO CHANGE IN THE AFFAIRS OF THE COMPANY SINCE SUCH DATE.
TABLE OF CONTENTS

                                        PAGE
                                        ----
Prospectus Summary....................    3
Risk Factors..........................    8
Use of Proceeds.......................   17
Dividend Policy.......................   17
Capitalization........................   18
Dilution..............................   19
Selected Consolidated Financial
  Data................................   20
Pro Forma Consolidated Financial
  Data................................   22
Management's Discussion and Analysis
  of Financial Condition and Results
  of Operations.......................   29
Business..............................   38
Management............................   70
Certain Transactions..................   80
Principal and Selling Stockholders....   82
Description of Capital Stock..........   83
Shares Eligible for Future Sale.......   85
Certain United States Federal Tax
  Consequences to Non-U.S. Holders....   86
Underwriting..........................   89
Notice to Canadian Residents..........   92
Legal Matters.........................   92
Experts...............................   93
Available Information.................   93
Consolidated Financial Statements.....  F-1	

UNTIL , 1996 (25 DAYS AFTER THE DATE OF THIS PROSPECTUS), ALL DEALERS EFFECTING TRANSACTONS IN THE COMMON STOCK OFFERED HEREBY, WHETHER OR NOT PARTICIPATING IN THIS DISTRIBUTION, MAY BE REQUIRED TO DELIVER A PROSPECTUS. THIS IS IN ADDITION TO THE OBLIGATION OF DEALERS TO DELIVER A PROSPECTUS WHEN ACTING AS UNDERWRITERS AND WITH RESPECT TO THEIR UNSOLD ALLOTMENTS OR SUBSCRIPTIONS.

LOGO
18,045,000 Shares
Common Stock
PROSPECTUS
CS First Boston
Morgan Stanley & Co.
Incorporated
PaineWebber Incorporated
Salomon Brothers Inc

Alternate Page A-1
SUBJECT TO COMPLETION, DATED SEPTEMBER 19, 1996

                      18,045,000 Shares
                     Calpine Corporation
LOGO                     Common Stock
                      ($.001 par value)	

Of the shares of Common Stock, $.001 par value ("Common Stock"), of Calpine Corporation (the "Company" or "Calpine") offered hereby, 5,477,820 shares are being sold by the Company and 12,567,180 shares are being sold by the Selling Stockholder named herein under "Principal and Selling Stockholders." Of the 18,045,000 shares of Common Stock being offered, 3,609,000 shares are initially being offered outside the United States and Canada (the "International Shares") by the Managers (the "International Offering") and 14,436,000 shares are initially being concurrently offered in the United States and Canada (the "U.S.
Shares") by the U.S. Underwriters (the "U.S. Offering" and, together with the International Offering, the "Common Stock Offering"). The offering price and underwriting discounts and commissions of the International Offering and the U.S. Offering are identical.
Prior to the Common Stock Offering, there has been no public market for the Common Stock. It is anticipated that the initial public offering price will be between $17.00 and $20.00 per share. For information relating to the factors considered in determining the initial public offering price to the public, see "Subscription and Sale."
The Common Stock has been approved for listing on the New York Stock Exchange under the symbol "CPN," subject to notice of issuance.

FOR A DISCUSSION OF CERTAIN FACTORS THAT SHOULD BE CONSIDERED IN CONNECTION WITH
AN INVESTMENT
IN THE COMMON STOCK, SEE "RISK FACTORS" BEGINNING ON PAGE 8 HEREIN.
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR
HAS THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE
SECURITIES COMMISSION PASSED UPON THE ACCURACY OR AD-
EQUACY OF THIS PROSPECTUS. ANY REPRESENTATION
TO THE CONTRARY IS A CRIMINAL OFFENSE.

                                                         Underwriting                    Proceeds to
                                           Price to     Discounts and    Proceeds to       Selling
                                            Public       Commissions      Calpine(1)     Stockholder
                                       ----------------------------------------------------------------
Per Share..............................        $              $               $               $
Total(2)...............................        $              $               $               $	

(1) Before deduction of expenses payable by Calpine, estimated at $809,000.
(2) The Company has granted the Managers and the U.S. Underwriters an option, exercisable by CS First Boston Corporation for 30 days from the date of this Prospectus, to purchase a maximum of 2,706,750 additional shares to cover over-allotments of shares. If the option is exercised in full, the total Price to Public will be $ , Underwriting Discounts and Commissions will be $ , Proceeds to Calpine will be $ and Proceeds to Selling Stockholder will be $ .
The International Shares are offered by the several Managers when, as and if delivered to and accepted by the Managers and subject to their right to reject orders in whole or in part. It is expected that the International Shares will be

ready for delivery on or about               , 1996, against payment in
immediately available funds.

CS First Boston  Morgan Stanley & Co.
                        International

PaineWebber International                         Salomon Brothers International

               The date of this Prospectus is             , 1996.	

INFORMATION CONTAINED HEREIN IS SUBJECT TO COMPLETION OR AMENDMENT. A REGISTRATION STATEMENT RELATING TO THESE SECURITIES HAS BEEN FILED WITH THE SECURITIES AND EXCHANGE COMMISSION. THESE SECURITIES MAY NOT BE SOLD NOR MAY OFFERS TO BUY BE ACCEPTED PRIOR TO THE TIME THE REGISTRATION STATEMENT BECOMES EFFECTIVE. THIS PROSPECTUS SHALL NOT CONSTITUTE AN OFFER TO SELL OR THE SOLICITATION OF AN OFFER TO BUY NOR SHALL THERE BE ANY SALE OF THESE SECURITIES IN ANY STATE IN WHICH SUCH OFFER, SOLICITATION OR SALE WOULD BE UNLAWFUL PRIOR TO REGISTRATION OR QUALIFICATION UNDER THE SECURITIES LAWS OF ANY SUCH STATE.

ALTERNATE PAGE A-2
NO DEALER, SALESPERSON OR OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY INFORMATION OR TO MAKE ANY REPRESENTATION NOT CONTAINED IN THIS PROSPECTUS, AND, IF GIVEN OR MADE, SUCH INFORMATION OR REPRESENTATION MUST NOT BE RELIED UPON AS HAVING BEEN AUTHORIZED BY THE COMPANY OR ANY UNDERWRITER. THIS PROSPECTUS DOES NOT CONSTITUTE AN OFFER TO SELL OR A SOLICITATION OF AN OFFER TO BUY ANY OF THE SECURITIES OFFERED HEREBY IN ANY JURISDICTION TO ANY PERSON TO WHICH IT IS UNLAWFUL TO MAKE SUCH OFFER IN SUCH JURISDICTION. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR ANY SALE MADE HEREUNDER SHALL, UNDER ANY CIRCUMSTANCES, CREATE ANY IMPLICATION THAT THE INFORMATION CONTAINED HEREIN IS CORRECT AS OF ANY TIME SUBSEQUENT TO THE DATE HEREOF OR THAT THERE HAS BEEN NO CHANGE IN THE AFFAIRS OF THE COMPANY SINCE SUCH DATE.
IN THIS PROSPECTUS, REFERENCES TO "DOLLARS" AND "$" ARE TO UNITED STATES
DOLLARS.
IN CONNECTION WITH THE COMMON STOCK OFFERING, CS FIRST BOSTON CORPORATION ON BEHALF OF THE U.S. UNDERWRITERS AND MANAGERS MAY OVER-ALLOT OR EFFECT TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICE OF THE COMMON STOCK AT A LEVEL ABOVE THAT WHICH MIGHT OTHERWISE PREVAIL IN THE OPEN MARKET. SUCH TRANSACTIONS MAY BE EFFECTED ON THE NEW YORK STOCK EXCHANGE OR OTHERWISE. SUCH STABILIZING, IF COMMENCED, MAY BE DISCONTINUED AT ANY TIME.
DURING THE COMMON STOCK OFFERING, CERTAIN PERSONS AFFILIATED WITH PERSONS PARTICIPATING IN THE DISTRIBUTION MAY ENGAGE IN TRANSACTIONS FOR THEIR OWN ACCOUNTS OR FOR THE ACCOUNTS OF OTHERS IN THE COMMON STOCK PURSUANT TO EXEMPTIONS FROM RULES 10B-6, 10B-7, AND 10B-8 UNDER THE SECURITIES EXCHANGE ACT OF 1934.
TABLE OF CONTENTS

                                            PAGE
                                            ----
Prospectus Summary........................    3
Risk Factors..............................    8
Use of Proceeds...........................   17
Dividend Policy...........................   17
Capitalization............................   18
Dilution..................................   19
Selected Consolidated Financial Data......   20
Pro Forma Consolidated Financial Data.....   22
Management's Discussion and Analysis of
  Financial Condition and Results of
  Operations..............................   29
Business..................................   38
Management................................   70

                                            PAGE
                                            ----
Certain Transactions......................   80
Principal and Selling Stockholders........   82
Description of Capital Stock..............   83
Shares Eligible for Future Sale...........   85
Certain United States Federal Tax
  Consequences to Non-U.S. Holders........   86
Subscription and Sale.....................   89
Notice to Canadian Residents..............   92
Legal Matters.............................   92
Experts...................................   93
Available Information.....................   93
Consolidated Financial Statements.........  F-1	

A-2

ALTERNATE PAGE A-3
Common Stock could be subject to wide fluctuations in response to quarter-to-quarter variations in operating results, announcements of new acquisitions or power projects by the Company or its competitors, general conditions in the independent power production industry, and other events or factors. In addition, stock markets have experienced extreme price and trading volume volatility in recent years. This volatility has had a substantial effect on the market prices of securities of many companies for reasons frequently unrelated to the operating performance of the specific companies. These broad market fluctuations may adversely affect the market price of the Company's Common Stock. Moreover, investors in the Common Stock Offering will incur immediate, substantial book value dilution. See "Dilution" and "Subscription and Sale."
QUARTERLY FLUCTUATIONS; SEASONALITY
The Company's quarterly operating results have fluctuated in the past and may continue to do so in the future as a result of a number of factors, including but not limited to the timing and size of acquisitions, the completion of development projects, the timing and amount of curtailment, and variations in levels of production. Furthermore, the majority of capacity payments under certain of the Company's power sales agreements are received during the months of May through October. The market price of the Common Stock could be subject to significant fluctuations in response to those variations in quarterly operating results and other factors. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Quarterly Results of Operations and Seasonality."
SHARES ELIGIBLE FOR FUTURE SALE
Sales of substantial amounts of Common Stock in the public market after the Common Stock Offering could adversely affect the prevailing market price of the Common Stock. Other than the 18,045,000 shares of Common Stock offered hereby, there will be no shares of Common Stock outstanding immediately following the completion of the Common Stock Offering. All of the shares of Common Stock sold in the Common Stock Offering will be freely transferable without registration or further registration under the Securities Act of 1933, as amended (the "Securities Act"), unless held by an "affiliate" of the Company (as defined in the Securities Act). As of the date of this Prospectus, options to purchase 2,392,026 shares of Common Stock were outstanding under the Company's Stock Option Program. Of such amount, options to purchase 1,366,696 shares were exercisable, all of which will become eligible for sale 180 days after the date of this Prospectus, upon expiration of certain lock-up agreements with the Underwriters and pursuant to Rule 701, subject in some cases to certain volume and other resale restrictions. See "Shares Eligible for Future Sale."
A-3

ALTERNATE PAGE A-4
Rule 144 and (ii) by Affiliates, beginning 90 days after the date of this Prospectus, subject to all provisions of Rule 144 except its two-year minimum holding period.
LOCK-UP AGREEMENTS
All holders of options to purchase shares of Common Stock have agreed with the Underwriters that they will not, without the prior written consent of CS First Boston, offer, sell, contract to sell or otherwise dispose of any shares of Common Stock beneficially owned by them or any shares issuable upon exercise of stock options for a period of 180 days from the date of this Prospectus. See "Subscription and Sale."
CERTAIN UNITED STATES FEDERAL TAX CONSEQUENCES
TO NON-U.S. HOLDERS
The following is a general discussion of certain United States federal income and estate tax consequences of an investment in Common Stock by a holder that, for United States federal income tax purposes, is not a "United States person" (a "Non-U.S. Holder"). For purposes of this discussion, a "United States person" means a citizen or resident (as defined for United States federal income and estate tax purposes, as the case may be) of the United States, a corporation or partnership created or organized in the United States or under the laws of the United States or of any State thereof or an estate or trust whose income is includible in gross income for United States federal income tax purposes regardless of its source. The discussion is based on the United States Internal Revenue Code of 1986, as amended (the "Code"). Treasury regulations promulgated thereunder, and judicial and administrative interpretations thereof, all as in effect on the date hereof and all of which are subject to change, possibly retroactively, and is for general information only. The discussion does not address aspects of United States federal taxation other than income and estate taxation and does not address all aspects of United States federal income and estate taxation. The discussion does not consider any specific facts or circumstances that may apply to a particular Non-U.S. Holder. PROSPECTIVE INVESTORS ARE URGED TO CONSULT THEIR TAX ADVISORS WITH RESPECT TO THE UNITED STATES FEDERAL, STATE, LOCAL AND NON-U.S. INCOME AND OTHER TAX CONSEQUENCES TO THEM OF AN INVESTMENT IN COMMON STOCK.
DIVIDENDS
Dividends paid to a Non-U.S. Holder will generally be subject to withholding of United States federal income tax at a rate equal to 30% of the gross amount of the distribution (or at a lower rate prescribed by an applicable tax treaty) unless the dividends are effectively connected with the conduct of a trade or business within the United States by the Non-U.S. Holder, in which case the dividends generally will not be subject to withholding (if the Non-U.S. Holder files certain forms with the payor of the dividend) and generally will be subject to the United States federal income tax on net income that applies to United States persons generally (and, in the case of corporate holders, effectively connected dividends may also, under certain circumstances, be subject to the branch profits tax at a 30% rate or such lower rate as may be specified by an applicable income tax treaty). An applicable income tax treaty may, however, change these rules. To determine the applicability of a tax treaty providing for a lower rate of withholding, dividends paid to an address in a foreign country are presumed under current interpretation of existing Treasury regulations to be paid to a resident of that country. Treasury regulations proposed to be effective for payments made after December 31, 1997, which have not been finally adopted, however, would require Non-U.S. Holders to file certain new forms to obtain the benefit of any applicable tax treaty providing for a lower rate of withholding tax on dividends. Such forms would contain the holder's name and address and certain other information.
The gross amount of a distribution with respect to Common stock will be treated as a dividend to the extent of the Company's current and accumulated earnings and profits as determined for U.S. federal income tax purposes. In the event that such a distribution exceeds the amount of the Company's earnings and profits, it will be treated first as a non-taxable return of capital to the extent of the Non-U.S. Holder's basis in Common Stock (but not below zero), and thereafter as capital gain. A Non-U.S. Holder will have to file a refund claim to obtain a refund of tax withheld on distributions in excess of the dividend portion of any distribution.
A-4

ALTERNATE PAGE A-5
SUBSCRIPTION AND SALE
The institutions named below (the "Managers") have, pursuant to a Subscription Agreement dated , 1996 (the "Subscription Agreement"), severally and not jointly, agreed with Calpine and the Selling Stockholder to subscribe and pay for the following respective numbers of International Shares as set forth opposite their names:

                                                                                   NUMBER OF
                                 MANAGER                                      INTERNATIONAL SHARES
- --------------------------------------------------------------------------    --------------------
CS First Boston Limited...................................................
Morgan Stanley & Co. International Limited................................
PaineWebber International (U.K.) Limited..................................
Salomon Brothers International Limited....................................
                                                                              --------------------
          Total...........................................................          3,609,000
                                                                               ==============	

The Subscription Agreement provides that the obligations of the Managers are subject to certain conditions precedent and the Managers will be obligated to purchase all of the International Shares offered hereby (other than those shares covered by the over-allotment option described below) if any are purchased. The Subscription Agreement provides that, in the event of a default by a Manager, in certain circumstances the purchase commitments of the non-defaulting managers may be increased or the Subscription Agreement may be terminated.
Calpine has entered into an Underwriting Agreement (the "Underwriting Agreement") with the U.S. Underwriters of the U.S. Offering (the "U.S. Underwriters" and, together with the Managers, the "Underwriters") providing for the concurrent offer and sale of the U.S. Shares in the United States and Canada. The closing of the U.S. Offering is a condition to the closing of the International Offering and vice versa.
Calpine has granted to the Managers and the U.S. Underwriters an option, exercisable by CS First Boston Corporation, expiring at the close of business on the 30th day after the date of this Prospectus to purchase up to 2,706,750 additional shares at the initial public offering price, less the underwriting discounts and commissions, all as set forth on the cover page of this Prospectus. Such option may be exercised only to cover over-allotments in the sale of the shares of Common Stock offered hereby. To the extent that this option to purchase is exercised, each Manager and each U.S. Underwriter will become obligated, subject to certain conditions, to purchase approximately the same percentage of additional shares being sold to the Managers and the U.S. Underwriters as the number of International Shares set forth next to such Manager's name in the preceding table and as the number set forth next to such U.S. Underwriter's name in the corresponding table in the Prospectus relating to the U.S. Offering bears to the sum of the total number of shares of Common Stock in such tables.
Calpine has been advised by CS First Boston Limited, on behalf of the Managers, that the Managers propose to offer the International Shares outside the United States and Canada initially at the public offering price set forth on the cover page of this Prospectus and, through the Managers, to certain dealers at such price less a commission of $ per share and that the Managers and such dealers may reallow a commission of $ per share on sales to certain other dealers. After the initial public offering, the public offering price and commission and reallowances may be changed by the Managers.
The offering price and the aggregate underwriting discounts and commissions per share and per share commission and re-allowance to dealers for the International Offering and the concurrent U.S. Offering will be identical. Pursuant to an Agreement between the U.S. Underwriters and Managers (the "Intersyndicate Agreement") relating to the Common Stock Offering, changes in the offering price, the aggregate underwriting discounts and commissions per share and per share commission and reallowance to dealers will be made
A-5

ALTERNATE PAGE A-6
only upon the mutual agreement of CS First Boston Limited, on behalf of the Managers, and CS First Boston Corporation, on behalf of the U.S. Underwriters.
Pursuant to the Intersyndicate Agreement, each of the Managers has agreed that, as part of the distribution of International Shares and subject to certain exceptions, it has not offered or sold, and will not offer or sell, directly or indirectly, any shares of Common Stock or distribute any prospectus relating to the Common Stock in the United States or Canada or to any other dealer who does not so agree. Each of the U.S. Underwriters has agreed that, as part of the distribution of the U.S. Shares and subject to certain exceptions, it has not offered or sold and will not offer or sell, directly or indirectly, any shares of Common Stock or distribute any prospectus relating to the Common Stock to any person outside the United States and Canada or to any other dealer who does not so agree. The foregoing limitations do not apply to stabilization transactions or to transactions between the Managers and the U.S. Underwriters pursuant to the Intersyndicate Agreement. As used herein, "United States" means the United States of America (including the State and the District of Columbia), its territories, possessions and other areas subject to its jurisdiction. "Canada" means Canada, its provinces, territories, possessions and other areas subject to its jurisdiction, and an offer or sale shall be in the United States or Canada if it is made to (i) any individual resident in the United States or Canada or
(ii) any corporation, partnership, pension, profit-sharing or other trust or other entity (including any such entity acting as an investment adviser with discretionary authority) whose office most directly involved with the purchase is located in the United States or Canada.
Pursuant to the Intersyndicate Agreement, sales may be made between the Managers and the U.S. Underwriters of such number of shares of Common Stock as may be mutually agreed upon. The price of any shares so sold will be the public offering price less such amount agreed upon by CS First Boston Limited, on behalf of the Managers, and CS First Boston Corporation, as representative of the U.S. Underwriters, but not exceeding the selling concession applicable to such shares. To the extent there are sales between the Managers and the U.S. Underwriters pursuant to the Intersyndicate Agreement, the number of shares of Common Stock initially available for sale by the Managers or by the U.S. Underwriters may be more or less than the amount appearing on the cover page of this Prospectus. Neither the Managers nor the U.S. Underwriters are obligated to purchase from the other any unsold shares of Common Stock.
Each of the Managers and the U.S. Underwriters severally represents and agrees that: (i) it has not offered or sold and, prior to the date six months after the date of issue of the Common Stock will not offer or sell, any Common Stock to persons in the United Kingdom except to persons whose ordinary activities involve them in acquiring, holding, managing or disposing of investments (as principal or agent) for the purposes of their businesses or otherwise in circumstances which do not constitute an offer to the public in the United Kingdom for the purposes of the Public Offers of Securities Regulations 1995; (ii) it has complied and will comply with all applicable provisions of the Public Offers of Securities Regulations 1995 and the Financial Services Act 1986 with respect to anything done by it in relation to the Common Stock in, from or otherwise involving the United Kingdom; and (iii) it has only issued or passed on and will only issue or pass on in the United Kingdom any document in connection with the issue or sale of the Common Stock to a person who is of a kind described in Article 11(3) of the Financial Services Act 1986 (Investment Advertisements) (Exemptions) Order 1996 or is a person to whom such document may otherwise lawfully be issued or passed on.
Calpine has agreed that it will not offer, sell, contract to sell, announce its intention to sell, pledge or otherwise dispose of, directly or indirectly, or file with the Securities and Exchange Commission a registration statement under the Securities Act (other than a registration statement on Form S-8) relating to, any additional shares of its Common Stock or securities convertible into or exchangeable or exercisable for any shares of its Common Stock without the prior written consent of CS First Boston Corporation for a period of 180 days after the date of this Prospectus, except issuances pursuant to the exercise of employee stock options outstanding on the date hereof. In addition, all holders of options to purchase shares of Common Stock have agreed that they will not, without the prior written consent of CS First Boston Corporation, offer, sell, contract to sell or otherwise dispose of any shares of Common Stock beneficially owned by them or any shares issuable upon exercise of stock options for a period of 180 days after the date of this Prospectus.
A-6

ALTERNATE PAGE A-7
Calpine has agreed to indemnify the Managers and the U.S. Underwriters against certain liabilities, including civil liabilities under the Securities Act, or to contribute to payments that the Managers and the U.S. Underwriters may be required to make in respect thereof.
CS First Boston Corporation, one of the U.S. Underwriters, is an affiliate of the Company. The Common Stock Offering therefore is being conducted in accordance with the applicable provisions of Rule 2720 to the Conduct Rules of the National Association of Securities Dealers, Inc. Rule 2720 requires that the initial public offering price of the Common Stock not be higher than that recommended by a "qualified independent underwriter" meeting certain standards. Accordingly, PaineWebber Incorporated is assuming the responsibilities of acting as the qualified independent underwriter in pricing the Common Stock Offering and conducting due diligence. The initial public offering price of the Common Stock set forth on the cover page of this Prospectus is no higher than the price recommended by PaineWebber Incorporated.
In connection with the Common Stock Offering, PaineWebber Incorporated in its role as qualified independent underwriter has performed due diligence investigations and reviewed and participated in the preparation of this Prospectus and the Registration Statement of which this Prospectus forms a part. In addition, the Underwriters may not confirm sales to any discretionary account without the prior specific written approval of the customer.
The decision made by CS First Boston Corporation and CS First Boston Limited to underwrite the Common Stock Offering was made independently of the Company, CS Holding and Electrowatt. The net proceeds from the Common Stock Offering will not be applied for the benefit of CS First Boston Corporation or CS First Boston Limited. CS First Boston Corporation and CS First Boston Limited will not receive any benefit from the Common Stock Offering other than their respective portion of the underwriting discounts and commissions.
The Common Stock has been approved for listing on the New York Stock Exchange, subject to notice of issuance, under the symbol "CPN." In connection with the listing of the Common Stock on the New York Stock Exchange, the Underwriters have undertaken to sell round lots of 100 shares or more to a minimum of 2,000 beneficial holders.
Prior to the Common Stock Offering, there has been no public market for the shares of Common Stock offered hereby. The initial public offering price for the shares was determined by negotiations among the Company, the Selling Stockholder and CS First Boston Corporation, as one of the Representatives of the U.S. Underwriters, and by CS First Boston Limited, on behalf of the Managers, and does not necessarily reflect the secondary market prices for the Common Stock following the initial offering hereby. Among the principal factors considered in determining the initial public offering price were prevailing economic prospects, the sales, earnings and financial and operating performance of the Company in recent periods, the future prospects of the Company, market valuations of companies in related businesses and the history and prospects for the industries in which the Company competes. Additionally, consideration has been given to the general condition of the securities markets, the market for new issues of securities and the demand for securities of comparable companies.
In the ordinary course of their business, CS First Boston Corporation and certain of the other Underwriters and their affiliates have engaged in and may in the future engage in investment banking transactions with Calpine, including the provision of certain advisory services to Calpine. CS Holding, a Swiss corporation, holds approximately 44.9% of the outstanding shares of Electrowatt, which indirectly holds all of the outstanding capital stock of the Company. CS Holding also holds (i) approximately 100% of the outstanding shares of Credit Suisse and (ii) approximately 69.3% of the outstanding common stock of CS First Boston, Inc., which holds all of the outstanding common stock of CS First Boston Corporation and of CSFBL. CS First Boston Corporation was one of the Underwriters in connection with the public offering of the Company's 9 1/4% Senior Notes in February 1994, one of the placement agents in connection with the sale of the 10 1/2% Senior Notes in May 1996 and is one of the Representatives of the U.S. Underwriters in the U.S. Offering, and CSFBL is one of the Managers in the International Offering. See "Certain Transactions."
A-7

ALTERNATE PAGE A-8

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

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

A-8

PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
ITEM 13. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION
The following table sets forth the various expenses expected to be incurred by the Registrant in connection with the sale and distribution of the securities being registered hereby, other than underwriting discounts and commissions. All amounts are estimated except the Securities and Exchange Commission registration fee, the NASD filing fee and the NYSE listing application fee.

SEC registration fee......................................................  $150,272
NASD filing fee...........................................................    30,500
NYSE listing application fee..............................................    93,200
Transfer Agent fees and expenses..........................................    10,000
Printing and engraving expenses...........................................   125,000
Legal fees and expenses...................................................   175,000
Blue Sky fees and expenses................................................    25,500
Accounting fees and expenses..............................................   175,000
Miscellaneous.............................................................    24,528
                                                                            --------
          Total...........................................................  $809,000
                                                                            ========	

ITEM 14. INDEMNIFICATION OF DIRECTORS AND OFFICERS
Section 145 of the Delaware General Corporation Law authorizes a court to award or a corporation's Board of Directors to grant indemnification to directors and officers in terms sufficiently broad to permit such indemnification under certain circumstances for liabilities (including reimbursement for expenses incurred) arising under the Securities Act of 1933, as amended (the "Securities Act"). Article X of the Registrant's Bylaws provides for mandatory indemnification of its directors and officers and permissible indemnification of employees and other agents to the maximum extent permitted by the Delaware General Corporation Law. The Registrant's Certificate of Incorporation provides that, pursuant to Delaware law, its directors shall not be liable for monetary damages for breach of the directors' fiduciary duty as directors to the Company and its stockholders. This provision in the Certificate of Incorporation does not eliminate the directors' fiduciary duty, and in appropriate circumstances equitable remedies such as injunctive or other forms of non-monetary relief will remain available under Delaware law. In addition, each director will continue to be subject to liability for breach of the director's duty of loyalty to the Company for acts or omissions not in good faith or involving intentional misconduct, for knowing violations of law, for actions leading to improper personal benefit to the director, and for payment of dividends or approval of stock repurchases or redemptions that are unlawful under Delaware law. The provision also does not affect a director's responsibilities under any other law, such as the federal securities laws or state or federal environmental laws. The Registrant has entered into Indemnification Agreements with its officers and directors, a form of which is attached as Exhibits 10.11 and 10.12 hereto and incorporated herein by reference. The Indemnification Agreements provide the Registrant's officers and directors with further indemnification to the maximum extent permitted by the Delaware General Corporation Law. Reference is also made to Section 7 of the Underwriting Agreement contained in Exhibit 1.1 hereto, indemnifying officers and directors of the Registrant against certain liabilities.
ITEM 15. RECENT SALES OF UNREGISTERED SECURITIES.
On March 21, 1996, the Company issued and sold 5,000,000 shares of its Series A Preferred Stock to Electrowatt Ltd for an aggregate purchase price of $50.0 million pursuant to Section 4(2) under the Securities Act of 1933, as amended.
On May 16, 1996, the Company issued and sold $180,000,000 aggregate principal amount of 10 1/2% Senior Notes Due 2006 to certain institutional and accredited investors pursuant to Rule 144A under the Securities Act of 1933, as amended.
II-1

ITEM 16. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
EXHIBITS

 EXHIBIT
  NUMBER                                        DESCRIPTION
- ----------   ---------------------------------------------------------------------------------
 1.1**       Form of Underwriting Agreement.
 1.2**       Form of Subscription Agreement.
 3.1         Amended and Restated Articles of Incorporation of Calpine Corporation, a
             California corporation.(k)
 3.2**       Form of Amended and Restated Certificate of Incorporation of Calpine Corporation,
             a Delaware corporation, to be filed prior to the consummation of the offering
             made pursuant to this Registration Statement.
 3.3         Amended and Restated Bylaws of Calpine Corporation, a California corporation.(a)
 3.4**       Form of Amended and Restated Bylaws of Calpine Corporation, a Delaware
             corporation, to be adopted prior to the consummation of the offering made
             pursuant to this Registration Statement.
 4.1         Indenture dated as of February 17, 1994 between the Company and Shawmut Bank of
             Connecticut, National Association, as Trustee, including form of Notes.(a)
 4.2         Indenture dated as of May 16, 1996 between the Company and Fleet National Bank,
             as Trustee, including form of Notes.(l)
 4.3*        Specimen Common Stock Certificate.
 4.4**       Form of Agreement and Plan of Merger Between Calpine Corporation, a Delaware
             corporation, and Calpine Corporation, a California corporation.
 5.1**       Opinion of Brobeck, Phleger & Harrison LLP.
10.1         Financing Agreements
10.1.1       Term and Working Capital Loan Agreement, dated as of June 1, 1990, between
             Calpine Geysers Company, L.P. (formerly Santa Rosa Geothermal Company, L.P.), and
             Deutsche Bank AG, New York Branch.(a)
10.1.2       First Amendment to Term and Working Capital Loan Agreement, dated as of June 29,
             1990, between Calpine Geysers Company, L.P. (formerly Santa Rosa Geothermal
             Company, L.P.), and Deutsche Bank AG, New York Branch.(a)
10.1.3       Second Amendment to Term and Working Capital Loan Agreement, dated as of December
             1, 1990, between Calpine Geysers Company, L.P. (formerly Santa Rosa Geothermal
             Company, L.P.), and Deutsche Bank AG, New York Branch.(a)
10.1.4       Third Amendment to Term and Working Capital Loan Agreement, dated as of June 26,
             1992, between Calpine Geysers Company, L.P. (formerly Santa Rosa Geothermal
             Company, L.P.), Deutsche Bank AG, New York Branch, National Westminster Bank PLC,
             Union Bank of Switzerland, New York Branch, and The Prudential Insurance Company
             of America.(a)
10.1.5       Fourth Amendment to Term and Working Capital Loan Agreement, dated as of April 1,
             1993, between Calpine Geysers Company, L.P. (formerly Santa Rosa Geothermal
             Company, L.P.), Deutsche Bank AG, New York Branch, National Westminster Bank PLC,
             Union Bank of Switzerland, New York Branch, and The Prudential Insurance Company
             of America.(a)
10.1.6       Construction and Term Loan Agreement, dated as of January 30, 1992, between Sumas
             Cogeneration Company, L.P., The Prudential Insurance Company of America, and
             Credit Suisse, New York Branch.(a)
10.1.7       Amendment No. 1 to Construction and Term Loan Agreement, dated as of May 24,
             1993, between Sumas Cogeneration Company, L.P., The Prudential Insurance Company
             of America, and Credit Suisse, New York Branch.(a)
10.1.8       Credit Agreement-Construction Loan and Term Loan Facility, dated as of January
             10, 1990, between Credit Suisse and O.L.S. Energy-Agnews.(a)
10.1.9       Amendment No. 1 to Credit Agreement-Construction Loan and Term Loan Facility,
             dated as of December 5, 1990, between Credit Suisse and O.L.S. Energy-Agnews.(a)	

II-2

 EXHIBIT
  NUMBER                                        DESCRIPTION
- ----------   ---------------------------------------------------------------------------------
10.1.10      Participation Agreement, dated as of December 1, 1990, between O.L.S.
             Energy-Agnews, Nynex Credit Company, Credit Suisse, Meridian Trust Company of
             California, and GATX Capital Corporation.(a)
10.1.11      Facility Lease Agreement, dated as of December 1, 1990, between Meridian Trust
             Company of California and O.L.S. Energy-Agnews.(a)
10.1.12      Project Revenues Agreement, dated as of December 1, 1990, between O.L.S.
             Energy-Agnews, Meridian Trust Company of California and Credit Suisse.(a)
10.1.13      Credit Agreement, dated as of September 9, 1994, between Calpine Thermal Power,
             Inc., Thermal Power Company and The Bank of Nova Scotia.(b)
10.1.14      Project Credit Agreement, dated as of June 30, 1995, between Calpine Greenleaf
             Corporation, Greenleaf Unit One Associates, Greenleaf Unit Two Associates, Inc.
             and The Sumitomo Bank, Limited.(g)
10.1.15      Lease dated as of April 24, 1996 between BAF Energy A California Limited
             Partnership, Lessor, and Calpine King City Cogen, LLC, Lessee.(j)
10.1.16*     Credit Agreement, dated as of August 28, 1996, among Calpine Gilroy Cogen, L.P.
             and Banque Nationale de Paris.
10.2         Purchase Agreements
10.2.1       Purchase Agreement, dated as of April 1, 1993, between Sonoma Geothermal
             Partners, L.P., Healdsburg Energy Company, L.P., and Freeport-McMoRan Resource
             Partners, Limited Partnership.(a)
10.2.2       Stock Purchase Agreement, dated as of June 27, 1994, between Maxus International
             Energy Company, Natomas Energy Company, Calpine Corporation and Calpine Thermal
             Power, Inc. and amendment thereto dated July 28, 1994.(b)
10.2.3       Share Purchase Agreement dated March 30, 1995 between Calpine Corporation,
             Calpine Greenleaf Corporation, Radnor Power Corp. and LFC Financial Corp.(e)
10.2.4       Asset Purchase Agreement, dated as of August 28, 1996, among Gilroy Energy
             Company, McCormick & Company, Incorporated and Calpine Gilroy Cogen, L.P. (m)
10.2.5       Noncompetition/Earnings Contingency Agreement, dated as of August 28, 1996, among
             Gilroy Energy Company, McCormick & Company, Incorporated and Calpine Gilroy
             Cogen, L.P. (m)
10.3         Power Sales Agreements
10.3.1       Long-Term Energy and Capacity Power Purchase Agreement relating to the Bear
             Canyon Facility, dated November 30, 1984, between Pacific Gas & Electric and
             Calpine Geysers Company, L.P. (formerly Santa Rosa Geothermal Company, L.P.),
             Amendment dated October 17, 1985, Second Amendment dated October 19, 1988, and
             related documents.(a)
10.3.2       Long-Term Energy and Capacity Power Purchase Agreement relating to the Bear
             Canyon Facility, dated November 29, 1984, between Pacific Gas & Electric and
             Calpine Geysers Company, L.P. (formerly Santa Rosa Geothermal Company, L.P.), and
             Modification dated November 29, 1984, Amendment dated October 17, 1985, Second
             Amendment dated October 19, 1988, and related documents.(a)
10.3.3       Long-Term Energy and Capacity Power Purchase Agreement relating to the West Ford
             Flat Facility, dated November 13, 1984, between Pacific Gas & Electric and
             Calpine Geysers Company, L.P. (formerly Santa Rosa Geothermal Company, L.P.), and
             amendments dated May 18, 1987, June 22, 1987, July 3, 1987 and January 21, 1988,
             and related documents.(a)
10.3.4       Agreement for Firm Power Purchase, dated as of February 24, 1989, between Puget
             Sound Power & Light Company and Sumas Energy, Inc. and amendment thereto dated
             September 30, 1991.(a)
10.3.5       Long-Term Energy and Capacity Power Purchase Agreement, dated April 16, 1985,
             between O.L.S. Energy-Agnews and Pacific Gas & Electric Company and amendment
             thereto dated February 24, 1989.(a)	

II-3

 EXHIBIT
  NUMBER                                        DESCRIPTION
- ----------   ---------------------------------------------------------------------------------
10.3.6       Long-Term Energy and Capacity Power Purchase Agreement, dated November 15, 1984,
             between Geothermal Energy Partners, Ltd., and Pacific Gas & Electric Company and
             related documents.(a)
10.3.7       Long-Term Energy and Capacity Power Purchase Agreement, dated November 15, 1984,
             between Geothermal Energy Partners, Ltd., and Pacific Gas & Electric Company (see
             Exhibit 10.3.6 for related documents).(a)
10.3.8       Long-Term Energy and Capacity Power Purchase Agreement, dated December 12, 1984,
             between Greenleaf Unit One Associates, Inc. and Pacific Gas and Electric
             Company.(f)
10.3.9       Long-Term Energy and Capacity Power Purchase Agreement, dated December 12, 1984,
             between Greenleaf Unit Two Associates, Inc. and Pacific Gas and Electric
             Company.(f)
10.3.10*     Long-Term Energy and Capacity Power Purchase Agreement, dated December 5, 1985,
             between Calpine Gilroy Cogen, L.P. and Pacific Gas and Electric Company, and
             amendments thereto dated December 19, 1993, July 18, 1985, June 9, 1986, August
             18, 1988 and June 9, 1991.
10.4         Steam Sales Agreements
10.4.1       Geothermal Steam Sales Agreement, dated July 19, 1979, between Calpine Geysers
             Company, L.P. (formerly Santa Rosa Geothermal Company, L.P.), and Sacramento
             Municipal Utility District and related documents.(a)
10.4.2       Agreement for the Sale and Purchase of Geothermal Steam, dated March 23, 1973,
             between Calpine Geysers Company, L.P. (formerly Santa Rosa Geothermal Company,
             L.P.), and Pacific Gas & Electric Company and related letter dated May 18,
             1987.(a)
10.4.3       Thermal Energy and Kiln Lease Agreement, dated as of January 16, 1992, between
             Sumas Cogeneration Company, L.P., and Socco, Inc. and amendment thereto dated May
             24, 1993.(a)
10.4.4       Amended and Restated Energy Service Agreement, dated as of December 1, 1990,
             between the State of California and O.L.S. Energy-Agnews.(a)
10.4.5       Agreement for the Sale of Geothermal Steam, dated as of July 28, 1992, between
             Thermal Power Company and Pacific Gas & Electric Company.(c)
10.4.6       Amendment to the Agreement for the Sale of Geothermal Steam, dated as of August
             9, 1995, between Union Oil Company of California, NEC Acquisition Company,
             Thermal Power Company, and Pacific Gas and Electric Company.(h)
10.5         Service Agreements
10.5.1       Operation and Maintenance Agreement, dated as of April 5, 1990, between Calpine
             Operating Plant Services, Inc. (formerly Calpine-Geysers Plant Services, Inc.),
             and Calpine Geysers Company, L.P. (formerly Santa Rosa Geothermal Company,
             L.P.).(a)
10.5.2       Amended and Restated Operating and Maintenance Agreement, dated as of January 24,
             1992, between Calpine Operating Plant Services, Inc. and Sumas Cogeneration
             Company, L.P.(a)
10.5.3       Amended and Restated Operation and Maintenance Agreement, dated as of December
             31, 1990, between O.L.S. Energy-Agnews and Calpine Operating Plant Services, Inc.
             (formerly Calpine Cogen-Agnews, Inc.).(a)
10.5.4       Operating and Maintenance Agreement, dated as of January 1, 1995, between Calpine
             Corporation and Geothermal Energy Partners, Ltd.(h)
10.5.5       Amended and Restated Operating Agreement for the Geysers, dated as of December 1,
             1993, by and between Magma-Thermal Power Project, a joint venture composed of NEC
             Acquisition Company and Thermal Power Company, and Union Oil Company of
             California.(c)
10.6         Gas Supply Agreements
10.6.1       Gas Sale and Purchase Agreement, dated as of December 23, 1991, between ENCO Gas,
             Ltd. and Sumas Cogeneration Company, L.P.(a)
10.6.2       Gas Management Agreement, dated as of December 23, 1991, between Canadian
             Hydrocarbons Marketing Inc., ENCO Gas, Ltd. and Sumas Cogeneration Company,
             L.P.(a)
10.6.4       Natural Gas Sales Agreement, dated as of November 1, 1993, between O.L.S.
             Energy-Agnews, Inc. and Amoco Energy Trading Corporation.(a)	

II-4

 EXHIBIT
  NUMBER                                        DESCRIPTION
- ----------   ---------------------------------------------------------------------------------
10.6.5       Natural Gas Service Agreement, dated November 1, 1993, between Pacific Gas &
             Electric Company and O.L.S. Energy-Agnews, Inc.(a)
10.7         Agreements Regarding Real Property
10.7.1       Office Lease, dated March 15, 1991, between 50 West San Fernando Associates,
             L.P., and Calpine Corporation.(a)
10.7.2       First Amendment to Office Lease, dated April 30, 1992, between 50 West San
             Fernando Associates, L.P. and Calpine Corporation.(a)
10.7.3       Geothermal Resources Lease CA 1862, dated July 25, 1974, between the United
             States Bureau of Land Management and Calpine Geysers Company, L.P. (formerly
             Santa Rosa Geothermal Company, L.P.).(a)
10.7.4       Geothermal Resources Lease PRC 5206.2, dated December 14, 1976, between the State
             of California and Calpine Geysers Company, L.P. (formerly Santa Rosa Geothermal
             Company, L.P.).(a)
10.7.5       First Amendment to Geothermal Resources Lease PRC 5206.2, dated April 20, 1994,
             between the State of California and Calpine Geysers Company, L.P. (formerly Santa
             Rosa Geothermal Company, L.P.).(a)
10.7.6       Industrial Park Lease Agreement, dated December 18, 1990, between Port of
             Bellingham and Sumas Energy, Inc.(a)
10.7.7       First Amendment to Industrial Park Lease Agreement, dated as of July 16, 1991,
             between Port of Bellingham, Sumas Energy, Inc., and Sumas Cogeneration Company,
             L.P.(a)
10.7.8       Second Amendment to Industrial Park Lease Agreement, dated as of December 17,
             1991 between Port of Bellingham and Sumas Cogeneration Company, L.P.(a)
10.7.9       Amended and Restated Cogeneration Lease, dated as of December 1, 1990, between
             the State of California and O.L.S. Energy-Agnews.(a)
10.8         General
10.8.1       Limited Partnership Agreement of Sumas Cogeneration Company, L.P., dated as of
             August 28, 1991, between Sumas Energy, Inc. and Whatcom Cogeneration Partners,
             L.P.(a)
10.8.2       First Amendment to Limited Partnership Agreement of Sumas Cogeneration Company,
             L.P., dated as of January 30, 1992, between Whatcom Cogeneration Partners, L.P.,
             and Sumas Energy, Inc.(a)
10.8.3       Second Amendment to Limited Partnership Agreement of Sumas Cogeneration Company,
             L.P., dated as of May 24, 1993, between Whatcom Cogeneration Partners, L.P., and
             Sumas Energy, Inc.(a)
10.8.4       Second Amended and Restated Shareholders' Agreement, dated as of October 22,
             1993, among GATX Capital Corporation, Calpine Agnews, Inc., JGS-Agnews, Inc., and
             GATX/Calpine-Agnews, Inc.(a)
10.8.5       Amended and Restated Reimbursement Agreement, dated October 22, 1993, between
             GATX Capital Corporation, Calpine Agnews, Inc., JGS-Agnews, Inc.,
             GATX/Calpine-Agnews, Inc., and O.L.S. Energy-Agnews, Inc.(a)
10.8.6       Amended and Restated Limited Partnership Agreement of Geothermal Energy Partners
             Ltd., L.P., dated as of May 19, 1989, between Western Geothermal Company, L.P.,
             Sonoma Geothermal Company, L.P., and Cloverdale Geothermal Partners, L.P.(a)
10.8.7       Assignment and Security Agreement, dated as of January 10, 1990, between O.L.S.
             Energy-Agnews and Credit Suisse.(a)
10.8.8       Pledge Agreement, dated as of January 10, 1990, between GATX/Calpine-Agnews,
             Inc., and Credit Suisse.(a)
10.8.9       Equity Support Agreement, dated as of January 10, 1990, between Calpine
             Corporation and Credit Suisse.(a)
10.8.10      Assignment and Security Agreement, dated as of December 1, 1990, between O.L.S.
             Energy-Agnews and Meridian Trust Company of California.(a)	

II-5

 EXHIBIT
  NUMBER                                        DESCRIPTION
- ----------   ---------------------------------------------------------------------------------
10.8.11      Calpine Subordination Agreement, dated as of April 1, 1993, between
             Freeport-McMoRan Resource Partners, L.P., Calpine Corporation, Sonoma Geothermal
             Partners, L.P., Calpine Sonoma, Inc., Healdsburg Energy Company, L.P., and
             Calpine Geysers Company, L.P. (formerly Santa Rosa Energy Company, L.P.).(a)
10.8.12      First Amended and Restated Limited Partner Pledge and Security Agreement, dated
             as of April 1, 1993, between Sonoma Geothermal Partners, L.P., Healdsburg Energy
             Company, L.P., Calpine Geysers Company, L.P. (formerly Santa Rosa Geothermal
             Company, L.P.), Freeport-McMoRan Resource Partners, L.P., and Meridian Trust
             Company of California.(a)
10.8.13      Management Services Agreement, dated January 1, 1995, between Calpine Corporation
             and Electrowatt Ltd.(k)
10.8.14      Revolving Credit Facility Letter Agreements, dated April 21, 1995, between
             Calpine Corporation and Credit Suisse, and between Calpine Greenleaf Corporation
             and Credit Suisse.(g)
10.8.15      Letter regarding Credit Facility, dated April 7, 1993, from Electrowatt Ltd. to
             Credit Suisse.(a)
10.8.16      Promissory Grid Note, dated April 29, 1996, between Calpine Corporation and
             Credit Suisse.(k)
10.8.17      Guarantee Fee Agreement, dated January 1, 1995, between Calpine Corporation and
             Electrowatt Ltd.(g)
10.8.18      Registration Rights Agreement dated as of May 16, 1996 between the Company,
             Morgan Stanley & Co. Incorporated, CS First Boston, Goldman Sachs & Co. and
             Scotia Capital Markets (USA) Inc.(l)
10.8.19**    Commitment Letter between The Bank of Nova Scotia and Calpine Corporation.
10.9.1       Calpine Corporation Stock Option Program and forms of agreements thereunder.(a)
10.9.2**     Calpine Corporation 1996 Stock Incentive Plan and forms of agreements thereunder.
10.9.3**     Calpine Corporation Employee Stock Purchase Plan and forms of agreements
             thereunder.
10.10.1**    Amended and Restated Employment Agreement between Calpine Corporation and Mr.
             Peter Cartwright.
10.10.2**    Senior Vice President Employment Agreement between the Company and Ms. Ann B.
             Curtis.
10.10.3**    Senior Vice President Employment Agreement between the Company and Mr. Lynn A.
             Kerby.
10.10.4**    Vice President Employment Agreement between the Company and Mr. Ron A. Walter.
10.10.5**    Vice President Employment Agreement between the Company and Mr. Robert D. Kelly.
10.10.6**    First Amended and Restated Consulting Contract between Calpine Corporation and
             Mr. George J. Stathakis.
10.11**      Form of Indemnification Agreement for directors and officers.
21.1**       Subsidiaries of the Company.
23.1**       Consent of Brobeck, Phleger & Harrison LLP (contained in the opinion filed as
             Exhibit 5).
23.2*        Independent Public Accountants' Consent of Arthur Andersen LLP.
23.3*        Independent Public Accountants' Consent of Moss Adams LLP.
23.4*        Independent Accountants' Consent of Coopers & Lybrand L.L.P.
23.5*        Independent Public Accountants' Consent of Ernst & Young LLP.
24.1**       Power of Attorney.
99.1*        Consent of Director Nominee	

* Filed herewith.
** Previously filed
(a) Incorporated by reference to Registrant's Registration Statement on Form S-1 (Registration Statement No. 33-73160).
(b) Incorporated by reference to Registrant's Current Report on Form 8-K dated September 9, 1994 and filed on September 26, 1994.
II-6

(c) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q dated September 30, 1994 and filed on November 14, 1994.
(d) Incorporated by reference to Registrant's Annual Report on Form 10-K dated December 31, 1994 and filed on March 29, 1995.
(e) Incorporated by reference to Registrant's Current Report on Form 8-K dated April 21, 1995 and filed on May 5, 1995.
(f) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q dated March 31, 1995 and filed on May 12, 1995.
(g) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q dated June 30, 1995 and filed on August 14, 1995.
(h) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q dated September 30, 1995 and filed on November 14, 1995.
(i) Incorporated by reference to Registrant's Annual Report on Form 10-K dated December 31, 1995 and filed on March 29, 1996.
(j) Incorporated by reference to Registrant's Current Report on Form 8-K dated May 1, 1996 and filed on May 14, 1996.
(k) Incorporated by reference to Registrant's Quarterly Report on Form 10-Q dated March 31, 1996 and filed on May 15, 1996.
(l) Incorporated by reference to Registrant's Registration Statement on Form S-4 (Registration Statement No. 333-6259).
(m) Incorporated by reference to Registrant's Current Report on Form 8-K dated August 29, 1996 and filed on September 13, 1996.
FINANCIAL STATEMENT SCHEDULES
Schedule I -- Condensed Financial Information of Registrant
Schedule II -- Valuation and Qualifying Accounts and Reserves
Schedules not listed above have been omitted because the information required to be set forth therein is not applicable or is shown in the financial statements or the notes thereto.
ITEM 22. UNDERTAKINGS
The undersigned registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.
Insofar as indemnification for liabilities arising under the Securities Act of 1933 (the "Act") may be permitted to directors, officers and controlling persons of the Company pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.
The undersigned Registrant hereby undertakes that:
(1) For purposes of determining any liability under the Act, the information omitted from the form of prospectus filed as part of this Registration Statement in reliance upon Rule 430A and contained in a form of prospectus filed by the Registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Act shall be deemed to be part of this Registration Statement as of the time it was declared effective.
(2) For the purpose of determining any liability under the Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.
II-7

SIGNATURES
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES ACT OF 1933, AS AMENDED, THE REGISTRANT HAS DULY CAUSED THIS AMENDMENT NO. 2 TO THE REGISTRATION STATEMENT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED, IN THE CITY OF SAN JOSE, CALIFORNIA, ON THE 19TH DAY OF SEPTEMBER, 1996.
CALPINE CORPORATION

By:     /s/  PETER CARTWRIGHT

  ------------------------------------
            Peter Cartwright
     President and Chief Executive
                 Officer	

Pursuant to the requirements of the Securities Act of 1933, as amended, this Amendment No. 2 to the Registration Statement has been signed below by the following persons in the capacities and on the dates indicated.

               SIGNATURE                               CAPACITY                      DATE
- ----------------------------------------   --------------------------------   ------------------
            /s/  PETER CARTWRIGHT           President and Chief Executive     September 19, 1996
- ----------------------------------------     Officer, Director (principal
            Peter Cartwright                      executive officer)

                                                     Director and
- ----------------------------------------        Chairman of the Board
             Pierre Krafft

                       *                               Director               September 19, 1996
- ----------------------------------------
            Hans-Peter Aebi

                       *                              Director                September 19, 1996
- ----------------------------------------
             Rudolf Boesch

         /s/  ANN B. CURTIS                    Senior Vice President          September 19, 1996
- ----------------------------------------    (principal financial officer)
             Ann B. Curtis

         /s/  GLORIA S. GEE                     Corporate Controller          September 19, 1996
- ----------------------------------------    (principal accounting officer)
             Gloria S. Gee

     *By:     /s/  PETER CARTWRIGHT
- ----------------------------------------
            Peter Cartwright
            Attorney-in-Fact

     *By:       /s/  ANN B. CURTIS
- ----------------------------------------
             Ann B. Curtis
            Attorney-in-Fact	

II-8

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
We have audited in accordance with generally accepted auditing standards, the consolidated financial statements of Calpine Corporation and subsidiaries included in this Registration Statement and have issued our report thereon dated March 15, 1996. Our audit was made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedules listed in the index of financial statement schedules are the responsibility of the Company's management and are presented for purposes of complying with the Securities and Exchange Commission's rules and are not part of the basic financial statements. These schedules have been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole.
ARTHUR ANDERSEN LLP
San Jose, California
March 15, 1996 (except with respect to
the matter discussed in Note 6 to Schedule I,
as to which the date is September 13, 1996)
S-1

CALPINE CORPORATION
SCHEDULE I
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
BALANCE SHEETS
DECEMBER 31, 1995 AND 1994
ASSETS

                                                                      1995             1994
                                                                  ------------     ------------
Current assets:
  Cash and cash equivalents.....................................  $ (1,970,526)    $  5,514,002
  Accounts receivable...........................................     6,304,594        2,196,912
  Acquisition project receivables...............................     8,805,186               --
  Intercompany receivables......................................    38,360,583       57,696,201
  Other current assets..........................................       270,806          189,526
                                                                  ------------     ------------
     Total current assets.......................................    51,770,643       65,596,641
Property, plant and equipment, net..............................       724,359          554,582
Investments in power projects...................................    82,610,719       44,913,432
Notes receivable from related parties...........................    19,090,286       23,953,294
Notes receivable from Coperlasa.................................     6,394,462               --
Deferred charges................................................     3,390,677        3,807,425
Other assets....................................................       197,144           74,900
                                                                  ------------     ------------
     Total assets...............................................  $164,178,290     $138,900,274
                                                                  ============     ============
                             LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities:
  Accounts payable..............................................  $  2,667,808     $    777,637
  Accrued payroll and related expenses..........................     2,582,194        2,417,302
  Accrued interest payable......................................     4,051,785        4,046,875
  Other accrued expenses........................................     2,704,257          964,312
                                                                  ------------     ------------
     Total current liabilities..................................    12,006,044        8,206,126
Long-term line of credit........................................    14,000,000               --
Senior Notes Due 2004...........................................   105,000,000      105,000,000
Deferred income taxes...........................................     7,877,537        6,976,950
Deferred revenue................................................        67,925           67,925
                                                                  ------------     ------------
     Total liabilities..........................................   138,951,506      120,251,001
                                                                  ------------     ------------
Stockholder's equity:
  Common stock..................................................        10,000           10,000
  Additional paid-in capital....................................     6,214,000        6,214,000
  Retained earnings.............................................    19,002,784       12,425,273
                                                                  ------------     ------------
     Total stockholder's equity.................................    25,226,784       18,649,273
                                                                  ------------     ------------
     Total liabilities and stockholder's equity.................  $164,178,290     $138,900,274
                                                                  ============     ============	

The accompanying notes are an integral part of these condensed financial statements.
S-2

CALPINE CORPORATION
SCHEDULE I
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
STATEMENTS OF OPERATIONS
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993

                                                         1995            1994            1993
                                                      -----------     -----------     -----------
Revenue:
  Service contract revenue from related parties...    $28,733,399     $22,929,897     $ 2,373,319
  Income from unconsolidated investments in power
     projects.....................................     32,397,392      23,711,895      15,450,720
                                                      -----------     -----------     -----------
     Total revenue................................     61,130,791      46,641,792      17,824,039
Cost of revenue:
  Service contract expenses.......................     27,433,069      19,161,445       1,914,375
                                                      -----------     -----------     -----------
Gross profit......................................     33,697,722      27,480,347      15,909,664
Project development expenses......................      3,087,316       2,822,459       1,280,125
General and administrative expenses...............      8,081,458       6,867,520       4,808,139
                                                      -----------     -----------     -----------
     Income from operations.......................     22,528,948      17,790,368       9,821,400
Other (income) expense:
  Interest expense................................     10,479,144       9,207,381       2,613,212
  Other income, net...............................       (377,276)     (1,290,739)     (1,153,797)
     Income before provision for income taxes and
       cumulative effect of change in accounting
       principle..................................     12,427,080       9,873,726       8,361,985
Provision for income taxes........................      5,049,568       3,853,115       4,194,733
                                                      -----------     -----------     -----------
     Income before cumulative effect of change in
       accounting principle.......................      7,377,512       6,020,611       4,167,252
Cumulative effect of adoption of SFAS No. 109.....             --              --        (413,410)
                                                      -----------     -----------     -----------
     Net income...................................    $ 7,377,512     $ 6,020,611     $ 3,753,842
                                                       ==========      ==========      ==========
As adjusted earnings per share assuming conversion
  of preferred stock:
  As adjusted weighted average shares
     outstanding..................................     14,187,433
                                                       ==========
  Net income per share............................    $      0.52
                                                       ==========	

The accompanying notes are an integral part of these condensed financial statements.
S-3

CALPINE CORPORATION
SCHEDULE I
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993

                                                           1995           1994           1993
                                                       ------------   ------------   ------------
Net cash used in operating activities................  $ (8,874,945)  $(44,753,732)  $    (84,812)
                                                       ------------   ------------   ------------
Cash flows from investing activities:
  Acquisitions of property, plant and equipment......      (367,711)      (299,961)       (73,292)
  Investments in power projects......................    (1,262,000)      (175,352)      (882,730)
  Decrease (increase) in notes receivable............   (10,336,640)     3,294,727    (15,576,775)
  Other, net.........................................      (122,244)        97,838        (85,478)
                                                       ------------   ------------   ------------
       Net cash provided by (used in) investing
          activities.................................   (12,088,595)     2,917,252    (16,618,275)
                                                       ------------   ------------   ------------
Cash flows from financing activities:
  Payment of dividends...............................      (800,000)      (800,000)      (800,000)
  Borrowings under line of credit....................    14,000,000             --     23,000,000
  Repayment of borrowings under line of credit.......            --    (52,595,000)    (5,872,500)
  Proceeds from Senior Notes Due 2004................            --    105,000,000             --
  Costs associated with future financing.............       279,012     (3,419,003)      (748,993)
  Repayment of note payable to shareholder...........            --     (1,200,000)            --
                                                       ------------   ------------   ------------
       Net cash provided by financing activities.....    13,479,012     46,985,997     15,578,507
                                                       ------------   ------------   ------------
Net increase (decrease) in cash and cash
  equivalents........................................    (7,484,528)     5,149,517     (1,124,580)
Cash and cash equivalents, beginning of period.......     5,514,002        364,485      1,489,065
                                                       ------------   ------------   ------------
Cash and cash equivalents, end of period.............  $ (1,970,526)  $  5,514,002   $    364,485
                                                       ============   ============   ============
Supplementary information:
  Cash paid during the period for:
     Interest........................................  $  9,945,443   $  4,917,773   $  2,120,637
     Income taxes....................................  $  4,293,725   $    683,364   $     12,800	

The accompanying notes are an integral part of these condensed financial statements.
S-4

CALPINE CORPORATION
SELECTED NOTES TO CONDENSED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
1. ORGANIZATION AND OPERATION OF CALPINE
Calpine Corporation (Calpine) is engaged in the development, acquisition, ownership and operation of power generation facilities in the United States. Calpine has ownership interests in and operates geothermal power generation facilities and steam fields and natural gas-fired cogeneration facilities through subsidiaries and investees. Founded in 1984 as a supplier of engineering and management services, Calpine is wholly-owned by Electrowatt Services, Inc., which is wholly-owned by Electrowatt Ltd (Electrowatt), a Swiss company. Calpine brings expertise in the area of engineering, finance, construction and plant operations and maintenance.
For the purposes of these registrant-only financial statements, Calpine's wholly-owned subsidiaries are accounted for under the equity method and are included in investments in power projects in the accompanying balance sheets.
In 1994, Calpine assumed the operations and maintenance agreements for the projects in which Calpine has an interest. Prior to 1994, a wholly-owned subsidiary, Calpine Operating Plant Services, Inc. (COPS) performed these services. In 1993, COPS recorded service contract revenue from related parties of $15.6 million and service contract expenses of $13.4 million pursuant to these agreements.
As Adjusted Earnings Per Share
Net income per share is computed using weighted average shares outstanding, which includes the net additional number of shares which would be issuable upon the exercise of outstanding stock options, assuming that the Company used the proceeds received to purchase additional shares at an assumed public offering price. Net income per share also gives effect, even if antidilutive, to common equivalent shares from preferred stock that will automatically convert upon the closing of the Company's initial public offering (using the as-if-converted method). If the offering contemplated by the Company is consummated, all of the convertible preferred stock outstanding as of the closing date will automatically be converted into shares of common stock based on the shares of convertible preferred stock outstanding at June 30, 1996.
2. LINES OF CREDIT AND REVOLVING CREDIT FACILITY
At December 31, 1995, the line of credit with Credit Suisse (whose parent company owns approximately 44.2% of Electrowatt) provided for advances of $50.0 million. Interest may be paid at either LIBOR or the Credit Suisse base rate, plus applicable margins in both cases. At December 31, 1995, Calpine had $19.9 million of borrowings outstanding, bearing interest at LIBOR plus 0.5% (6.4% at December 31, 1995). At Calpine's discretion, the debt outstanding can be held for various maturity periods of up to six months. Interest is paid on the last day of each interest period for such loans, but not less often than quarterly, based on the principal amount outstanding during the period. No stated amortization exists for this indebtedness. From January 1 to March 13, 1996, Calpine borrowed an additional $8.8 million and issued a letter of credit for $3.0 million for working capital requirements, other development projects and to fund Calpine Vapor, Inc. (Calpine Vapor), a subsidiary of Calpine. Calpine Vapor made loans for construction of new geothermal wells in Mexico. No borrowings were outstanding at December 31, 1994. The credit agreement specifies that Calpine maintain certain covenants with which Calpine was in compliance.
At December 31, 1995, Calpine had three loan facilities with available borrowings totaling $10.2 million. Borrowings and letters of credit outstanding were $1.2 million and $3.8 million as of December 31, 1995, respectively, with interest payable at variable interest rates based on bank base rates, LIBOR or prime plus applicable margins in all cases (approximately 7.6% at December 31, 1995 on borrowings). At December 31,
S-5

CALPINE CORPORATION
SELECTED NOTES TO CONDENSED FINANCIAL STATEMENTS -- (CONTINUED)
1994, no borrowings and $900,000 of letters of credit were outstanding on these facilities. The credit agreements specify that Calpine maintain certain covenants with which Calpine was in compliance.
3. NOTE PAYABLE TO STOCKHOLDER
On December 31, 1991, Calpine declared a dividend of $1.2 million to its parent company, Electrowatt Services, Inc. On the same date, Calpine issued a note payable to Electrowatt Services, Inc. for $1.2 million. Interest was paid quarterly at a rate of 4.25%, which approximated market. The note was paid on June 30, 1994, the maturity date.
4. SENIOR NOTES DUE 2004
On February 17, 1994, Calpine completed a $105.0 million public debt offering of 9 1/4% Senior Notes Due 2004 (Senior Notes). The net proceeds of $100.9 million were used to repay all of the indebtedness outstanding under Calpine's existing line of credit, and to repay subsidiaries' non-recourse notes payable to Freeport-McMoRan Resource Partners, L.P. (FMRP) plus accrued interest. The remaining proceeds were used for general corporate purposes including a loan to the sole shareholder of Sumas Energy, Inc., the partner in one of Calpine's power projects. The transaction costs of $4.1 million incurred in connection with the public debt offering have been recorded as a deferred charge and are amortized over the ten-year life of the Senior Notes using the interest method.
The Senior Notes will mature on February 1, 2004 and bear interest at 9 1/4% payable semiannually on February 1 and August 1 of each year, commencing August 1, 1994, to holders of record. Based on the traded yield to maturity, the approximate fair market value of the Senior Notes was $97.0 million as of December 31, 1995.
Under provisions of the indenture applicable to the Senior Notes, Calpine may, under certain circumstances be limited in its ability to make restricted payments, as defined, which include dividends and certain purchases and investments, incur additional indebtedness and engage in certain transactions.
5. COMMITMENTS AND CONTINGENCIES
Capital Projects
Calpine has 1996 commitments for capital expenditures totaling $6.8 million related to various projects at its geothermal facilities. In March 1996, Calpine entered into an energy agreement with Phillips Petroleum Company to develop, construct, own and operate a 240 megawatt gas-fired cogeneration facility at Phillips Houston Chemical Complex in Pasadena, Texas. The initial permitting process is underway, with construction of the facility planned to begin in late 1996 and to be completed in 1998. Calpine is currently evaluating options to finance the construction of this facility. Calpine issued a $3.0 million letter of credit and has a 1996 capital commitment of $3.0 million in connection with this facility. In a separate transaction, as of March 15, 1996, Calpine was negotiating the potential acquisition of an operating lease for a 120 megawatt gas-fired cogeneration facility located in Northern California.
S-6

CALPINE CORPORATION
SELECTED NOTES TO CONDENSED FINANCIAL STATEMENTS -- (CONTINUED)
Office and Equipment Leases
Calpine leases its corporate office, Santa Rosa office facilities and certain office equipment under noncancellable operating leases expiring through 2000. Future minimum lease payments under these leases are (in thousands):

1996........................................................  $  899
1997........................................................     905
1998........................................................     907
1999........................................................     776
2000........................................................     745
thereafter..................................................     286
                                                              ------
Total future minimum lease commitments......................  $4,518
                                                              ======	

Lease payments are subject to adjustment for Calpine's pro rata portion of annual increases or decreases in building operating costs. In 1995, 1994 and 1993, rent expense for noncancellable operating leases amounted to $733,000, $663,000 and $636,000, respectively.
CPUC Restructuring
Electricity and steam sales agreements with PG&E are regulated by the California Public Utilities Commission (CPUC). In December 1995, the CPUC proposed the transition of the electric generation market to a competitive market beginning January 1, 1998, with all consumers participating by 2003. The proposed restructuring provides for phased-in customer choice, development of non-discriminatory market structure, recovery of utilities' stranded costs, sanctity of existing contracts, and continuation of existing public policy programs including the promotion of fuel diversity through a renewable energy purchase requirement.
As the proposed restructuring has widespread impact and the market structure requires the participation and oversight of the Federal Energy Regulatory Commission (FERC), the CPUC will seek to build a California consensus involving the legislature, the Governor, public and municipal utilities, and customers. The consensus would then be placed before the FERC so that both the CPUC and FERC would implement the new market structure no later than January 1, 1998. There can be no assurance that the proposed restructuring will be enacted in substantially the same form as discussed above. Calpine is unable to predict the ultimate outcome of the restructuring.
Litigation
Calpine, together with over 100 other parties, was named as a defendant in the second amended complaint in an action brought in August 1993 by the bankruptcy trustee for Bonneville Pacific Corporation (Bonneville), captioned Roger G. Segal, as the Chapter 11 Trustee for Bonneville Pacific Corporation v. Portland General Corporation, et al., in the United States District Court for the District of Utah. This complaint alleges that, in conjunction with top executives of Bonneville and with the alleged assistance of the other 100 defendants, Calpine engaged in a broad conspiracy and fraud. The complaint has been amended a number of times. Calpine has answered each version of the complaint by denying all claims and is in the process of conducting discovery. In August 1994 Calpine successfully moved for an order severing the trustee's claim against Calpine from the claims against the other defendants. Although the case involves over 25 separate financial transactions entered into by Bonneville, the severed case concerns Calpine in respect of only one of these transactions. In 1988, Calpine invested $2.0 million in a partnership formed with Bonneville to develop four hydroelectric projects in the State of Hawaii. The projects were not successfully developed by the partnership, and, subsequent to Bonneville's Chapter 11 filing, Calpine filed a claim as a creditor against Bonneville's bankruptcy estate. The trustee alleges that the equity investment was actually a "sham" loan
S-7

CALPINE CORPORATION
SELECTED NOTES TO CONDENSED FINANCIAL STATEMENTS -- (CONTINUED)
designed to inflate Bonneville's earnings. The trustee further alleges that Calpine is one of many defendants in this case responsible for Bonneville's insolvency and the amount of damages attributable to Calpine based on the $2.0 million partnership investment is alleged to be $577.2 million. The trustee is seeking to hold each of the other defendants liable for a portion, all or, in certain cases, more than this amount. Calpine expects the matter will be set for trial in 1996. Calpine believes the claims against it are without merit and will continue to defend the action vigorously. Calpine further believes that the resolution of this matter will not have a material adverse effect on its financial position or results of operations.
Calpine is involved in various other claims and legal actions arising out of the normal course of business. Management does not expect that the outcome of these cases will have a material adverse effect on Calpine's financial position or results of operations.
6. SUBSEQUENT EVENT
In July 1996, the Company's Board of Directors authorized the reincorporation of the Company into Delaware in connection with the Company's initial public equity offering. Also, the Board of Directors approved a stock split at a ratio of approximately 5.194 to 1. On September 13, 1996, the reincorporation of the Company and the stock split became effective. The accompanying financial statements reflect the reincorporation and the stock split as if such transactions had been effective for all periods.
S-8

CALPINE CORPORATION AND SUBSIDIARIES
SCHEDULE II
VALUATION AND QUALIFYING ACCOUNTS
(IN THOUSANDS)
FOR THE YEAR ENDED DECEMBER 31, 1995

                                                              ADDITIONS
                                                      -------------------------
                                      BALANCE AT      CHARGED TO     CHARGED TO                    BALANCE AT
                                     BEGINNING OF     COSTS AND        OTHER                         END OF
           DESCRIPTION                  PERIOD         EXPENSES       ACCOUNTS      DEDUCTIONS       PERIOD
- ---------------------------------    ------------     ----------     ----------     ----------     ----------
Reserve for capitalized costs....      $  1,838        $     --       $     --       $     --       $   1,838(1)
                                      =========        ========       ========       ========        ========
Allowance for uncollectible
  accounts.......................      $    238        $     --       $     --       $     --       $     238
                                      =========        ========       ========       ========        ========	

FOR THE YEAR ENDED DECEMBER 31, 1994

                                                              ADDITIONS
                                                      -------------------------
                                      BALANCE AT      CHARGED TO     CHARGED TO                    BALANCE AT
                                     BEGINNING OF     COSTS AND        OTHER                         END OF
           DESCRIPTION                  PERIOD         EXPENSES       ACCOUNTS      DEDUCTIONS       PERIOD
- ---------------------------------    ------------     ----------     ----------     ----------     ----------
Reserve for capitalized costs....      $    800        $  1,038       $     --       $     --       $   1,838(1)
                                      =========        ========       ========       ========        ========
Allowance for uncollectible
  accounts.......................            --             238       $     --       $     --       $     238
                                      =========        ========       ========       ========        ========	

FOR THE YEAR ENDED DECEMBER 31, 1993

                                                              ADDITIONS
                                                      -------------------------
                                      BALANCE AT      CHARGED TO     CHARGED TO                    BALANCE AT
                                     BEGINNING OF     COSTS AND        OTHER                         END OF
           DESCRIPTION                  PERIOD         EXPENSES       ACCOUNTS      DEDUCTIONS       PERIOD
- ---------------------------------    ------------     ----------     ----------     ----------     ----------
Reserve for capitalized costs....      $    800        $     --       $     --       $     --       $     800(1)
                                      =========        ========       ========       ========        ========	

(1) Provision for write-off of project development expenses.
S-9

APPENDIX -- CALPINE GRAPHIC IMAGES
GRAPHIC (Domestic Inside Front Cover)
Upper Photo--Sumas 125 mw Gas-fired Facility
Lower Photo--King City 120 mw Gas-fired Facility
Calpine Logo
GRAPHIC (International Inside Front Cover-Alternate Page A-2)
Photo--Sumas 125 mw Gas-fired Facility
Calpine Logo
GRAPHIC (Inside Back Cover)
Upper Photo--Cerro Prieto 80 mw Geothermal Steam Field
The Power of Innovation
Lower Photo--West Ford Flat 27 mw Geothermal Facility
Calpine Logo
GRAPHIC (page 43)
CALPINE CORPORATION

 1      -       Calpine Corporation Headquarters
                San Jose, California

 2      -       Calpine Corporation Geothermal Office
                Santa Rosa, California

 3      -       Aidlin 20 mw Geothermal Facility

 4      -       Agnews 29 mw Cogeneration Facility

 5      -       Bear Canyon 20 mw Geothermal Facility

 6      -       Black Hills 80 mw Coal Project

 7      -       Cerro Prieto 80 mw Steam Fields

 8      -       Coso 150 mw Geothermal Project

 9      -       Gilroy 120 mw Cogeneration Facility

10      -       Glass Mountain 145 mw Geothermal Project

11      -       Greenleaf 1 49.5 mw Cogeneration Facility

12      -       Greenleaf 2 49.5 mw Cogeneration Facility

13      -       King City 120 mw Cogeneration Facility

14      -       Navajo South 1,700 mw Coal Project

15      -       Pasadena 240 mw Cogeneration Facility

16      -       PG&E Unit 13 Steam Fields

17      -       PG&E Unit 16 Steam Fields

18      -       SMUDGEO #1 Steam Fields

19      -       Sumas 125 mw Cogeneration Facility

20      -       Thermal Power Company Steam Fields

21      -       Watsonville 28.5 mw Cogeneration Facility

22      -       West Ford Flat 27 mw Geothermal Facility	

Map of western and southwestern United States indicating:
Corporate Headquarters
Corporate Geothermal Office
Operating Facility
Steam Fields
Future Projects
Graphic (page 40)
Illustration of a Combined Cycle Power Plant
Graphic (page 41)
Illustration of a Geothermal Power Plant

EXHIBIT 4.3
TEMPORARY CERTIFICATE -- EXCHANGEABLE FOR DEFINITIVE CERTIFICATE
WHEN READY FOR DELIVERY

COMMON STOCK COMMON STOCK
CT [CALPINE CORPORATION LOGO]
CALPINE CORPORATION
SEE REVERSE FOR
CERTAIN OPERATIONS
INCORPORATED UNDER THE LAWS OF CUSIP 131347 10 6
THE STATE OF DELAWARE
THIS CERTIFIES THAT
IS THE OWNER OF
FULLY PAID AND NONASSESSABLE SHARES OF THE COMMON STOCK,
$.001 PAR VALUE PER SHARE, OF
CALPINE CORPORATION
transferable on the books of the Corporation by the holder hereof in person or by duly authorized attorney upon surrender of this certificate properly endorsed. This certificate is not valid until countersigned and registered by the Transfer Agent and Registrar.
WITNESS the facsimile seal of the Corporation and the facsimile signatures of its duly authorized officers.
Dated:
CALPINE CORPORATION
CORPORATE

/s/ Ann B. Curtis                     SEAL             /s/ Peter Cartwright
- ----------------------                1982             -------------------------
SENIOR VICE PRESIDENT,              DELAWARE             CHAIRMAN OF THE BOARD,
CHIEF FINANCIAL OFFICER                                      PRESIDENT AND
   AND SECRETARY                                        CHIEF EXECUTIVE OFFICER	

COUNTERSIGNED AND REGISTERED:
FIRST CHICAGO TRUST COMPANY
OF NEW YORK
TRANSFER AGENT AND REGISTRAR

BY /s/ [SIGNATURE]
   -------------------------
     AUTHORIZED SIGNATURE	

A statement of the powers, designations, preferences and relative, participating, optional or other special rights of each class of stock or series thereof and the qualifications, limitations or restrictions of such preferences and/or rights as established, from time to time, by the Certificate of incorporation of the Corporation and by any certificate of determination, the number of shares constituting each class and series, and the designations thereof, may be obtained by the holder hereof upon request and without charge at the principal office of the Corporation.
The following abbreviations, when used in the inscription on the face of this certificate, shall be construed as though they were written out in full according to applicable laws or regulations:

TEN COM -- as tenants in common                UNIF GIFT MIN ACT --                  Custodian
TEN ENT -- as tenants by the entireties                             ----------------           ----------------
JT TEN  -- as joint tenants with right or                                (Cust)                   (Minor)
           survivorship and not as tenants                          under Uniform Gifts to Minors
           in common                                               Act
                                                                       ----------------------------------------
                                                                                        (State)
                                               UNIF TRF MIN ACT --             Custodian (until age           )
                                                                    ----------                      ----------
                                                                     (Cust)
                                                                                         under Uniform Transfers
                                                                    --------------------
                                                                    to Minors Act
                                                                                  ------------------------------
                                                                                           (State)	

ADDITIONAL ABBREVIATIONS MAY ALSO BE LISTED THOUGH NOT IN THE ABOVE LIST.

FOR VALUE RECEIVED,                              hereby sell(s), assign(s) and
                    ----------------------------
transfer(s) unto

PLEASE INSERT SOCIAL SECURITY OR OTHER
    IDENTIFYING NUMBER OF ASSIGNEE
- --------------------------------------

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

- --------------------------------------------------------------------------------
 (PLEASE PRINT OR TYPEWRITE NAME AND ADDRESS, INCLUDING ZIP CODE, OF ASSIGNEE)

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

- --------------------------------------------------------------------------------
                                                                          Shares
- -------------------------------------------------------------------------	

of the common stock represented by the within Certificate, and do hereby irrevocably constitute and appoint
Attorney

to transfer the said stock on the books of the within named Corporation with full power of substitution in the premises.

Dated

X
X
 NOTICE: The SIGNATURE(S) TO THIS ASSIGNMENT MUST
CORRESPOND WITH THE NAME(S) AS WRITTEN UPON
THE FACE OF THE CERTIFICATE IN EVERY
PARTICULAR, WITHOUT ALTERATION OR ENLARGE-
MENT OR ANY CHANGE WHATEVER.
Signature(s) Guaranteed
By
 THE SIGNATURE(S) SHOULD BE GUARANTEED BY AN ELIGIBLE GUARANTOR INSTITUTION (BANKS, STOCK- BROKERS, SAVINGS AND LOAN ASSOCIATIONS AND CREDIT UNIONS WITH MEMBERSHIP IN AN APPROVED SIGNATURE GUARANTEE MEDALLION PROGRAM), PUR- SUANT TO S.E.C. RULE 17A?-15.

- -----------------------------------------------------------------
AMERICAN BANK NOTE COMPANY   AUG 29, 1996 fm
3504 ATLANTIC AVENUE
SUITE 12
LONG BEACH, CA  90807        046176bk
(310) 989-2333
(FAX) (310) 428-7460         Proof /s/ [Signature Illegible]  NEW
                                   -------------------------
- -----------------------------------------------------------------	

EXHIBIT 10.1.16
CREDIT AGREEMENT
among
CALPINE GILROY COGEN, L.P.
 (As Borrower)
and
BANQUE NATIONALE DE PARIS,
Los Angeles Branch
and
THE ADDITIONAL FINANCIAL
INSTITUTIONS SET FORTH ON APPENDIX I
 (The Lenders)
and
BANQUE NATIONALE DE PARIS,
Los Angeles Branch
 (As Issuing Bank)
and
BANQUE NATIONALE DE PARIS,
Los Angeles Branch
 (As Agent)
Dated as of August 28, 1996

TABLE OF CONTENTS

                                                                                                           PAGE
                                                                                                           ----
ARTICLE I  DEFINITIONS.......................................................................................    1

   Section 1.1  Certain Defined Terms........................................................................
   Section 1.2  Other Definitional Provisions...............................................................

ARTICLE II  LOANS...........................................................................................

   Section 2.1  Loans.......................................................................................
   Section 2.2  Use of Proceeds.............................................................................
   Section 2.3  Disbursements...............................................................................
   Section 2.4  Interest Periods............................................................................

ARTICLE III  NOTES..........................................................................................

   Section 3.1  Notes.......................................................................................
   Section 3.2  Repayment of Notes..........................................................................
   Section 3.3  Interest....................................................................................
   Section 3.4  Default Interest............................................................................
   Section 3.5  Method of Payments..........................................................................
   Section 3.6  Payments Due on Days Other Than
                              Business Days.................................................................
   Section 3.7  Mandatory Prepayment........................................................................
   Section 3.8  Optional Prepayment.........................................................................
   Section 3.9  Security for the Notes......................................................................
   Section 3.10  Distribution of Amounts in Respect of Events
                               of Loss and Events of Default................................................
   Section 3.11  Interest Rate Contracts....................................................................
   Section 3.12  Funding and Yield Protection...............................................................
   Section 3.13  Illegality.................................................................................
   Section 3.14  Basis for Determining Interest Rate
                               Inadequate or Unfair.........................................................
   Section 3.15  Capital Adequacy...........................................................................
   Section 3.16  Breakage Indemnity.........................................................................
   Section 3.17  Replacement of Lenders.....................................................................
   Section 3.18  Interest...................................................................................

ARTICLE IV  LETTERS OF CREDIT...............................................................................

   Section 4.1  Letters of Credit...........................................................................
   Section 4.2  Participation and Funding Commitments.......................................................
   Section 4.3  Nature of Issuing Bank's Duties.............................................................
   Section 4.4  Increased Cost of Letter of Credit..........................................................
   Section 4.5  Borrower's Obligations Absolute.............................................................

ARTICLE V  FEES AND ADDITIONAL PAYMENTS.....................................................................

   Section 5.1  Up-Front Fee................................................................................	

   Section 5.2  Letter of Credit Fees.......................................................................
   Section 5.3  Issuing Bank Letter of Credit Fee...........................................................
   Section 5.4  Agency Fee..................................................................................

ARTICLE VI  REPRESENTATIONS AND WARRANTIES..................................................................

   Section 6.1  Existence and Business of the Borrower......................................................
   Section 6.2  Existence and Business of the Partners......................................................
   Section 6.3  Power and Authorization; Enforceable
                              Obligations...................................................................
   Section 6.4  Collateral Security Documents...............................................................
   Section 6.5  No Legal Bar................................................................................
   Section 6.6  Governmental Approvals and Other
                              Consents and Approvals........................................................
   Section 6.7  Financial Statements........................................................................
   Section 6.8  Taxes.......................................................................................
   Section 6.9  No Proceeding or Litigation.................................................................
   Section 6.10  No Default or Event of Loss................................................................
   Section 6.11  Title to Property..........................................................................
   Section 6.12  Project Contracts..........................................................................
   Section 6.13  Agreements and Licenses....................................................................
   Section 6.14  Compliance with Law........................................................................
   Section 6.15  Environmental Matters......................................................................
   Section 6.16  Federal Reserve Regulations................................................................
   Section 6.17  ERISA......................................................................................
   Section 6.18  Principal Place of Business................................................................
   Section 6.19  Offer of Notes or Securities...............................................................
   Section 6.20  Labor Matters..............................................................................
   Section 6.21  Full Disclosure............................................................................
   Section 6.22  Investment Company Act Status..............................................................

ARTICLE VII  CONDITIONS PRECEDENT...........................................................................

   Section 7.1  The Closing Date............................................................................

ARTICLE VIII  AFFIRMATIVE COVENANTS.........................................................................

   Section 8.1  Conduct of Business, Maintenance of
                              Existence, etc................................................................
   Section 8.2  Operation of Project........................................................................
   Section 8.3  Payment of Obligations......................................................................
   Section 8.4  Payment of Taxes and Claims.................................................................
   Section 8.5  Performance of Obligations..................................................................
   Section 8.6  Insurance; Taking; Warranties...............................................................
   Section 8.7  Inspection of Property, Books and
                              Records; Discussions..........................................................
   Section 8.8  Compliance with Laws, Contractual
                              Obligations, etc..............................................................
   Section 8.9  Financial Statements........................................................................
   Section 8.10  Certificates; Other Information............................................................
   Section 8.11  Notices....................................................................................
   Section 8.12  Assignments of Additional Contracts;	

                               Maintenance of Liens of the Collateral
                               Security Documents; Future Mortgages.........................................
   Section 8.13  Defend Title...............................................................................
   Section 8.14  Accounts; Operating Budget.................................................................
   Section 8.15  Environmental Matters......................................................................
   Section 8.16  Fuel Supply................................................................................
   Section 8.17  Application of Proceeds....................................................................
   Section 8.18  Accounts Receivable........................................................................

ARTICLE IX  NEGATIVE COVENANTS..............................................................................

   Section 9.1  Organization, Sale of Assets,
                              Purchases, etc................................................................
   Section 9.2  Indebtedness................................................................................
   Section 9.3  Liens.......................................................................................
   Section 9.4  Nature of Business..........................................................................
   Section 9.5  Amendment of Contracts, Additional
                              Contracts, etc................................................................
   Section 9.6  Investments or Loans........................................................................
   Section 9.7  Qualifying Facility.........................................................................
   Section 9.8  Change of Office............................................................................
   Section 9.9  Change of Name..............................................................................
   Section 9.10  Limitation on Transactions
                               with Affiliates..............................................................
   Section 9.11  Restricted Payments........................................................................
   Section 9.12  Assignment.................................................................................
   Section 9.13  Abandonment of Project.....................................................................

ARTICLE X  EVENTS OF DEFAULT................................................................................

   Section 10.1  Events of Default..........................................................................
   Section 10.2  Other Remedies.............................................................................
   Section 10.3  Foreclosure Under Certain Circumstances....................................................

ARTICLE XI  THE AGENT AND THE ISSUING BANK..................................................................

   Section 11.1  Appointment................................................................................
   Section 11.2  Delegation of Duties.......................................................................
   Section 11.3  Exculpatory Provisions.....................................................................
   Section 11.4  Reliance by Agent..........................................................................
   Section 11.5  Notice of Default..........................................................................
   Section 11.6  Non-Reliance on Agent and Other Lenders....................................................
   Section 11.7  Indemnification............................................................................
   Section 11.8  Agent and Issuing Bank in Individual
                               Capacities...................................................................
   Section 11.9  Successor Agents...........................................................................
   Section 11.10  Documents and Notices.....................................................................
   Section 11.11  Response to Certain Borrower Requests.....................................................

ARTICLE XII  MISCELLANEOUS..................................................................................	

Section 12.1  Expenses; Indemnification, etc.............................................................
Section 12.2  Amendments; Consent to Amendments..........................................................
Section 12.3  Form, Registration, Transfer and
                            Exchange of Notes; Lost Notes................................................
Section 12.4  Notices to Subsequent Holder ..............................................................
Section 12.5  Persons Deemed Owners .....................................................................
Section 12.6  Survival of Representations
                            and Warranties ..............................................................
Section 12.7  Successors and Assigns ....................................................................
Section 12.8  Notices ...................................................................................
Section 12.9  Descriptive Headings ......................................................................
Section 12.10  Governing Law ............................................................................
Section 12.11  No Waiver ................................................................................
Section 12.12  Severable ................................................................................
Section 12.13  Counterparts .............................................................................
Section 12.14  Waiver of Jury Trial; Consent to
                              Jurisdiction; Limitation of Remedies ......................................
Section 12.15  No Recourse ..............................................................................
Section 12.16  Confidentiality ..........................................................................
Section 12.17  Prior Understandings .....................................................................	

Appendix I        Lender Schedule and Applicable
                           Lending Offices

Exhibits

A        Form of Borrowing Notice
B-1      Form of Tranche A Note
B-2      Form of Tranche B Note
B-3      Form of Tranche C Note
C        Form of Deed of Trust
D        Form of Security Agreement
E        Form of Collateral Assignment of Contract
F        Form of Deposit and Security Agreement
G        Form of Commitment Transfer Supplement
H        Form of Consent
I        Site Description
J-1      Form of Tranche C Letter of Credit
J-2      Form of Tranche D Letter of Credit
K-1      Form of Collateral Assignment of Partnership
         Interests of Calpine Gilroy 1, Inc.
K-2      Form of Collateral Assignment of Partnership
         Interests of Calpine Gilroy 2, Inc.
L        Form of Replacement Gas Agreement
M        Terms of Subordination

Schedules

 1.1(a)  Base Case
 1.1(b)  Sources and Uses
 1.1(c)  Fuel Plan Index
 1.1(d)  Fuel Transportation Report Index
 1.1(e)  Operating Plan Index
 6.4     Filings and Recordings
 6.6     Permits and Approvals
 6.17    Commonly Controlled Entities
 8.6     Insurance Requirements	

                  CREDIT AGREEMENT, dated as of August 28, 1996, among CALPINE	

GILROY COGEN, L.P., a limited partnership organized under the laws of the State of Delaware (together with its permitted successors and assigns, the "Borrower"), BANQUE NATIONALE DE PARIS, Los Angeles Branch ("BNP"), and each financial institution listed as a Lender on the Lender Schedule attached hereto as Appendix I (BNP and such other financial institutions, collectively, the "Lenders"), BNP, as the issuing bank (together with its successors and assigns in such capacity, the "Issuing Bank"), and BNP, as agent for the Lenders and the Issuing Bank (together with its successors and assigns in such capacity, the "Agent"). Capitalized terms not otherwise defined in this Agreement shall have the meanings ascribed to them in Article I hereof.
PRELIMINARY STATEMENT
This Agreement sets forth the terms and conditions on which the Lenders will, inter alia, provide funding for, and the Issuing Bank will provide certain letters of credit with respect to, the acquisition and operation of a 120 megawatt (nominal net) gas-fired combined-cycle cogeneration facility located in Gilroy, California.
ARTICLE I
DEFINITIONS
Section 1.1 Certain Defined Terms. As used in this Agreement, the following terms have the following meanings (such definitions to be equally applicable to both singular and plural forms of the terms defined):
"Abandonment": (a) the permanent cessation of operation of the Project pursuant to a decision of the Borrower, (b) the announcement by the Borrower of its abandonment of the Project, or (c) the abandonment of the Project by the Borrower and the Operator for a continuous period of at least 30 days without notice.
"Acceptable Security": as defined in the Performance Agreement.
"Accounts": the Receipt Account, the Operating Account, the Debt Service Reserve Account, the Insurance Proceeds Account, the Major Maintenance Reserve Account and the Fuel Reserve Account.
"Additional Contract": any agreement, contract, lease or Easement Agreement entered into by or assigned to the Borrower after execution and delivery of this Agreement related to the maintenance, repair, operation, lease, operation or use of or

supply to the Project other than a Permitted Contract.
"Affiliate": of any Person, any Person which, directly or indirectly, controls or is controlled by or is under common control with such designated Person and, without limiting the generality of the foregoing, shall include (a) any Person which beneficially owns or holds 5% or more of any class of voting securities of such designated Person or 5% or more of the equity interest in such designated Person and (b) any Person of which such designated Person beneficially owns or holds 5% or more of any class of voting securities or in which such designated Person beneficially owns or holds 5% or more of the equity interests. For the purposes of this definition, "control" (including, with correlative meanings, the terms "controlled by" and "under common control with"), as used with respect to any Person, shall mean the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of such Person, whether through the ownership of voting securities or by contract or otherwise.
"Agency Fee": the fee set forth in a separate letter agreement, as defined in Section 5.4.
"Agreement": this Credit Agreement.
"Alternate Base Rate": as of any date, a rate per annum equal the per annum rate of interest from time to time publicly announced by the Agent as its base lending rate for domestic (United States of America) commercial loans, the Alternate Base Rate to change when and as such rate changes. The Alternate Base Rate is not necessarily the lowest rate of interest charged by the Agent in connection with extensions of credit.
"Alternate Base Rate Loan": any Loan that bears interest at the Alternate Base Rate plus the Applicable Margin as provided in Section 3.3(a).
"Amended and Restated Lease Agreement": the Amended and Restated Lease Agreement, dated as of even date with the Asset Purchase Agreement, between ConAgra and the Borrower.
"Amoco": Amoco Energy Trading Corporation, a Delaware corporation.
"Amortization Schedule": Schedule I attached to each Note.
"Applicable Lending Office": shall mean, for each Lender party to this Agreement on the Closing Date, the "Lending Office" of such Lender (or of an affiliate of such Lender) designed in Appendix I, and for each Lender which may become a party to this Agreement after the Closing Date, the "Lending

Office" of such Lender (or of an Affiliate of such Lender) designated in the Commitment Transfer Supplement executed by such Lender; provided, that any Lender may from time to time change its "Applicable Lending Office" by delivering notice of such change to the Agent and the Borrower.
"Applicable Margin": (a) with respect to the Tranche A Loan, the Tranche B Loan and the Tranche C Loans, for years 1 through 5 following the Closing Date, 1.125% per annum, for years 6 through 10, 1.250% per annum, for years 11 through 15, 1.50% per annum; for the Tranche B Loan, for years 16 through 18, 1.75% per annum; and for Drawings under the Tranche D Letter of Credit, 1.0% per annum.
"Asset Purchase Agreement": the Asset Purchase Agreement, dated as of even date herewith, among Gilroy, the Borrower and McCormick & Company, Incorporated.
"Asset Purchase Documents": collectively, the Asset Purchase Agreement, the Assignment of Lease Agreement, the Assignment of Natural Gas Sales Agreement, the Assignment of Power Purchase Agreement, the Assignment of Steam Sales Agreement, the Assignment of Wastewater Discharge Requirements, the ConAgra Assignment Agreement, GE Services Agreement, Spare Parts Agreement, the Bill of Sale, the General Assignment and Assumption Agreement, the ConAgra Option Agreements, the Noncompete Agreement, the Substation Operating Agreement, and all other agreements to be executed and delivered at the closing of the Asset Purchase Agreement as agreed to by Gilroy, McCormick & Company, Incorporated and the Borrower.
"Assigned Agreements": as defined in the Security Agreement.
"Assignment of Lease Agreement": the Assignment of Lease Agreement, dated as of even date with the Asset Purchase Agreement, between Gilroy and the Borrower whereby Gilroy assigns and the Borrower assumes all of Gilroy's rights and obligations under the Site Lease, as more fully set forth therein.
"Assignment of Leases and Rents": the Assignment of Leases and Rents, dated as of even date herewith, from the Borrower to the Agent.
"Assignment of Natural Gas Sales Agreement": the Assignment of Natural Gas Sales Agreement, dated as of even date with the Asset Purchase Agreement, between Gilroy and the Borrower whereby Gilroy assigns and the Borrower assumes all of Gilroy's rights and obligations under the Natural Gas Sales Agreement, dated August 1, 1995, between Gilroy and Amoco, as more fully set forth therein.
"Assignment of Power Purchase Agreement": the

Assignment of Power Purchase Agreement, dated as of even date with the Asset Purchase Agreement, between Gilroy and the Borrower whereby Gilroy assigns and the Borrower assumes all of Gilroy's rights and obligations under the Power Purchase Agreement, as more fully set forth therein.
"Assignment of Steam Sales Agreement": the Assignment of Steam Sales Agreement, dated as of even date with the Asset Purchase Agreement, between Gilroy and the Borrower whereby Gilroy assigns and the Borrower assumes all of Gilroy's rights and obligations under the Steam Sales Agreement, as more fully set forth therein.
"Assignment of Wastewater Discharge Requirements": the Assignment in Part of Waste Discharge and Water Reclamation Requirements, dated as of even date with the Asset Purchase Agreement, among Gilroy, ConAgra and the Borrower whereby Gilroy and ConAgra assign and the Borrower assumes all of Gilroy's and ConAgra's rights, benefits and duties under those certain Waste Discharge and Water Reclamation Requirements (as defined in the Assignment of Wastewater Discharge Requirements) to the extent that such rights, benefits and duties relate to the discharge of wastewater from the Facility.
"Assignments of Partnership Interests": as defined in Section 3.9(d).
"Bankruptcy Law": as defined in Section 10.1(a)(xiv).
"Base Case": the Base Case Financial Model attached hereto as Schedule 1.1(a).
"Basic Documents": the collective reference to the Loan Documents and the Project Contracts.
"Bill of Sale": the Bill of Sale contemplated by Section 3.2.2 of the Asset Purchase Agreement.
"Borrowing Notice": as defined in Section 7.1(a).
"Business Day": any day excluding Saturday, Sunday and any day on which commercial banks in Los Angeles, California are required or authorized to be closed.
"Calpine": Calpine Corporation, a California corporation.
"Calpine Credit Event": a Calpine Credit Event Level I or Calpine Credit Event Level II.
"Calpine Credit Event Level I": Calpine's Credit Rating has one Rating Downgrade.

"Calpine Credit Event Level II": either (i) Calpine's Credit Rating has two Rating Downgrades, or (ii) a Minimum Credit Rating occurs.
"Calpine's Credit Rating": the higher of (i) Calpine's long-term credit rating as of the Closing Date as reported by Standard & Poor's (B) and Moody's (Ba3) or (ii) Calpine's long-term credit rating as reported by Standard & Poor's and Moody's promptly after the closing (and in any event within ninety (90) days thereafter) of Calpine's initial public offering.
"Calpine Fuels": Calpine Fuels Corporation, a California corporation.
"Calpine Guarantees": collectively, the Fuel Margin Guaranty, the Letter of Credit Guaranty and the Major Maintenance Guaranty.
"Calpine Performance Agreement": the Performance Agreement, dated as of even date herewith, among Calpine, the Borrower and the Agent.
"Capacity Utilization": for any period, the percentage resulting from the following calculation:
California Gas Demand - California Gas Production (Interstate Capacity plus Additional Interstate Capacity) x Days in Period
where:
"California Gas Demand": means, for such period, the Gas delivered to all consumers in California as reported in the Energy Information Administration's Natural Gas Monthly, "Table 18-Natural Gas Deliveries to All Consumers, by State";
"California Gas Production": means, for such period, all Gas produced in California for such period, as reported in the Energy Information Administration's Natural Gas Monthly, "Table 7-Marketed Production of Natural Gas, by State";
"Interstate Capacity": means 7,230 MMcf per day, as such amount is adjusted from time to time to account for additional interstate pipeline capacity interconnecting with any California intrastate Gas systems at the Delivery Point, once such additional capacity (measured at its nominal capacity) commences service; and
"Additional Interstate Capacity": means, for any period, the nominal interstate Gas transportation capacity of all Gas transportation projects which when completed will be capable of providing interstate Gas transportation to the Delivery Point

and for which pipe for the proposed pipeline of such project(s) has been ordered.
"Cash Flow": for any period, all revenues and income of the Borrower derived from the operation or ownership of the Project, calculated in accordance with GAAP, including, without limitation, revenues earned from the sale of electric energy or steam transmitted or distributed by the Project, Net Proceeds, amounts earned by the Borrower pursuant to an arbitration or legal award, amounts received by the Borrower from a sale of property permitted by this Agreement, cash equity contributions made to the Borrower, fines, penalties, indemnities, claims, judgments or awards and investment income on amounts deposited in the Accounts.
"Closing Date": August 28, 1996.
"Code": the Internal Revenue Code of 1986, as amended from time to time, and any successor statute and all rules and regulations promulgated thereunder.
"Collateral": the collective reference to all real and personal property, tangible and intangible, and the proceeds and products thereof, subjected from time to time to the Liens intended to be created by the Collateral Security Documents.
"Collateral Assignment": a collateral assignment of any contract to the Agent for the benefit of the Agent, the Issuing Bank and the Lenders, in substantially the form of Exhibit E.
"Collateral Assignment of Option Agreements": the Collateral Assignment of Option Agreements, dated as of even date herewith, by the Borrower.
"Collateral Security Documents": the collective reference to the Deed of Trust, the Collateral Assignment of Option Agreements, the Assignment of Leases and Rents, the Security Agreement, the Consents, the Deposit and Security Agreement, the Assignments of Partnership Interests, the Calpine Performance Agreement, each Collateral Assignment, the Calpine Guarantees, the UCC-1 financing statements, and any other agreement or instrument hereafter entered into by the Borrower or any other Person which secures any of the Obligations, including, without limitation, any deed of trust entered into by the Borrower in accordance with Section 8.12(c).
"Commitment": the Loan Commitment and the Letter of Credit Commitment.
"Commitment Transfer Supplement": an instrument of transfer substantially in the form of Exhibit G.

"Commonly Controlled Entity": as applied to the Borrower, any person who is a member of a group which is under common control with the Borrower, who together with the Borrower is treated as a single employer within the meaning of Section 414(b), (c), (m) or (o) of the Code or Section 4001(b) of ERISA.
"ConAgra": ConAgra, Inc., a Delaware corporation.
"ConAgra Assignment Agreement": the Assignment and Assumption Agreement, dated as of event date with the Asset Purchase Agreement, between Gilroy Foods and ConAgra, pursuant to which, among other things, Gilroy Foods assigns to, and ConAgra assumes, all of Gilroy Foods' right, title, interest, duties, liabilities and obligations under the Steam Sales Agreement, from and after the effective date of such assignment, as more fully set forth therein.
"ConAgra Shutdown Consent": the Consent and Agreement (Shutdown Agreement), dated as of even date herewith, among ConAgra, the Borrower and the Agent.
"ConAgra Option Agreements": collectively, (i) the QF Site Option Agreement, dated as of even date with the Asset Purchase Agreement, between ConAgra and the Borrower, (ii) the Wastewater Discharge Option Agreement, dated as of even date with the Asset Purchase Agreement, between ConAgra and the Borrower, and (iii) the Facility Site Option Agreement, dated as of even date with the Asset Purchase Agreement, between ConAgra and the Borrower.
"Consent": each Consent and Agreement, substantially in the form set forth in Exhibit H, to be executed and delivered by each party (other than the Borrower) to each Project Contract in effect as of the date of this Agreement.
"Contractual Obligation": as to any Person, any provision of any security issued by such Person or of any indenture, mortgage, deed of trust, contract, document, agreement, lease, instrument, written preferential payment arrangement or written undertaking to which such Person is a party or by which it or any of its property is bound or subject.
"Cost of Fuel": on a per mmbtu basis, the sum of (i) the cost of purchasing fuel at the delivery point under the Gas Supply Agreement or any replacement agreement or otherwise, plus (ii) the cost of transporting such fuel over a California intrastate system to the burnertip.
"Debt Service": for any period, the aggregate (without duplication) of (a) all amounts of interest on the Loans and any Drawing required to be paid during such period, plus (b) all amounts of principal on the Loans and amounts payable with respect to any Drawing which are required to be paid during such

period (whether by maturity, acceleration upon an exercise of remedies, or otherwise), excluding any optional or mandatory prepayments of principal pursuant to Section 3.7 or 3.8 during such period, plus (c) all other premiums, fees, costs, charges, expenses and penalties which are due and payable to the Agent, the Issuing Bank or the Lenders during such period pursuant to the Loan Documents (other than the Interest Rate Contracts), plus (d) all fees, costs, charges, expenses and penalties and all other payments which are due and payable by the Borrower in connection with the Interest Rate Contracts during such period.
"Debt Service Coverage Ratio": for any period, (a) Cash Flow for such period less Operating and Maintenance Costs for such period, divided by
(b) Debt Service for such period.
"Debt Service Reserve Account": the Debt Service Reserve Account established pursuant to the Deposit and Security Agreement and funded in accordance with Section 8.14(a).
"Debt Service Reserve Account Margin": As of any Quarterly Payment Date on which the Debt Service Coverage Ratio for the preceding twelve-month period was less than 1.20, an amount equal to Excess Cash Flow remaining after making any deposits required pursuant to Sections 3.2(a), (b) or
(c), 3.3(b), 3.4(a), 3.5(a) and (b) of the Deposit and Security Agreement.
"Deed of Trust": as defined in Section 3.9(a).
"Default": any of the events specified in Section 10.1, whether or not any requirement for the giving of notice, the lapse of time, or both, or for the happening of any other condition, has been satisfied.
"Default Rate": as defined in Section 3.4.
"Delivery Point": means, for the purposes of calculating Interstate Capacity or Additional Interstate Capacity, any point of interconnection between any intrastate gas transporter's or pipeline company's Gas system and any California intrastate gas transportation system.
"Deposit and Security Agreement": the Deposit and Security Agreement, dated as of even date herewith, among the Borrower, the Agent and BNP, as disbursement agent.
"Disbursement Agent": as defined in the recitals to the Deposit and Security Agreement.
"Disposition": as defined in Section 10.3.
"Dollars" or "$": dollars in lawful currency of the

United States of America.
"Drawing": any drawing under either Letter of Credit.
"Easement Agreements": collectively, all easements (including, without limitation, any partial easements), licenses, franchises, rights-of-way, joint use agreements and spur track agreements to which the Borrower is now or hereafter a party or beneficiary, affecting the use, maintenance or operation, or constituting a part, of the Project Site as the same may be amended, modified or supplemented from time to time.
"Environmental Consultant": Pilko & Associates, Inc., or any other environmental consulting firm as shall be engaged by the Agent on behalf of the Lenders, after consultation with the Borrower to determine a mutually acceptable selection; provided, that if the Agent and the Borrower are unable to agree upon a selection within five Business Days, the Agent shall select such other consultant upon not less than five Business Days' notice to the Borrower setting forth the identity of the proposed consultant, the scope and duration of such Person's services and the proposed budget therefor.
"Environmental Laws": all federal, state and local laws and regulations including, without limitation, the Comprehensive Environmental Response Compensation and Liability Act (42 U.S.C. Section 9601 et seq.), the Resource Conservation and Recovery Act (42 U.S.C. Section 6901 et seq.), the National Environmental Policy Act (42 U.S.C. Section 4321 et seq.), the Hazardous Materials Transportation Act (49 U.S.C. Section 1801 et seq.), the Toxic Substances Control Act (15 U.S.C. Section 2601 et seq.), the Clean Air Act (42 U.S.C. Section 7401 et seq.), the Federal Water Pollution Control Act (33 U.S.C. Section 1251 et seq.), the Safe Drinking Water Act (42 U.S.C. Section 300f et seq.), Carpenter-Presley-Tanner Hazardous Substance Account Act, California Health and Safety Code sections 25300 et seq., California Hazardous Waste Control Law, California Health and Safety Code Sections 25100 et seq., California Air Resources Code, California Health and Safety Code sections 39000 et seq., Porter-Cologne Water Quality Control Act, California Water Code sections 13000 et seq., Safe Drinking Water and Toxic Enforcement Act ("PROP 65"), California Health and Safety Code sections 25249.5 et seq., California Public Resources Code sections 25500 et seq., California Environmental Quality Act, California Public Resources Code sections 21000 et seq., Santa Clara County Ordinance NS517, City of Gilroy Hazardous Materials Storage Ordinance, and any common law theory of liability, in any case relating to pollution or protection of human health or the environment (including, without limitation, ambient air, surface water, ground water, land surface or subsurface strata), all as currently in effect or as shall be promulgated, issued and amended or ordered in the future, including, without limitation, laws and regulations relating to emissions, discharges, releases

or threatened releases of Materials of Environmental Concern, or otherwise relating to the manufacture, processing, refining, distribution, use, treatment, storage, disposal, transport, recycling, reporting or handling of Materials of Environmental Concern, and all federal, state and local zoning and land use laws or regulations, as currently in effect or as shall be promulgated, issued and amended or ordered in the future.
"Environmental Report": the Phase I Environment Site Assessment, Gilroy Energy Company, Gilroy, California, dated June 18, 1996, prepared by EMCON.
"ERISA": the Employee Retirement Income Security Act of 1974, as amended from time to time, and any successor statute and all rules and regulations promulgated thereunder.
"Eurocurrency Reserve Period": as defined in Section 3.12(b).
"Event of Default": any of the events specified in Section 10.1; provided that any requirement set forth therein for the giving of notice, the lapse of time, or both, or for the happening of any other condition, has been satisfied.
"Event of Loss": (a) the actual or constructive total loss of the Project, (b) loss, theft, destruction or damage of any portion of the Project, to an extent that operation of the Project would, in the written opinion of the Independent Engineer, a copy of which shall be provided to the Borrower, be uneconomical (taking into account any Net Proceeds received by the Borrower and all funds otherwise available to the Borrower) or infeasible without repairs or replacements that would also be uneconomical (taking into account any Net Proceed received by the Borrower and all funds otherwise available to the Borrower) or infeasible or for which sufficient funds are not available, or (c) the Taking for one year or more of the use of any portion of the Project which would, in the written opinion of the Independent Engineer, a copy of which shall be provided to the Borrower, make operation of the Project uneconomical (taking into account any Net Proceeds received by the Borrower and all funds otherwise available to the Borrower) or infeasible.
"Excess Cash Flow": as of any date, the amount of Cash Flow remaining in the Receipt Account after payment of Debt Service on such date, in accordance with the priorities set forth in Section 4.2 of the Deposit and Security Agreement.
"Excluded Payments": as defined in the Security Agreement.
"Federal Funds Rate": for any period, a fluctuating interest rate per annum equal for each day during such period to the weighted average of the rates on overnight Federal Funds

transactions with members of the Federal Reserve System arranged by Federal Funds brokers, as published for such day (or, if such day is not a Business Day, for the immediately preceding Business Day) by the Federal Reserve Bank of San Francisco, or, if such rate is not so published for any day which is a Business Day, the average of the quotations for such day on such transactions received by the Agent from three Federal Funds brokers of recognized standing selected by the Agent.
"Form 1001": Form 1001 (Ownership, Exemption, or Reduced Rate Certificate) of the Department of Treasury of the United States of America (or such successor and related forms as may from time to time be adopted by the relevant taxing authorities of the United States of America to document a claim to which such form relates).
"Form 4224": Form 4224 (Exemption from Withholding of Tax on Income Effectively Connected with the Conduct of a Trade or Business in the United States) of the Department of Treasury of the United States of America (or such successor and related forms as may from time to time be adopted by the relevant taxing authorities of the United States of America to document a claim to which such form relates).
"Fuel Cost Differential": as defined in Section 8.14(c)(i).
"Fuel Management Contract": the Fuel Management Agreement, dated as of even date herewith, between the Borrower and Calpine Fuels.
"Fuel Manager": Calpine Fuels, or any successor fuel manager for the Project.
"Fuel Margin Guaranty": the Fuel Margin Guaranty, dated as of even date herewith, by Calpine in favor of the Borrower.
"Fuel Plan": an annual fuel plan prepared by Calpine Fuels, in form reasonably satisfactory to the Required Lenders, which will (a) summarize the Project's fuel supply arrangements and Cost of Fuel, (b) demonstrate price linkage between such Cost of Fuel and the UEG Rate, and (c) address the other topics listed in the Fuel Plan Index attached here as Schedule 1.1(c).
"Fuel Reserve Account": the Fuel Reserve Account established pursuant to the Deposit and Security Agreement.
"Fuel Transportation Report": a quarterly report prepared by or on behalf of the Borrower which will address the topics listed in the Fuel Transportation Report Index attached hereto as Schedule 1.1(d).

"Fuel Transportation Trigger Event": (a) Capacity Utilization (on a 12-month rolling average, based on quarterly calculations) equals or exceeds 85%, or (b) a default by Calpine of its covenants set forth in Section
3(a)(iv), 3(b)(iv) of the Calpine Performance Agreement, or a default by Calpine or the Borrower of its covenants set forth in Section 8(g) of the Calpine Performance Agreement, or (c) a failure by the Borrower to renew the term of the Gas Transportation Agreement (or any replacement agreement) at the end of any term thereof, for an additional two-year period, or (d) the occurrence of a Calpine Credit Event Level II.
"GAAP": generally accepted accounting principles in effect from time to time in the United States of America, provided that if any changes in accounting principles from those used by the Borrower in the preparation of its financial statements are hereafter required by the rules, regulations, pronouncements and opinions of the Financial Accounting Standards Board or the American Institute of Certified Public Accountants (or successors thereto or agencies with similar functions) and are adopted by the Borrower with the agreement of its independent certified public accountants and such changes materially affect (or result in a material change in the method of calculation of) any of the covenants, standards or terms found in this Agreement, the parties hereto agree to enter into negotiations in order to amend such provisions so as to reflect equitably such changes with the desired result that the criteria for evaluating compliance with such covenants, standards and terms by the Borrower shall be the same after such changes as if such changes had not been made; provided, however, that no change in generally accepted accounting principles that would affect any of such covenants, standards or terms or the method of calculation of any such covenants, standards or terms) shall be given effect in such calculations until such provisions are amended, in a manner reasonably satisfactory to the Agent and the Borrower, to reflect such change in accounting principles.
"Gas": means natural and/or residue gas comprised primarily of methane, which complies with the quality requirements of the applicable intrastate gas transporter or pipeline company or PG&E or any other local Gas distribution or transportation company that transports Gas to the Delivery Point.
"Gas Consultant": ICF Kaiser, or any other gas consulting firm as shall be engaged by the Agent on behalf of the Lenders after consultation with the Borrower to determine a mutually acceptable selection; provided, that if the Agent and the Borrower are unable to agree upon a selection within five Business Days, the Agent shall select such other consultant upon not less than five Business Days' notice to the Borrower setting forth the identity of the proposed consultant, the scope and duration of such Person's services and the proposed budget

therefor.
"Gas Supply Agreement": the Amended and Restated Natural Gas Sales Agreement, dated as of even date herewith, between the Borrower and Amoco, and the Performance Guaranty, dated as of August 1, 1995 made by Amoco Production Company, a Delaware corporation, in favor of the Borrower.
"Gas Transportation Agreement": the Natural Gas Services Agreement executed by PG&E on June 1, 1995, between PG&E and Gilroy, as assigned by Gilroy to the Borrower pursuant to the General Assignment and Assumption Agreement.
"GE Services Agreement": the GE Services Agreement, dated as of December 17, 1992, between General Electric Industrial and Power Systems and Gilroy, as assigned by Gilroy to the Borrower pursuant to the Assignment, Assumption and Consent Agreement among Gilroy, the Borrower and General Electric Industrial and Power Systems.
"General Assignment and Assumption Agreement": the General Assignment and Assumption Agreement, dated as of even date with the Asset Purchase Agreement, between Gilroy and the Borrower.
"Gilroy": Gilroy Energy Company, Inc., a California corporation.
"Gilroy Facility": the onion and garlic dehydrating facility located adjacent to the Facility.
"Gilroy Foods": Gilroy Foods, Incorporated, a California corporation.
"Governmental Approvals": authorizations, consents, approvals, waivers, exemptions, variances, franchises, permissions, permits and licenses of, and filings and declarations with, and rulings by any Governmental Authority.
"Governmental Authority": any government, or any nation, state, or political subdivision of any nation or state, and any entity exercising executive, legislative, judicial, regulatory or administrative functions of or pertaining to government, including, without limitation, any central bank or other fiscal, monetary or other authority.
"Improvements": as defined in the recitals to the Deed of Trust.
"Indebtedness": as to any Person, (a) all obligations of such Person for borrowed money and for the deferred purchase price of property, including, without limitation, pursuant to any capital lease, or services (other than obligations under

agreements for the purchase of goods and services in the normal course of business which are not more than 30 days past due), and obligations evidenced by bonds, debentures, notes or similar instruments (excluding "deposit only" endorsements on checks payable to the order of such Person); (b) all indebtedness secured by any Lien on any property owned or held by such Person subject thereto, whether or not the indebtedness secured thereby shall have been assumed; (c) obligations of such Person under direct or indirect guaranties in respect of, and obligations (contingent or otherwise) to purchase or otherwise acquire, or otherwise to assure a creditor against loss in respect of, indebtedness or obligations of others, and (d) obligations of such Person incurred under any financial hedging arrangements and interest rate contracts.
"Independent Engineer": Stone & Webster Engineering Corp., or such other independent engineering firm as shall be engaged by the Agent on behalf of the Lenders after consultation with the Borrower to determine a mutually acceptable selection; provided, that if the Agent and the Borrower are unable to agree upon a selection within five Business Days, the Agent shall select such other consultant upon not less than five Business Days' notice to the Borrower setting forth the identity of the proposed consultant, the scope and duration of such Person's services and the proposed budget therefor.
"Insufficiency": with respect to any employee benefit plan, the amount, if any, by which the present value of the vested and non-vested benefits under such plan (determined as of the latest actuarial valuation date for such plan and determined in accordance with the same assumptions and methods as used in the most recent actuarial valuation for such plan) exceeds the fair market value of the assets of such plan allocable to such benefits.
"Insurance Consultant": Sedgewick James of Tennessee, Inc., or any other insurance consulting firm as shall be engaged by the Agent on behalf of the Lenders after consultation with the Borrower to determine a mutually acceptable selection; provided, that if the Agent and the Borrower are unable to agree upon a selection within five Business Days, the Agent shall select such other consultant upon not less than five Business Days' notice to the Borrower setting forth the identity of the proposed consultant, the scope and duration of such Person's services and the proposed budget therefor.
"Insurance Proceeds Account": the Insurance Proceeds Account established pursuant to the Deposit and Security Agreement.
"Interconnection Agreement": the Agreement for Installation or Allocation of Special Facilities For Parallel Operation of Nonutility-Owned Generation and/or Electrical

Standby Service, executed by PG&E on June 10, 1986.
"Interest Period": shall mean, with respect to any LIBOR Rate Loan, the period beginning on and including the date on which such LIBOR Rate Loan is made or, if such Loan already is outstanding, the Interest Period End Date for the existing Interest Period for such Loan, and ending on but excluding the date numerically corresponding to such beginning date in the first, second, third, sixth or, if funds are available in the Eurodollar market to all the Lenders during such period, twelfth succeeding month as the Borrower may specify or be deemed to specify, provided, however, that if such beginning day or ending day is not a LIBOR Business Day or Business Day, as applicable, then such beginning and/or ending day shall be the next succeeding LIBOR Business Day or Business Day, as applicable, unless such next succeeding LIBOR Business Day or Business Day falls in the next succeeding calendar month, in which event such beginning day or ending day shall be the next preceding LIBOR Business Day or Business Day, as applicable; and, with respect to each Alternate Base Rate Loan, the period beginning on and including the date on which such Loan is made and ending on the next Quarterly Payment Date.
"Interest Period End Date": the ending date of each Interest Period or, if earlier, the applicable Maturity Date, and any date on which all of the Notes become due under Section 3.7 or Article X.
"Interest Rate Contracts": as defined in Section 3.11.
"Issuing Bank": as defined in the first paragraph of this Agreement.
"Issuing Bank Letter of Credit Fees": as defined in Section 5.4.
"Lender Schedule": the Lender Schedule attached hereto as Appendix I, as amended from time to time.
"Letter of Credit Commitment": the Tranche C Letter of Credit Commitment and the Tranche D Letter of Credit Commitment.
"Letter of Credit Fees": as defined in Section 5.2.
"Letter of Credit Guaranty": the Letter of Credit Guaranty, dated as of even date herewith, made by Calpine in favor of the Agent, the Issuing Bank and the Lenders.
"LIBOR": for any Interest Period, the interest rate per annum equal to the London Interbank Offered Rate, at 11:00 AM (London Time) two LIBOR Business Days prior to the first day of such Interest Period for United States dollar deposits in the London Interbank Market in immediately available funds for

delivery on the first day of such Interest Period, and having a maturity equal to such Interest Period, as such rate is reported on the display designated as "Page 3750" by "Telerate-The Financial Information Network" published by Telerate-Systems Incorporated, or its successor company ("Telerate"). If Telerate shall cease to report such rates on a regular basis, "LIBOR" shall mean for any Interest Period the rate per annum determined by the Agent to be the arithmetic average (rounded upwards, if necessary, to the nearest 1/16 of 1%) of the rates per annum as quoted to the Agent by the Agent (if it is a Reference Bank) and two (or three, if the Agent is not a Reference Bank) other Reference Banks as being offered by the Agent and such Reference Banks to prime banks two LIBOR Business Days prior to the first day of such Interest Period for U.S. dollar deposits in the London Interbank Market in the approximate amount of the portion of the applicable Loan to be made by the applicable LIBOR Lender on the first day of such Interest Period in immediately available funds for delivery on the first day of such Interest Period.
"LIBOR Business Day": a day of the year on which dealings are carried on in the London Interbank Market and banks are open for business in London, England, and are not required or authorized to close in Los Angeles, California.
"LIBOR Rate": any interest rate priced in relation to LIBOR.
"LIBOR Rate Loan": any Loan that bears interest at the LIBOR Rate for the applicable Interest Period plus the Applicable Margin as provided in Section 3.3(b).
"Lien": any mortgage, deed of trust, security interest, pledge, hypothecation, deposit arrangement, assignment, charge, encumbrance, lien (statutory or other) or other preferential arrangement in the nature of a security interest, including, without limitation, any agreement to give any of the foregoing, any conditional sale or other title retention agreement, any financing lease having substantially the same economic effect as any such agreement, and the filing of any statement under the Uniform Commercial Code or comparable law of any jurisdiction.
"Loan" or "Loans": the Tranche A Loan, the Tranche B Loan and/or the Tranche C Loans.
"Loan Commitment": the commitment of the Lenders to make the Tranche A Loan and Tranche B Loan, in an aggregate amount not to exceed $116,000,000.
"Loan Documents": this Agreement, the Collateral Security Documents, the Notes, the Letters of Credit, any and all Interest Rate Contracts in effect from time to time, and such other instruments evidencing, securing or pertaining to the

Commitments as shall from time to time be executed and delivered by the Borrower or any other party, pursuant to or as contemplated by this Agreement.
"Local Bank Account": any bank account of the Borrower held by a financial institution located in California, in connection with which the Borrower and such financial institution have executed and delivered a blocked account agreement approved in advance by the Lenders (which approval will not be unreasonably withheld).
"Long-Term Gas Supply Agreement": any gas supply agreement entered into by the Borrower pursuant to Section 8.16(c) hereof.
"Major Maintenance Guaranty": the Major Maintenance Guaranty, dated as of even date herewith, made by Calpine in favor of the Agent, the Issuing Bank and the Lenders.
"Major Maintenance Plan": each annual major maintenance plan (which shall include annual and longer-term major maintenance schedules) for the Project prepared by or on behalf of the Borrower and reviewed and commented on by the Independent Engineer.
"Major Maintenance Reserve Account": the Major Maintenance Reserve Account established pursuant to the Deposit and Security Agreement.
"Material Adverse Effect": a material adverse effect on (a) any material part of, or the value of, the security or Collateral provided under the Collateral Security Documents, (b) the financial condition, business, operations or prospects of the Project, the Borrower, Calpine, Calpine Fuels or PG&E, (c) the ability of the Borrower, Calpine or PG&E to observe and perform its obligations under the Basic Documents to which it is a party, (d) the rights or interests of any Lender which is reasonably likely to prevent such Lender from realizing in any material respect the benefits of this Agreement or any Basic Document, (e) the operation, maintenance or use of the Project, or (f) the status of the Project as a Qualifying Facility.
"Material Obligor": the Borrower, Calpine, Calpine Fuels or PG&E.
"Materials of Environmental Concern": those chemicals, pollutants, contaminants, wastes, degradation by-products, toxic substances, petroleum and petroleum products, including, without limitation, "hazardous substances," "hazardous wastes," "toxic substances" and "toxic pollutants," as defined in or identified pursuant to any Environmental Law.
"Maturity Date": the Tranche A Maturity Date, the

Tranche B Maturity Date, the Tranche C Maturity Date and/or the Tranche D Maturity Date.
"Minimum Credit Rating": a rating by Standard & Poor's of Calpine's long-term credit of "B-" or less, with a negative outlook, or a rating by Moody's of Calpine's long-term credit of "B2" or less, with a "negative outlook" determination.
"Moody's": Moody's Investors Service, Inc., a Delaware corporation.
"Multiemployer Plan": a Plan which is a multiemployer plan as defined in Section 4001(a)(3) of ERISA.
"Natural Gas Sales Consent and Agreement": the Consent and Agreement (Natural Gas Sales Agreement), dated as of even date herewith, by and among Amoco, the Borrower and the Agent.
"Net Proceeds": all amounts, including, without limitation, insurance proceeds, received by or for the account of the Borrower as a result of (a) the loss, theft, destruction or damage to all or any portion of the Project, (b) a condemnation, confiscation or requisition of all or any portion of the Project or (c) a defect in title of all or any portion of the Project.
"Noncompete Agreement": the Noncompetition/Earnings Contingency Agreement, dated as of even date with the Asset Purchase Agreement, by and among Gilroy, McCormick & Company, Incorporated and the Borrower.
"Note" or "Notes": the Tranche A Notes, Tranche B Notes and/or Tranche C Notes.
"Obligations": all obligations, fees, charges, liabilities and indebtedness of every nature of the Borrower from time to time owing to the Agent or the Issuing Bank or any Lender under or in connection with the transactions contemplated by the Loan Documents.
"O&M Reserve Sub-Account": the O&M Reserve Sub-Account of the Operating Account to be established pursuant to the Deposit and Security Agreement.
"Operating Account": the Operating Account (including the O&M Reserve Sub-Account) established pursuant to the Deposit and Security Agreement.
"Operating Plan": each annual operating plan for the Project prepared by or on behalf of the Borrower and reviewed and commented on by the Independent Engineer which shall address each of the topics set forth in the Operating Plan Index attached hereto as Schedule 1.1(e).

"Operations and Maintenance Agreement": the Operation and Maintenance Agreement, dated as of even date herewith, between Calpine and the Borrower.
"Operations and Maintenance Costs": for any period, operation and maintenance costs relating to the Project, calculated in accordance with GAAP, including, without duplication "Recoverable Costs" and fees under the Operations and Maintenance Agreement (but excluding operating and maintenance costs paid by and not reimbursable to the Operator pursuant to the Operations and Maintenance Agreement), costs of overhauls and other major maintenance, costs of repair or restoration, costs of purchasing property, equipment, supplies, inventory and consumables, capital expenditures, costs of responding to emergency or force majeure situations, fuel supply and transportation costs, Taxes, insurance premiums, fees relating to Governmental Approvals, general administrative costs, payments under Project Contracts, Assigned Agreements and Permitted Contracts, payments of Indebtedness (other than Debt Service and Indebtedness to any partner of the Borrower except if such Indebtedness constitutes Permitted Indebtedness), fines, penalties, indemnities, claims, judgments or awards, and legal, accounting and other professional fees, but excluding non-cash charges, including depreciation or obsolescence charges or reserves therefor, amortization of intangibles or other bookkeeping entries of a similar nature.
"Operator": Calpine, or any successor operator of the Project.
"Partner": Calpine Gilroy 1, Inc., a Delaware corporation and the general partner of the Borrower.
"Partnership Agreement": the Limited Partnership Agreement, dated as of even date herewith, among the Partner, as general partner, and Calpine Gilroy 2, Inc., a Delaware corporation, as limited partner.
"Payment Dates": each August 31 and November 30 set forth in any of the Amortization Schedules on which principal payments on any Note are due.
"PBGC": the Pension Benefit Guaranty Corporation.
"Permitted Contract": any agreement of the Borrower with respect to the Project entered into after the Closing Date pursuant to which the Borrower incurs obligations or liabilities, together with the Borrower's obligations and liabilities under all other Permitted Contracts then in effect, of not more than $500,000 in any operating year or more than $1,500,000 in the aggregate outstanding at any one time, provided that the Agent shall receive notice of the execution of any such agreement.

"Permitted Indebtedness": (a) trade accounts and unsecured payables (not the result of any borrowing) incurred and payable in the ordinary course of the Borrower's business provided that any such trade account or unsecured payable is no more than one hundred twenty (120) days old, (b) capital leases or purchase money debt secured by Improvements in a principal amount approved by the Required Lenders, such approval not to be withheld unreasonably,
(c) any Indebtedness incurred under the Loan Documents, (d) unsecured Indebtedness in an amount not to exceed $250,000 in the aggregate outstanding at any one time (provided that such Permitted Indebtedness may be loans made by a partner of the Borrower only if the Borrower has been unsuccessful in obtaining necessary financing from third parties on acceptable terms), or (e) purchase money security interests in equipment purchased by the Borrower in accordance with the Major Maintenance Plan or Section 8.14(d)(iii) in an amount not to exceed $500,000 in the aggregate outstanding at any one time.
"Permitted Investments": (a) marketable direct obligations issued or unconditionally guaranteed by the United States of America maturing within three months from the date of acquisition thereof, (b) commercial paper maturing no more than three months from the date of creation thereof and as at any date of determination rated "A-1" or better by Standard & Poor's and "P-1" or better by Moody's, (c) certificates of deposit, term deposits or Euro-term deposits maturing within three months from the date of acquisition thereof issued by any bank the short-term obligations of which are rated "P-1" or better by Moody's "A-1" or better by Standard & Poor's, (d) guaranteed investment contracts provided by the Agent or any other financial institution the short-term obligations of which are rated "P-1" or better by Moody's or "A-1" or better by Standard & Poor's and (e) any advances, loans or extensions of credit or any stock, bonds, notes, debentures or other securities as the Required Lenders may from time to time approve in their sole and absolute discretion; provided, that with respect to the credit ratings specified above, if neither Moody's nor Standard & Poor's is in the business of rating the relevant Permitted Investment, such Permitted Investment shall have received a rating equivalent to that specified above for such Permitted Investment by another nationally recognized credit rating agency of similar standing.
"Permitted Liens": (a) Liens created by the Collateral Security Documents or any other Loan Document; (b) Liens for Taxes the payment of which is not at the time required by Section 8.4; (c) carrier's, warehousemen's, mechanics', materialmen's, repairmen's or other like Liens arising in the ordinary course of business or incidental to the improvement, maintenance or repair of any property of the Project not filed of record which secure payment of sums which are not delinquent and unbonded for more than 30 days, and mechanics', materialmen's, repairmen's and other like Liens which have been filed of record but which are being contested in good faith proceedings and have

not proceeded to judgment (unless such contest involves a risk of sale, loss or forfeit of the Project or any significant part thereof, title thereto or any significant interest therein, or of the use of the Project), provided, that the Borrower shall have posted a bond or other security acceptable to the Required Lenders for the full amount of such Liens; (d) Liens (other than any Lien imposed by ERISA) incurred or deposits made in the ordinary course of business in connection with worker's compensation, unemployment insurance and other types of social security; (e) exceptions to the title of the Project Site as set forth in the Title Policy as approved by the Lenders; (f) rights reserved to or vested in any Governmental Authority under applicable law to control or regulate any property of the Borrower which do not in the aggregate materially interfere with or impair the operation or use thereof for the purposes for which it is or may reasonably be expected to be held by the Borrower; (g) Liens for Permitted Indebtedness incurred pursuant to clauses (a), (b) or (e) of the definition thereof; (h) judgment Liens which, within five days of their existence, are bonded against or are otherwise secured to the reasonable satisfaction of the Required Lenders; (i) Liens which are being contested in accordance with Section 8.8; and (j) minor defects, irregularities, encumbrances, easements, rights-of-way, restrictions and clouds on title to the Project Site which are not recorded or filed and which do not individually or in the aggregate materially impair the use or enjoyment of the Project Site and which do not individually or in the aggregate impair the value of the Collateral or the priority of the Lien in favor of the Agent, the Lenders and the Issuing Bank granted under the Collateral Security Documents.
"Permitted Transferee": (a) Calpine, (b) any Person which is wholly-owned, directly or indirectly, by Calpine, and (c) any other person which is or is owned at least fifty-one percent (51%), directly or indirectly, by a Person, which (i) has a long-term credit rating of at least B or its equivalent by Standard & Poor's or Moody's or is an entity which is substantially well-capitalized and acceptable to the Agent, such approval not to be unreasonably withheld, (ii) is a sophisticated investor reasonably experienced in the ownership or operation of or the investment in energy production facilities or is advised by a Person with such experience, and (iii) whose direct and indirect ownership in the Project, when combined with the other direct and indirect ownership interests in the Project, would not result in the Project ceasing to be a Qualifying Facility, in each case, if such Person has entered into an assignment of partnership interests in favor of the Agent substantially in the form of the Collateral Assignment of Partnership Interest attached hereto as Appendix K-2.
"Person": an individual, partnership, corporation, business trust, joint stock company, trust, unincorporated association, joint venture, Governmental Authority or other

entity of whatever nature.
"PG&E": Pacific Gas and Electric Company, a California corporation.
"Plan": any plan (other than a Multiemployer Plan) covered by Title IV of ERISA maintained for employees of a Person or any Commonly Controlled Entity.
"Power Purchase Agreement": the Long-Term Energy and Capacity Power Purchase Agreement among Gilroy Foods, Pacific Thermonetics, Inc. and PG&E, as executed by Pacific Gas and Electric Company on December 19, 1983, as amended by a First Amendment to "Long-Term Energy and Capacity Power Purchase Agreement Between Gilroy Foods, Inc., Pacific Thermonetics, Inc. and Pacific Gas and Electric Company" dated December 19, 1983, as executed by PG&E on July 18, 1985, and, as so amended, as assigned by Gilroy Foods to Gilroy, as further amended by a Second Amendment to "Long-Term Energy and Capacity Power Purchase Agreement" dated December 19, 1983, as Amended July 18, 1985, as executed by PG&E on June 9, 1986, as further amended by a Third Amendment to "Long-Term Energy and Capacity Power Purchase Agreement" dated December 19, 1983, as Amended July 18, 1985 and June 9, 1986, as executed by PG&E on August 18, 1988, and as further amended by a Fourth Amendment to the Long-Term Energy and Capacity Power Purchase Agreement Between Gilroy Energy Company and Pacific Gas and Electric Company, as executed by PG&E on June 6, 1991.
"Power Purchase Consent and Agreement": the Consent to Assignment and Agreement (Power Purchase Agreement), dated as of even date herewith, among Pacific Gas and Electric Company, the Borrower and the Agent.
"Preliminary Fuel Transportation Trigger Event": Capacity Utilization (on a 12-month rolling average, based on quarterly calculations) equals or exceeds 75%.
"Project": a 120 megawatt (nominal net) gas-fired combined-cycle cogeneration facility located in Gilroy, California including, without limitation, related facilities from time to time located on the Project Site, including any and all appliances, parts, instruments, appurtenances, accessories and other property that may be incorporated or installed in or attached to or otherwise become part of the cogeneration facility, and the Project Contracts.
"Project Contracts": the Power Purchase Agreement, the QF Operating Agreement, the Steam Sales Agreement, the Gas Supply Agreement, the Gas Transportation Agreement(s), all replacement gas supply or transportation agreements with a term of ninety (90) days or longer, the Fuel Management Contract, the Operations and Maintenance Agreement, the Interconnection Agreement, the

Site Lease, the Easement Agreements, the Partnership Agreement, the ConAgra Option Agreements, the Shutdown Agreement and any Additional Contract but excluding any Permitted Contract.
"Project Site": the real property described in the Site Lease and on Exhibit I, and all tenements, hereditaments, easements, rights-of-way, rights, privileges and appurtenances relating thereto.
"Purchasing Lender": as defined in Section 12.7(d).
"QF Operating Agreement": the Qualifying Facility Standard Operating Agreement, dated as of November 17, 1987, between PG&E and Gilroy, as assigned to the Borrower pursuant to the General Assignment and Assumption Agreement.
"Qualifying Facility": a facility qualified under Public Utility Regulatory Policies Act of 1978 and Part 292 of Title 18 of the Code of Federal Regulations.
"Quarterly Payment Date": the last day of November, 1996, and the last day in each succeeding February, May, August and November, and on each Maturity Date.
"Rating Downgrade": a downgrade by one level of Calpine's Credit Rating by Standard & Poor's and Moody's, respectively (e.g., a downgrade by Standard & Poor's from B+ to B and a downgrade by Moody's from Ba3 to B1).
"Receipt Account": the Receipt Account established pursuant to the Deposit and Security Agreement.
"Replacement Lender": a financial institution that has agreed to acquire and assume all of a Lender's Loans and Commitments, is reasonably satisfactory to the Agent, the Issuing Bank and the Lenders, and is reasonably satisfactory to the Borrower.
"Required Debt Service Reserve Account Balance": on the Closing Date $4,000,000; as of any date after the Closing Date, through and including the tenth anniversary thereof, $9,000,000; thereafter through and including the fifteenth anniversary thereof, $8,000,000; and thereafter, $4,500,000.
"Required Lenders": on any date, Lenders (including for purposes of this definition the Issuing Bank) that at such time hold at least 662/3% of the sum of (i) the aggregate outstanding Tranche A Loans, Tranche B Loans and Tranche C Loans, plus (ii) the Letter of Credit Commitment on such date plus (iii) any unreimbursed Drawings.
"Requirement of Law": as to any Person, any law, treaty, rule, directive or regulation, or determination,

interpretation or order of an arbitrator or a court or other Governmental Authority, in each case applicable to or binding upon such Person or any of its properties or to which such Person or any of its properties (including without limitation the Project) is subject.
"Responsible Officer": as to any Person, the president, any vice president, the secretary or any other authorized corporate officer of such Person, or if such Person is a partnership the president, any vice president, the secretary or any other authorized corporate officer of a general partner of such Person, or, if such Person is a limited liability company, any management committee member, or, with respect to financial matters, the chief financial officer or other authorized senior financial officer of such Person, or if such Person is a partnership, the chief financial officer or other authorized senior financial officer of a general partner of such Person or, if such Person is a limited liability company, any management committee member having primary responsibility for financial and accounting matters for such limited liability company.
"Restricted Payment": (a) any distribution, dividend or other similar payment, direct or indirect, on account of any ownership interest in the Borrower, (b) any redemption, retirement, purchase or other acquisition by the Borrower, direct or indirect, of any ownership interest in the Borrower, or (c) any payment with respect to Indebtedness to any partner of the Borrower which does not constitute Permitted Indebtedness.
"Secured Parties": the Agent, the Issuing Bank, each Lender (including in its capacity as a counterparty or intermediary to any Interest Rate Contract), and their respective successors and assigns in such capacities.
"Security Agreement": as defined in Section 3.9(b).
"Shutdown Agreement": the Shutdown Agreement, dated as of even date with the Asset Purchase Agreement, between ConAgra and the Borrower.
"Site Lease": the Lease Agreement, dated June 13, 1986, between Gilroy and Gilroy Foods, as amended by Amendment No. 1 to Lease Agreement, dated September 14, 1994, between Gilroy and Gilroy Foods, as assigned by Gilroy Foods to ConAgra pursuant to the ConAgra Assignment Agreement, and as amended and restated pursuant to that certain Amended and Restated Lease Agreement, dated as of even date with the Asset Purchase Agreement, between ConAgra and the Borrower.
"Spare Parts Agreement": the Mutual Spare Parts Principles of Agreement, dated April 23, 1996, between Gilroy and Calpine King City Cogen, LLC, a Delaware limited liability

company.
"Standard & Poor's": Standard & Poor's Corporation, a New York corporation.
"Stated Amount": with respect to either of the Letters of Credit on any date, the maximum amount that may be drawn thereunder.
"Steam Sales Agreement": the Steam Purchase and Sale Contract, dated as of January 20, 1986, by and between Gilroy and Gilroy Foods, as assigned by Gilroy Foods to ConAgra pursuant to the ConAgra Assignment Agreement, as amended by the Steam Sales Amendment, and, as so amended, as assigned by Gilroy to the Borrower pursuant to the Assignment of Steam Sales Agreement.
"Steam Host": ConAgra.
"Steam Sales Amendment": the First Amendment to Steam Purchase and Sale Contract, dated as of even date with the Asset Purchase Agreement, by and between ConAgra and the Borrower.
"Steam Sales Consent and Agreement": the Consent and Agreement (Steam Sales Agreement), dated as of even date with the Asset Purchase Agreement, by and among ConAgra, the Borrower and the Agent.
"Substation Operating Agreement": the Substation Operating Agreement, dated as of even date with the Asset Purchase Agreement, by and between ConAgra and Calpine.
"Taking": a temporary or permanent taking, condemnation, seizure, requisition or confiscation or requisition of title by a Governmental Authority or political subdivision thereof during the term hereof of all or any part of the Project, or any interest therein or right accruing thereto, as the result of or in lieu of or in anticipation of the exercise of the right of condemnation or eminent domain.
"Taxes": any and all federal, state, local and other income, franchise, property, excise, sales or other taxes, fees or charges, or payments in lieu of any of the foregoing, together with all related assessments, interest and penalties.
"Title Company": as defined in Section 7.1(j).
"Title Policy": as defined in Section 7.1(j).
"Tranche A Lender": each Lender listed as a Tranche A Lender on the Lender Schedule.
"Tranche A Loan": as defined in Section 2.1(a).

"Tranche A Maturity Date": as defined in Section 3.1(a).
"Tranche A Note": as defined in Section 3.1(a)(i).
"Tranche A Pro Rata Share": with respect to any Tranche A Lender, the percentage set forth for such Lender on the Lender Schedule (as amended from time to time pursuant to Section 12.7(d)) under the caption "Tranche A Pro Rata Share".
"Tranche B Lender": each Lender listed as a Tranche B Lender on the Lender Schedule.
"Tranche B Loan": as defined in Section 2.1(a).
"Tranche B Maturity Date": as defined in Section 3.1(a).
"Tranche B Note": as defined in Section 3.1(a)(ii).
"Tranche B Pro Rata Share": with respect to any Tranche B Lender, the percentage set forth for such Lender on the Lender Schedule (as amended from time to time in accordance with Section 12.7(d)) under the caption "Tranche B Pro Rata Share".
"Tranche C Lender": each Lender listed as a Tranche C Lender on the Lender Schedule.
"Tranche C Letter of Credit": as defined in Section 4.1(a)(i).
"Tranche C Letter of Credit Commitment": the commitment of the Tranche C Lenders to reimburse the Issuing Bank for Drawings made under the Tranche C Letter of Credit, in an aggregate amount not to exceed $20,000,000.
"Tranche C Loans": as defined in Section 2.1(b).
"Tranche C Maturity Date": as defined in Section 3.1(a).
"Tranche C Note": as defined in Section 3.1(a)(iii).
"Tranche C Pro Rata Share": with respect to any Tranche C Lender, the percentage set forth for such Lender on the Lender Schedule (as amended from time to time pursuant to Section 12.7(d)) under the caption "Tranche C Pro Rata Share".
"Tranche D Lender": each Lender listed as a Tranche D Lender on the Lender Schedule.
"Tranche D Letter of Credit": as defined in

Section 4.1(a)(ii).
"Tranche D Letter of Credit Commitment": the commitment of the Tranche D Lenders to reimburse the Issuing Bank for Drawings made under the Tranche D Letter of Credit in an aggregate amount not to exceed $4,140,000.
"Tranche D Maturity Date": as defined in Section 4.1(b).
"Tranche D Pro Rata Share": with respect to any Tranche D Lender, the percentage set forth for such Lender on the Lender Schedule (as amended from time to time pursuant to Section 12.7(d)) under the caption "Tranche D Pro Rata Share".
"UEG Rate": PG&E's monthly average burnertip cost of gas as calculated in PG&E's monthly posting of "Energy Prices for Qualifying Facilities" or subsequent replacement calculation for the gas cost component of energy prices ordered by the California Public Utilities Commission for the Sale of electric energy to electronic utilities in California should regulatory reform or other events alter or eliminate the monthly posting.
"Upfront Fee": the fee set forth in a separate letter agreement, as defined in Section 5.1.
Section 1.2 Other Definitional Provisions.
(a) All terms defined in this Agreement shall have the same meanings when used in the Notes, the Letters of Credit or in any certificate or other document made or delivered pursuant to this Agreement, unless otherwise stated therein.
(b) All references to a contract, agreement or lease herein shall mean such contract, agreement or lease and all exhibits, schedules and other attachments thereto, as any such contract, agreement or lease may be assigned, amended, supplemented or otherwise modified in accordance with, or otherwise not in contravention of, the provisions of this Agreement. All references to any Person shall include such Person's successors and permitted assigns.
(c) As used in this Agreement and in any certificate or other document made or delivered pursuant hereto, accounting terms, to the extent not defined in Section 1.1, shall have the respective meanings given to them under GAAP.
ARTICLE II
LOANS
Section 2.1 Loans.

(a) Tranche A Loans. Subject to and upon the terms and conditions of this Agreement, each of the Tranche A Lenders, severally and not jointly, agrees on the Closing Date to make available to the Borrower such Lender's Tranche A Pro Rata Share of a term loan (the "Tranche A Loan") in an aggregate amount of $81,000,000.
(b) Tranche B Loans. Subject to and upon the terms and conditions of this Agreement, each of the Tranche B Lenders, severally and not jointly, agrees on the Closing Date to make available to the Borrower such Lender's Tranche B Pro Rata Share of a term loan (the "Tranche B Loan") in an aggregate amount of $35,000,000.
(c) Tranche C Loans. If the Issuing Bank shall make any payment in connection with the Tranche C Letter of Credit, such payment shall be deemed to be a loan (each, a "Tranche C Loan") outstanding under the Tranche C Notes on the date and in the aggregate amount of such payment.
Section 2.2 Use of Proceeds. The proceeds of any Loan shall be used only to pay to Gilroy the "Purchase Price" (as defined in Section 2.3 of the Asset Purchase Agreement) and to pay amounts payable to Gilroy pursuant to the Noncompete Agreement or to pay on the Closing Date fees, costs or expenses to the Persons entitled thereto pursuant to this Agreement.
Section 2.3 Disbursements. No later than l1:00 a.m. Los Angeles time, on the Closing Date, each of the Tranche A Lenders shall make available an amount equal to its Tranche A Pro Rata Share of the Tranche A Loan and each of the Tranche B Lenders shall make available an amount equal to its Tranche B Pro Rata Share of the Tranche B Loan in Dollars and immediately available funds at the Agent's office. After the Agent's receipt of funds from the Lenders, the Agent will transfer to Gilroy or its designee prior to 1:00
p.m. Los Angeles time on the Closing Date funds in the amount so made available by the Lenders to the Agent.
Section 2.4 Interest Periods. The Borrower shall have the right to elect one or more Interest Periods for each LIBOR Rate Loan; provided, that all Loans shall not be divided at any time into more than five separate interest periods. No interest period for any Loan shall extend beyond the Maturity Date of such Loan.
ARTICLE III
NOTES
Section 3.1 Notes
(a) Generally. The Borrower's obligations to pay the

principal of, and interest on, (i) each Tranche A Lender's Tranche A Loan shall be evidenced by notes of the Borrower substantially in the form of Exhibit B-1 (the "Tranche A Notes"), (ii) each Tranche B Lender's Tranche B Loan shall be evidenced by notes of the Borrower substantially in the form of Exhibit B-2 (the "Tranche B Notes") and (iii) each Tranche C Lender's Tranche C Loans shall be evidenced by notes of the Borrower substantially in the form of Exhibit B-3 (the "Tranche C Notes"). Each Note shall be dated the date of this Agreement, be subject to prepayment as required or permitted under this Agreement, and be entitled to the benefits of this Agreement and the Collateral Security Documents. Each Tranche A Note shall be in the stated principal amount of the Lender's Tranche A Pro Rata Share of the Tranche A Loan mature, and the principal amount thereof shall be due and payable, on the fifteenth anniversary of the Closing Date (the "Tranche A Maturity Date"), and bear interest as provided in Section 3.3. Each Tranche B Note shall be in the stated principal amount of the Lender's Tranche B Pro Rata Share of the Tranche B Loan mature, and the principal amount thereof shall be due and payable on, the eighteenth anniversary of the Closing Date (the "Tranche B Maturity Date") and bear interest as provided in Section 3.3. Each Tranche C Note shall be in the stated principal amount of the Lender's Tranche C Pro Rata Share of the Stated Amount of the Tranche C Letter of Credit on the Closing Date, mature, and the principal amount thereof shall be due and payable on, the fifteenth anniversary of the Closing Date (the "Tranche C Maturity Date"), and bear interest as provided in
Section 3.3.
Section 3.2 Repayment of Notes. The principal amount of each Note shall be due and payable in the amounts and on the dates set forth in the Amortization Schedule attached to such Note together with accrued interest thereon from and after the Closing Date until the Note is paid in full; provided, however, that on the final payment date set forth in the applicable Amortization Schedule, all of the outstanding principal amount of the applicable Loans shall be paid in full. If the Stated Amount of the Tranche C Letter of Credit has not been reduced to zero prior to expiration of the Tranche C Letter of Credit, the Amortization Schedule attached to the Tranche C Note will be amended to take into account the aggregate principal amount of the Tranche C Loans outstanding on the date of expiration of the Tranche C Letter of Credit. Payments of principal of each Note shall be payable on Quarterly Payment Dates in accordance with the applicable Amortization Schedule.
Section 3.3 Interest
(a) Alternate Base Rate Loans. Loans which are Alternate Base Rate Loans shall bear interest for the period from and including the applicable borrowing date until paid in full or converted to a LIBOR Rate Loan in accordance with this Agreement, on the unpaid principal amount thereof at a rate per annum equal

to the Alternate Base Rate as in effect from time to time plus the Applicable Margin, computed on the basis of actual days elapsed (including the first day but excluding the last day) over a year of 365 or 366 days, as the case may be.
(b) LIBOR Rate Loans. Loans which are LIBOR Rate Loans shall bear interest for each Interest Period on the unpaid principal amount thereof at a rate per annum equal to the LIBOR Rate determined for such Interest Period in accordance with the terms hereof plus the Applicable Margin, computed on the basis of actual days elapsed (including the first day but excluding the last day) over a year of 360 days.
(c) Conversion or Continuation of Interest Rates. Subject to
Section 2.4, the Borrower shall have the option to convert an Alternate Base Rate Loan to LIBOR Rate Loans or to continue on the applicable Interest Period End Date any one or more of the outstanding LIBOR Rate Loans for an additional Interest Period of such duration as the Borrower shall elect. The Borrower shall notify the Agent of such conversion or continuation by an irrevocable written notice specifying the proposed commencement date, which notice must be received by the Agent no later than the third Business Day prior to the proposed commencement date of the Interest Period for such Loan.
(d) Payments. Interest on each LIBOR Rate Loan shall be payable on the applicable Interest Period End Date, and, in respect of each LIBOR Rate Loan having an Interest Period in excess of three months, on each Quarterly Payment Date during such Interest Period, and interest on each other Loan shall be payable on each Quarterly Payment Date. Interest on each Loan shall also be payable on the date of any prepayment, at maturity (whether by acceleration or otherwise) and, after such maturity, on demand.
Section 3.4 Default Interest. Upon the occurrence and during the continuance of an Event of Default, each Loan or Drawing (whether or not past due), and, irrespective of the occurrence of an Event of Default, any other amounts (if past due) owing by the Borrower hereunder, including (to the extent permitted by law) overdue interest, shall bear interest, payable on demand, at a rate per annum (the "Default Rate") equal to the Alternate Base Rate plus the Applicable Margin plus 1%.
Section 3.5 Method of Payments. All payments made by the Borrower under this Agreement or under any Note or on account of principal or interest, fees and any other Obligations shall be made so that the Agent receives confirmation of such payment no later than 12:00 noon Los Angeles time on the date when due, to the account set forth for the Agent in the Lender Schedule, or such other account of the Agent as the Agent may from time to time specify to the Borrower, in Dollars by wire transfer of immediately available funds. All payments under this Agreement

or under any Note shall be made in full without any right of set-off by the Borrower or counterclaims of the Borrower whatsoever and without any presentment of such Note to the Borrower.
Section 3.6 Payments Due on Days Other Than Business Days. Subject to the provisions of the definition of Interest Period, whenever any payment to be made under this Agreement or under any Note shall be stated to be due on a day which is not a Business Day, the due date thereof shall be extended to the next succeeding Business Day, and interest shall be payable at the applicable rate during such extension.
Section 3.7 Mandatory Prepayment.
(a) Event of Loss. If an Event of Loss shall occur, subject to the provisions of Section 3.10, the Borrower shall repay in full all of the Obligations on the earlier to occur of (x) the date occurring 90 days after the date of such Event of Loss and (y) upon receipt by the Borrower or the Agent of Net Proceeds in respect of such Event of Loss.
(b) Application of Insurance Proceeds. Any Net Proceeds required under Section 8.6(c) or 8.6(d) to be applied in accordance with this
Section 3.7(b) shall be applied to the mandatory prepayment of a portion of the principal of, and accrued interest on, the Notes and outstanding Drawings in an aggregate amount equal to such Net Proceeds, for the pro rata account of the Lenders, applied first to accrued interest, and second against such Drawings and remaining principal payments of the Notes (in inverse order of maturity).
(c) Interest Rate Contracts. If upon making any prepayment pursuant to this Section 3.7, the aggregate notional amount listed in all Interest Rate Contracts then in effect exceeds the aggregate outstanding principal amount of the Loans, the Borrower shall make corresponding adjustments to the notional amounts listed in all such Interest Rate Contracts and shall pay or receive any settlement amounts due in accordance therewith.
(d) Amounts Prepaid. Amounts prepaid pursuant to this Section 3.7 may not be reborrowed.
Section 3.8 Optional Prepayment.
(a) Prepayment of Loans. The Borrower shall have the option, upon five Business Days' prior written notice to the Agent, to prepay the outstanding principal amount of the Loans, in whole or in part, plus accrued interest, for the pro rata account of the Lenders, first against such accrued interest and then against remaining principal payments in inverse order of maturity. Such notice shall specify the date and amount of prepayment. If the Borrower elects to prepay any LIBOR Rate

Loans prior to the applicable Interest Period End Date the Borrower shall also pay any breakage costs incurred by the Lenders in connection therewith (in accordance with Section 3.16). Upon making any prepayment of Loans pursuant to this Section 3.8, if the aggregate notional amount listed in all Interest Rate Contracts then in effect exceeds the aggregate outstanding principal amount of the Loans, the Borrower shall make adjustments to the notional amounts listed in all Interest Rate Contracts with the Lenders and shall pay any settlement amounts due in accordance therewith.
(b) Amounts Prepaid. Amounts prepaid pursuant to this Section 3.8 may not be reborrowed hereunder.
Section 3.9 Security for the Notes. The Borrower covenants and agrees that the Notes and all other Obligations will be secured by:
(a) a deed of trust in the form of Exhibit C (the "Deed of Trust");
(b) a security agreement in the form of Exhibit D (the "Security Agreement") and a collateral assignment in the form of Exhibit E of the Project Contracts;
(c) a deposit and security agreement in the form of Exhibit F (the "Deposit and Security Agreement") and, if the Agent so requests, separate collateral assignments of the accounts created thereunder;
(d) collateral assignments of partnership interests in the form of Exhibits K-1 and K-2, as applicable (the "Assignments of Partnership Interests"), together with any necessary consents to such assignments;
(e) such other collateral documents as the Agent may from time to time reasonably require to further evidence or perfect the interest of the Agent, the Issuing Bank and the Lenders in the Collateral and/or to grant to the Agent for the benefit of such Persons a mortgage, security interest or other Lien in all right, title and interest of the Borrower in the Project, the Project Contracts, the Assigned Agreements, the Borrower's interest in the Project Site and related real and personal property interests. If the Agent, the Issuing Bank or any Lender receives any Excluded Payments, such Person shall forthwith pay over such amounts in the same form as received (with any necessary endorsement) to the Borrower or to such Person(s) as the Borrower may designate.
Section 3.10 Distribution of Amounts in Respect of Events of Loss and Events of Default. Except as otherwise provided in this Article III, all payments received and amounts

realized by the Agent, the Issuing Bank or any Lender under any Loan Document with respect to the occurrence of an Event of Loss or while an Event of Default shall have occurred and be continuing, as well as all payments or amounts then held or thereafter received by the Agent as part of the Collateral following an Event of Loss or while an Event of Default shall be continuing, as applicable, shall be distributed by the Agent in the following order of priority:
(a) First, so much of such amounts as shall be required to reimburse the Agent for (i) the reasonable] costs and expenses of retaking, holding and preparing the Collateral for sale and the selling of the Collateral (including, without limitation, reasonable advertising, selling and legal expenses and attorneys' fees), (ii) costs of discharging any assessments or Liens, if any, on the Collateral prior to the Lien of the Collateral Security Documents and
(iii) for any reasonable fees, expenses or other losses incurred by the Agent in connection with its duties and rights hereunder or under any other Loan Document, shall be distributed to the Agent;
(b) Second, so much of such amounts as shall be required to reimburse the Agent, the Issuing Bank or any Lender for amounts advanced by them for purposes of curing the Event of Default or enforcing rights under any Collateral Security Document shall be distributed to such Persons ratably, without priority of one over the other;
(c) Third, so much of such amounts as shall be required to pay in full all fees due to the Issuing Bank and the Lenders, shall be distributed to such Persons ratably, without priority of one over the other;
(d) Fourth, so much of such amounts as shall be required to pay in full (i) all interest due on the Loans and the Drawings to the Issuing Bank and Lenders, ratably, without priority of one over the other and (ii) all amounts accruing under the Interest Rate Contracts prior to the occurrence of the Event of Loss or Event of Default and remaining unpaid to the Lenders entitled to the same; and in case such amounts are insufficient to pay in full all such interest and accrued amounts under the Interest Rate Contracts, then to the payment thereof to the Issuing Bank and each Lender ratably in proportion to its percentage of the aggregate of all such amounts;
(e) Fifth, so much of such amounts as shall be required to pay or prepay in full (i) the principal of the Loans and the Drawings to the Issuing Bank and Lenders, ratably, without priority of one over the other, and (ii) all payments due under any Interest Rate Contracts to the Lenders entitled to the same; and in case such amounts shall

be insufficient to pay in full all such principal due on the Loans and Drawings and all such payments due under the Interest Rate Contracts, then to the payment thereof to the Issuing Bank and each Lender ratably in proportion to its percentage of the sum of the aggregate amount of all such principal due and the aggregate amount of all such payments due under the Interest Rate Contracts;
(f) Sixth, so much of such amounts as shall be required to pay any Obligations (including, without limitation, any breakage fees) not covered in clause First, Second, Third, Fourth or Fifth above to the Lenders entitled to the same, ratably, without priority of one over the other; and
(g) Seventh, the balance, if any, of such amounts remaining thereafter shall be paid to the Borrower.
Section 3.11 Interest Rate Contracts. Within 90 days following the Closing Date, the Borrower will enter into interest rate exchanges, collars, caps or similar arrangements or hedging mechanisms with one or more of the Lenders providing interest rate protection with respect to the Loans through the applicable Maturity Date (each, an "Interest Rate Contract") in an aggregate notional amount no less than 65% of the aggregate principal amount of the Loans outstanding from time to time. Any Lender providing an Interest Rate Contract shall be a financial institution the long-term debt of which is rated A- or better by Standard & Poor's and A3 or better by Moody's at the time of execution of the Interest Rate Contract, and during the term of the Interest Rate Contract the long-term credit rating of such Lender must be at least A- or its equivalent by Standard & Poor's or Moody's. The Borrower's obligations to make payments under any Interest Rate Contract to any Lender shall be secured by the Collateral Security Documents pari passu with all other Obligations. The Borrower shall promptly deliver to the Agent true and complete copies of all Interest Rate Contracts entered into by the Borrower, duly authorized, executed and delivered by each of the parties thereto.
Section 3.12 Funding and Yield Protection.
(a) Taxes.
(i) The Borrower shall make all payments of all amounts payable hereunder and under the Notes free and clear of all Taxes (excluding net income Taxes and franchise Taxes imposed on the Agent, the Issuing Bank or any Lender) and shall reimburse the Agent, the Issuing Bank and each Lender for the cost of any such Taxes imposed on it or on any payment under or with respect to any aspect of any Loan, either Letter of Credit, the Notes or the Drawings or the making, execution or enforcement thereof. If the Borrower is prohibited or prevented by any Requirement of Law

or otherwise from making any such payment net, free and clear of any Taxes or from reimbursing the Agent, the Issuing Bank or any Lender for the cost of any such Taxes (other than such Taxes as are excluded above), then the amount of such payment to be made by the Borrower shall be increased by such additional amount or amounts as may be necessary to ensure that the Agent, the Issuing Bank and each Lender shall receive a net amount which after payment of any Taxes imposed shall be equal to the amount the Agent, the Issuing Bank and each such Lender, as applicable, would have received had no such imposition been made. The Borrower shall provide evidence that all such Taxes imposed on all payments under or with respect to any Loan, either Letter of Credit, the Notes or the Drawings or any related instrument shall have been paid in full to the appropriate authorities by delivery of official receipts or certified copies thereof to the Agent within 30 days after payment thereof. The Borrower shall be entitled to make all filings, pursue all remedies and appeals and take such other lawful action to prevent or challenge the imposition of any such Taxes, or to procure a refund of any Taxes paid; provided that the Borrower shall indemnify and hold the Agent, the Issuing Bank and the Lenders harmless for such Taxes (and any penalties, interest or other charges attached thereto or payable with respect thereto) and for any liabilities, costs or expenses incurred by the Agent, the Issuing Bank or the Lenders (including reasonable fees and expenses of counsel) in connection with any such action by the Borrower. The obligations of the Borrower under this Section 3.12(a)(i) shall survive satisfaction in full of the Obligations.
(ii) From and after the Closing Date, each Lender shall provide to the Borrower all forms and documents appropriate under the circumstances that are required to establish that payments hereunder by the Borrower are exempt from withholding for or on account of Taxes. The forms to be provided by each Lender organized outside the United States shall include, if appropriate under the circumstances, Form 4224 if such Lender is acting through a branch or office in the United States or Form 1001 or W-8 (if such Lender is acting through a branch or office outside of the United States). The Borrower's obligation to reimburse the Lenders as aforesaid shall not include any obligation to reimburse any Lender for, or to make any additional payment to any Lender pursuant to this Section 3.12(a) or Section 3.12(b)(i), or to make any such additional payment to any Lender with respect to, Taxes, interest, penalties, fines, assessments or other costs and expenses which are incurred by such Lender due to such Lender's failure to provide the forms and documents described above or the inaccuracy of any such forms or documents provided by such Lender.
(b) Increased Cost and Reduced Return.
(i) If, after the Closing Date, the adoption of any law, rule or regulation, or any change therein, or any change

in the interpretation or administration thereof by any Governmental Authority, central bank or comparable agency charged with the interpretation or administration thereof, or compliance by any Lender with any request or directive (whether or not having the force of law) of any such authority, central bank or comparable agency results in an increase in cost to such Lender of making or maintaining any Loan, or reduces the amount of any sum received or receivable by such Lender under this Agreement or under its Notes with respect thereto by an amount deemed by such Lender to be material, then, such Lender shall deliver to the Borrower and the Agent as promptly as practicable a certificate setting forth in reasonable detail the amount of such increase in costs or reduction in amounts receivable, and the basis and the calculations thereof.
(ii) In the event that any Lender shall determine (which determination shall, absent manifest error, be final and conclusive and binding on all the parties hereto) at any time there is an increase in reserves that such Lender is required to maintain in respect of its LIBOR Rate Loans (a "Eurocurrency Reserve Period"), and such Lender is at such time actually maintaining reserves with respect to its LIBOR Rate Loans, then such Lender shall promptly give notice in reasonable detail to the Borrower and to the Agent of such determination, and the Borrower shall directly pay to such Lender additional interest on the unpaid principal amount of such Loans during such Eurocurrency Reserve Period at a rate per annum which shall, during each monthly period applicable to such Loans, be the amount by which (x) the LIBOR Rate for such monthly period divided by a percentage equal to 100% minus the then stated maximum rate of all reserve requirements (including, without limitation, any marginal, emergency, supplemental, special or other reserves) applicable to such Lender in respect of its LIBOR Rate Loans exceeds (y) the LIBOR Rate for such monthly period. Each Lender so requesting compensation shall furnish along with such notice a certificate setting forth in reasonable detail the cost actually incurred to maintain such reserves and the basis for the determination of such amount. Additional interest payable pursuant to the immediately preceding sentence shall be paid by the Borrower at the time that it is otherwise required to pay interest in respect of such Loans or, if later demanded by such Lender, promptly on demand. Such Lender agrees that, if it gives notice to the Borrower and the Agent of the existence of a Eurocurrency Reserve Period, it shall promptly notify the Borrower and the Agent of any termination thereof, at which time the Borrower shall cease to be obligated to pay additional interest to such Lender pursuant to the first sentence of this paragraph until such time, if any, as a subsequent Eurocurrency Reserve Period shall occur.
(iii) Each Lender shall notify the Borrower of any event occurring after the date of the execution of this Credit Agreement entitling such Lender to compensation under

Sections 3.12, 3.13, 3.15 or 4.4 hereof and of the cessation of each such event, in each case as promptly as practicable, but in any event within 180 days, after such Lender obtains actual knowledge thereof; provided, that (a) if any Lender fails to give such notice within 180 days after it obtains actual knowledge of such an event, such Lender shall, with respect to compensation payable pursuant to Sections 3.12, 3.13, 3.15 or 4.4, in respect of any costs resulting from such event, only be entitled to payment under Sections 3.12, 3.13, 3.15 or 4.4 for costs incurred from and after the date 180 days prior to the date that such Lender does give such notice, and (b) each Lender shall designate a different Applicable Lending Office for the Loans of such Lender affected by such event if such designation will avoid the need for, or reduce the amount of, such compensation and will not, in the reasonable opinion of such Lender (in accordance with regulatory, economic and policy considerations consistently applied), be disadvantageous to such Lender except for de minimus costs (in accordance with regulatory, economic and policy considerations consistently applied), except that such Lender shall have no obligation to designate an Applicable Lending Office located in the United States if such Lender's Applicable Lending Office is at such time not located in the United States.
(iv) Each Lender and the Issuing Bank agrees that such Person shall administer, and shall make claims for compensation, reimbursement or indemnification under, the provisions of Sections 3.12, 3.13, 3.15 and/or 4.4, as applicable, in a manner that is consistent with customary practices, procedures and policies consistently applied.
Section 3.13 Illegality. If, after the date of this Agreement, the adoption of any applicable law, rule or regulation, or any change therein, or any change in the interpretation or administration thereof by any Governmental Authority, central bank or comparable agency charged with the interpretation or administration thereof, or compliance by any Lender with any request or directive (whether or not having the force of law) of any such Governmental Authority, central bank or comparable agency shall make it unlawful or impossible for any Lender to make, maintain or fund its LIBOR Rate Loans and such Lender shall so notify the Agent, the Agent shall forthwith give notice thereof to the other Lenders and the Borrower, whereupon until the circumstances giving rise to such suspension no longer exist, each Loan of such Lender then outstanding shall be immediately converted to an Alternate Base Rate Loan.
Section 3.14 Basis for Determining Interest Rate Inadequate or Unfair. If on or prior to the first day of any Interest Period for any Loan:
(a) the Required Lenders, in their reasonable judgment, determine that deposits in Dollars (in the applicable amounts) are not being offered in the relevant

market for such Interest Period, or
(b) the Required Lenders, in their reasonable judgment, shall advise the Agent that the LIBOR Rate will not adequately and fairly reflect the cost to such Lender of funding its LIBOR Rate Loans for such Interest Period,
the Agent shall forthwith give notice thereof (which notice shall describe in reasonable detail the basis for such determination) to the Borrower and the Lenders, whereupon so long as the circumstances giving rise to such suspension continue to exist, the obligations of the Lenders to make a LIBOR Rate Loan shall be suspended and each outstanding LIBOR Rate Loan shall be converted into an Alternate Base Rate Loan on the Interest Period End Date of the Interest Period applicable thereto.
Section 3.15 Capital Adequacy. If any Lender or the Issuing Bank shall have determined that, after the Closing Date, the adoption of any applicable law, rule or regulation regarding capital adequacy, or any change therein, or any change in the interpretation or administration thereof by any Governmental Authority, central bank or comparable agency charged with the interpretation or administration thereof, or any request or directive regarding capital adequacy (whether or not having the force of law) of any such Governmental Authority, central bank or comparable agency, has or would have the effect of reducing the rate of return on capital of such Lender or the Issuing Bank as a consequence of such Lender's or the Issuing Bank's obligations hereunder to a level below that which such Lender or the Issuing Bank could have achieved but for such adoption, change, request or directive (taking into consideration its policies with respect to capital adequacy) by an amount deemed by such Lender or the Issuing Bank to be material, then such Lender or the Issuing Bank shall deliver to the Borrower and the Agent as promptly as practicable (but in no event later than 180 days after such Lender or the Issuing Bank has actual knowledge of such claim for capital adequacy) a certificate setting forth in reasonable detail the amount being charged by such Lender or the Issuing Bank and the basis for the determination of such amount. Within fifteen (15) days after the delivery of such certificate by such Lender or the Issuing Bank (with a copy to the Agent), the Borrower shall pay to such Lender or the Issuing Bank the amount shown as due on any such certificate.
Section 3.16 Breakage Indemnity. The Borrower shall indemnify each Lender against any loss, cost or reasonable expense which such Lender may sustain or incur as a consequence of (i) any payment or prepayment of a Loan required (whether by regularly scheduled installment, mandatory prepayment, acceleration or otherwise) or permitted by any other provision of this Agreement or otherwise made on a date other than on the Interest Period End Date applicable thereto or (ii) any default in payment or prepayment of the principal amount of any Loan or

any part thereof or interest accrued thereon, as and when due and payable (at the due date thereof, by irrevocable notice of prepayment or otherwise), including, in each such case, any loss or reasonable expense sustained or incurred or to be sustained or incurred in liquidating or employing deposits from third parties acquired to effect or maintain such Loan or any part thereof. Such loss, cost or reasonable expense shall include an amount equal to the excess, if any, as reasonably determined by such Lender, of (A) its cost of obtaining the funds for the Loan being paid, prepaid, converted or not borrowed (based on the Interest Period End Date applicable thereto over (B) the amount of interest (as reasonable determined by such Lender) that would be realized by such Lender in reemploying the funds so paid or prepaid for such period or Interest Period, as the case may be. For purposes of this Section 3.16, it shall be presumed that each Lender shall have funded each such Loan with a fixed-rate instrument bearing the rates and maturities designated in the determination of the interest rate applicable to such Loan. A certificate as to the amount of any loss, cost or expense to which the foregoing indemnity applies in reasonable detail (specifying the basis of such loss, cost or expense) shall be submitted to the Borrower (with a copy to the Agent) and shall be conclusive and binding as to the amount thereof absent manifest error.
Section 3.17 Replacement of Lenders. Upon the receipt of any notice from a Lender pursuant to Section 3.12(b), 3.13, 3.15 or 3.16 or 4.4, or if the Borrower shall be required to pay, withhold or deduct Taxes relative to a Lender, and provided that no Event of Default shall have occurred and be continuing, the Borrower may designate a Replacement Lender (which may be one of the other Lenders) to replace the affected Lender. If any Replacement Lender is obtained, the Replacement Lender shall purchase all of such Lender's Loans, Commitments, and other interests under the Loan Documents. Any transfer made by a Lender pursuant to this Section 3.17 shall satisfy the following conditions:
(i) the Borrower shall promptly pay when due all reasonable fees and expenses of such Lender incurred or to be incurred in connection with such transfer and (ii) any transfer of all or part of the Loans agreed upon shall be made without recourse, representation or warranty (other than the representation or warranty that the transferor Lender is the legal and beneficial owner of the interest being transferred, free and clear of any adverse claim), and (iii) the Borrower shall cause the transferee to pay to the Agent or to the account of the transferor Lender in immediately available funds all amounts outstanding or payable under this Agreement and any other Basic Document to such transferor Lender.
Section 3.18 Interest. Anything in this Agreement notwithstanding, in the event that the interest rate chargeable on any of the Obligations pursuant to the terms of this Agreement shall exceed the highest lawful rate that may be charged under

applicable law, the interest rate shall be deemed to be equal to the highest lawful rate.
ARTICLE IV
LETTERS OF CREDIT
Section 4.1 Letters of Credit.
(a) Issuance. Subject to the terms and conditions hereinafter set forth,
(i) the Issuing Bank agrees to issue a letter of credit (the "Tranche C Letter of Credit"), substantially in the form of Exhibit J-1 hereto, on the Closing Date. The Tranche C Letter of Credit will be issued in a Stated Amount of $20,000,000, which amount will be available to be drawn upon to pay amounts payable by the Borrower to Gilroy pursuant to the Noncompete Agreement; and
(ii) the Issuing Bank agrees to issue a letter of credit (the "Tranche D Letter of Credit"), substantially in the form of Exhibit J-2 hereto, on the Closing Date. The Tranche D Letter of Credit will be issued in the Stated Amount of $4,140,000, which amount will be used to pay amounts payable by the Borrower to Gilroy pursuant to the Noncompete Agreement.
(b) Term. Each Letter of Credit shall expire at the close of business on November 30, 1999 (the "Tranche D Maturity Date").
(c) Reduction of Letters of Credit. On each date on which a Drawing is made under either of the Letters of Credit, the Stated Amount of such Letter of Credit automatically shall be reduced by an amount equal to the amount of such Drawing. Each such reduction of the Stated Amount of the Tranche C Letter of Credit shall reduce each Tranche C Lender's Tranche C Letter of Credit Commitment in an amount equal to such Lender's Tranche C Pro Rata Share of such reduction, and each such reduction of the Stated Amount of the Tranche D Letter of Credit shall reduce each Tranche D Lender's Tranche D Letter of Credit Commitment in an amount equal to such Lender's Tranche D Pro Rata Share of such reduction.
(d) Each payment by a Tranche C Lender of its Tranche C Pro Rata Share of a Drawing under the Tranche C Letter of Credit in accordance with
Section 4.2(b) shall be deemed to be a Tranche C Loan outstanding under such Lender's Tranche C Note, in the amount of such payment.
(e) Reimbursement of Drawings under the Tranche D Letter of Credit; Interest.

(i) The Borrower hereby agrees to pay (or cause to be paid) to the Agent for the account of the Tranche D Lenders on each date that a Drawing is made under the Tranche D Letter of Credit a sum equal to the amount of such Drawing. Until so repaid by the Borrower, each such Drawing shall constitute an Obligation for all purposes of the Loan Documents.
(ii) The Borrower agrees to pay interest to the Agent for the account of the Tranche D Lenders on the amount of each Drawing under the Tranche D Letter of Credit from the date of the Drawing to and including the date the Agent is reimbursed in full for such Drawing at a rate per annum equal to the Default Rate. Interest on such Drawings shall be payable on demand.
(iii) Whenever the Agent receives any payment in the form of reimbursement from, or on behalf of, the Borrower with respect to any Drawing under the Tranche D Letter of Credit or any payment of interest on a Drawing under the Tranche D Letter of Credit, the Agent will pay to each Tranche D Lender in immediately available funds such Lender's Tranche D Pro Rata Share of such payment (i) before the close of business on the day such payment is received, if such payment is received at or prior to 12:00 noon (Los Angeles time) on such day or (ii) before 2:00 p.m. (Los Angeles time) on the next succeeding Banking Day if such payment is received after 12:00 noon (Los Angeles time) on such day. Any such amounts received by Agent but paid to the Tranche D Lenders after the times for payment set forth in the preceding sentence shall bear interest at the Federal Funds Rate, payable by the Agent.
Section 4.2 Participation and Funding Commitments.
(a) Grant and Acceptance. The Issuing Bank hereby grants to each Tranche C Lender and each Tranche C Lender hereby, severally and not jointly, takes an undivided participating interest in the rights and obligations of the Issuing Bank under, and in connection with, the Tranche C Letter of Credit Commitment in a fraction equal to such Lender's Tranche C Pro Rata Share. The Issuing Bank hereby grants to each Tranche D Lender and each Tranche D Lender hereby, severally and not jointly, takes an undivided participating interest in the rights and obligations of the Issuing Bank under, and in connection with, the Tranche D Letter of Credit Commitment in a fraction equal to such Lender's Tranche D Pro Rata Share. Subject to the limitations set forth below, each Lender shall be liable to the Issuing Bank for its Tranche C Pro Rata Share of the amount of any Drawing under the Tranche C Letter of Credit and for its Tranche D Pro Rata Share of any Drawing under the Tranche D Letter of Credit. Such liability to the Issuing Bank shall be absolute, unconditional and irrevocable and shall not be affected by any condition or event, including without limitation: (i) the occurrence of any Default or Event of Default under this Agreement or any other Loan Document, (ii) any breach or default by the Agent, the

Issuing Bank or any Lender hereunder, (iii) any lack of validity or enforceability of this Agreement, either of the Letters of Credit or any other Loan Document, (iv) any amendment or waiver of, or consent to departure from, any Loan Document, (v) the existence of any claim, set-off, defense or other right which the Borrower may have at any time against any beneficiary or any transferee of either of the Letters of Credit, the Agent, the Issuing Bank, the Lenders or any other Person, whether in connection with this Agreement, any other Loan Document or any unrelated transactions, (vi) any statement or other document presented under the either of Letters of Credit proving to be forged, fraudulent, invalid or insufficient in any respect or any statement therein being untrue or inaccurate in any respect whatsoever, (vii) payment by the Issuing Bank under either of the Letters of Credit against presentation of a draft or certificate which does not comply with the terms thereof, provided that such payment shall not have constituted gross negligence or willful misconduct of the Issuing Bank; or (viii) any other circumstance or happening whatsoever, whether or not similar to any of the foregoing, provided that the same shall not have constituted gross negligence or willful misconduct of the Issuing Bank.
(b) Reimbursement by Lenders. Upon payment of any Drawing under either Letter of Credit, the Issuing Bank will notify the Agent of the amount of such Drawing, and the Agent shall notify each of the Tranche C Lenders and the Tranche D Lenders, as the case may be, promptly by telecopy of its share of such Drawing. Each such Lender shall pay in immediately available funds its share of each Drawing to the Issuing Bank, not later than 3:30 p.m. (Los Angeles time) on the day such notice is received (where the relevant notice is received at or prior to 2:00 p.m. (Los Angeles time) on any day), and before 12:00 noon (Los Angeles time) on the next succeeding Business Day (where the relevant notice is received after 2:00 p.m. (Los Angeles time) on any day). If a Lender does not pay to the Agent its share of such Drawing by 3:30 p.m. (Los Angeles time) on the date the Drawing is made, such Lender shall be required to pay interest to the Issuing Bank on its share of such Drawing at the Federal Funds Rate from the date the Drawing is made until the date such Lender's payment is received by the Issuing Bank.
Section 4.3 Nature of Issuing Bank's Duties. (a) As among the Borrower, the Issuing Bank, the Lenders and the Agent, the Borrower hereby assumes all risks of the acts, omissions or misuse of either of the Letters of Credit by the beneficiaries thereof. The Issuing Bank, the Lenders and the Agent shall not be responsible: (i) for the use which may be made of either of the Letters of Credit or any acts or omissions of any beneficiary or transferee in connection therewith, (ii) for the form, validity, sufficiency, accuracy, genuineness or legal effect of any document, even if it should in fact prove to be in any or all respects invalid, insufficient, inaccurate, fraudulent or forged, (iii) for failure of any beneficiary to comply fully with the

conditions required in order to effect a Drawing and (iv) for any other circumstances whatsoever in making or failing to make payment under either of the Letters of Credit, except only that the Borrower shall have a claim against the Issuing Bank, and the Issuing Bank shall be liable to the Borrower, to the extent, but only to the extent, of any direct, as opposed to consequential, damages suffered by the Borrower which the Borrower proves were caused by (A) the Issuing Bank's willful misconduct or gross negligence in determining whether documents presented under either of the Letters of Credit complied with the terms of such Letter of Credit or (B) the Issuing Bank's failure to pay under either of the Letters of Credit in accordance with its terms after the presentation to it by the beneficiary of a sight draft and certificate strictly complying with the terms and conditions of such Letter of Credit. In furtherance and not in limitation of the foregoing, the Issuing Bank may accept documents that appear on their face to be in order, without responsibility for further investigation, regardless of any notice or information to the contrary.
(b) Indemnification. Each Tranche C Lender and Tranche D Lender agrees to indemnify the Issuing Bank in its capacity as such (to the extent not reimbursed by the Borrower and without limiting the obligations of the Borrower to do so), ratably, from and against any and all liabilities, obligations, losses, damages, penalties, actions, judgments, suits, other legal proceedings, costs, expenses or disbursements of any kind whatsoever (including, without limitation, reasonable counsel fees and expenses) which may at any time (including, without limitation, at any time following the payment of the Obligations, the termination of this Agreement and expiration of the Letters of Credit) be imposed on, incurred by or asserted against the Issuing Bank in any way relating to or arising out of this Agreement, or any documents contemplated by or referred to herein or the transactions contemplated hereby or any action taken or omitted by the Issuing Bank under or in connection with any of the foregoing; provided that no Lender shall be liable for the payment of any portion of such liabilities, obligations, losses, damages, penalties, actions, judgments, suits, other legal proceedings, costs, expenses or disbursements resulting solely from the Issuing Bank's gross negligence or willful misconduct.
(c) The Borrower hereby agrees at all times to protect, indemnify and save harmless the Issuing Bank from and against any and all liabilities, obligations, losses, damages, penalties, actions, judgments, suits, other legal proceedings, costs, expenses or disbursements of any kind whatsoever (including, without limitation, reasonable counsel fees and expenses) which may at any time (including, without limitation, at any time following the payment of the Obligations, the termination of this Agreement and expiration of the Letters of Credit) be imposed on, incurred by or asserted against the Issuing Bank in any way relating to or arising out of this

Agreement, or any documents contemplated by or referred to herein or the transactions contemplated hereby or any action taken or omitted by the Issuing Bank under or in connection with any of the foregoing; provided that the Borrower shall not be liable for the payment of any portion of such liabilities, obligations, losses, damages, penalties, actions, judgments, suits, other legal proceedings, costs, expenses or disbursements resulting solely from the Issuing Bank's gross negligence or willful misconduct.
(d) Issuing Bank in Its Individual Capacity. The Issuing Bank and its Affiliates may make loans to, accept deposits from and generally engage in any kind of business with the Borrower as though the Issuing Bank were not the Issuing Bank hereunder. With respect to Loans made or renewed by the Issuing Bank or on its behalf and any Note issued to the Issuing Bank or for its benefit, the Issuing Bank shall have the same rights and powers under this Agreement as any Lender and may exercise the same as though it were not the Issuing Bank, and the term "Lender" shall include the Issuing Bank in its individual capacity.
Section 4.4 Increased Cost of Letter of Credit. If, after the date hereof, the adoption of any applicable law, rule or regulation, or any change therein, or any change in the interpretation or administration thereof by any Governmental Authority, central bank or comparable agency charged with the interpretation or administration thereof, or compliance by the Issuing Bank or any Tranche C Lender or Tranche D Letter of Credit with any request or directive (whether or not having the force of law) of any such authority, central bank or comparable agency:
(a) shall subject the Issuing Bank or any such Lender to any Tax (other than any net income Taxes and franchise Taxes), duty or other charge (other than routine examination fees) with respect to either of the Letters of Credit or any Drawing or shall change the basis of taxation of payments to the Issuing Bank or any such Lender in respect of such Letter of Credit or any Drawing or the participations therein (except for changes in the rate of tax on the overall net income of the Issuing Bank or such Lender imposed by the federal, state or local jurisdiction in which the Issuing Bank's or such Lender's principal executive office is located); or
(b) shall impose, modify or deem applicable any reserve, special deposit or similar requirement (including, without limitation, any such requirement imposed by the Board of Governors) against assets of or deposits with or for the account of, or credit extended by, the Issuing Bank or any such Lender with respect to either of the Letters of Credit or any Drawing or the participations therein or shall

impose on the Issuing Bank or any such Lender any other condition affecting the Letters of Credit or any Drawing or the participations therein,
and the result of any of the foregoing is to increase the cost to the Issuing Bank of issuing or maintaining the Letters of Credit or to increase the cost to any such Lender of any Drawing or its participation therein, or to reduce the amount of any sum received or receivable by the Issuing Bank or any such Lender under this Agreement, by an amount deemed by the Issuing Bank or such Lender to be material, then the Issuing Bank or such Lender shall deliver to the Borrower and the Agent a certificate setting forth in reasonable detail the basis for such determination as soon as practicable but in no event later than 180 days after such Lender or the Issuing Bank has actual knowledge of such event. Within fifteen (15) days after delivery of such certificate, the Borrower shall pay to the Issuing Bank or such Lender the amount shown as due on such certificate; provided, that the Borrower shall not be obligated to compensate the Issuing Bank or such Lender for the amount of such increased cost incurred with respect to a period of time prior to the date which is 180 days before the date of such certificate.
Section 4.5 Borrower's Obligations Absolute. The obligations of the Borrower under this Article IV shall be absolute, unconditional and irrevocable, shall be paid strictly in accordance with the terms of this Agreement and shall not be affected by any condition or event, including without limitation the existence of any claim, set-off, defense, or other right which the Borrower may have at any time against any beneficiary or any transferee of either of the Letters of Credit or any statement or other document presented under either of the Letters of Credit proving to be forged, fraudulent, invalid or insufficient in any respect or any statement therein being untrue or inaccurate in any respect whatsoever, or payment by the Issuing Bank under either of the Letters of Credit against presentation of a draft or certificate which does not comply with the terms thereof, provided that such payment shall not have constituted gross negligence or willful misconduct of the Issuing Bank.
ARTICLE V
FEES AND ADDITIONAL PAYMENTS
The Borrower shall pay the following fees:
Section 5.1 Up-Front Fee. To the Agent for the account of the Lenders, on the Closing Date, a nonrefundable fee (the "Upfront Fee") as set forth in a separate letter agreement between the Agent and the Borrower.
Section 5.2 Letter of Credit Fees. To the Agent for

the account of the Tranche C Lenders or the Tranche D Lenders, as the case may be, a letter of credit fee (the "Letter of Credit Fee"), calculated by the Agent, on the daily average outstanding Stated Amount of the Tranche C Letter of Credit at a rate equal to the Applicable Margin with respect to Tranche C Loans and on the average daily outstanding Stated Amount of the Tranche D Letter of Credit at a rate equal to 1% per annum. The Letter of Credit Fee shall be computed on the basis of the actual number of days elapsed and a year of 365 days or 366 days, as appropriate. The Letter of Credit Fee shall commence to accrue on the Closing Date and shall be payable on each Quarterly Payment Date prior to termination or expiration of the applicable Letter of Credit.
Section 5.3 Issuing Bank Letter of Credit Fee. To the Issuing Bank, on the date of issuance of each Letter of Credit and on January 1 of each year thereafter until the expiration or termination of such Letter of Credit, the Issuing Bank's non-refundable fees (the "Issuing Bank Letter of Credit Fee"), in the amounts specified in separate letters between the Borrower and the Issuing Bank, and upon each Drawing under, permanent reduction in or transfer of either Letter of Credit, the Issuing Bank's then current standard transaction fees and other customary administrative fees and reserve adjustments.
Section 5.4 Agency Fee. To the Agent for its own account, a non-refundable agency fee (the "Agency Fee") as set forth in a separate letter agreement between the Agent and the Borrower.
ARTICLE VI
REPRESENTATIONS AND WARRANTIES
The Borrower represents and warrants on and as of the Closing Date that:
Section 6.1 Existence and Business of the Borrower. The Borrower is a limited partnership duly organized and validly existing under the laws of the State of Delaware and is qualified to do business as a limited partnership under the laws of the State of California, the only jurisdiction in which the conduct of its business or the ownership or lease of its assets requires such qualification. The Borrower has been and will be engaged solely in the business of operating the Project.
Section 6.2 Existence and Business of the Partners.
(a) Each of the partners of the Borrower is a corporation duly organized, validly existing and in good standing under the laws of the State of Delaware and is qualified to do business as a foreign corporation under the laws of the State of California, the only jurisdiction in which the conduct of its business or the ownership or lease of its assets requires such

qualification. The Partner has full power and authority to conduct its business as currently conducted and has the authority to act as the general partner of the Borrower. The Partner is the sole general partner of the Borrower.
(b) Neither the Borrower nor the Partner has any subsidiaries.
Section 6.3 Power and Authorization; Enforceable Obligations.
(a) The Borrower has full power and authority to own and operate the Project, to conduct its business as now conducted and as proposed to be conducted by it, to execute, deliver and perform this Agreement and the Basic Documents to which it is a party, to take all actions necessary to complete the transactions contemplated by this Agreement and such other Basic Documents and to grant the liens and security interests provided for in the Collateral Security Documents to which it is a party and to borrow hereunder. The Borrower has taken all necessary action to authorize the transactions contemplated hereby on the terms and conditions set forth herein and the other Basic Documents to which it is a party, to grant the Liens and security interests provided for in the Collateral Security Documents to which it is a party and to authorize the execution, delivery and performance of this Agreement, the Notes, the Letters of Credit and the other Basic Documents to which it is a party.
(b) Each of this Agreement and the other Basic Documents to which the Borrower is a party has been duly executed and delivered by the Borrower and constitutes (subject to proper authorization, execution and delivery by each other party thereto) the legal, valid and binding obligation of the Borrower, enforceable against the Borrower in accordance with its terms, except as enforcement thereof may be limited by bankruptcy, insolvency, reorganization, moratorium or similar laws affecting the enforcement of creditors' rights generally or by limitation upon the availability of equitable remedies.
(c) Each partner of the Borrower has full corporate power and authority and the legal right to execute, deliver and perform the Basic Documents to which it is a party and to take such action as may be necessary to complete the transactions contemplated thereby, and has taken all necessary corporate action to authorize the execution, delivery and performance of such Basic Documents. Each of the Partnership Agreement and each other Basic Document to which it is a party has been duly executed and delivered by and constitutes a legal, valid and binding obligation of each of the partners party thereto and (subject to proper authorization, execution and delivery by each other party thereto) is enforceable against such partner in accordance with its terms, except as enforcement thereof may be limited by bankruptcy, insolvency, reorganization, moratorium or

similar laws affecting the enforcement of creditors' rights generally or by limitation upon the availability of equitable remedies.
Section 6.4 Collateral Security Documents. The Collateral Security Documents are or when executed will be effective to create, in favor of the Agent, for the benefit of the Issuing Bank and the Lenders, legal, valid, enforceable and, upon proper recording or filing for those documents or instruments that require such recording and possession for those security interests perfected by possession, perfected and first priority Liens (subject only to Permitted Liens) on and security interests in all of the Collateral. The descriptions of the Collateral set forth in the Collateral Security Documents are true, complete and correct in all material respects and are adequate for the purpose of establishing, preserving, protecting and perfecting the interests, rights and first priorities intended to be created by the Collateral Security Documents. All necessary and appropriate recordings, filings and registrations have been or will be duly effected in all appropriate public offices and partnership registers so that on or prior to the Closing Date each of the Collateral Security Documents constitutes or will constitute a perfected first Lien on and prior perfected first security interest in all right, title, estate and interest of the owner thereof in and to the Collateral (subject only to Permitted Liens). The recordings, filings and other actions shown on Schedule 6.4 are all the recordings, filings and other actions necessary and appropriate in order to establish, protect and perfect the Lien of the Agent, the Issuing Bank and the Lenders on and security interest in the right, title estate and interest of the owner thereof in and to the Collateral.
Section 6.5 No Legal Bar. The execution, delivery and performance of this Agreement and the Basic Documents to which the Borrower or either partner of the Borrower is a party will not (a) violate any Requirement of Law applicable to, or any material Contractual Obligation of, such Person, or
(b) result in, or require, the creation or imposition of any Lien on any of the properties or revenues of such Person pursuant to any Requirement of Law or Contractual Obligation, except for the Liens created or permitted by the Collateral Security Documents. No approvals or consents of any trustee or any holder of any Indebtedness of the Borrower or either partner of the Borrower are required in connection with the execution, delivery and performance by such Person of any Basic Documents to which it is a party, except such approvals or consents as are set forth on Schedule 6.6, which consents and approvals have been duly obtained and are in full force and effect.
Section 6.6 Governmental Approvals and Other Consents and Approvals. Except for the Governmental Approvals, consents and other approvals set forth on Schedule 6.6, no

Governmental Approvals or other consents or approvals except routine filings, registrations and permits which are ministerial in nature are required to be obtained by or on behalf of the Borrower or the Partner in connection with (a) the participation by the Borrower or either partner of the Borrower in the transactions contemplated by this Agreement and the other Basic Documents, or the execution, delivery or performance by such Person of any Basic Document to which it is a party or (b) the use, ownership, lease, operation or maintenance of the Project in accordance with the applicable provisions of the Basic Documents and in compliance in all respects with all applicable Requirements of Law. Each of the Governmental Approvals and other consents and approvals listed in Part A of Schedule 6.6 has been duly obtained or made, validly issued, is in full force and effect and, in the case of any Governmental Approval, is not subject to appeal or judicial, governmental or other review, except as disclosed on Schedule 6.6. Except as otherwise provided in Schedule 6.6, the Borrower has no actual knowledge of any violation of the terms and conditions of such Governmental Approvals and other consents and approvals. None of the Governmental Approvals and other consents and approvals listed in Part B of Schedule 6.6 is required to be obtained prior to the Closing Date in order to be in compliance in all respects with all Requirements of Law. The Borrower has no reason to believe that any of the Governmental Approvals listed in Part B of Schedule 6.6 cannot or will not be obtained or made in the normal course of business as and when required (as set forth in Schedule 6.6) and without significant expense. Each routine filing, registration or permit required to be obtained by the Borrower or either partner of the Borrower for the applicable purposes set forth in clauses (a) and (b) above which is ministerial in nature and not included in Schedule 6.6 has been or will be made or obtained by such Person as and when so required.
Section 6.7 Financial Statements.
(a) The balance sheet of the Borrower furnished to the Agent at the Closing Date fairly presents the financial condition of the Borrower as at the date thereof. There has been no material adverse change in the financial condition, operations, properties or prospects of the Borrower.
(b) The Base Case has been prepared with due care and, on the Closing Date, (i) is complete in all material respects and fairly presents the Borrower's best estimates as to the matters covered thereby, (ii) is based on reasonable assumptions as to the factual and legal matters material to the good faith estimates therein at the time made and (iii) is believed in good faith to be consistent with the provisions of this Agreement and the Basic Documents. There has been no material adverse change in the financial condition, operations, properties or prospects

of the Project from those set forth and assumed in the Base Case.
Section 6.8 Taxes. The Borrower has filed or caused to be filed all Tax returns required to be filed by it, has paid all Taxes shown to be due and payable on such returns and has paid all assessments made against it or any of its property and all other Taxes imposed on it or any of its property by any Governmental Authority other than Taxes and assessments which are not yet delinquent and remain payable without penalty or are being contested in accordance with the provisions of Section 8.4.
Section 6.9 No Proceeding or Litigation. No litigation, proceeding or similar action of or before any arbitrator or Governmental Authority is pending or, to the knowledge of the Borrower, threatened against or affecting the Borrower or either partner of the Borrower or against or affecting any of its respective properties, rights, revenues or assets, or, to the knowledge of the Borrower, the Project that could reasonably be expected to result in a Material Adverse Effect or which challenges the enforceability of this Agreement, any Collateral Security Document or any other Basic Document.
Section 6.10 No Default or Event of Loss. The Borrower is not in default under or with respect to any material Contractual Obligation. The Borrower has complied with all requirements of the Governmental Approvals and other consents and approvals listed on Schedule 6.6 (except where non-compliance could not reasonably be expected to have a Material Adverse Effect). No Event of Default and no Default with respect to the Borrower, the Partner, Calpine or Calpine Fuels or, to the Borrower's knowledge, with respect to the Project, any party to any Project Contract (other than the Borrower, the Partner, Calpine or Calpine Fuels) or any Material Obligor or the Steam Host, has occurred and is continuing. No Event of Loss has occurred and the Project has not been affected by fire, explosion, accident, strike, lockout or other labor dispute, drought, flood, storm, hail, earthquake, embargo, civil disturbance, lightning, act of God or of the public enemy or other casualty or event of force majeure.
Section 6.11 Title to Property. Except as set forth in
Section 6.6, all contracts, Governmental Approvals, entitlements and other property relating to the Project are owned by the Borrower (or the Borrower has full contractual rights to the benefits thereof) free and clear of any Lien, other than Permitted Liens. The Borrower has a good and marketable leasehold interest in the Project Site and good title to all other Collateral, free and clear of all Liens, except Permitted Liens. No deed of trust, mortgage or financing statement or other instrument of recordation covering all or any part of the Collateral is on file in any recording office, other than with respect to Permitted Liens or with respect to any such document or instrument which has been released. The Borrower has been

granted and has good title to any and all easements, licenses and other real property rights required for access to, or operation or maintenance of, the Project (including, without limitation, all gas, electrical, water and sewage interconnections and pipelines), free and clear of all Liens other than Permitted Liens.
Section 6.12 Project Contracts.
(a) The Borrower has delivered to the Agent and the Lenders on the date hereof true and correct copies of all agreements to which the Borrower is a party. The services to be performed, the materials to be supplied and the property interests, easements and other rights granted pursuant to the Project Contracts or otherwise owned or leased by the Borrower (i) comprise all of the services, materials and property interests necessary to secure any right material to the operation and maintenance of the Project (including, without limitation, all gas, electrical, water and sewage interconnections and pipelines), and (ii) provide adequate ingress and egress from the Project Site for any reasonable purpose in connection with the operation and maintenance of the Project.
(b) Each of the Project Contracts is in full force and effect with respect to the Borrower, the Partner, Calpine and Calpine Fuels, and, to the Borrower's knowledge, each other party thereto, and none of the Project Contracts has heretofore been amended, modified, suspended, cancelled or terminated, except as described in the definition thereof. No default exists with respect to the Borrower, the Partner, Calpine or Calpine Fuels, or, to the Borrower's knowledge, any other party under any of the Project Contracts. The Borrower is not subject to any Contractual Obligation (other than pursuant to the Project Contracts, the Asset Purchase Agreement and the other Closing Documents (as defined in the Asset Purchase Agreement) executed prior to the date hereof).
Section 6.13 Agreements and Licenses. No licenses, trademarks, patents, copyrights or agreements with respect to the usage of technology or other permits are necessary for the ownership, operation or maintenance of the Project, except for the licenses, trademarks, patents, agreements or permits to be provided under or maintained pursuant to the terms of the Project Contracts.
Section 6.14 Compliance with Law. Except as set forth in Schedule 6.6, each of the Borrower, each partner of the Borrower and the Project is in compliance with all Requirements of Law, including, without limitation, federal, state and local Tax laws, zoning, subdivision and use laws and building codes (but excluding all Environmental Laws, the sole representations and warranties as to which are set forth in Section 6.15), except to the extent that the failure to comply therewith would not, in

the aggregate, have a Material Adverse Effect.
Section 6.15 Environmental Matters. Except as set forth in the Environmental Reports, and to the Borrower's knowledge, no Materials of Environmental Concern have been or are currently located at, in, on, under or about the Project Site (or any other property with respect to which the Borrower has or may have retained or assumed liability either contractually or by operation of law) in a manner which violates any Environmental Law, or for which cleanup or corrective action of any kind is required or authorized under any Environmental Law; no release of any Materials of Environmental Concern from the Project Site onto or into any other property or from any other property onto or into the Project Site has occurred or is occurring in violation of any Environmental Law currently in effect; and no notice of violation, Lien, complaint, suit, order or other notice with respect to the environmental condition of the Project Site (or any other property with respect to which the Borrower has or may have retained or assumed liability either contractually or by operation of law) is outstanding or anticipated, nor has any such notice been issued which has not been fully satisfied and complied with or otherwise resolved in a timely fashion so as to bring the Project Site (or any other property with respect to which the Borrower has or may have retained or assumed liability either contractually or by operation of law) into full compliance with all Environmental Laws.
Section 6.16 Federal Reserve Regulations. The Borrower has not and will not, directly or indirectly, use any of the proceeds of the Loans for the purpose, whether immediate, incidental or ultimate, of buying a "margin stock" or of maintaining, reducing or retiring any indebtedness originally incurred to purchase a stock that is currently a "margin stock", or for any other purpose which might constitute this transaction a "purpose credit", in each case within the meaning of Regulations G or U of the Board of Governors of the Federal Reserve System, or otherwise take or permit to be taken any action which would involve a violation of such Regulations G or U or of Regulation T or Regulation X or any other regulation of such Board.
Section 6.17 ERISA. As of the Closing Date, there are no Commonly Controlled Entities, except as shown on Schedule 6.17 with respect to each Plan, as to which the Borrower may have any liability, (i) there has been no material breach of Requirements of Law that could reasonably be expected to result in material liability for the Borrower, (ii) no Notice of Reportable Event (as defined in Section 4043 of ERISA) has been filed with respect to any such Plan, (iii) there has been no withdrawal from any such Plan or steps taken to do so which has resulted or could reasonably be expected to result in a material liability for the Borrower, (iv) no steps have been taken to terminate any such Plan in a distress termination, (v) no contribution failure has

occurred with respect to any such Plan sufficient to give rise to a lien under
Section 302(f) of ERISA or Section 412 of the Code and (vi) to the Borrower's knowledge, no other condition exists or event or transaction has occurred with respect to any such Plan which could reasonably be expected to result in material liability for the Borrower.
Section 6.18 Principal Place of Business. The principal place of business and chief executive office of the Borrower (including for federal tax purposes) and the office where the Borrower keeps its records concerning the Project and copies of all contracts relating thereto is located at the address for the Borrower specified in Section 12.8.
Section 6.19 Offer of Notes or Securities. Neither the Borrower nor any other Person acting on its behalf has directly or indirectly offered the Notes, the partnership interests or any part thereof or any similar securities for sale to, or solicited any offer to buy any of the same from, or otherwise approached or negotiated in respect thereof with, any Person in violation of the Securities Act of 1933, as amended, the securities laws or "blue sky" laws of any jurisdiction or any other applicable law. Neither the Borrower nor any Person acting on its behalf has taken or will take any action which would subject the issuance and sale of the Notes or any part thereof, any Partnership Interest in or securities of the Borrower or any interest in the Project to the provisions of Section 5 of the Securities Act of 1933, as amended, or to the registration or qualification provisions of any securities or "blue sky" law of any applicable jurisdiction.
Section 6.20 Labor Matters. There are no collective bargaining agreements covering the employees of the Borrower or the Operator, and neither the Borrower nor the Operator has suffered any strikes, walkouts, work stoppages, or other material labor difficulty within the last five years.
Section 6.21 Full Disclosure. No representation, warranty or written information made or provided by the Borrower in any Loan Document, or in any certificate, written statement or other document furnished to the Agent, the Issuing Bank, the Lenders or the Independent Engineer by or on behalf of the Borrower, contains any untrue statement of a material fact or omits to state a material fact necessary in order to make the statements or information contained in such documents, written statements or certificates (taken as a whole) not misleading as of the date provided. There is no fact known to the Borrower which the Borrower has not disclosed to the Agent and the Independent Engineer which materially adversely affects the Project or the properties, business, prospects, operations or financial condition of the Borrower or the ability of the Borrower to perform its obligations under the Basic Documents.

Section 6.22 Investment Company Act Status. The Borrower is not an "investment company" or a company controlled by an "investment company" within the meaning of the Investment Company Act of 1940.
ARTICLE VII
CONDITIONS PRECEDENT
Section 7.1 The Closing Date. The obligations of the Lenders to make the Loans and of the Issuing Bank to issue the Letters of Credit shall be subject to the conditions precedent that the Agent, the Lenders and the Issuing Bank shall have received on the Closing Date the documents, opinions, certificates and information referred to in this Section 7.1, each of which shall be in form and substance satisfactory to the Agent, the Lenders and the Issuing Bank, and that the conditions set forth in this Section 7.1 shall have been satisfied or waived in writing:
(a) Borrowing Notice. The Agent and each Lender shall have received, at least three Business Days prior to the Closing Date, a borrowing notice substantially in the form of Exhibit A hereto (the "Borrowing Notice"), signed by a Responsible Officer of the Borrower.
(b) Notes. Each of the Lenders shall have received its Tranche A Note, Tranche B Note and Tranche C Note, duly authorized, executed and delivered by the Borrower.
(c) Purchase of Project. The Asset Purchase Documents shall have been executed and delivered by the parties thereto, in form and substance satisfactory to the Agent, the Issuing Bank and the Lenders. The Agent, the Issuing Bank and each of the Lenders shall have received evidence that the transactions contemplated by the Asset Purchase Documents have been consummated.
(d) Steam Host. The Agent, the Lenders and the Issuing Bank shall have received such information regarding the Steam Host as they may reasonably request and shall have completed to their satisfaction their due diligence investigation thereof. The Agent, the Issuing Bank and each of the Lenders shall have received evidence that ConAgra has acquired the Gilroy Facility and the transactions contemplated by the ConAgra Assignment Agreement have been consummated.
(e) Opinions of Counsel. The Agent, the Issuing Bank and the Lenders shall have received the following opinions, each of which shall be in form and substance satisfactory to the

Agent, the Lenders and the Issuing Bank, dated the Closing Date:
(i) an opinion of Thelen, Marrin, Johnson & Bridges, special California counsel for the Borrower, each partner of the Borrower, Calpine and Calpine Fuels;
(ii) an opinion of Downey Brand Seymour & Rohwer, special counsel for the Borrower; (iii) an opinion of Miller, Karp & Grattan, special counsel for the Borrower;
(iv) an opinion of Joseph Ronan, Esq., counsel for the Borrower, each partner of the Borrower, Calpine and Calpine Fuels;
(v) an opinion of Baker and McKenzie, counsel for Gilroy and McCormick & Company, Inc.;
(vi) an opinion of Robert W. Skelton, counsel for Gilroy and McCormick & Company, Inc.;
(vii) an opinion of counsel for ConAgra; and
(viii) such other opinions of counsel as the Lenders may reasonably request.
(f) Corporate and Governmental Proceedings. All partnership, corporate and legal proceedings and all instruments and agreements in connection with the transactions contemplated by this Agreement and the other Basic Documents shall be satisfactory in form and substance to the Lenders, and the Lenders shall have received all information and copies of all documents and papers, including records of corporate and governmental proceedings and the financial information, which the Lenders may reasonably request in connection therewith, such documents and papers, when appropriate, to be certified by proper corporate or governmental authorities. The documentation to be delivered to the Lenders on or before the Closing Date shall include, without limitation, the following, certified or dated as of the Closing Date:
(i) evidence as to the authority of and certified signatures of the representatives of each of the Borrower and Calpine authorized to execute the Basic Documents to which such Person is a party and all related documents and certificates required hereunder or thereunder;
(ii) evidence of partnership and corporate authorization of the Borrower and Calpine, with respect to the execution, delivery and performance of the Basic Documents to which such Person is a party;
and

(iii) duly authorized and executed partnership agreement, articles of incorporation, by-laws, any amendments to any of the foregoing, incumbency certificates and good standing certificates, as appropriate, with respect to each of the Borrower, the Partner, Calpine, Calpine Fuels and, to the extent made available to the Borrower, the Steam Host.
(g) Loan Documents. Each of the Loan Documents shall have been duly authorized, executed and delivered by the Borrower and each other party thereto, each of which shall be in form and substance satisfactory to the Lenders.
(h) Assigned Contracts, etc. The Agent shall have received copies of the Project Contracts and the Asset Purchase Documents and any supplements or amendments thereto, each of which shall be in form and substance satisfactory to the Lenders, certified by the Borrower as of the Closing Date as being true, complete and correct copies thereof and as being duly authorized, executed and delivered by the parties thereto and in full force and effect (such certification as to parties other than the Borrower or any of its Affiliates being to the best of the Borrower's knowledge). The Borrower shall have no obligations or liabilities with respect to the Bechtel Operations and Maintenance Agreement between Gilroy and Bechtel North American Power Corporation, dated January 20, 1986.
(i) Accuracy of Representations. All representations and warranties made to the Agent, the Issuing Bank or the Lenders contained in this Agreement or any other Loan Document or in any writing delivered to the Agent or the Independent Engineer by the Borrower or any party (other than the Agent, the Issuing Bank and the Lenders) to the Loan Documents pursuant hereto or thereto, shall be true and correct in all material respects with the same force and effect as though such representations and warranties had been made on and as of the Closing Date, except to the extent that any such representation related only to a specific date.
(j) Title to Project; Title Insurance. (i) The Borrower shall have (A) a good and marketable leasehold interest in the Project Site, (B) fee title to the Improvements, and (C) record title to all easements and rights of way necessary for the use and operation of the Project, in each case free and clear of all Liens (other than Permitted Liens). The Agent shall have received from Stewart Title Company of California (the "Title Company") an ALTA prepaid title insurance policy (the "Title Policy") in form acceptable to the Lenders insuring the Lien of the Deed of Trust, in an amount not less than the Commitment, as a valid, prior Lien on the interest of the Borrower in and to the Project, the Project Site, and in and to the easements and other rights of the Borrower, subject only to such exceptions as shall be approved by the Lenders and their counsel and including a comprehensive endorsement covering restrictions, a contiguity

endorsement (if required by the nature of the legal description), an endorsement insuring access to duly open public roads (specifying such roads) and an endorsement providing mechanics' lien coverage.
(k) Survey. There shall be delivered a current ALTA/ASCM Class A survey and certification of a registered or certified surveyor showing outlines of the Project Site and the area thereof in square feet, building locations, setback lines, encroachments, rights-of-way, easements (including encroachments, rights-of-way, and easements not located on the Project Site but benefiting the Project Site), those easements referenced in the Easement Agreements and the outlines of the parcel(s) burdened thereby, with courses and distances so as to permit a verbal description of the Project Site and of any other item noted on the survey, all of which shall be sufficient to enable the Agent to obtain a mortgagee's title insurance policy free of the survey exceptions. The survey shall be delivered with a certificate of the surveyor of the legal description, and be in favor of the Agent and the Title Company. The survey shall contain the express certification that, except as specifically noted, there are no encroachments of lot or building lines, or obstructed easements. The legal description on the survey shall coincide exactly with that on the title commitment to be furnished to the Agent by the Title Company.
(l) Filings and Recordings. Each of the Collateral Security Documents shall have been duly filed, recorded and/or registered in all places as may be required, necessary or desirable to establish, perfect, protect and preserve the rights, titles, interests, remedies, privileges, Liens and security interests of the Agent for the benefit of the Agent, the Issuing Bank and the Lenders thereunder or in respect thereof, and to create valid first Liens and first priority security interests in the Collateral superior to all other Liens other than Permitted Liens, and all recording and filing taxes and fees shall have been paid, and any giving of notice or taking of any other action to such end (whether similar or dissimilar) required or reasonably requested by the Agent shall have been given or taken and the Lenders shall have received evidence satisfactory to it as to any such filing, recording, registration, search, giving of notice and/or other action.
(m) UCC Searches. The Lenders shall have received Uniform Commercial Code and other judgment and lien searches with respect to the Borrower and each other Person (other than the Agent) party to a Collateral Security Document in each jurisdiction in which such Person is organized or its principal executive offices are located or any Collateral is located or as the Agent shall deem advisable to obtain such searches, which shall reveal no filings or recordings with respect to any of the Collateral in favor of any Person other than the Agent (other

than with respect to Permitted Liens).
(n) Release of Prudential Liens. The Agent, the Lenders and the Issuing Bank shall have received evidence satisfactory to such Person of (i) the satisfaction in full of all amounts due to The Prudential Insurance Company of America ("Prudential") under the Construction and Term Loan Agreement, dated as of May 15, 1986, and all documents entered into in connection therewith and
(ii) the recordation and filing of the reconveyance of the related deed of trust and all Uniform Commercial Code termination statements necessary to release all Liens in favor of Prudential.
(o) Technical Assessment. The Agent and the Lenders shall have received a report of the Independent Engineer (with a copy to the Borrower at the time of delivery to the Agent or any Lender) with respect to the construction and operation of the Project, covering such matters as shall be requested by the Agent, which report shall be in form and substance satisfactory to the Agent and the Lenders.
(p) Environmental Information. The Agent and the Lenders shall have received the Environmental Report and a report of the Environmental Consultant (with a copy to the Borrower at the time of delivery to the Agent or any Lender) with respect to the Project, and such reports shall be acceptable in form and substance to the Agent and the Lenders.
(q) Fuel Information. The Agent and the Lenders shall have received a report of the Gas Consultant (with a copy to the Borrower at the time of delivery to the Agent or any Lender) with respect to the fuel arrangements for the Projects and such report shall be acceptable in form and substance to the Agent and the Lenders.
(r) Financial Statements. The Borrower shall have furnished to the Lenders the most recent annual and quarterly financial statements of the Borrower, Calpine, Calpine Fuels and, to the extent made available to the Borrower, of the Steam Host and the contracted fuel suppliers for the Project. Each such Person shall certify (as to itself) that (i) its financial statements for such periods are true, correct and complete in all material respects, (ii) its balance sheet fairly presents its financial position as at the dates thereof and has been prepared in accordance with GAAP except as otherwise specifically noted therein, (iii) there has been no material adverse change in its financial position from that set forth in the balance sheet prepared as at the dates thereof, and (iv) all respective liabilities, contingent or otherwise, are disclosed by, or reserved against in, such financial statements or the footnotes thereto to the extent required by GAAP.
(s) Base Case. The Agent and the Lenders shall have

received the Base Case, in form satisfactory to the Agent, the Lenders and the Independent Engineer.
(t) Operating Budget. The Agent and the Lenders shall have received an operating budget for the Project for the one-year period commencing on the Closing Date, in form satisfactory to the Agent, the Lenders and the Independent Engineer.
(u) No Requirement of Law. No Requirement of Law shall be in effect or shall have occurred (or shall have been proposed, if such proposed Requirement of Law has a reasonable likelihood of being enacted) the effect of which is to prevent the Agent, the Issuing Bank, the Lenders, the Borrower, Calpine or any party to any Project Contract from fulfilling its obligations hereunder under the Collateral Security Documents or any such Project Contract, or which would subject the Agent, the Issuing Bank or any Lender (or any Affiliate of a Lender) to any penalty or sanction caused by its performance of its obligations under the Loan Documents.
(v) Force Majeure, Cancellation, Suspension, Termination, etc. No event of force majeure or other event or condition shall exist which permits or requires any party to any of the Basic Documents to cancel, suspend or terminate its performance of such document in accordance with its terms or which could reasonably be expected to excuse any such party from liability for nonperformance thereof.
(w) Insurance. There shall have been delivered to the Lenders:
(i) binders evidencing the commitment of insurers to provide the insurance policies required by Section 8.6, together with evidence of the payment of all premiums in respect of such insurance polices;
(ii) a certificate of a Responsible Officer of the Borrower that all such insurance policies are in full force and effect; and
(iii) certificates of the Insurance Consultant and the Borrower's insurance advisor, addressed to the Agent and the Lenders, as to the adequacy and effectiveness of insurance coverages, and as to such other matters as the Agent and the Lenders may reasonably request, including a certification that the Borrower has made adequate arrangements for insurance in accordance with the requirements of this Agreement and all of the Basic Documents to which the Borrower is a party and that such insurance is not subject to cancellation without prior notice to the Agent and the Lenders.

(x) Consents. The Borrower shall have delivered the Consents to the Agent and the Lenders, together with a certificate of a Responsible Officer of the Borrower to the effect that such Consents are true, complete and correct copies and in full force and effect (such certification as to parties other than the Borrower or any of its Affiliates being to the Borrower's knowledge).
(y) Payment of Fees. The Borrower shall have paid or shall pay on the Closing Date to the Persons entitled thereto, in Dollars, all fees, costs and expenses then due pursuant to this Agreement or any other Loan Document.
(z) Approvals. All Governmental Approvals and other consents and approvals required as of such date shall have been duly obtained, and the Agent shall have received copies of such Governmental Approvals and other consents and approvals (and all correspondence referred to therein), certified by a Responsible Officer of the Borrower to be true, correct and complete. Such Governmental Approvals and other consents and approvals shall (i) be in full force and effect, (ii) have been validly issued in the name of the Person named on Schedule 6.6 as the recipient thereof and in compliance with all Requirements of Law (including without limitation all Environmental Laws) and (iii) not be subject to appeal or any restriction, condition, limitation or other provision that has, or could be reasonably expected to have, a Material Adverse Effect. The Project and the Project Contracts shall comply in all respects with all such Governmental Approvals and other consents and approvals except where non-compliance therewith could not, in the judgment of the Lenders, reasonably be expected to have a Material Adverse Effect.
(aa) Adverse Change. In the opinion of the Lenders, no material adverse change in the Project, the Collateral, or in the financial condition, business operations, properties or prospects of the Borrower, Calpine, Calpine Fuels or the Steam Host (including, without limitation, any change in the status of the Governmental Approvals or other consents and approvals listed on Schedule 6.6) shall have occurred.
(bb) FIRREA Appraisal. An appraisal meeting the requirements of the Financial Institutions Reform, Recovery, and Enforcement Act of 1989 shall have been completed and shall be reasonably satisfactory to the Lenders.
(cc) Equity Contribution. Calpine shall have contributed cash equity to the Borrower in an amount equal to at least $9,000,000, and such equity contribution shall be applied to pay to Gilroy a portion of the "Purchase Price" under the Asset Purchase Agreement. Calpine shall have deposited in the Receipt Account $2,000,000, and in the Debt Service Reserve

Account $4,000,000.
(dd) Other Conditions. All acts, conditions and things required by the provisions of this Agreement or the other Basic Documents to be done and performed and to have happened prior to the execution and delivery of this Agreement shall have been done and performed and have happened.
(ee) Officer's Certificate. The Agent and each Lender shall have received a certificate of a Responsible Officer of the Borrower dated the applicable Borrowing Date to the effect that the conditions specified in this
Section 7.1 are satisfied at such time.
ARTICLE VIII
AFFIRMATIVE COVENANTS
The Borrower agrees that:
Section 8.1 Conduct of Business, Maintenance of Existence, etc. The Borrower will at all times (i) engage solely in the business of owning and operating the Project and activities necessarily related thereto and (ii) preserve and maintain in full force and effect (A) its existence as a limited partnership under the laws of the State of Delaware and its qualification in the State of California and in each jurisdiction in which the failure to so qualify could reasonably be expected to have a Material Adverse Effect and (B) all of its rights, privileges and franchises necessary for the ownership or operation of the Project.
Section 8.2 Operation of Project. The Borrower, at its expense, shall (i) maintain and operate the Project in a safe manner and in accordance with prudent independent power industry operating practices, (ii) perform or cause to be performed the periodic overhauls and maintenance in accordance with the Operation and Maintenance Agreement and the Major Maintenance Plan for the Project from time to time in effect (as approved by the Agent and the Borrower after consultation with the Independent Engineer), and make or cause to be made all alterations, repairs, capital expenditures, replacements, renewals, additions and betterments which are necessary for the Project to satisfy the provisions of the Project Contracts and, subject to any contest permitted by this Section 8.2, all Requirements of Law affecting the Project and to insure the continued operation of the Project, (iii) maintain in good working order all equipment necessary to the operation of the Project, to maintain an adequate spare parts inventory in accordance with prudent independent power industry practices, and (iv) operate the Project in accordance with the requirements of the Project Contracts. The Borrower shall have the right to contest in good faith and by appropriate proceedings timely

instituted any Requirement of Law if (w) the Borrower diligently pursues such contest, (x) the Borrower sets aside on its books adequate reserves required by GAAP with respect to the contested items, (y) during the period of such contest, the enforcement of the contested item is effectively stayed, and (z) such contest does not involve any risk of sale, forfeiture or loss of any of the Collateral. The Borrower will promptly pay all required amounts and comply or cause the compliance with any Requirement of Law upon the termination of such contest.
Section 8.3 Payment of Obligations. The Borrower will pay, discharge or otherwise satisfy at or before due (taking into account all applicable notice and grace periods) stated maturity all of its Indebtedness and other material Contractual Obligations relating to the payment of money, except for any Indebtedness or other Contractual Obligations which are being contested in good faith and by appropriate proceedings if (i) reserves in conformity with GAAP are maintained on the books of the Borrower with respect to such obligations and (ii) such contest does not involve any risk of the sale, forfeiture or loss of any material part of the Collateral.
Section 8.4 Payment of Taxes and Claims. The Borrower will pay and discharge, or cause to be paid and discharged, all Taxes imposed on it or on its income or profits or on any of its property prior to the date on which interest or penalties attach thereto and all claims, levies or liabilities (including, without limitation, claims for labor, services, materials and supplies) for sums which have become due and payable and which have or, if unpaid, are reasonably likely to become a Lien (other than a Permitted Lien) upon any of the Collateral. The Borrower shall have the right, however, to contest in good faith the validity or amount of any such Tax or claim by proper proceedings timely instituted, and may permit the Taxes or claims so contested to remain unpaid during the period of such contest if (i) the Borrower diligently prosecutes such contest, (ii) the Borrower sets aside on its books adequate reserves as required by GAAP with respect to the contested items, (iii) during the period of such contest the enforcement of any contested item is effectively stayed, and (iv) such contest does not involve any risk of sale, forfeiture or loss of any of the Collateral. The Borrower will promptly pay or cause to be paid any valid, final and non-appealable judgment enforcing any such Tax or claim and cause the same to be satisfied of record.
Section 8.5 Performance of Obligations. The Borrower will duly perform and observe all covenants, agreements and conditions on its part to be performed and observed under this Agreement, the Notes, the Letters of Credit, the Collateral Security Documents and the other Basic Documents to which it is a party and the Permitted Contracts. The Borrower shall diligently enforce all of its rights under and the covenants of the other parties set forth in each Project Contract and under the Asset

Purchase Agreement.
Section 8.6 Insurance; Taking; Warranties.
(a) The Borrower will maintain insurance coverages in accordance with Schedule 8.6 hereto. If the insurance required by this Section 8.6(a) is not at any time reasonably available on commercially feasible terms and conditions in the commercial insurance industry in the judgment of an independent insurance consultant selected by the Agent and reasonably acceptable to the Borrower, the Agent shall not withhold, delay or condition its waiver of the requirement to maintain such required insurance if the Borrower obtains and maintains insurance of the types, in amounts and at the coverages comparable to the best and most comprehensive insurance then available in the commercial insurance industry for the Project. Any such waiver shall be effective only so long as such required insurance shall not be reasonably available on commercially feasible terms and conditions in the commercial insurance market, as may be determined from time to time by such independent insurance consultant.
(b) All Net Proceeds in respect of any Taking or any insurance policy (other than proceeds payable to third parties under liability coverages) maintained in accordance with this Section 8.6 and Schedule 8.6 shall be paid by the respective insurers directly to the Agent for the benefit of the Lenders pursuant to Sections 8.6(c) and 8.6(d) below, relative to any single loss in excess of $500,000. All such Net Proceeds relative to a single loss of $500,000 or less shall be paid directly to the Borrower. If any Net Proceeds relative to any single loss in excess of $500,000, or, during the occurrence and continuance of an Event of Default, relative to any loss are paid to the Borrower, such Net Proceeds shall be received only in trust for the Agent, shall be segregated from other funds of such Person, and shall be promptly paid over to the Agent in the same form as received (with any necessary endorsement).
(c) (i) If there does not exist an Event of Default, Net Proceeds in respect of any Taking or under any insurance policy (other than proceeds payable to third parties under liability coverages) relative to a single loss of $500,000 or less shall be applied by the Borrower for the sole purpose of paying the necessary costs of repair, restoration or replacement of the Project.
(ii) If there does not exist an Event of Default or an Event of Loss and if there shall occur any damage, destruction, casualty or Taking with respect to which Net Proceeds in excess of $500,000 are payable, and if (A) the Borrower promptly (and, in any event, within 30 days) gives written notice to the Agent that the Borrower wishes to repair, restore or replace the Project to the condition that it was in

immediately prior to such damage, destruction, casualty or Taking; (B) the proceeds of business interruption insurance payable to the Borrower together with funds otherwise available to the Borrower, will be sufficient to pay Debt Service during the period necessary to repair, restore or replace the Project;
(C) the Net Proceeds and other funds available to the Borrower will be sufficient to cover all costs and expenses necessary to repair, restore or replace the Project and the repair, restoration or replacement of the Project is technically and economically feasible; (D) after giving effect to any proposed repair, restoration or replacement, there will exist no default under any Project Contract; (E) the Agent and the Lenders shall receive an opinion of counsel in form and substance reasonably satisfactory to the Lenders to the effect that no Governmental Approval, amendment to this Agreement or the Collateral Security Documents, or any other instrument is necessary for the purpose of subjecting the repairs, restoration or replacement to the Liens of the Collateral Security Documents except such, if any, as may be delivered to the Agent with such opinion of counsel; and (F) the Agent shall have received from the Borrower and the Independent Engineer such certificates or other evidence as the Lenders may reasonably require regarding the foregoing matters, then Net Proceeds covering physical loss or damage to the Project shall be delivered to the Borrower and applied by the Borrower for the sole purpose of paying or reimbursing the Borrower for the necessary costs of repair, restoration or replacement of the Project. After making such payments to the Borrower, any excess Net Proceeds shall be deposited in the Receipt Account.
(d) If an Event of Default shall have occurred and is continuing or an Event of Loss exists, then Net Proceeds received by the Agent or any Lender shall be applied in accordance with Section 3.7(a). If there shall occur any damage, destruction, casualty or Taking with respect to which Net Proceeds for any single loss in excess of $500,000 are payable, and if the Borrower (x) has not notified the Agent or the Lenders promptly (and, in any event, within 30 days) that it wishes to repair, restore or replace the Project or (y) has not otherwise complied with the provisions of Section 8.6(c) above, then Net Proceeds shall be applied in accordance with Section 3.7(b).
Section 8.7 Inspection of Property, Books and Records; Discussions.
The Borrower will keep proper books of record and account in which full, true and correct entries in conformity with GAAP and all Requirements of Law shall be made of all dealings and transactions in relation to its business and activities. The Borrower shall permit representatives of the Agent or any Lender to visit and inspect its properties, to examine its books of record and accounts and to make copies thereof and to discuss its affairs, finances and accounts with its principal officers, engineers and independent accountants,

all at such times during business hours upon at least three Business Day's notice and otherwise at such intervals as the Agent or any Lender may reasonably request. The Borrower shall reimburse the reasonable costs of the Agent or any Lender incurred in connection with any such visit or inspection during the continuation of an Event of Default and of the Agent at any other time. The Borrower will at all times cause an accurate and complete set of the plans and specifications for the Project and a survey of the Project Site ("as built" following Completion) relating to the Project to be maintained at the Project and available for inspection during normal business hours upon at least one Business Day's notice by the Independent Engineer, any Lender and the Agent. The plans and specifications for the Project shall be promptly amended and supplemented from time to time to reflect all current improvements, additions and modifications to the Project.
Section 8.8 Compliance with Laws, etc. The Borrower will comply, subject to any contest permitted by this Section 8.8, with, and shall operate the Project in accordance with, all Requirements of Law and applicable Governmental Approvals except any Requirements of Law or Governmental Approvals the non-compliance with which would not have a Material Adverse Effect, and shall obtain, prior to the earlier to occur of (a) the lapse of the applicable time period set forth in Schedule 6.6 and (b) the dates required therefor under any applicable Governmental Approval or Requirement of Law, and shall maintain in full force and effect, all Governmental Approvals and other consents and approvals as shall now or hereafter be necessary in connection with the ownership, operation or maintenance of the Project or the entering into and performance by the Borrower of the Basic Documents to which it is a party, except where the failure to so obtain or maintain in effect such Governmental Approvals could not reasonably be expected to have a Material Adverse Effect. The Borrower shall have the right to contest in good faith and by appropriate proceedings timely instituted any Requirement of Law if (w) the Borrower diligently pursues such contest, (x) the Borrower sets aside on its books adequate reserves required by GAAP with respect to the contested items, (y) during the period of such contest, the enforcement of the contested item is effectively stayed, and (z) such contest does not involve any risk of sale, forfeiture or loss of any of the Collateral. The Borrower will promptly pay all required amounts and comply or cause the compliance with any Requirement of Law upon the termination of such contest.
Section 8.9 Financial Statements. The Borrower will furnish, or cause to be furnished, to the Agent:
(a) as soon as available, but not later than 120 days after the end of each fiscal year of the Borrower, Calpine and Calpine Fuels, and, to the extent delivered to the Borrower by the Steam Host or any contracted fuel supplier for the Project,

each such Person and a profit and loss statement, a statement of partners' capital or retained earnings and a statement of cash flows of such Person for such year, and a balance sheet of such Person as at the end of such year, in each case setting forth in comparative form the figures for the previous fiscal year of such Person, certified as meeting the requirements of this Section 8.9 and as presenting in accordance with GAAP the profit and loss position, partners' capital or retained earnings, cash flows and balance sheet of such Person as of the date thereof, without qualification or exception as to the scope of its audit, by independent certified public accountants of national standing reasonably acceptable to the Agent (it being understood that consolidated financial statements of Calpine and its Affiliates will meet the requirements of this Section 8.9(a) with respect to Calpine Fuels and the Borrower); in addition, if PG&E spins off or otherwise transfers its gas supply and/or transportation services, the Borrower will use all reasonable efforts to deliver such financial statements of the newly-formed gas supply/transportation company; and
(b) as soon as available, but not later than 45 days after the end of each quarterly period of each fiscal year of the Borrower, Calpine and Calpine Fuels and, to the extent delivered to the Borrower by the Steam Host or any contracted fuel supplier for the Project, a profit and loss statement and statement of partners' capital or retained earnings for such Person as at the end of each such period, in each case setting forth in comparative form the figures for the corresponding period of the previous fiscal year of such entity, certified by a Responsible Officer of such Person as meeting the requirements of this Section 8.9 and as fairly presenting in all material respects the profit and loss position, partners' capital or retained earnings, cash flows and balance sheet of such Person as of the date thereof (subject to normal year-end audit adjustments).
All financial statements delivered pursuant to Sections 8.9(a) and (b) shall be prepared in reasonable detail and in accordance with GAAP throughout the periods involved except as otherwise specifically noted therein, and shall be complete and correct in all material respects (subject, in the case of financial statements delivered pursuant to Section 8.9(b), to normal year-end audit adjustments).
Section 8.10 Certificates; Other Information. The Borrower will furnish or cause to be furnished to the Agent:
(a) concurrently with the delivery of the financial statements of the Borrower referred to in Sections 8.9(a) and 8.9(b), a certificate of a Responsible Officer stating (i) that, to the best of such Person's knowledge after due inquiry, the Borrower, during the period covered by such financial statements, has observed and performed in all material respects all of the covenants and other agreements, and satisfied in all material

respects every condition contained in this Agreement and the other Basic Documents to be observed, performed or satisfied by such Borrower, (ii) that, except as stated in such certificate, the Borrower does not have actual knowledge of any Default or Event of Default that is continuing on the date of such certificate, (iii) that, except as stated in such certificate, the Borrower does not have any actual knowledge of any default or event which with the giving of notice or the lapse of time or both would constitute a default under any of the other Basic Documents (or, if any such Default or Event of Default or default or event shall have occurred, a statement setting forth the nature thereof and the steps being taken by the Borrower to remedy the same), (iv) the computations and amounts of Excess Cash Flow and the amount, if any, of Restricted Payments that were made during such period and (v) that the Borrower has complied with the requirements of Section 8.14 as of the date of such certificate;
(b) promptly after delivery or receipt thereof, a copy of each material notice or other material document issued or received by the Borrower pursuant to any Basic Document or relating to a transfer of any Partnership Interest;
(c) promptly after receipt thereof, copies of the monthly operating reports, annual operating reports (including, without limitation, reports of all operating and maintenance costs incurred in connection with the Project) and any other reports provided under the Operation and Maintenance Agreement;
(d) promptly after receipt thereof, copies of each Governmental Approval (and copies of any material correspondence referred to in any such Governmental Approval) or any other material consent or approval obtained or made by the Borrower or obtained or made by any other Material Obligor or by the Steam Host and delivered to the Borrower pursuant to the applicable Project Contract;
(e) promptly upon availability and at least 45 days prior to the start of each calendar year relating to such upcoming calendar year, a Fuel Plan and an annual budget (which shall be based on operating assumptions reviewed and commented on by the Independent Engineer and shall include anticipated capital expenditures, broken out to show expenditures of $50,000 or more) prepared by or on behalf of the Borrower relating to the Project, which shall be satisfactory to the Required Lenders, and an Operating Plan and a Major Maintenance Plan for the upcoming calendar year;
(f) within 45 days following each calendar year, a report of the output and dispatch of the Project and steam deliveries by the Project in the preceding calendar year and as projected for the current year, and setting forth calculations showing whether the Project has met the operating requirements of

a Qualifying Facility during such year, and within 45 days following the end of each quarterly period, a report setting forth calculations of the Capacity Utilization for the preceding twelve-month period;
(g) within 30 days following each calendar year, a report of all operating and maintenance costs incurred in connection with the Project, including any such costs paid by and not reimbursed to the Operator pursuant to the Operations and Maintenance Agreement; and
(h) promptly, such information with respect to the Borrower or the Project as the Agent or any Lender may from time to time reasonably request.
Section 8.11 Notices. The Borrower will, promptly upon obtaining actual knowledge of, and verifying with due diligence the accuracy or occurrence of, any of the following, give notice to the Agent:
(a) of the occurrence of any Default or Event of Default;
(b) of any default or event which with the giving of notice or the lapse of time or both would constitute a default under any Project Contract or any notice or assertion thereof or of any event which would give rise to a right to terminate, to refuse to perform or to decrease or extend the time for payments otherwise due under any Project Contract;
(c) of any litigation, investigation or proceeding which may exist at any time between the Borrower and any Governmental Authority which could reasonably be expected to have a Material Adverse Effect;
(d) of any litigation or proceeding affecting the Borrower in which the amount involved is $250,000 or more or in which injunctive or similar relief is sought;
(e) of any material adverse change in the properties, business, operations or financial condition of the Borrower from the condition reflected in the most recent financial information delivered to the Agent, and of any change of local or regional law, rule or regulation which has caused or could reasonably be expected to have a Material Adverse Effect;
(f) of any loss or damage to the Collateral in excess of $250,000;
(g) of any event or claim of force majeure under any

Project Contract (other than a Permitted Contract);
(h) of the occurrence of any of the following with respect to any Plan as to which the Borrower may have any material liability, the Borrower shall deliver to the Agent written notice thereof, describing the same and steps being taken by the Borrower with respect thereto:
(i) the acquisition of a Commonly Controlled Entity, (ii) the occurrence of a Reportable Event (as defined in Section 4043 of ERISA) with respect to any such plan, (iii) the institution of steps to withdraw from any Multiemployer Plan, (iv) the institution of any steps to terminate any such Plan, (v) the failure to make a required contribution to any such Plan if such failure is sufficient to give rise to a lien under Section 302(f) of ERISA or Section 412 of the Code, (vi) the taking of any action with respect to any such Plan which could result in the requirement that the Borrower furnish a bond or other security to the PBGC or such Plan, or (vii) the occurrence of any other event or events with respect to any such Plan which in the aggregate could reasonably be expected to result in material liability for the Borrower; and
(i) of any proposed Additional Contract, as soon as possible and in any event at least 45 days prior to the expected execution thereof by the Borrower, and of any Permitted Contract, promptly upon the Borrower's execution and delivery thereof.
Each notice pursuant to this Section 8.11 (other than clause (i)) shall be accompanied by a statement of a Responsible Officer of the Borrower setting forth details of the occurrence referred to and stating what action the Borrower proposes to take with respect to such occurrence. A notice given pursuant to clause (i) shall be accompanied by a copy of the current draft of the proposed Additional Contract.
Section 8.12 Assignments of Additional Contracts; Maintenance of Liens of the Collateral Security Documents; Future Mortgages. The Borrower will:
(a) at the Borrower's expense, concurrently with the execution of any Additional Contract, execute and deliver to the Agent a Collateral Assignment with respect to such Additional Contract and, upon the Agent's request, cause the other party or parties to such Additional Contract (other than a Permitted Contract) to execute and deliver, or cause to be delivered, to the Agent a consent and an opinion of counsel in form and substance reasonably satisfactory to the Agent;
(b) at the Borrower's expense, execute and deliver, or cause the execution and delivery of, and thereafter

register, file or record in each appropriate governmental office, any document or instrument supplemental to or confirmatory of the Collateral Security Documents or otherwise deemed by the Agent to be necessary or desirable for the creation or perfection of the Liens and security interests and the maintenance, protection and continuation thereof purported to be created by the Collateral Security Documents;
(c) if the Borrower shall at any time acquire any real property or leasehold or other interests in any real property not covered by the Deed of Trust or any other Collateral Security Document, the Borrower will promptly upon such acquisition execute, deliver and record a deed of trust, in form and substance satisfactory to the Agent and Lenders, in favor of the Agent covering such interests, granting a Lien prior and superior to all other Liens and security interests therein, existing or future, subject to Permitted Liens. The Borrower shall deliver to the Agent a survey of the newly-acquired property meeting the requirements set forth in Section 7.1(k). The Borrower shall also provide title insurance insuring the lien of such deed of trust as a valid first lien on the Borrower's interest, subject only to exceptions reasonably approved by the Agent. The Borrower shall also deliver to the Agent and the Lenders such opinions of counsel and certificates as shall reasonably be required by the Agent in connection with the Borrower's interest in the newly-acquired property.
Section 8.13 Defend Title. The Borrower will at all times at its own cost and expense warrant and defend the title to the Project, its interest in the Project Site and all other property it owns against the claims and demands of all Persons whomsoever, except with respect to Permitted Liens.
Section 8.14 Accounts; Operating Budget.
(a) Receipt Account. (i) On the Closing Date, the Borrower shall deposit in the Receipt Account $2,000,000, and thereafter all revenues received pursuant to the Power Purchase Agreement or any other Project Contract or Assigned Agreement (other than Excluded Payments) and any indemnity payments received under the Asset Purchase Agreement shall be deposited in the Receipt Account and, subject to the provisions of this Agreement and the Deposit and Security Agreement, may be withdrawn from time to time to pay Project operation and maintenance expenses and Debt Service, to make required deposits into the Debt Service Reserve Account, Major Maintenance Reserve Account and the Fuel Reserve Account, and to pay Restricted Payments (as permitted by this Agreement).
(ii) If a Calpine Credit Event Level I occurs, and if, as of any date during the period the Calpine Credit Event

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Level I is continuing, the Debt Service Coverage Ratio for the preceding twelve-month period was less than 1.30, the Borrower shall, within fifteen Business Days, cause Calpine to deposit in the O&M Reserve Sub-Account $1,000,000. If and when Calpine's long-term credit rating is upgraded to Calpine's Credit Rating (but provided that no Calpine Credit Event Level II has occurred), at the Borrower's request, the Disbursement Agent shall transfer to Calpine so much of such $1,000,000 as remains in the O&M Reserve Sub-Account, together with any interest and earnings thereon then in the O&M Reserve Sub-Account. If a Calpine Credit Event Level II occurs and if, as of any date, the Debt Service Coverage Ratio for the preceding twelve-month period was less than 1.30, the Borrower shall, within fifteen Business Days, cause Calpine to deposit in the O&M Reserve Sub-Account $2,500,000. Thereafter, if on any Quarterly Payment Date the balance in the O&M Reserve Sub-Account is less than $2,500,000, the Disbursement Agent shall, after making any deposits required pursuant to Section 3.2, 3.3(b), 3.4(a), 3.5(a) and 3.5(b) of the Deposit and Security Agreement, deposit Excess Cash Flow (to the extent available) in the O&M Reserve Sub-Account in an amount equal to the excess of $2,500,000 over the amount then on deposit in the O&M Reserve Sub-Account.
(b) Debt Service Reserve Account.
(i) On the Closing Date, the Borrower shall deposit in the Debt Service Reserve Account $4,000,000. Thereafter, after $1,500,000 shall have been deposited out of Excess Cash Flow in the O&M Reserve Sub-Account, 100% of Excess Cash Flow shall be deposited in the Debt Service Reserve Account until the balance on deposit therein equals the Required Debt Service Reserve Account Balance. In addition, to the extent required pursuant to the Deposit and Security Agreement, Debt Service Reserve Account Margins shall be deposited in the Debt Service Reserve Account.
(ii) Unless, to the Agent's knowledge, a Default or Event of Default shall have occurred and be continuing, if Cash Flow is insufficient to pay Debt Service due on any Quarterly Payment Date or Payment Date, the Agent shall release amounts held in the Debt Service Reserve Account to pay Obligations then due and owing.
(iii) If amounts on deposit in the Debt Service Reserve Account are used to pay Debt Service, 100% of Excess Cash Flow shall be deposited in the Debt Service Reserve Account on each Quarterly Payment Date thereafter until the amount on deposit in the Debt Service Reserve Account equals the Required Debt Service Reserve Account Balance.
(c) Fuel Reserve Account.
(i) If in any quarterly period the Project's

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all-in cost of fuel exceeds the UEG Rate by more than 20% (such excess above 20%, the "Fuel Cost Differential"), the Borrower shall deposit in the Fuel Reserve Account on each Quarterly Payment Date Excess Cash Flow remaining after any required deposits in the Debt Service Reserve Account have been made in an amount equal to the Fuel Cost Differential.
(ii) If Cash Flow is insufficient to pay fuel costs when due, the Agent shall release amounts held in the Fuel Reserve Account to pay such costs.
(iii) The Agent shall release amounts on deposit in the Fuel Reserve Account in accordance with the Deposit and Security Agreement if (A) no Fuel Cost Differential occurred in any of the preceding four quarterly periods, (B) no Fuel Margin Payments (as defined in Section 9.2 of the Fuel Management Contract) were required to be made in the preceding four quarterly periods and (C) no Calpine Credit Event has occurred unless, if a Calpine Credit Event Level I has occurred (and a Calpine Credit Event Level II has not occurred), Calpine's long-term credit rating has been upgraded to Calpine's Credit Rating.
(d) Major Maintenance Reserve Account.
(i) On each Quarterly Payment Date, the Borrower shall deposit in the Major Maintenance Reserve Account an amount equal to (A) at least 100% and not more than 105% of the budgeted costs of major maintenance of the Project for the following quarterly period, as set forth in the annual budget and the Major Maintenance Plan then in effect.
(ii) If, to the Agent's knowledge, no Event of Default shall have occurred and be continuing, the Agent shall release amounts on deposit in the Major Maintenance Reserve Account to pay costs of completing scheduled major maintenance.
(iii) If any Requirement of Law applicable to the Project (or which will become applicable to the Project on a future date) requires the Project to meet the NOx emissions standards which the Project, in its then current configuration and operating condition, will be unable to meet when such Requirement of Law becomes effective, the Borrower shall, within 30 days following Borrower's obtaining actual knowledge of such event, submit to the Agent a report setting forth the anticipated cost of installing selective catalytic reduction, similar technology, or any other emissions reduction capital improvements in the Project or of any alternative method of responding to such new standards which the Borrower proposes to pursue, together with an anticipated schedule of deposits of funds in the Major Maintenance Reserve Account to ensure that sufficient funds will be available when needed for the Borrower to install such capital improvements or complete such alternative response prior to the

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effective date of the more restrictive NOx emissions standards applicable to the Project. Such report shall be subject to the approval of the Required Lenders, after consultation with the Independent Engineer and the Borrower. Amounts deposited in the Major Maintenance Reserve Account for such purpose shall be released to pay the costs of acquiring and installing such capital improvements or implementing such alternative response.
(iv) If and for so long as a Calpine Credit Event has not occurred, the Borrower may, in lieu of making all or any portion of required deposits in the Major Maintenance Reserve Account, cause to be delivered to the Agent a guarantee of Calpine, in the form of the Major Maintenance Guaranty. The Borrower shall draw on the Major Maintenance Guaranty from time to time and apply amounts received thereunder to pay costs of major maintenance and costs of acquiring and installing capital improvements, or implementing an alternative response, as described in subsection (iii) above. If after delivery of a Major Maintenance Guaranty, a Calpine Credit Event Level I occurs, the Borrower shall commence (or recommence) deposits in the Major Maintenance Reserve Account as required by this clause (d), and the Borrower shall cause Calpine to deposit in the Major Maintenance Reserve Account cash in the amount that would have been on deposit in the Major Maintenance Reserve Account on the most recent Quarterly Payment Date if the Borrower had been making deposits in accordance with this clause (d) during the period the Major Maintenance Guaranty was in effect. If and when Calpine's long-term credit rating is upgraded to Calpine's Credit Rating following a Calpine Credit Event Level I (but not following a Calpine Credit Event Level II), the Borrower may, in lieu of making all or any portion of deposits required thereafter in the Major Maintenance Reserve Account, cause to be delivered to the Agent a guarantee of Calpine in the form of the Major Maintenance Guaranty. In no event may the Borrower deliver a Major Maintenance Guaranty if the aggregate amount of the guaranteed obligations under all Calpine Guarantees would exceed $7 million.
(e) Permitted Investments. Amounts deposited in the Receipt Account, the Debt Service Reserve Account, the Major Maintenance Reserve Account, the Insurance Proceeds Account and the Fuel Reserve Account shall be invested and reinvested by the Agent in Permitted Investments, in accordance with the written directions of the Borrower.
(f) No Prejudice to Rights. If any provision of this Section 8.14 shall be construed in derogation of the security interest purported to be created under the Deposit and Security Agreement, such provision shall be deemed ineffective without invalidating the effectiveness of any other provision of this Section 8.14.
(g) Operating Budget. At least 45 days prior to the

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end of each calendar year, the Borrower shall submit its proposed operating and capital expenditure budget (with a summary of the operating assumptions on which the budget is based), the Major Maintenance Plan and the Fuel Plan to the Lenders for approval after consultation with the Independent Engineer. The Required Lenders will provide their approval or disapproval (with the reasons therefor) within 30 days. The budget so approved, or if the Borrower incorporates the comments of the Required Lenders, the budget as so amended, shall be the approved operating budget for the following calendar year. If a budget is not agreed prior to the start of any year, the budget approved for the preceding year (other than amounts budgeted therein for capital expenditures or major maintenance expenses which shall be adjusted to reflect the Major Maintenance Plan then in effect) shall be adjusted for changes in the Consumer Price Index and shall be the budget in effect until a new budget is approved by the Required Lenders. In the event a Force Majeure event (as defined in the Operations and Maintenance Agreement), a change in the Operator's services requested by the Borrower, a change in a Project Contract or any other change with respect to the Project results in increased or decreased Recoverable Costs (as defined in the Operations and Maintenance Agreement), the Borrower shall submit its proposed revised budget for the remainder of the calendar year to the Lenders for approval after consultation with the Independent Engineer. The Required Lenders will provide their approval or disapproval (with the reasons therefor) within 30 days. A copy of each Operating Plan will be delivered to the Lenders at least 45 days prior to the start of the year to which the plan relates.
(h) If a Calpine Credit Event occurs, the Borrower shall cause Calpine to provide Acceptable Security to the extent required pursuant to the terms of the Calpine Performance Agreement, and otherwise perform its covenants set forth in the Performance Agreement.
Section 8.15 Environmental Matters.
(a) The Borrower will comply with, and ensure compliance by any and all occupants of the Project with, Environmental Laws (subject to Borrower's right to contest any Requirement of Law in accordance with Section 8.8 hereof); will not treat, store, transport or release any Materials of Environmental Concern on or from the Project Site except as authorized, permitted or otherwise allowed under Environmental Laws, or in any manner or quantity which could reasonably be expected to result in any clean-up obligation or liability under any Environmental Law; will keep the Project free of any Lien imposed pursuant to Environmental Laws; and will pay or cause to be paid when due any and all costs of complying with Environmental Laws and responding to the presence, release or threatened release of Materials of Environmental Concern (including without limitation, all damages, liabilities, expenses

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and costs of all third party claims). If the Borrower fails to do any of the foregoing, then the Agent may, if so directed by the Lenders, upon such prior written notice to the Borrower as is reasonable under the circumstances, take any action necessary in its reasonable judgment to respond to such presence, release or threatened release affecting the Collateral, and the cost of such response action shall be added to the Obligations evidenced by the Notes and secured by this Agreement and the Collateral Security Documents. Nothing herein shall require, or be deemed to require, the Agent or the Lenders to inspect the Project or to respond to any presence, release or threatened release of Materials of Environmental Concern, wherever occurring.
(b) The Borrower agrees to indemnify and hold the Agent, the Issuing Bank and each Lender and their respective directors, officers, agents and employees free and harmless from and against all liability, loss, cost, damage and expense (including, without limitation, reasonable attorneys' and consultant's fees and expenses incurred in connection with environmental compliance, clean-up and other response obligations (including all third party claims) imposed under any Environmental Laws) that any such indemnitee may sustain by reason of the assertion against it by any party of any claim in connection with any violation of any Environmental Law or Materials of Environmental Concern used, generated, treated, stored or otherwise located on, or released or threatened to be released in, on, under, from or affecting the Project, except to the extent resulting from such indemnitee's gross negligence or willful misconduct.
(c) The Borrower will notify the Agent promptly after receipt or after it otherwise becomes aware of any written notice or written communication from any Governmental Authority or any other source with respect to Materials of Environmental Concern in, on, under or released from or affecting the Project in violation of Requirements of Law or of any other such notice or communication respecting a pending or threatened investigation, proceeding or claim related to any such Materials of Environmental Concern. The Borrower will notify the Agent of any event or circumstance actually known to the Borrower the occurrence of which renders any of the representations in Section 6.15 untrue.
(d) The Borrower shall install such capital improvements in the Project, or implement any alternative response approved by the Required Lenders in response to changed emissions standards applicable to the Project, to the extent required under Section 8.14(d)(iii) hereof.
Section 8.16 Fuel Supply.
(a) The Borrower shall renew the term of the Gas Transportation Agreement at the end of each term thereof, for an

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additional two-year period.
(b) The Borrower shall enter into with one or more creditworthy entities (or with entities whose obligations are guaranteed by creditworthy entities or with any other entity reasonably acceptable to the Required Lenders) replacement gas supply agreements having at least a two-year term and providing for firm supply of gas at the Project's receipt point(s) into the PG&E system (or the system of any other gas distribution or transportation company party to a Project Contract) of 100% of the Project's full fuel requirements, at least 90 days prior to the expiration date of the then-effective Gas Supply Agreement. Any replacement agreement shall be in the form of Exhibit L hereto or otherwise satisfactory in form and substance to the Required Lenders, which approval shall not be unreasonably withheld or delayed if the terms and conditions of such replacement agreement are on terms and conditions at least as favorable as those set forth in Exhibit L.
(c) The Borrower shall deliver, or cause the Fuel Manager to deliver, to the Agent within 45 days after the end of each calendar quarter a quarterly Fuel Transportation Report. If a Preliminary Fuel Transportation Trigger Event has occurred, the Borrower and Calpine Fuels shall meet and confer as required pursuant to Section 3.6 of the Fuel Management Contract to negotiate a revised fuel plan, which revised fuel plan shall be subject to the approval of the Borrower and the Required Lenders, after consultation with the Gas Consultant, Calpine Fuels and any gas consultant of the Borrower. If a Fuel Transportation Trigger Event has occurred, the Borrower shall, or shall cause the Fuel Manager to, within 30 days thereafter, or, if a Preliminary Fuel Transportation Trigger Event did not precede such Fuel Transportation Trigger Event, and provided that the Borrower enters into successive 30-day gas supply contracts during such period, within 90 days, enter into with one or more creditworty entities (or entities whose obligations are guaranteed by creditworthy entities or other entities reasonably acceptable to the Required Lenders) fuel supply contracts providing for firm supply of the Project's full fuel requirements to the Project's receipt point on the PG&E gas system (or the system of any other gas distribution or transportation company party to a Project Contract), in the form attached hereto as Exhibit L or otherwise in form and substance approved by the Required Lenders (which approval will not be withheld unreasonably if the proposed agreement provides for gas supply on terms and conditions at least as favorable as those set forth in Exhibit L). Such long-term contracts shall have a term expiring no earlier than the latest Maturity Date.
(d) If as a result in a change in law, regulation or tariff structure occurring after the Closing Date, the Project's priority to capacity on the California intrastate gas transportation grid with respect to the allocation or curtailment

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of such capacity is lowered, the Borrower shall use all reasonable efforts to obtain (including causing the Fuel Manager to locate and negotiate) the class of transportation service (firm delivery) having the highest priority with respect to allocation or curtailment of such intrastate capacity if such service accommodates the operational mode and Contractual Obligations of the Project.
Section 8.17 Application of Proceeds. The Borrower shall use the proceeds of the Loans in accordance with the provisions of Article II.
Section 8.18 Accounts Receivable. The Borrower shall promptly bill and diligently pursue collection of all accounts receivable owing to the Borrower.
ARTICLE IX
NEGATIVE COVENANTS
The Borrower agrees that:
Section 9.1 Organization, Sale of Assets, Purchases, etc. The Borrower will not:
(a) merge into or consolidate with any other Person, change its form of organization as a limited partnership or the scope or nature of its business or business objectives, or liquidate or dissolve itself (or suffer any such liquidation or dissolution), or sell, lease, transfer or otherwise dispose of all or any substantial portion of its assets which constitute part of the Collateral other than (i) in the ordinary course of its business as reasonably required in connection with the maintenance and operation of the Project, (ii) assets that are obsolete, worn out, damaged or destroyed and which have been replaced, if such replacement is necessary for the safe or efficient operation of the Project or in order to comply with any Requirement of Law or Governmental Approval, by adequate substitutes of substantially equal or greater value and utility than the replaced items, (iii) Permitted Investments, (iv) sales of electricity pursuant to the Power Purchase Agreement or steam pursuant to the Steam Sales Agreement; or
(b) purchase or acquire any assets or sell any Project asset, other than (i) in the ordinary course of its business as reasonably required in connection with the maintenance and operation of the Project or otherwise as expressly contemplated in the approved Annual Budget, (ii) assets that are obsolete and which have been replaced, if such replacement is necessary for the safe or efficient operation of the Project or in order to comply with any Requirement of Law or Governmental Approval, by adequate substitutes of substantially equal or greater value and utility than the replaced items when new or (iii) Permitted

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Investments, (iv) the purchase of assets reasonably required for the repair or restoration of the Project in accordance with the approved budget and the Major Maintenance Plan and the terms of the Loan Documents or (v) any other improvement to the Project, to the extent included in the approved budget and the Major Maintenance Plan and financed by Permitted Indebtedness or by funds otherwise available to the Borrower; or
(c) purchase or acquire any real property except pursuant to the ConAgra Option Agreements.
Section 9.2 Indebtedness. The Borrower will not create, incur, assume or suffer to exist any Indebtedness, except Permitted Indebtedness. The Borrower will not incur Indebtedness to any partner of the Borrower except Permitted Indebtedness (which shall contain the subordination terms attached hereto as Exhibit M).
Section 9.3 Liens. The Borrower will not create, incur, assume or suffer to exist any Lien against all or any portion of the Collateral, except Permitted Liens.
Section 9.4 Nature of Business. The Borrower will not engage in any business other than the development, financing, ownership and operation of the Project and other activities necessarily related thereto.
Section 9.5 Amendment of Contracts, Additional Contracts, etc. The Borrower will not, without the prior approval of the Agent and the Lenders, (a) agree to or permit the cancellation or termination of any Basic Document or the Asset Purchase Agreement, except upon the expiration of the stated term thereof,
(b) agree to the assignment of the rights or obligations of any party to any Basic Document or the Asset Purchase Agreement, except as contemplated by this Agreement or the Collateral Security Documents, (c) agree to any amendment, supplement or modification of, or waiver with respect to any of the provisions of, the Asset Purchase Agreement or any Basic Document to which the Borrower is a party or with respect to which the consent of the Borrower is required, (d) agree to any amendment, supplement or modification of, or waiver with respect to any of the provisions of, any Project Contract, (e) permit any amendment, supplement or modification of, or waiver with respect to, any of the provisions of, the Partnership Agreement except to the extent required for the admission of limited partners as permitted by this Agreement, (f) petition, request or take any other legal or administrative action that seeks, or may reasonably be expected, to rescind, terminate or suspend any Basic Document to which the Borrower is a party or amend or modify any portion thereof, or (g) enter into any Additional Contract; provided, that notwithstanding the foregoing, any such termination, amendment, modification, supplement, waiver or assignment with respect to any provision of, or any replacement

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of, any Project Contract other than the Power Purchase Agreement, the Steam Sales Agreement or any Long-Term Gas Supply Agreement shall require the prior approval only of the Required Lenders (which approval of the Required Lenders shall not be unreasonably withheld).
Section 9.6 Investments or Loans. The Borrower will not make any loans or advances to, or investments in (whether by transfer of property, contributions to capital, acquisitions of stock, bonds, promissory notes or other securities, loans, advances or otherwise) any Person, other than Permitted Investments.
Section 9.7 Qualifying Facility. The Borrower will not take any action, or omit to take any action, the effect of which results in the Project ceasing to be a Qualifying Facility.
Section 9.8 Change of Office. The Borrower will not change the location of its chief executive office or principal place of business or the office where it keeps its records concerning the Partnership, the Project and all related contracts from that existing on the date of this Agreement and specified in
Section 6.18, except in accordance with the Security Agreement.
Section 9.9 Change of Name. The Borrower will not change its name, except in accordance with the Security Agreement.
Section 9.10 Limitation on Transactions with Affiliates. Except as expressly permitted by the Loan Documents, including, without limitation, delivery and performance of the Fuel Management Contract, the Operations and Maintenance Agreement and the Spare Parts Agreement, the Borrower will not, directly or indirectly, conduct any business or engage in any transaction with any Affiliate other than pursuant to a Project Contract to which such Affiliate is a party, except (i) with the prior written approval of the Lenders (which approval shall not be unreasonably withheld if the conditions of Section 9.10(iv) are met), (ii) Permitted Contracts, (iii) Restricted Payments made in accordance with Section 9.14, or (iv) in the ordinary course of such Affiliate's business and upon fair and reasonable terms no less favorable to the Affiliate than the Affiliate would obtain in a comparable arms-length transaction with an unaffiliated Person.
Section 9.11 Restricted Payments.
(a) Generally. The Borrower will not make any Restricted Payments other than on a Payment Date and as permitted by Section 9.11(b) below.
(b) Additional Limitations on Restricted Payments. The Borrower will not make any Restricted Payment if (i) Excess

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Cash Flow remaining in the Receipt Account after all withdrawals required to be made therefrom pursuant to priorities First through Eighth of Section 4.2 of the Deposit and Security Agreement have been made (if any) is not greater than zero or (ii), as of the Payment Date on which such Restricted Payment is proposed to be made:
(i) any Default or Event of Default shall have occurred and be continuing;
(ii) for the twelve-month period immediately preceding such Payment Date (including the month ending on such Payment Date), the Debt Service Coverage Ratio was less than 1.20;
(iii) the balance in the Debt Service Reserve Account was less than the Required Debt Service Reserve Account Balance, or any withdrawal was made from the Debt Service Reserve Account (other than to transfer to the Receipt Account amounts in excess of the Required Debt Service Reserve Account Balance) during the four-quarter period preceding such Payment Date; or
(iv) a Fuel Transportation Trigger Event shall have occurred but the Borrower shall not have entered into a fuel supply contract in accordance with Section 8.16(c).
Section 9.12 Assignment. Except as permitted by the Loan Documents, the Borrower shall not assign any of its rights or obligations under this Agreement, the Loans, either of the Letters of Credit or the Notes to any Person without the prior written consent of the Lenders.
9.13 Abandonment of Project. The Borrower shall not cause or permit an Abandonment to occur.
ARTICLE X
EVENTS OF DEFAULT
Section 10.1 Events of Default.
(a) An Event of Default shall occur if:
(i) the Borrower shall default in the payment of any principal of any of the Notes or of amounts due to the Agent in respect of any Drawing or of payments under Interest Rate Contracts when the same shall become due (as scheduled, by acceleration or in accordance with Section 3.7); or
(ii) the Borrower shall default in the payment of any interest on the Notes or the Drawings for more than three Business Days after the date on which the same shall become due;

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or
(iii) the Borrower shall default in the payment of any fee payable under Article V or any payment payable under Section 4.1 (other than the principal amount of or any interest on any Drawing), or under any Interest Rate Contract or any Collateral Security Document for more than five Business Days after the date on which the same shall become due or, in the case of payments due under Section 3.12, 3.13, 3.15, 3.16, 4.4 or 8.15(b), 12.1 or under any Collateral Security Documents, for more than fifteen Business Days after the Agent or any Lender shall have delivered written demand therefor; or
(iv) any representation or warranty made in writing by the Borrower or Calpine to the Agent, the Issuing Bank or any of the Lenders herein or in any other Basic Document, or in any certificate, or other document required to be furnished under this Agreement to the Agent, the Issuing Bank or any of the Lenders, shall prove to have been false or misleading in any material respect as of the time made or deemed made and the Borrower or Calpine, as the case may be, fails to correct any such inaccuracy or eliminate the adverse effects of such inaccuracy to the reasonable satisfaction of the Lenders within 30 days after the Borrower obtains actual knowledge thereof; or
(v) the Borrower shall fail to perform or observe, or cause to be performed or observed, any covenant contained in Section 8.6(a) or
Section 6(a) of the Security Agreement; provided, that in the case of insurance with respect to which cancellation, change or lapse for nonpayment of premium shall not be effective as to the Agent and the Lenders for 30 days, or such other period as may from time to time be customarily obtainable in the insurance industry after receipt by the Agent and the Lenders of notice of such cancellation, change or lapse, no such failure to carry and maintain insurance shall constitute an Event of Default (so long as the Borrower is diligently pursuing replacement insurance) until the earlier (1) the date such failure shall have continued unremedied for a period resulting in 15 days' or less coverage remaining with respect to each of the additional insured parties, or
(2) the date on which such insurance is not in effect as to any such additional insured party; or
(vi) the Borrower shall fail to perform or observe, or cause to be performed or observed, any covenant contained in Section 8.1, 8.5 (provided that any cure period with respect to a covenant default under any Loan Document provided in another clause of this Section 10.1 shall not be limited by this clause (vi)), 8.9, 8.10, clause (a), (b), (g), (h) or (i) of Section 8.11, 8.14 or 8.16; or Section 3(a)(i) (but without limiting the default set forth in clause (xviii) hereof) or Section 6(b) of the Security Agreement; or Section
II.E, III.C.1

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or V.A.1 of the Deed of Trust; or
(vii) the Borrower shall fail to perform or observe, or cause to be performed or observed, any covenant contained in Section 8.4, clause
(b) or (c) of Section 8.6, 8.7, 8.8 (but without limiting the default set forth in clause (xviii) hereof), 8.12, 8.15 (but without limiting Borrower's right to contest any Requirement of Law in accordance with Section 8.8) or 8.18, and such failure shall continue for a period of 30 days after the Borrower obtains actual knowledge thereof; or
(viii) the Borrower shall fail to perform or observe, or cause to be performed or observed, any other covenant, term or agreement (other than those covenants referred to in clauses (i) through (vii) above) contained in this Agreement and such failure shall continue unremedied for a period of 30 days after the Borrower obtains actual knowledge thereof; provided that if (1) such failure cannot be cured within such 30-day period, (2) the Borrower submits to the Lenders within such period a cure plan and, in the reasonable judgment of the Required Lenders, such plan is technically and economically feasible, (3) the Borrower is proceeding with diligence and in good faith to cure such failure, (4) and the Agent shall have received a certification from an authorized representative of the Borrower to the effect of subclauses (1) and
(3) above and the then anticipated time to effect such cure, the time within which such failure may be cured shall be extended for an additional period not to exceed 120 days as shall be necessary for the Borrower diligently to cure such failure;
(ix) the Borrower or the Partner shall default in any payment of principal of or interest on any Indebtedness (other than the Notes, any Interest Rate Contract, any Drawing or any other Indebtedness under the Loan Documents) or in the payment of money under any other material Contractual Obligation when due totalling for any such Person $250,000 or more (taking into account any grace periods provided in the documentation relating to such Indebtedness or Contractual Obligation), or shall fail to observe or perform any other material condition or material obligation under the terms of such Indebtedness, and in either case, the effect of which is to permit the holder, or any trustee or agent to realize upon any collateral given as security therefor or to accelerate such Indebtedness or payment obligations under a material Contractual Obligation totalling $250,000 or more; or
(x) Calpine shall fail to make any payment pursuant to the Calpine Guarantees when due, or shall otherwise be in default under any of the Calpine Guarantees, or shall fail to perform its obligations under the Fuel Management Contract or the Calpine Performance Agreement;
(xi) PG&E shall fail to perform or observe any of

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its material covenants or obligations in the Power Purchase Agreement, which failure shall not be remedied for a period of 30 days after any applicable cure period under the Power Purchase Agreement; or any material provision of the Power Purchase Agreement shall (i) cease to be valid and binding and in full force and effect, or (ii) be terminated prior to the end of the term thereof; or any material provision of the Power Purchase Agreement shall be declared by a court or other Governmental Authority of competent jurisdiction to be null and void or be terminated; or
(xii) any party (other than the Agent, any Lender, the Issuing Bank or the Borrower) to a Project Contract (other than the Power Purchase Agreement) shall fail to perform or observe any of its material covenants or obligations in any such Project Contract, which failure shall not be remedied for a period of 30 days after any applicable grace or cure period under the Project Contract; or any material provision of any Project Contract shall (i) cease to be valid and binding or in full force and effect or (ii) be terminated prior to the end of the term thereof as specified in such Project Contract; or any material provision of any Project Contract shall be declared by a court or other Governmental Authority of competent jurisdiction to be null and void or be terminated; and any such failure, event or circumstance, in the reasonable opinion of the Agent and the Lenders, materially adversely affects the Borrower's ability to maintain the effective operation of the Project or to make any payments when and as due under this Agreement, the Notes or any of the other Basic Documents to which it is a party, or materially adversely affects the ability of the Agent, the Issuing Bank or the Lenders to receive payments under this Agreement, the Notes or any other Basic Document when and as due, unless, within 30 days following any such failure, event or circumstance the Borrower either enters into an agreement to replace the applicable Project Contract, with a party acceptable to the Lenders and containing substantially the same terms and conditions as such replaced Project Contract or otherwise implements an alternative response to such failure, event or circumstance acceptable to the Lenders; provided, that, with respect to any Project Contract other than the fuel supply agreement, if the Borrower cannot enter into a replacement agreement or implement an alternative response to such failure, event or circumstance within such 30-day period, the time within which the Borrower may enter into a replacement agreement or implement an alternative response shall be extended for an additional period not in excess of 120 days as may be necessary to effect such cure, if (1) the Borrower submits to the Lenders within the 30-day period a cure plan (which plan shall include replacement of the Operator, if the Operator has been grossly negligent in the performance of its material covenants and obligations under the Operations and Maintenance Agreement), and such plan, in the reasonable judgment of the Lenders, is technically and economically feasible within such additional cure

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period, (2) the Borrower demonstrates to the reasonable satisfaction of the Lenders that, upon completion of such cure plan, the Power Purchase Agreement will be in full force and effect and the Borrower will not be in default thereunder, (3) the Borrower is proceeding with diligence and in good faith to cure such failure, event or circumstance; provided, further, that, with respect to a fuel supply agreement, if the Borrower cannot enter into a replacement agreement or a binding letter of intent, in either case reasonably acceptable to the Lenders, within such 30-day period, the time within which the Borrower may enter into a replacement contract or binding letter of intent shall be extended for an additional 60-day period, if (1) the Borrower enters into a 30-day gas supply agreement during the initial 30-day cure period so that fuel deliveries to the Project continue without interruption (except interruptions caused by force majeure events) and (2) the Borrower is proceeding with diligence and in good faith to enter into a replacement agreement or binding letter of intent therefor; or
(xiii) any Material Obligor shall make an assignment for the benefit of creditors or shall generally not be paying its or his debts as such debts become due; or
(xiv) (A) any decree or order for relief in respect of any Material Obligor shall be entered under any bankruptcy, reorganization, compromise, arrangement, insolvency, readjustment of debt, dissolution or liquidation or similar law, whether now or hereafter in effect (herein called the "Bankruptcy Law") of any jurisdiction, (B) any petition or application of the types described in clause (xv) below shall be filed, or any such proceeding shall be commenced, against any Material Obligor and such Material Obligor, by any act, shall indicate its approval, consent thereto or acquiescence therein, or an order, judgment or decree shall be entered appointing any such trustee, receiver, custodian, liquidator or similar official, or approving the petition in any such proceedings, and such order, judgment or decree shall remain unstayed and in effect for more than 60 days, or (C) any order, judgment or decree shall be entered in any proceedings against any Material Obligor decreeing the dissolution of such Material Obligor and such order, judgment or decree shall remain unstayed and in effect for more than 60 days; or
(xv) any Material Obligor shall petition or apply to any tribunal for, or shall consent to, the appointment of, or taking possession by, a trustee, receiver, custodian, liquidator or similar official of such Material Obligor or of any substantial part of the assets of such Material Obligor, or shall commence a voluntary case under the Bankruptcy Law of the United States or any proceedings relating to any Material Obligor under the Bankruptcy Law of any other jurisdiction; or
(xvi) a judgment or judgments in an aggregate

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amount in excess of $250,000 shall be rendered against the Borrower and, within 60 days after entry thereof, such judgment shall not be discharged or execution thereof stayed pending appeal, or within 60 days after the expiration of any such stay, such judgment shall not be discharged; or
(xvii) any Collateral Security Document shall fail to provide, or cease to be effective to grant, to the Agent a perfected Lien on the Collateral intended to be created thereby superior to all other Liens, other than Permitted Liens, or cease to be in full force and effect, or the validity thereof or the applicability thereof to the Obligations or any part thereof shall be questioned or disaffirmed by or on behalf of the Borrower or any other party thereto; or
(xviii) any of the Governmental Approvals, or any other acts contemplated by Section 8.8, required in connection with the Loans, this Agreement, the Letters of Credit or any of the other Basic Documents or the Project, or any of the Governmental Approvals required to be obtained by any Material Obligor in connection with the full performance of any Basic Document to which it is a party, shall be rejected or otherwise denied or shall expire (without being timely renewed) or be revoked, rescinded, suspended, held invalid or otherwise limited in effect, and such rejection, denial, expiration, revocation, rescission, suspension, holding or other limiting action, in the reasonable judgment of the Agent and the Lenders, materially adversely affects the Borrower's ability to maintain the effective operation of the Project or to make any payments when and as due under this Agreement, the Notes, or any of the other Basic Documents to which it is a party, or materially adversely affects the ability of the Agent, the Issuing Bank or the Lenders to receive payments under this Agreement, the Notes, or any other Basic Document when and as due, which event, circumstance or act is not being contested, in accordance with
Section 8.8 by the Borrower within 30 days of the occurrence thereof (without limiting the default set forth in clause xxiv hereof); or
(xix) the passage or promulgation of, or any change in, any statute, ordinance or regulation affecting the Project that materially adversely affects the Borrower's ability to maintain the effective operation of the Project or to make payments as and when due under this Agreement, the Notes or any of the other Basic Documents to which it is a party, or materially adversely affects the ability of the Agent, the Issuing Bank or the Lenders to receive payments under this Agreement, the Notes or any other Basic Document as and when due, which statute, ordinance or regulation, or change therein, is not contested by the Borrower in accordance with Section 8.8 within 30 days of passage or promulgation thereof (without limiting the default set forth in clause xxiv hereof); or
(xx) the Partner shall sell, transfer, convey or

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otherwise dispose of or pledge its partnership interest in the Borrower (other than pursuant to the Assignment of Partnership Interests of Calpine Gilroy 1, Inc. or to any wholly owned, direct or indirect, subsidiary, partnership or limited liability company of Calpine which has entered into an acceptable assignment of partnership interests in favor of the Agent in the form of Exhibit K-1 or Exhibit K-2 hereto, as applicable) except with the prior written approval of the Lenders; or
(xxi) Calpine (or one or more wholly-owned subsidiaries, partnerships or limited liability companies of Calpine) shall cease to own, directly or indirectly, all of the ownership interests in the Partner or at least 51% of the ownership interests in the Borrower without the prior consent of the Required Lenders, or any additional general partner shall be admitted to the Partnership, or any limited partner shall be admitted to the Partnership other than any Permitted Transferee or any other Person which is approved by the Required Lenders; or
(xxii) the Borrower shall cease to have good and marketable title or any real property right necessary to operate and maintain the Project, or the Borrower shall cease to have a good and marketable leasehold interest in the Project Site, or the Borrower shall sell, lease, assign or otherwise transfer any part of the Collateral in violation of the terms of this Agreement; or
(xxiii) there shall have occurred an Abandonment or an Event of Loss; or
(xxiv) the Facility shall have lost its status as a Qualifying Facility, or the Agent, any Lender or the Issuing Bank shall, solely as a result of the transactions contemplated hereby, become subject to regulation as an "electric utility", "electric corporation", "natural gas company", "public service company", "electric utility company" or "holding company" under the Public Utility Holding Company Act of 1935, as amended, the Federal Power Act, as amended, the Natural Gas Act, as amended, the Public Utility Regulatory Policies Act of 1978, as amended, or any comparable state law or regulation; or
(xxv) with respect to any Plan, as to which the Borrower could reasonably be expected to have material liability, (1) there shall exist an Insufficiency with respect to such Plan which could reasonably be expected to have a Material Adverse Effect, (2) steps are or have been taken to terminate a Plan in a distress termination, (3) any Reportable Event (as defined in Section 4043 of ERISA) with respect to a Plan shall occur which could reasonably be expected to have a Material Adverse Effect, (4) a contribution failure occurs with respect to a Plan which is sufficient to give rise to a lien under Section 302(f) of ERISA or Section 412 of the Code or (5) with respect to any Multiemployer Plan (as defined in Section 4001(a)(3) of ERISA)

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the Borrower shall have incurred withdrawal liability to such Plan in an amount which, when aggregated with all other amounts required to be paid to Multiemployer Plans in connection with withdrawal liabilities exceeds in the aggregate $250,000.
(b) Upon an Event of Default specified in clause (xiv) or (xv) of
Section 10.1(a) with respect to the Borrower, the Notes and the Drawings (with accrued interest thereon) and all other amounts owing under this Agreement or any Loan Document (together with interest accrued thereon) shall automatically become immediately due and payable, without presentment, demand, protest or other notice of any kind, all of which are hereby waived by the Borrower, and the Borrower shall deposit with the Issuing Bank cash in the amount of the then-current Stated Amount of the Tranche C Letter of Credit (it being understood that the obligation to make such deposit shall constitute an Obligation for all purposes of the Loan Documents).
(c) Upon an Event of Default specified in any clause of
Section 10.1(a), other than an Event of Default specified in clause (xiv) or
(xv) with respect to the Borrower, the Agent shall, at the request of the Required Lenders, in addition to any right, power or remedy permitted by law or equity, by notice in writing to the Borrower, declare the Notes and the Drawings (with accrued interest thereon) and all other amounts owing under this Agreement or any Collateral Security Document to be, and the Notes, the Drawings and such amounts shall thereupon be and become, immediately due and payable (with accrued interest thereon) without presentment, demand, protest or other notice of any kind, all of which are hereby waived by the Borrower, and the Borrower shall deposit with the Issuing Bank cash in the amount of the then-current Stated Amount of Tranche C Letter of Credit (it being understood that the obligation to make such deposit shall constitute an Obligation for all purposes of the Loan Documents).
Section 10.2 Other Remedies. If any Event of Default shall occur and be continuing the Agent, at the request of the Required Lenders, shall proceed to protect and enforce the rights of the Agent, the Issuing Bank and the Lenders under this Agreement, the Notes, the Drawings, any Collateral Security Document, any Project Contract or any other Basic Document by exercising such rights and remedies as are available to the Agent and/or the Issuing Bank or Lenders in respect thereof under applicable law or otherwise, either by suit in equity or by action of law, or both, whether for specific performance of any covenant or other agreement contained in any such document or in aid of the exercise of any power granted in any such document. No remedy conferred in this Agreement upon the Agent and/or the Lenders is intended to be exclusive of any other remedy, and each and every such remedy shall be cumulative and shall be in addition to every other remedy conferred herein or now or hereafter existing at law or in equity or by statute or

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otherwise.
Section 10.3 Foreclosure Under Certain Circumstances. If an Event of Default shall occur and be continuing, the Lenders (or the Agent on behalf of the Lenders and the Issuing Bank) shall exercise remedies the purpose of which is to effect a transfer of title to or control of the Project, then the Lenders (or the Agent on behalf of the Lenders and the Issuing Bank) (a) shall exercise commercially reasonable efforts to sell the Project to third parties on commercially reasonable terms, or (b) shall, in the event that no third party sale may be effected on commercially reasonable terms, and the Lenders elect to acquire title to the Project (whether directly or indirectly through a trust, agent, nominee or designee, and whether through foreclosure, sale by power of sale or judicial sale, deed in lieu of foreclosure or other remedies effecting a transfer of title to the Project) (such event, a "Disposition"), (i) take title either (A) through a credit bid of the minimum amount of the Loans and other outstanding Obligations necessary to achieve such acquisition of the Project (the sufficiency of the credit bid to be supported by an opinion or advice of counsel to the Lenders (in either case acceptable to the Lenders), and such credit bid to be allocated among the Lenders and the Issuing Bank on the basis of their respective outstanding Obligations or (B) by a voluntary transfer by the Borrower or the partners of the Borrower that does not require a credit bid, and (ii) hold such title, share the benefits and obligations of the Project, and have management voting rights, in each case on the basis of their respective outstanding Obligations.
ARTICLE XIARTICLE XI
THE AGENT AND THE ISSUING BANKTHE AGENT AND THE ISSUING BANK
Section 11.1 Appointment. The Issuing Bank and each Lender hereby designates and appoints BNP as the Agent of such Person under this Agreement and each other Basic Document, and each such Person irrevocably authorizes BNP, as the Agent for such Person, to execute each of the Basic Documents contemplated hereby to be executed by it, to take such action on its behalf under the provisions of this Agreement and each other Basic Document and to exercise such powers and perform such duties as are expressly delegated to the Agent by the terms of this Agreement and each other Basic Document, together with such other powers as are reasonably incidental thereto. Notwithstanding any provision to the contrary elsewhere in this Agreement, the Agent shall not have any duties or responsibilities, except those expressly set forth herein and those necessarily incidental thereto, or any fiduciary relationship with any the Issuing Bank or any Lender and no implied covenants, functions, responsibilities, duties, obligations or liabilities on the part of the Agent shall be read into this Agreement or otherwise exist against the Agent. The provisions of this Article XI are solely

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for the benefit of the Agent and the Issuing Bank and the Lenders. In performing its functions and duties hereunder and under the other Basic Documents, the Agent shall act solely as the agent of the Issuing Bank and the Lenders and does not assume nor shall be deemed to have assumed any obligation or relationship of trust or functions and duties hereunder and under the other Basic Documents, the Agent shall act solely as the agent of the Issuing Bank and the Lenders and does not assume nor shall be deemed to have assumed any obligation or relationship of trust or agency with or for the Borrower or its successors and assigns.
Section 11.2 Delegation of Duties. The Agent may execute any of its duties under this Agreement or the other Basic Documents by or through agents or attorneys-in-fact and shall be entitled to advice of counsel concerning all matters pertaining to such duties. The Agent shall not be responsible for the negligence or misconduct of any agents or attorneys-in-fact selected by it with reasonable care.
Section 11.3 Exculpatory Provisions. The Agent shall not be (i) liable for any action lawfully taken or omitted to be taken by it or any Person described in Section 11.2 under or in connection with this Agreement or any other Basic Document (except for its own gross negligence or willful misconduct), or (ii) responsible in any manner to the Issuing Bank any of the Lenders for any recitals, statements, representations or warranties made by any other Person contained in this Agreement or under any other Basic Document or in any certificate, report, statement or other document referred to or provided for in, or received under or in connection with, this Agreement or any other Basic Document or for the value, validity, effectiveness, genuineness, enforceability or sufficiency of this Agreement, or any other Basic Document (except for the due execution hereof and thereof by the Agent) or for any failure of any other Person to perform its obligations hereunder or thereunder. The Agent shall not be under any obligation to the Issuing Bank or any Lender to ascertain or to inquire as to the observance or performance of any of the agreements contained in, or conditions of, this Agreement or any other Basic Document, or to inspect the properties, books or records of any Person, except if so requested by the Lenders. This Section 11.3 is intended solely to govern the relationship between the Agent, on the one hand, and the Issuing Bank and the Lenders, on the other.
Section 11.4 Reliance by Agent. The Agent shall be entitled to rely, and shall be fully protected in relying, upon any Note, writing, resolution, notice, consent, certificate, affidavit, letter, cablegram, telegram, telecopy, telex or teletype message, statement, order or other document or conversation believed by it to be genuine and correct and to have been signed, sent or made by the proper Person or Persons and upon advice and statements of legal counsel, independent

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accountants and other experts selected by the Agent. The Agent may deem and treat the payee of any Note as the owner thereof for all purposes (including, without limitation, for purposes of making any payment in accordance with this Agreement) unless the Agent shall have received an executed Commitment Transfer Supplement in respect thereof. All payments made by the Agent to the Lenders prior to the receipt of such Commitment Transfer Supplement shall be valid and binding for all purposes of this Agreement and the Notes. The Agent shall be fully justified in failing or refusing to take any action under this Agreement or any other Basic Document unless it shall first receive such advice or concurrence of the Lenders as it deems appropriate or it shall first be indemnified to its satisfaction (subject to the provisions of Section 11.7) by all of the Lenders against liabilities and expenses which may be incurred by it by reason of taking or continuing to take any such action. The Agent shall in all cases be fully protected in acting, or in refraining from acting, under this Agreement, the Letters of Credit and the other Basic Documents in accordance with a request of the Required Lenders and such request and any action taken or failure to act pursuant thereto shall be binding upon all the Lenders and all future holders of the Notes.
Section 11.5 Notice of Default. The Agent shall not be deemed to have knowledge or notice of the occurrence of any Default or Event of Default unless the Agent has received written notice from the Issuing Bank, a Lender or the Borrower referring to this Agreement, describing such Default or Event of Default and stating that such notice is a "notice of default". In the event that the Agent receives such a notice, the Agent shall promptly give notice thereof to the Issuing Bank and the Lenders. The Agent shall take such action with respect to such Default or Event of Default as shall be directed by the Required Lenders; provided that unless and until the Agent shall have received such directions, the Agent may (but shall not be obligated to) take such action, or refrain from taking such action, with respect to such Default or Event of Default as the Agent shall deem advisable and in the best interests of the Issuing Bank and the Lenders.
Section 11.6 Non-Reliance on Agent and Other Lenders. The Issuing Bank and each Lender expressly acknowledges that neither the Agent, nor any of its officers, directors, employees, agents, attorneys-in-fact or Affiliates has made any representations or warranties to it and that no act by the Agent hereafter taken, including, without limitation, any review of the affairs of any Person, shall be deemed to constitute any representation or warranty by the Agent. The Issuing Bank and each Lender represents and warrants to the Agent that it has, independently and without reliance upon the Agent, or any other Lender, and based on such documents and information as it has deemed appropriate, made its own appraisal of and investigation into the business, operations, property, prospects, financial and

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other conditions and creditworthiness of each Person deemed relevant by such Lender and made its own decision to make its Loans hereunder and enter into this Agreement. The Issuing Bank and each Lender also represents that it will, independently and without reliance upon the Agent, or any other Lender, and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit analysis, appraisals and decisions in taking or not taking action under this Agreement, and to make such investigation as it deems necessary to inform itself as to the business, operations, property, prospects, financial and other condition and creditworthiness of each Person deemed relevant by such Lender. Except for notices, reports and other documents expressly required under the Basic Documents or Section 11.10 to be furnished to the Issuing Bank and the Lenders by the Agent, the Agent shall not have any duty or responsibility to provide the Issuing Bank and the Lenders with any credit or other information concerning the business, operations, property, prospects, financial and other condition or creditworthiness of any Person which may come into the possession of the Agent or any of its officers, directors, employees, agents, attorneys-in-fact or affiliates.
Section 11.7 Indemnification. Each of the Lenders hereby agrees to indemnify the Agent (in its capacity as Agent) and its Affiliates and its officers, directors, employees, representatives and agents and the Issuing Bank (in its capacity as Issuing Bank) and its Affiliates and its officers, directors, employees, representatives and agents (in each case to the extent not reimbursed by the Borrower and without limiting the obligation of the Borrower to do so) from and against any and all liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind or nature whatsoever (including, without limitation, the reasonable fees and disbursements of counsel for the Agent or Issuing Bank, as the case may be, or such Person in connection with any investigative, administrative or judicial proceeding commenced or threatened, whether or not the Agent or Issuing Bank, as the case may be, or such Person shall be designated a party thereto) that may at any time (including, without limitation, at any time following the payment in full of the Obligations) be imposed on, incurred by or asserted against the Agent or Issuing Bank, as the case may be, or such Person as a result of, or arising out of, or in any way related to or by reason of, any of the transactions contemplated hereby or the execution, delivery or performance of any Basic Document or related document (but excluding any such liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements resulting solely from the gross negligence or willful misconduct of the Agent or Issuing Bank or any Lender, as the case may be, or such Person as finally determined by a court of competent jurisdiction).
Section 11.8 Agent and Issuing Bank in Individual

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Capacities. Each of the Agent and the Issuing Bank and each of their respective Affiliates may engage in any kind of business with the Borrower and its Affiliates as though the Agent or the Issuing Bank were not the Agent or the Issuing Bank, as the case may be, hereunder. With respect to Loans made or renewed by it and any Note issued to it, the Agent and the Issuing Bank shall have the same rights and powers under this Agreement as any Lender and may exercise the same as though it were not the Agent or the Issuing Bank, as the case may be, and the terms "Lender" and "Lenders" shall include the Agent and the Issuing Bank in their respective individual capacities.
Section 11.9 Successor Agents. Subject to the appointment and acceptance of a successor Agent as provided below, the Agent may resign at any time either under this Agreement or under the Collateral Security Documents by giving written notice thereof to the Lenders, the Issuing Bank and the Borrower, and the Agent may be removed at any time with cause by the Required Lenders. Upon any such resignation or removal, the Required Lenders shall have the right to appoint a successor Agent reasonably acceptable to the Borrower. If no successor Agent shall have been so appointed by the Required Lenders and shall have accepted such appointment within 30 days after the retiring Agent's notice of resignation or the Required Lenders' removal of the retiring Agent, then the retiring Agent may, on behalf of the Issuing Bank and the Lenders, appoint one of the Lenders as successor Agent. Upon the acceptance of any appointment as Agent hereunder by a successor Agent, such successor Agent shall thereupon succeed to and become vested with all the rights, powers, privileges and duties of the retiring Agent, and the retiring Agent shall be discharged from its duties and obligations hereunder. After any retiring Agent's resignation or removal hereunder as Agent, the provisions of this Article XI and Section 12.1 shall continue in effect for such Agent's benefit in respect of any actions taken or omitted by it while it served as Agent hereunder.
Section 11.10 Documents and Notices. The Agent will forward to each Lender and the Issuing Bank after the Agent's receipt thereof a copy of each document furnished to the Agent by the Borrower hereunder to the extent the Borrower is not obligated to deliver such document to the Issuing Bank and each Lender.
Section 11.11 Response to Certain Borrower Requests. The Agent, the Issuing Bank and each Lender will act diligently (and within the time periods (if any) set forth in this Agreement and the other Basic Documents and, to the extent practicable, within the time periods (if any) reasonably requested by the Borrower, in each case taking into account such consultation as the Agent, the Issuing Bank and the Lenders may require with the independent consultants) in the review of documents, the making of determinations or the consideration of requests for consents,

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approvals, waivers or amendments required to be reviewed, made or considered by each of the Agent, the Issuing Bank or the Lenders, as the case may be, as contemplated by and in accordance with the provisions of this Agreement and the other Basic Documents. The Borrower shall provide the Agent with reasonable notice of the expected occurrence of any such requirements and, at the request of the Borrower, the Agent shall promptly so advise the Issuing Bank and the Lenders as requested by the Borrower. The Borrower shall provide such documents and information to the Agent or the Issuing Bank or any Lender (through the Agent) as any of the Agent, the Issuing Bank or the Lenders may reasonably consider necessary, and shall otherwise cooperate with the Agent, the Issuing Bank and the Lenders in order so as to permit the Agent, the Issuing Bank and the Lenders effectively to review such documents, make such determinations or consider such requests for consents, approvals, waivers or amendments.
ARTICLE XII
MISCELLANEOUS
Section 12.1 Expenses; Indemnification, etc.
(a) The Borrower agrees, whether or not the transactions contemplated hereby shall be consummated, to pay, and save the Agent harmless against liability for the payment of, (i) reasonable syndication related expenses (including legal costs but excluding fees paid by the Agent to any Purchasing Lender) of the Agent, (ii) all reasonable filing and recordation fees which may at any time be payable in respect of the Collateral Security Documents, (iii) all reasonable fees and expenses of the Independent Engineer, the Fuel Consultant, the Insurance Consultant, the Environmental Consultant and any other consultants incurred in connection with the Project, or the transactions contemplated hereby or by any other Basic Document, (iv) all reasonable costs and fees and expenses of counsel and of special counsel to the Agent in connection with this Agreement, the Notes, the Collateral Security Documents or any other Basic Document, the transactions contemplated hereby or thereby, (v) the reasonable costs and expenses, including reasonable attorneys' fees, incurred by the Agent, the Issuing Bank or any of the Lenders in connection with the Loan Documents or the transactions contemplated thereby, including without limitation all such costs and expenses incurred in enforcing any rights under this Agreement, the Notes, the Letters of Credit, the Collateral Security Documents or any other Basic Document or in complying with any subpoena or other legal process served upon the Agent, the Issuing Bank or any of the Lenders in connection with this Agreement, the Notes, the Letters of Credit, the Collateral Security Documents or any other Basic Document, or in any bankruptcy case and (vi) the reasonable costs and expenses, including reasonable attorneys' and consultants' fees, the negotiation, preparation, execution or delivery of any amendment,

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modification, supplement, consent or waiver requested by any party relating to this Agreement, the Notes, the Letters of Credit, the Collateral Security Documents, or any other Basic Document or the transactions contemplated hereby or thereby.
(b) The Borrower agrees to pay, and hold the Agent, the Issuing Bank and the Lenders harmless from and against, any and all present and future stamp and other similar taxes with respect to the transactions contemplated by this Agreement, and save the Agent, the Issuing Bank and the Lenders harmless from and against any and all liabilities with respect to or resulting from any delay or omission to pay such taxes. A certificate in reasonable detail as to any amounts payable to the Agent, the Issuing Bank or any of the Lenders under this Section 12.1(b) submitted to the Borrower by the Agent, the Issuing Bank or any of the Lenders in good faith shall be presumed to be correct absent manifest error and shall be binding upon all of the parties to this Agreement and any assignees or transferees.
(c) The Borrower agrees, to the extent permitted by law, to indemnify, pay and hold harmless the Agent, the Issuing Bank and the Lenders (except from its or their gross negligence or willful misconduct) from and against any and all liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses and disbursements of any kind whatsoever (including reasonable attorney's fees) which may be imposed on, incurred by or asserted against the Agent, the Issuing Bank or such Person in any way relating to or arising out of (i) the Project, (ii) this Agreement, the Notes, the Letters of Credit, any of the Collateral Security Documents or the other Basic Documents, (iii) transactions contemplated hereby, (iv) the direct or indirect application or proposed application of the proceeds of any Loan or Drawing, (v) any violation of any law, ordinance, order, rule or regulation, including any such violation in respect of hazardous or toxic wastes or substances, (vi) the past or present disposal, release or threatened release of any Material of Environmental Concern on the Project Site, or (vii) any personal injury (including wrongful death) or property damage arising out of or relating to any Material of Environmental Concern on the Project Site. The Borrower agrees to indemnify the Agent, the Issuing Bank and the Lenders against any claims for brokerage fees or commissions payable to any broker or finder (to the extent not engaged by the Agent, the Issuing Bank or any Lender) in connection with the Loans or the financing contemplated by this Agreement and to pay all expenses (including reasonable attorneys' fees) incurred by any such parties in connection with the defense of any action brought to collect any brokerage fees or commissions by any such Person.
(d) The obligations of the Borrower under this Section 12.1 shall survive any resignation of the Agent, transfer by any Lender of its Notes and payment in full of the

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Obligations.
Section 12.2 Amendments; Consent to Amendments.
(a) None of this Agreement, the Notes, the Letters of Credit or the other Loan Documents may be changed orally, but only by an agreement in writing signed by all of the parties thereto.
(b) Each of this Agreement, the Notes, the Letters of Credit and the Collateral Security Documents may be amended, and the Borrower may take any action herein or therein prohibited, or omit to perform any act herein or therein required to be performed by it, if the Borrower shall obtain the written consent to such amendment, action or omission to act, of the Required Lenders and, with respect to the Letters of Credit, the Issuing Bank, except that no such action shall be taken if the effect thereof is to (i) extend the maturity of any Note or any installment thereof, or reduce the rate or extend the time of payment of interest thereon, or reduce or forgive the principal amount thereof, or reduce any fees payable to the Lenders hereunder or thereunder, without the prior written consent of the Issuing Bank and each Lender, (ii) change the amount of any Lender's Commitment, change the Stated Amount of either of the Letters of Credit or release collateral having a value of $100,000 or more (as estimated by the Agent) purported to be covered by any of the Collateral Security Documents, or amend the provisions of Section 12.2(a) or 12.2(b) or the definition of "Required Lenders" without the prior written consent of the Issuing Bank and each Lender, (iii) change the requirements in any Collateral Security Document or in Section 10.1 respecting the transfer of the partnership interests or ownership interests in the Borrower without the prior written consent of the Issuing Bank and each Lender, (iv) amend or modify the provisions of Section 11.9 without the prior consent of the Agent, the Issuing Bank and each Lender, (v) create or permit additional Indebtedness secured by the Collateral (other than Permitted Indebtedness described in clauses (b), (c) and
(e) of the definition thereof) without the prior consent of the Issuing Bank and each Lender or (vi) affect the rights or obligations of the Agent, without the consent of the Agent. Any such amendment, modification, supplement, cancellation or termination and any such waiver, properly consented to in accordance with the foregoing shall apply equally to each of the Lenders, the Agent and the Issuing Bank (to the extent applicable to such party) and shall be binding upon the Borrower, the Issuing Bank and each of the Lenders and all future holders of the Notes.
Section 12.3 Form, Registration, Transfer and Exchange of Notes; Lost Notes.
(a) The Notes are issuable as registered notes without coupons in the denomination of the aggregate principal amount

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thereof. The Borrower will keep at the principal office of the Borrower a register in which the Borrower will provide for the registration of the Notes and of transfers of the Notes. Upon surrender for registration or transfer of a Note at the principal office of the Borrower, the Borrower will, at its expense, execute and deliver a new Note or Notes of like tenor and of a like aggregate principal amount, registered in the name or names of such transferee or transferees. At the option of the holder of any Note, such Note may be exchanged for other Notes of like tenor and of any authorized denominations, of a like aggregate principal amount, upon surrender of the Note to be exchanged at the principal office of the Borrower. Whenever any Note is so surrendered for exchange, the Borrower will, at its expense, execute and deliver the Note which the holder making the exchange is entitled to receive. Every Note surrendered for registration of transfer or exchange shall be duly endorsed, and be accompanied by a Commitment Transfer Supplement duly executed by the holder of such Note or such holder's attorney duly authorized in writing. Any Note issued in exchange for any Note or upon transfer thereof shall carry the rights to unpaid interest and interest to accrue which were carried by the Note so exchanged or transferred, so that neither gain nor loss of interest shall result from any such transfer or exchange, and shall contain the following legend:
"This Note is issued in replacement of [ ] and, notwithstanding the date of this Note, this Note carries all of the rights to unpaid interest which were carried by such replaced Notes so that neither gain nor loss of interest shall result from any such replacement." Upon the transfer of any Note to a different holder in compliance with this Section 12.3 and Section 12.7 the Lender Schedule will be supplemented to reflect such transfer and such transferee's status as a "Lender" hereunder.
(b) Upon receipt of written notice from the holder of any Note or other evidence reasonably satisfactory to the Borrower of the loss, theft, destruction or mutilation of any Note and, in the case of mutilation upon surrender and cancellation of such Note, the Borrower will make and deliver a new Note, of like tenor, in lieu of the lost, stolen, destroyed or mutilated Note.
(c) Each of the Lenders represents that in making the Loans to the Borrower such Lender will be acquiring the Notes for the purpose of investment and not with the view to or for sale in connection with any distribution thereof within the meaning of the Securities Act of 1933, as amended, provided that the disposition of property of such Lender shall at all times be and remain within its control, it being understood and agreed that each of the Lenders shall have the right in accordance with the terms of this Agreement to syndicate the Commitment to additional financial institutions chosen by such Lender after the execution of this Agreement, provided that such syndication shall be in compliance with the Securities Act of 1933, as amended, and

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applicable state securities laws.
Section 12.4 Notices to Subsequent Holder. If any of the Notes shall have been transferred to another holder pursuant to Sections 12.3 and 12.7 and such holder shall have designated in writing the address to which communications with respect to such Note shall be mailed, all notices, certificates, requests, statements and other documents required or permitted to be delivered to any Lender or holder of a Note by any provision hereof shall also be delivered to each such holder.
Section 12.5 Persons Deemed Owners. Prior to due presentment for registration of transfer, the Borrower may treat the Person in whose name any of the Notes is registered as the owner and holder of such Note for the purpose of receiving payment of principal of and premium, if any, and interest on such Note and for all other purposes whatsoever, whether or not such Note shall be overdue, and the Borrower shall not be affected by notice to the contrary.
Section 12.6 Survival of Representations and Warranties. All representations and warranties contained herein or made in writing by the Borrower in connection herewith shall survive the execution and delivery of this Agreement, the Letters of Credit and the Notes, transfer of by any Lender of its notes and payment in full of the Obligations, regardless of any investigation made by any Lender or on its behalf.
Section 12.7 Successors and Assigns.
(a) This Agreement shall be binding upon and inure to the benefit of the Borrower, the Issuing Bank, the Lenders, the Agent, all future holders of the Notes and their respective successors and assigns, provided, however, that the Borrower may not assign any portion of its rights or obligations hereunder to any Person, except with the prior written consent of the Lenders.
(b) Each Lender may assign and pledge all or any portion of the Obligations owing to it hereunder to any Federal Reserve Bank or the United States Department of Treasury as collateral security pursuant to Regulation A of the Board of Governors of the Federal Reserve System and any Operating Circular issued by such Federal Reserve System, provided that any payment in respect of such assigned Obligations made by the Borrower to the assigning and/or the pledging Lender in accordance with the terms of this Agreement shall satisfy the Borrower's obligations hereunder in respect of such assigned Obligations to the extent of such payment. No such assignment shall release the assigning Lender from its obligations hereunder.
(c) The holder of any Note or any portion of the Commitment may from time to time grant participations in all or

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any part of such Note or portion of the Commitments to any Person on such terms and conditions as may be determined by such holder in its sole and absolute discretion, provided that the grant of such participation shall not relieve any Lender of its obligations hereunder.
(d) Any Lender may at any time sell to one or more financial institutions reasonably acceptable to the Borrower (a "Purchasing Lender"), all or any part of its rights and obligations under this Agreement, the Letters of Credit, the Notes and any Interest Rate Contracts to which such Lender is a party, subject to a minimum purchase requirement of $5 million of the Commitment, upon written notice to the Agent and upon the prior written consent of the Borrower (which consent shall not be unreasonably withheld) pursuant to a Commitment Transfer Supplement, executed by such Purchasing Lender and such transferor Lender. Notwithstanding the foregoing, no Lender shall sell all or any part of its rights and obligations under this Agreement, the Letters of Credit, the Notes or the Interest Rate Contracts in violation of the Securities Act of 1933, as amended, any state securities law, or any other law, rule or regulation. Upon such execution of such Commitment Transfer Supplement, and delivery of an executed copy thereof to the Borrower, subject to compliance with this Section 12.7, the Purchasing Lender shall for all purposes be a Lender party to this Agreement and shall have all the rights and obligations of a Lender under this Agreement, to the same extent as if it were an original party hereto with the Tranche A Pro Rata Share, Tranche B Pro Rata Share, Tranche C Pro Rata Share and/or Tranche D Pro Rata Share as set forth in such Commitment Transfer Supplement, which shall be deemed to amend this Agreement (including, without limitation, the Lender Schedule) to the extent, and only to the extent, necessary to reflect the addition of such Purchasing Lender and the resulting adjustment of the Tranche A Pro Rata Share, Tranche B Pro Rata Share, Tranche C Pro Rata Share and/or Tranche D Pro Rata Share arising from the purchase by such Purchasing Lender of all or a portion of the rights and obligations of the transferor Lender under this Agreement, the Letters of Credit, the Notes and the Interest Rate Contracts. Upon the consummation of any transfer pursuant to this
Section 12.7(d), the transferor Lender or the Agent and the Borrower shall make appropriate arrangements so that, if required, replacement Notes are issued to such transferor Lender and new Notes or, as appropriate, replacement Notes, are issued to such Purchasing Lender, pursuant to the applicable Commitment Transfer Supplement.
(e) The Borrower acknowledges that the holder of any Note may deliver copies of any financial statements and other documents delivered to such holder, and disclose any other information disclosed to such holder, by or on behalf of the Borrower in connection with or pursuant to this Agreement to (i) such holder's directors, officers, employees, agents and

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professional consultants, (ii) any other holder of any Note, (iii) any Person to which such holder offers to sell such Note or any part thereof, (iv) any Person to which such holder sells or offers to sell a participation in all or any part of such Note, (v) any federal or state regulatory authority having jurisdiction over such holder, or (vi) any other Person to which such delivery or disclosure may be necessary or appropriate (a) in compliance with any law, rule, regulation or order applicable to such holder, (b) in response to any subpoena or other legal process, (c) in connection with any litigation to which such holder is a party or (d) in order to protect such holder's investment in such Note (provided, that, in the case of clauses (i) through (iv) or clause (vi) hereof, such Person shall agree to be bound by such confidentiality agreements as shall exist between the Borrower and the Lenders).
Section 12.8 Notices. Except as otherwise expressly provided in this Agreement, all notices, demands, requests and other communications provided for hereunder shall be in writing and shall be deemed to have been given (a) when presented personally, (b) when transmitted by facsimile to the number, if any, specified below, (c) if sent by overnight courier service, on the Business Day following the date of delivery to such courier service, or such later day as demonstrated by a bona fide receipt therefor, or (d) if sent by the United States Postal Service, postage prepaid, registered or certified, return receipt requested, on the date received, addressed to the respective party, as the case may be, at the following address, or such other address as any party may from time to time designate by written notice to the others as herein required. Transmission by facsimile at the numbers provided below shall constitute provision of notice under this Agreement only if receipt thereof is acknowledged by the recipient.
For the Agent:
Banque Nationale de Paris, Los Angeles Branch 725 South Figueroa Street, Suite 2090 Los Angeles, CA 90017
Attn: Project Finance Group
Telephone: (213) 488-9120
Facsimile: (213) 891-0819
with a copy to:
Banque Nationale de Paris, New York Branch 499 Park Avenue
New York, New York 10022
Attn: Syndications Group
Telephone: (212) 750-1400
Facsimile: (212) 415-9805

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For the Issuing Bank:
Banque Nationale de Paris, Los Angeles Branch 725 South Figueroa Street, Suite 2090 Los Angeles, CA 90017
Attn: Project Finance Group
Telephone: (213) 488-9120
Facsimile: (213) 891-0819
For the Lenders:
At the addresses set forth on the
Lender Schedule

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For the Borrower:
Calpine Gilroy Cogen, L.P.
50 West San Fernando Street
San Jose, CA 95113
Attn: Vice President,
Asset Management
Telephone: (408) 995-5115
Facsimile: (408) 995-0505
Section 12.9 Descriptive Headings. The descriptive headings of the several Articles, Sections and paragraphs of this Agreement are inserted for convenience only and do not constitute a part of this Agreement.
Section 12.10 Governing Law. THIS AGREEMENT AND THE NOTES SHALL BE
CONSTRUED AND ENFORCED IN ACCORDANCE WITH, AND THE RIGHTS OF THE PARTIES SHALL BE GOVERNED BY, THE LAWS OF THE STATE OF CALIFORNIA APPLICABLE TO CONTRACTS AND NOTES EXECUTED AND DELIVERED IN CALIFORNIA, BY RESIDENTS THEREOF, AND TO BE PERFORMED ENTIRELY WITHIN SUCH STATE, WITHOUT GIVING EFFECT TO PRINCIPLES THEREOF RELATING TO CONFLICTS OF LAW.
Section 12.11 No Waiver. Failure by the Agent, the Issuing Bank or any of Lender to exercise, or any delay in exercising, any right, remedy, power or privilege it has under this Agreement, or any course of dealing between the Borrower and the Agent, the Issuing Bank or any Lender, shall not operate as a waiver of any such right, remedy, power or privilege. Neither shall any single or partial exercise of any right, remedy, power or privilege hereunder preclude any other or further exercise of the same or of any other right, remedy, power or privilege. The rights, remedies, powers and privileges provided under this Agreement are cumulative and not exclusive of any rights, remedies, powers and privileges provided by law.
Section 12.12 Severable. Any provision of this Agreement which is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions of this Agreement and without affecting the validity or enforceability of such or any other provision in any other jurisdiction.
Section 12.13 Counterparts. This Agreement may be executed simultaneously in counterparts, each of which shall be deemed an original, and it shall not be necessary in making proof of this Agreement to produce or account for more than one such counterpart for each party hereto.
Section 12.14 Waiver of Jury Trial; Consent to Jurisdiction; Limitation of Remedies.

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(a) THE PARTIES HERETO HEREBY KNOWINGLY, VOLUNTARILY, AND INTENTIONALLY WAIVE ANY RIGHTS THEY MAY HAVE TO A TRIAL BY JURY IN ANY LITIGATION OF CLAIM WHICH IS BASED HEREON, OR ARISES OUT OF, UNDER, OR IN CONNECTION WITH, THIS AGREEMENT, THE NOTES, ANY OF THE COLLATERAL SECURITY DOCUMENTS, BASIC DOCUMENTS, OR OTHER DOCUMENTS OR TRANSACTIONS IN CONNECTION WITH OR RELATING HERETO OR THERETO, OR ANY COURSE OF CONDUCT, COURSE OF DEALING, STATEMENTS (WHETHER ORAL OR WRITTEN), OR ACTIONS OF THE AGENT, THE ISSUING BANK, THE LENDERS OR THE BORROWER. THIS PROVISION IS A MATERIAL INDUCEMENT FOR THE AGENT, THE ISSUING BANK AND THE LENDERS TO ENTER INTO THIS AGREEMENT.
(b) ANY LEGAL ACTION OR PROCEEDING WITH RESPECT TO THIS AGREEMENT OR ANY OTHER LOAN INSTRUMENT OR TRANSACTIONS IN CONNECTION WITH OR RELATING HERETO OR THERETO, OR ANY COURSE OF CONDUCT, COURSE OF DEALING, STATEMENTS (WHETHER VERBAL OR WRITTEN), OR ACTIONS OF THE AGENT, THE ISSUING BANK, THE LENDERS OR THE BORROWER MAY BE BROUGHT IN ANY OF THE FEDERAL OR STATE COURTS OF THE STATE OF CALIFORNIA LOCATED IN LOS ANGELES, CALIFORNIA, AND THE BORROWER HEREBY ACCEPTS FOR ITSELF AND IN RESPECT OF ITS PROPERTY, GENERALLY AND UNCONDITIONALLY, THE JURISDICTION OF THE AFORESAID COURTS. THE BORROWER HEREBY IRREVOCABLY WAIVES ANY OBJECTIONS, INCLUDING, WITHOUT LIMITATION, ANY OBJECTION TO THE LAYING OF VENUE OR BASED ON THE GROUNDS OF FORUM NON CONVENIENS, WHICH IT MAY NOW OR HEREAFTER HAVE TO THE BRINGING OF ANY SUCH ACTION OR PROCEEDING IN SUCH RESPECTIVE JURISDICTIONS.
(c) Nothing contained in this Section 12.14 shall preclude the Agent, the Issuing Bank or the Lenders from bringing any legal suit, action or proceeding against the Borrower in the courts of any jurisdiction where the Borrower or any of its property or assets may be found or located. To the extent permitted by the applicable laws of any such jurisdiction, the Borrower hereby irrevocably submits to the jurisdiction of any such court and expressly waives, in respect of any such suit, action or proceeding, the jurisdiction of any court or courts which now or hereafter, by reason of its present or future domiciles, or otherwise, may be available to it.
(d) The Borrower agrees, regardless of cause, not to assert any claim whatsoever against the Agent, the Issuing Bank or any Lender for loss of anticipatory profits or consequential damages.
Section 12.15 No Recourse. No partner of the Borrower, nor any of their respective shareholders and Affiliates (other than the Borrower and, to the extent set forth in the Calpine Guarantees and the Calpine Performance Agreement, Calpine and, to the extent provided in the Assignments of Partnership Interests, the obligors thereunder), and their respective officers, directors, stockholders, partners, controlling persons or employees (each, a "Non-Recourse Party"), shall have any

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personal liability for any amounts payable by the Borrower hereunder or under the Notes, the Letters of Credit or any other Basic Document or for the performance of any covenant, agreement or obligation of the Borrower, or for the breach of any representation, warranty or covenant of the Borrower under this Agreement or in any other Basic Document, undertaking, certificate or any other document delivered by or on behalf of the Borrower in connection with this Agreement, and therefore no judgment or recourse shall be sought or enforced for the payment or performance of the obligations of the Borrower under any Basic Document or any other such agreement, undertaking, certificate or document executed by the Borrower against any Non-Recourse Party in its individual or personal capacity; provided, that the foregoing shall not prevent the Agent from bringing an action against the Partner to the extent necessary for the enforcement of remedies against the Borrower so long as no recourse liability shall be brought or enforced against the Partner except to the extent expressly provided in this Section 12.15. It is expressly understood that all obligations and liabilities of the Borrower under this Agreement, the Notes, the Letters of Credit and the other Basic Documents to which the Borrower is a party and any other related document, agreement or instrument executed by the Borrower, are solely obligations of the Borrower (except to the extent set forth in the Calpine Guarantees, the Calpine Performance Agreement and the Assignments of Partnership Interests), provided, that such limitation of liability shall not apply to a Non-Recourse Party if and to the extent that such Non-Recourse Party commits fraud or misappropriation (but only to the extent of such misappropriation) of earnings, revenues, profits or proceeds from the Borrower or the Project. Further, notwithstanding anything herein to the contrary, nothing herein shall limit, or be construed or deemed to limit, the liability of any Non-Recourse Party for its representations, warranties, covenants, agreements, obligations and liabilities under any Basic Document to which such Non-Recourse Party is a party.
Section 12.16 Confidentiality. Each of the Borrower, the Agent, the Issuing Bank and each Lender agrees, for a period of three years following termination or expiration of this Agreement, to exercise its reasonable efforts to keep each of the Basic Documents and the contents thereof, all operating and financial reports delivered pursuant to this Agreement or any other Loan Document and all other documents marked "confidential" delivered by or on behalf of any such Person, confidential from any Person other than Persons employed or retained by the Borrower or any such Person who are or are expected to become engaged in evaluating, approving, structuring or administering the Basic Documents or the transactions contemplated thereby; provided, however, that nothing herein shall prevent the Agent, the Issuing Bank or any Lender from making any disclosure of information contemplated under Section 12.7(e) or shall prevent the Borrower or the Agent, the Issuing Bank or any Lender or any such Person so employed or retained from disclosing such Basic

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Documents (i) to any other Lender (subject to the non-disclosure standard set forth herein), (ii) to its Affiliates, officers, directors, employees and agents who have a need to review such Basic Documents in accordance with customary borrowing or lending practices, as applicable, (iii) upon the order of any court or administrative agency, (iv) upon the request or demand of any regulatory agency or authority having jurisdiction over such Person, (v) which has been publicly disclosed by a Person other than the Person subject hereto, (vi) to the extent reasonably required in connection with any litigation arbitration, governmental investigation or similar proceeding to which the Borrower, the Agent, the Issuing Bank or any Lender or its Affiliates may be a party , (vii) to the extent reasonably required in connection with the exercise of any right or remedy hereunder, (viii) to any such Person's attorneys, accountants and independent auditors, (ix) to any actual or proposed assignee, participant or transferee of any of the Obligations (subject to the non-disclosure standard set forth herein) or (x) to any Person to which disclosure may be necessary or appropriate in compliance with any law, rule, regulation or order applicable to such Person.
Section 12.17 Prior Understandings. This Agreement supersedes all prior understandings and agreements, whether written or oral, among or between the parties hereto and their Affiliates relating to the transactions provided for herein.
IN WITNESS WHEREOF, the parties have caused this Agreement to be duly executed and delivered by their proper and duly authorized officers as of the day and year first written above.
CALPINE GILROY COGEN, L.P.,
 a Delaware limited partnership
By: Calpine Gilroy 1, Inc.
a Delaware corporation,
its general partner
By: ________________________
Title:

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BANQUE NATIONALE DE PARIS,
LOS ANGELES BRANCH, as Agent
By:__________________________________
Title:
By:__________________________________
Title:
BANQUE NATIONALE DE PARIS,
LOS ANGELES BRANCH, as Issuing Bank
By:__________________________________
Title:
By:__________________________________
Title:
LENDERS:
BANQUE NATIONAL DE PARIS,
LOS ANGELES BRANCH
By:__________________________________
Title:
By:__________________________________
Title:

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Appendix I
Lender Schedule and Applicable Lending Offices

Tranche A Lenders                           Tranche A Pro Rata Share

Banque Nationale de Paris                   100%
Los Angeles Branch
725 South Figueroa Street
Suite 2090
Los Angeles, CA  90017

Tranche B Lenders                           Tranche B Pro Rata Share

Banque Nationale de Paris                   100%
Los Angeles Branch
725 South Figueroa Street
Suite 2090
Los Angeles, CA  90017

Tranche C Lenders                           Tranche C Pro Rata Share

Banque Nationale de Paris                   100%
Los Angeles Branch
725 South Figueroa Street
Suite 2090
Los Angeles, CA  90017

Tranche D Lenders                           Tranche D Pro Rata Share

Banque Nationale de Paris                   100%
Los Angeles Branch
725 South Figueroa Street
Suite 2090
Los Angeles, CA  90017	

                                                                      Page 113

                                 Schedule 1.1(b)
                                Sources and Uses	

                                                                      Page 114	

Schedule 6.4
Filings and Recordings
UCC 1 Financing Statements
CGC
Secretary of State, California
Secretary of State, Delaware
Santa Clara County, California
CG1
Secretary of State, California
Secretary of State, Delaware
CG2
Secretary of State, California
Secretary of State, Delaware
UCC 3 Termination Statements
Gilroy
Secretary of State, California
Santa Clara County, California
Reconveyance of Deed of Trust
Santa Clara County, California
Mortgage Filing
CGC
Deed of Trust
Santa Clara County, California
Collateral Assignment of Option Agreements Santa Clara County, California
Assignment of Leases and Rents
Santa Clara County, California

EXHIBIT 10.3.10
COGENERATION PROJECT AT GILROY FOODS, INC.
GILROY FOODS, INC.,
PACIFIC THERMONETICS, INC.
AND
PACIFIC GAS AND ELECTRIC COMPANY
STANDARD OFFER #4
POWER PURCHASE AGREEMENT
FOR
LONG-TERM ENERGY AND CAPACITY
DECEMBER 1983
S.O. #4
December 5, 1983
1

STANDARD OFFER #4:
LONG-TERM ENERGY AND CAPACITY
POWER PURCHASE AGREEMENT
CONTENTS

Article                                                                                                Page
- -------                                                                                                ----
1        QUALIFYING STATUS                                                                                3

2        COMMITMENT OF PARTIES                                                                            4

3        PURCHASE OF POWER                                                                                5

4        ENERGY PRICE                                                                                     6

5        CAPACITY ELECTION AND CAPACITY PRICE                                                            10

6        LOSS ADJUSTMENT FACTORS                                                                         11

7        CURTAILMENT                                                                                     11

8        RETROACTIVE APPLICATION OF CPUC ORDERS                                                          12

9        NOTICES                                                                                         12

10       DESIGNATED SWITCHING CENTER                                                                     13

11       TERMS AND CONDITIONS                                                                            13

12       TERM OF AGREEMENT                                                                               14

Appendix A:      GENERAL TERMS AND CONDITIONS

Appendix B:      ENERGY PAYMENT OPTIONS

Appendix C:      CURTAILMENT OPTIONS

Appendix D:      AS-DELIVERED CAPACITY

Appendix E:      FIRM CAPACITY

Appendix F:      INTERCONNECTION

Appendix G:      FIRM CAPACITY AVAILABILITY TEST

Appendix H:      SAMPLE BILLING CALCULATIONS	

S.O. #4 December 5, 1983
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LONG-TERM ENERGY AND CAPACITY
POWER PURCHASE AGREEMENT
BETWEEN
GILROY FOODS, INC.,
PACIFIC THERMONETICS, INC.
AND
PACIFIC GAS AND ELECTRIC COMPANY
GILROY ENERGY COMPANY, a California corporation ("Seller"), and PACIFIC GAS AND ELECTRIC COMPANY ("PGandE"), referred to collectively as "Parties" individually as "Party", agree as follows:
ARTICLE 1 QUALIFYING STATUS
Seller warrants that, at the date of first power deliveries from Seller's Facility and during the term of agreement, its Facility shall meet the qualifying facility requirements established as of the effective date of this Agreement by the Federal Energy Regulatory Commission's rules (18 Code of Federal Regulations 292) implementing the Public Utility Regulatory Policies Act of 1978 (16 U.S.C.A. 796, et seq.).
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ARTICLE 2 COMMITMENT OF PARTIES
The prices to be paid Seller for energy and/or capacity delivered pursuant to this Agreement have wholly or partly been fixed at the time of execution. Actual avoided costs at the time of energy and/or capacity deliveries may be substantially above or below the prices fixed in this Agreement. Therefore, the Parties expressly commit to the prices fixed in this Agreement for the applicable period of performance and shall not seek to or have a right to renegotiate such prices for any reason. As part of its consideration for the benefit of fixing part or all of the energy and/or capacity prices under this Agreement, Seller waives any and all rights to judicial or other relief from its obligations and/or prices set forth in Appendices B, D, and E, or modification of any other term or provision for any reasons whatsoever.
This Agreement contains certain provisions which set forth methods of calculating damages to be paid to PGandE in the event Seller fails to fulfill certain performance obligations. The inclusion of such provisions is not intended to create any express or implied right in Seller to terminate this Agreement prior to the expiration of the term of agreement. Termination of this Agreement by Seller prior to its expiration date shall constitute a breach of this Agreement and the damages expressly set forth in this
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Agreement shall not constitute PGandE's sole remedy for such breach.
ARTICLE 3 PURCHASE OF POWER
(a) Seller shall sell and deliver and PGandE shall purchase and accept delivery of capacity and energy at the voltage level of 115 kV.
(b) Seller shall provide capacity and energy from its 130,000 kW Facility located at Gilroy Foods, Inc., Pacheco Pass Highway, Gilroy, California.
(c) The scheduled operation date of the Facility is April 30, 1986. At the end of each calendar quarter Seller shall give written notice to PGandE of any change in the scheduled operation date.
(d) To avoid exceeding the physical limitations of the interconnection facilities, Seller shall limit the Facility's actual rate of delivery into the PGandE system to 130,000 kW.
(e) The primary energy source for the Facility is natural gas.
(f) If Seller does not begin construction of its Facility by July 1, 1985, PGandE may reallocate the existing capacity on PGandE's transmission and/or distribution system
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which would have been used to accommodate Seller's power deliveries to other uses. In the event of such reallocation, Seller shall pay PGandE for the cost of any upgrades or additions to PGandE's system necessary to accommodate the output from the Facility. Such additional facilities shall be installed, owned and maintained in accordance with the applicable PGandE tariff.
ARTICLE 4 ENERGY PRICE
PGandE shall pay Seller for its net energy output(1) under the energy payment option checked below(2):
________ Energy Payment Option 1 - Forecasted Energy Prices
During the fixed price period, Seller shall be paid for energy delivered at prices equal to _____(3)

(1) Insert either "net energy output" or "surplus energy output" to show the energy sale option selected by Seller.
(2) Energy Payment Option 2 is not available to oil or gas-fired cogenerators.
(3) Insert either 0, 20, 40, 60, 80, or 100, at Seller's option. If Seller's Facility is an oil or gas-fired cogeneration facility, either 0 or 20 must be inserted.
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percent of the prices set forth in Table B-1, Appendix B, plus_____(1) percent of PGandE's full short-run avoided operating costs.
For the remaining years of the term of agreement, Seller shall be paid for energy delivered at prices equal to PGandE's full short-run avoided operating costs.
If Seller's Facility is not an oil or gas-fired cogeneration facility, Seller may convert from Energy Payment Option 1 to Energy Payment Option 2 and be subject to the conditions therein, provided that Seller shall not change the percentage of energy prices to be based on PGandE's full short-run avoided operating costs. Such conversion must be made at least 90 days prior to the date of initial energy deliveries and must be made by written notice in accordance with Section A-17, Appendix A.
________ Energy Payment Option 2 - Levelized Energy Prices
During the fixed price period, Seller shall be paid for energy delivered at prices equal to ____ (2)

(1) Insert the difference between 100 and the percentage selected under footnote 3 on page 6.
(2) Insert either 20, 40, 60, 80, or 100, at Seller's option.
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percent of the levelized energy prices set forth in Table B-2, Appendix B for the year in which energy deliveries begin and term of agreement, plus _______(1) percent of PGandE's full short-run avoided operating costs. During the fixed price period, Seller shall be subject to the conditions and terms set forth in Appendix B, Energy Payment Option 2.
For the remaining years of the term of agreement, Seller shall be paid for energy delivered at prices equal to PGandE's full short-run avoided operating costs.
Seller may convert from Energy Payment Option 2 to Energy Payment Option 1, provided that Seller shall not change the percentage of energy prices to be based on PGandE's full short-run avoided operating costs. Such conversion must be made at least 90 days prior to the date of initial energy deliveries and must be made by written notice in accordance with Section A-17, Appendix A.

(1) Insert the difference between 100 and the percentage selected under footnote 2 on page 7.
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X Energy Payment Option 3 - Incremental Energy Rate

Beginning with the date of initial energy deliveries and continuing until December 31, 1998(1), Seller shall be paid monthly for energy delivered at prices equal to PGandE's full short-run avoided operating costs, provided that adjustments shall be made annually to the extent set forth in Appendix B, Energy Payment Option 3.
The incremental energy rate band widths will be specified by Seller, no later than 30 days prior to the actual operation date, in the form of Table I below. The incremental energy rate band widths shall be used in determining the annual adjustment, if any.
Table I

Year                                            Incremental Energy Rate Band Widths
- ----                                            -----------------------------------
                                                (must be multiples of 100 or zero)
1984
                                                -----------------------------------

1985
                                                -----------------------------------

1986
                                                -----------------------------------

1987
                                                -----------------------------------

1988
                                                -----------------------------------

1989
                                                -----------------------------------

1990
                                                -----------------------------------

1991
                                                -----------------------------------

1992
                                                -----------------------------------

1993
                                                -----------------------------------

1994
                                                -----------------------------------

1995
                                                -----------------------------------	

(1) Specified by Seller. Must be December 31, 1998 or prior.
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Table I
 (Continued)

Year                                            Incremental Energy Rate Band Widths
- ----                                            -----------------------------------
                                                (must be multiples of 100 or zero)
1996
                                                -----------------------------------

1997
                                                -----------------------------------

1998
                                                -----------------------------------	

After December 31, 1998, Seller shall be paid for energy delivered at prices equal to PGandE's full short-run avoided operating costs.
ARTICLE 5 CAPACITY ELECTION AND CAPACITY PRICE
Seller may elect to deliver either firm capacity or as-delivered capacity, and Seller's election is indicated below. PGandE's prices for firm capacity and as-delivered capacity are derived from PGandE's full avoided costs as approved by the CPUC.

  X      Firm capacity - 120,000 kW for 30 years from the firm capacity
- ----     availability date with payment determined in accordance with Appendix
         E. Seller elects to have its firm capacity price determined from the
         firm capacity price schedule in effect on the date of execution of
         this Agreement.  PGandE shall pay Seller for capacity delivered in
         excess of firm capacity on an as-delivered capacity basis in
         accordance with As-Delivered Capacity Payment Option 2 set forth in
         Appendix D.	

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OR
________ As-delivered capacity with payment determined in accordance with As-Delivered Capacity Payment Option_____ set forth in Appendix D.
ARTICLE 6 LOSS ADJUSTMENT FACTORS
Capacity Loss Adjustment Factors shall be as shown in Appendix D and Appendix E, dependent upon Seller's capacity election set forth in Article 5 of this Agreement.
Energy Loss Adjustment Factors shall be considered as unity for all energy - payments related to Energy Payment Options 1 and 2 set forth in Appendix B for the entire fixed price period of this Agreement, except for the percentage of payments that seller elected in Article 4 to have calculated based on PGandE's full short-run avoided operating costs. Energy Loss Adjustment Factors for all payments related to PGandE's full short-run avoided operating costs, are subject to CPUC rulings for the entire term of agreement.
ARTICLE 7 CURTAILMENT
Seller has two options regarding possible curtailment by PGandE of Seller's deliveries, and Seller's selection is indicated below:
________ Curtailment option A - Hydro Spill and Negative Avoided Cost
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X Curtailment Option B - Adjusted Price Period

The two options are described in Appendix C.
ARTICLE 8 RETROACTIVE APPLICATION OF CPUC ORDERS
Pursuant to Ordering Paragraph 1(f) of CPUC Decision No. 83-09-054 (September 7, 1983), after the effective date of the CPUC's Application 82-03-26 decision relating to line loss factors, Seller has the option to retain the relevant terms of this Agreement or have the results of that decision incorporated into this Agreement. To retain the terms herein, Seller shall provide written notice to PGandE within 30 days after the effective date of the relevant CPUC decision on Application 82-03-26. Failure to provide such notice will result in the amendment of this Agreement to comply with that decision.
As soon as practicable following the issuance of a decision in Application 82-03-26, PGandE shall notify Seller of the effective date thereof and its results.
ARTICLE 9 NOTICES
All written notices shall be directed as follows:

To PGandE:       Pacific Gas and Electric Company
                 Attention: Vice President
                   Electric Operations
                 77 Beale Street
                 San Francisco CA 94106	

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To Seller:
ARTICLE 10 DESIGNATED SWITCHING CENTER
The designated PGandE switching center shall be, unless changed by PGandE:
Metcalf Substation 150 Metcalf Road Coyote, CA 95137 (408) 227-7182
ARTICLE 11 TERMS AND CONDITIONS
This Agreement includes the following appendices which are attached and incorporated by-reference:
Appendix A -- GENERAL TERMS AND CONDITIONS
Appendix B -- ENERGY PAYMENT OPTIONS
Appendix C -- CURTAILMENT OPTIONS
Appendix D -- AS-DELIVERED CAPACITY
Appendix E -- FIRM CAPACITY
Appendix F -- INTERCONNECTION
Appendix G -- FIRM CAPACITY AVAILABILITY TEST
Appendix H -- SAMPLE BILLING CALCULATIONS
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ARTICLE 12 TERM OF AGREEMENT
This Agreement shall be binding upon execution and remain in effect thereafter for 30 years from the Firm Capacity Availability Date; provided, however, that it shall terminate if energy deliveries do not start within five years of the execution date.
IN WITNESS WHEREOF, the Parties hereto have caused this Agreement to be executed by their duly authorized representatives and it is effective as of the last date set forth below.
PACIFIC THERMONETICS, INC. PACIFIC GAS AND ELECTRIC COMPANY

BY: /s/ JAMES M. SAMIS                  BY:  /s/   NOLAN H. DAINES
  ---------------------------              --------------------------------
       JAMES M. SAMIS                              NOLAN H. DAINES
         President                                  Vice President
                                                Planning and Research	

DATE SIGNED: Dec. 19, 1983 DATE SIGNED: Dec. 19, 1983
GILROY FOODS, INC.

By: /s/ GEORGE CLAUSEN
  ---------------------------
        GEORGE CLAUSEN
          President	

DATE SIGNED: Dec. 19, 1983
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December 5, 1983
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APPENDIX A
GENERAL TERMS AND CONDITIONS
CONTENTS

Section                                                                                            Page
A-1         DEFINITIONS                                                                             A-2

A-2         CONSTRUCTION                                                                            A-7

A-3         OPERATION                                                                               A-10

A-4         PAYMENT                                                                                 A-14

A-5         ADJUSTMENTS OF PAYMENTS                                                                 A-14

A-6         ACCESS TO RECORDS AND PGandE DATA                                                       A-15

A-7         INTERRUPTION OF DELIVERIES                                                              A-15

A-8         FORCE MAJEURE                                                                           A-16

A-9         INDEMNITY                                                                               A-18

A-10        LIABILITY; DEDICATION                                                                   A-18

A-11        SEVERAL OBLIGATIONS                                                                     A-19

A-12        NON-WAIVER                                                                              A-20

A-13        ASSIGNMENT                                                                              A-20

A-14        CAPTIONS                                                                                A-21

A-15        CHOICE OF LAWS                                                                          A-21

A-16        GOVERNMENTAL JURISDICTION AND                                                           A-21
            AUTHORIZATION

A-17        NOTICES                                                                                 A-22

A-18        INSURANCE                                                                               A-22	

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APPENDIX A
GENERAL TERMS AND CONDITIONS
A-1 DEFINITIONS
Whenever used in this Agreement, appendices, and attachments hereto, the following terms shall have the following meanings:
Adjusted firm capacity price - The $/kW-year purchase price for firm capacity from Table E-2, Appendix E for the period of Seller's actual performance.
As-delivered capacity Capacity delivered to PGandE in excess of firm capacity or in lieu of a firm capacity commitment.
CPUC - The Public Utilities Commission of the State of California.
Current firm capacity price - The $/kW-year capacity price from PGandE's firm capacity price schedule effective at the time PGandE derates the firm capacity pursuant to Section E-4(b), Appendix E or Seller terminates performance under this Agreement, for a term equal to the period from
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the date of deration or termination to the end of the term of agreement.
Designated PGandE switching center - That switching center or other PGandE installation identified in Article 10.
Facility - That generation apparatus described in Article 3 and all associated equipment owned, maintained, and operated by Seller.
Firm capacity - That capacity, if any, identified as firm in Article 5 except as otherwise changed as provided herein.
Firm capacity availability date - The day following the day during which all features and equipment of the Facility are demonstrated to PGandE's satisfaction to be capable of operating simultaneously to deliver firm capacity into PGandE's system as provided in this Agreement. The test required to demonstrate such capability is described in Appendix G.
Firm capacity price - The price for firm capacity applicable for the firm capacity availability date and the number of years of firm capacity delivery from either the firm capacity price schedule, Table E-2, Appendix E, or the
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successor to Table E-2 in effect on the firm capacity availability date. Seller has indicated its choice of firm capacity price schedule in Article 5.
Firm capacity price schedule - The periodically published schedule, of the $/kW-year prices that PGandE offers to pay for firm capacity. See Table E-2, Appendix E.
Fixed price period - The period during which forecasted or levelized energy prices, and/or forecasted as-delivered capacity prices, are in effect; defined as the first five years of the term of agreement if the term of agreement is 15 or 16 years; the first six years of the term of agreement if the term of agreement is 17, 18, or 19 years; or the first ten years of the term of agreement if the term of agreement is anywhere from 20 through 30 years.
Forced outage - Any outage resulting from a design defect, inadequate construction, operator error or a breakdown of the mechanical or electrical equipment that fully or partially curtails the electrical output of the Facility.
Full short-run avoided operating costs - CPUC-approved costs which are the basis of PGandE's published energy prices. PGandE's current energy price calculation is shown in Table B-5, Appendix B. PGandE's
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published off-peak hours' prices shall be adjusted, as appropriate, if Seller has selected Curtailment Option B.
Interconnection facilities - All means required and apparatus installed to interconnect and make deliveries of power, under the Agreement, from the Facility to the PGandE system including, but not limited to, connection, transformation, switching, metering, communications, and safety equipment, such as equipment required to protect (1) the PGandE system and its customers from faults occurring at the Facility, and (2) the Facility from faults occurring on the PGandE system or an the systems of others to which the PGandE system is directly or indirectly connected. Interconnection facilities also include any necessary additions and reinforcements by PGandE to the PGandE system required as a result of the interconnection of the Facility to the PGandE system.
Net energy output - The Facility's gross output in kilowatt-hours less station use and transformation and transmission losses to the point of delivery into the PGandE system. Where PGandE agrees that it is impractical to connect the station use on the generator side of the power purchase meter, PGandE may, at its option, apply a station load adjustment.
Prudent electrical practices - Those practices, methods, and equipment, as changed from time to time, that
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are commonly used in prudent electrical engineering and operations to design and operate electric equipment lawfully and with safety, dependability, efficiency, and economy.
Scheduled operation date - The day specified in Article 3(c) when the Facility is, by Seller's estimate, expected to produce energy that will be available for delivery to PGandE.
Special facilities - Those additions and reinforcements to the PGandE system which are needed to accommodate the maximum delivery of energy and capacity from the Facility as provided in this Agreement and those parts of the interconnection facilities which are owned and maintained by PGandE at Seller's request, including metering and data processing equipment. All special facilities shall be owned, operated, and maintained pursuant to PGandE's electric Rule No. 21, which is attached hereto.
Station use - Energy used to operate the Facility's auxiliary equipment. The auxiliary equipment includes, but is not limited to, forced and induced draft fans, cooling towers, boiler feed pumps, lubricating oil systems, plant lighting, fuel handling systems, control systems, and sump pumps.
Surplus energy output - The Facility's gross output, in kilowatt-hours, less station use, and any other use by
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Seller, and transformation and transmission losses to the point of delivery into the PGandE system.
Term of agreement - The number of years this Agreement will remain in effect as provided in Article 12.
Voltage level - The voltage at which the Facility interconnects with the PGandE system, measured at the point of delivery.

A-2    CONSTRUCTION

A-2.1  Land Rights

         Seller hereby grants to PGandE all necessary rights of way and	

easements, including adequate and continuing access rights on property of Seller, to install, operate, maintain, replace, and remove the special facilities. Seller agrees to execute such other grants, deeds, or documents as PGandE may require to enable it to record such rights of way and easements. If any part of PGandE's equipment is to be installed on property owned by other than Seller, Seller shall, at its own cost and expense, obtain from the owners thereof all necessary rights of way and easements, in a form satisfactory to PGandE, for the construction, operation, maintenance, and replacement of PGandE's equipment upon such property. If Seller is unable
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to obtain such rights of way and easements, Seller shall reimburse PGandE for all costs incurred by PGandE in obtaining them. PGandE shall at all times have the right of ingress to and egress from the Facility at all reasonable hours for any purposes reasonably connected with this Agreement or the exercise of any and all rights secured to PGandE by law or its tariff schedules.
A-2.2 Design, Construction, Ownership, and Maintenance
(a) Seller shall design, construct, install, own, operate, and maintain all interconnection facilities, except special facilities, to the point of interconnection with the PGandE system as required for PGandE to receive capacity and energy from the Facility. The Facility and interconnection facilities shall meet all requirements of applicable codes and all standards of prudent electrical practices and shall be maintained in a safe and prudent manner. A description of the interconnection facilities for which Seller is solely responsible is set forth in Appendix F, or if the interconnection requirements have not yet been determined at the time of the execution of this Agreement, the description of such facilities will be appended to this Agreement at the time such determination is made.
(b) Seller shall submit to PGandE all specifications for the interconnection facilities (except special facilities) and, at PGandE's option, the Facility, for
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review and written acceptance prior to their release for construction purposes. PGandE's review and acceptance of these specifications shall not be construed as confirming or endorsing the design or as warranting their safety, durability, or reliability. PGandE shall not, by reason of such review or lack of review, be responsible for strength, details of design, adequacy, or capacity of equipment built pursuant to such specifications, nor shall PGandE's acceptance, be deemed to be an endorsement of any of such equipment. Seller shall change the interconnection facilities as may be reasonably required by PGandE to meet changing requirements of the PGandE system.
(c) In the event it is necessary for PGandE to install interconnection facilities for the purposes of this Agreement, they shall be installed as special facilities.
(d) Upon the request of Seller, PGandE shall provide a binding estimate for the installation of interconnection facilities by PGandE.
A-2.3 Meter Installation
(a) PGandE shall specify, provide, install, own, operate, and maintain as special facilities all metering and data processing equipment for the registration and recording of energy and other related parameters which are required
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for the reporting of data to PGandE and for computing the payment due Seller from PGandE.
(b) Seller shall provide, construct, install, own, and maintain at Seller's expense all that is required to accommodate the metering and data processing equipment, such as, but not limited to, metal-clad switchgear, switchboards, cubicles, metering panels, enclosures, conduits, rack structures, and equipment mounting pads.
A-3 OPERATION
A-3.1 Inspection and Approval
Seller shall not operate the Facility in parallel with PGandE's system until an authorized PGandE representative has inspected the interconnection facilities, and PGandE has given written approval to begin parallel operation. Seller shall notify PGandE of the Facility's start-up date at least 45 days prior to such date. PGandE shall inspect the interconnection facilities within 30 days of the receipt of such notice. If parallel operation is not authorized by PGandE, PGandE shall notify Seller in writing within five days after inspection of the reason authorization for parallel operation was withheld
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A-3.2 Facility Operation and Maintenance
Seller shall operate and maintain its Facility according to prudent electrical practices, applicable laws, orders, rules, and tariffs and shall provide such reactive power support as may be reasonably required by PGandE to maintain system voltage level and power factor. Seller shall operate the Facility at the power factors or voltage levels prescribed by PGandE's system dispatcher or designated representative. If Seller fails to provide reactive power support, PGandE may do so at Seller's expense.
A-3.3 Point of Delivery
Seller shall deliver the energy at the point where Seller's electrical conductors (or those of Seller's agent) contact PGandE's system as it shall exist whenever the deliveries are being made or at such other point or points as the Parties may agree in writing. The initial point of delivery of Seller's power to the PGandE system is set forth in Appendix F.
A-3.4 operating communications
(a) Seller shall maintain operating communications with the designated PGandE switching center. The operating communications shall include, but not be limited to, system paralleling or separation, scheduled and unscheduled
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shutdowns, equipment clearances, levels of operating voltage or power factors and daily capacity and generation reports.
(b) Seller shall keep a daily operations log for each generating unit which shall include information on unit availability, maintenance outages, circuit breaker trip operations requiring a manual reset, and any significant events related to the operation of the Facility.
(c) If Seller makes deliveries greater than one megawatt, Seller shall measure and register on a graphic recording device power in kW and voltage in kV at a location within the Facility agreed to by both Parties.
(d) If Seller makes deliveries greater than one and up to and including ten megawatts, Seller shall report to the designated PGandE switching center, twice a day at agreed upon times for the current day's operation, the hourly readings in kW of capacity delivered and the energy in kWh delivered since the last report.
(e) If Seller makes deliveries of greater than ten megawatts, Seller shall telemeter the delivered capacity and energy information, including real power in kW, reactive power in kVAR, and energy in kWh to a switching center selected by PGandE. PGandE may also require Seller to telemeter transmission kW, kVAR, and kV data depending on the number of generators and transmission configuration.
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Seller shall provide and maintain the data circuits required for telemetering. When telemetering is inoperative, Seller shall report daily the capacity delivered each hour and the energy delivered each day to the designated PGandE switching center.
A-3.5 Meter Testing and Inspection
(a) All meters used to provide data for the computation of the payments due Seller from PGandE shall be sealed, and the seals shall be broken only by PGandE when the meters are to be inspected, tested, or adjusted.
(b) PGandE shall inspect and test all meters upon their installation and annually thereafter. At Seller's request and expense, PGandE shall inspect or test a meter more frequently. PGandE shall give reasonable notice to Seller of the time when any inspection or test shall take place, and Seller may have representatives present at the test or inspection. If a meter is found to be inaccurate or defective, PGandE shall adjust, repair, or replace it at its expense in order to provide accurate metering.
A-3.6 Adjustments to Meter Measurements
If a meter fails to register, or if the measurement made by a meter during a test varies by more than two percent from the measurement made by the standard meter used
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in the test, an adjustment shall be made correcting all measurements made by the inaccurate meter for -- (1) the actual period during which inaccurate measurements were made, if the period can be determined, or if not, (2) the period immediately preceding the test of the meter equal to one-half the time from the date of the last previous test of the meter, provided that the period covered by the correction shall not exceed six months.
A-4. PAYMENT
PGandE shall mail to Seller not later than 30 days after the end of each monthly billing period (1) a statement showing the energy and capacity delivered to PGandE during on-peak, partial-peak, and off-peak periods during the monthly billing period, (2) PGandE's computation of the amount due Seller, and (3) PGandE's check in payment of said amount. Except as provided in
Section A-5, if within 30 days of receipt of the statement Seller does not make a report in writing to PGandE of an error, Seller shall be deemed to have waived any error in PGandE's statement, computation, and payment, and they shall be considered correct and complete.
A-5. ADJUSTMENTS OF PAYMENTS
(a) In the event adjustments to payments are required as a result of inaccurate meters, PGandE shall use
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the corrected measurements described in Section A-3.6 to recompute the amount due from PGandE to Seller for the capacity and energy delivered under this Agreement during the period of inaccuracy.
(b) The additional payment to Seller or refund to PGandE shall be made within 30 days of notification of the owing Party of the amount due.
A-6 ACCESS TO RECORDS AND PGandE DATA
Each Party, after giving reasonable written notice to the other Party, shall have the right of access to all metering and related records including operations logs of the Facility. Data filed by PGandE with the CPUC pursuant to CPUC orders governing the purchase of power from qualifying facilities shall be provided to Seller upon request; provided that Seller shall reimburse PGandE for the costs it incurs to respond to such request.
A-7 INTERRUPTION OF DELIVERIES
PGandE shall not be obligated to accept or pay for and may require Seller to interrupt or reduce deliveries of energy when necessary in order to construct, install, maintain, repair, replace, remove, investigate, or inspect any of its equipment or any part of its system, or (2) if it determines that interruption or reduction is necessary
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because of PGandE system emergencies, forced outages, force majeure, or compliance with prudent electrical practices; provided that PGandE shall not interrupt deliveries pursuant to this section in order to take advantage, or make purchases, of less expensive energy elsewhere. Whenever possible, PGandE shall give Seller reasonable notice of the possibility that interruption or reduction of deliveries may be required.
A-8 FORCE MAJEURE
(a) The term force majeure as used herein means unforeseeable causes, other than forced outages, beyond the reasonable control of and without the fault or negligence of the Party claiming force majeure including, but not limited to, acts of God, labor disputes, sudden actions of the elements, actions by federal, state, and municipal agencies, and actions of legislative, judicial, or regulatory agencies which conflict with the terms of this Agreement.
(b) If either Party because of force majeure is rendered wholly or partly unable to perform its obligations under this Agreement, that Party shall be excused from whatever performance is affected by the force majeure to the extent so affected provided that:
(1) the non-performing Party, within two weeks after the occurrence of the force majeure, gives the
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other Party written notice describing the particulars of the occurrence,
(2) the suspension of performance is of no greater scope and of no longer duration than is required by the force majeure,
(3) the non-performing Party uses its best efforts to remedy its inability to perform (this subsection shall not require the settlement of any strike, walkout, lockout or other labor dispute on terms which, in the sole judgment of the Party involved in the dispute, are contrary to its interest. It is understood and agreed that the settlement of strikes, walkouts, lockouts or other labor disputes shall be at the sole discretion of the Party having the difficulty),
(4) when the non-performing Party is able to resume performance of its obligations under this Agreement, that Party shall give the other Party written notice to that effect, and
(5) capacity payments during such periods of force majeure on Seller's part shall be governed by Section E-2(c), Appendix E.
(c) In the event a Party is unable to perform due to legislative, judicial, or regulatory agency action, this Agreement shall be
[renegotiated to
S.O. #4 December 5, 1983
A-17

comply] with the legal change which caused the non-performance.
A-9 INDEMNITY
Each Party as indemnitor shall save harmless and indemnify the other Party and the directors, officers, and employees of such other Party against and from any and all loss and liability for injuries to persons including employees of either Party, and property damages including property of either Party resulting from or arising out of (1) the engineering, design, construction, maintenance, or operation of, or (2) the making of replacements, additions, or betterments to, the indemnitor's facilities. This indemnity and save harmless provision shall apply notwithstanding the active or passive negligence of the indemnitee. Neither Party shall be indemnified hereunder for its liability or loss resulting from its sole negligence or willful misconduct. The indemnitor shall, on the other Party's request, defend any suit asserting a claim covered by this indemnity and shall pay all costs, including reasonable attorney fees, that may be incurred by the other Party in enforcing this indemnity.
A-10 LIABILITY; DEDICATION
(a) Nothing in this Agreement shall create any duty to, any standard of care with reference to, or any liability
S.O. #4 December 5, 1983
A-18

to any person not a Party to it. Neither Party shall be liable to the other Party for consequential damages.
(b) Each Party shall be responsible for protecting its facilities from possible damage by reason of electrical disturbances or faults caused by the operation, faulty operation, or nonoperation of the other Party's facilities, and such other Party shall not be liable for any such damages so caused.
(c) No undertaking by one Party to the other under any provision of this Agreement shall constitute the dedication of that Party's system or any portion thereof to the other Party or to the public or affect the status of PGandE as an independent public utility corporation or Seller as an independent individual or entity and not a public utility.
A-11 SEVERAL OBLIGATIONS
Except where specifically stated in this Agreement to be otherwise, the duties, obligations, and liabilities of the Parties are intended to be several and not joint or collective. Nothing contained in this Agreement shall ever be construed to create an association, trust, partnership, or joint venture or impose a trust or partnership duty, obligation, or liability on or with regard to either Party.
S.O. #4 December 5, 1983
A-19

Each Party shall be liable individually and severally for its own obligations under this Agreement.
A-12 NON-WAIVER
Failure to enforce any right or obligation by either Party with respect to any matter arising in connection with this Agreement shall not constitute a waiver as to that matter or any other matter.
A-13 ASSIGNMENT
(a) PGandE acknowledges that Seller is executing this Agreement expecting to assign its interest and obligations hereunder to a different partnership to be formed between corporate affiliates of Pacific Thermonetics, Inc. and Gilroy Foods, Inc., to construct, own and operate the Facility and that this Agreement, including all rights and duties of Seller thereunder, is to be assigned to that partnership. It is further acknowledged that to finance the Facility an assignment of the rights of Seller under this Agreement may be necessary as security for the long term debt obligations of the partnership. PGandE hereby consents to both such assignments, subject to its receiving a prior notice of any such proposed assignment.
(b) Except as set forth in paragraph (a) above, neither Party shall voluntarily assign its rights nor
S.O. #4 December 5, 1983
A-20

delegate its duties under this Agreement, or any part of such rights or duties, without the written consent of the other Party, except in connection with the sale or merger of a substantial portion of its properties. Any such assignment or delegation made without such written consent shall be null and void. Consent for assignment shall not be withheld unreasonably. Such assignment shall include, unless otherwise specified therein, all of Seller's rights to any refunds which might become due under this Agreement.
A-14 CAPTIONS
All indexes, titles, subject headings, section titles, and similar items are provided for the purpose of reference and convenience and are not intended to affect the meaning of the contents or scope of this Agreement.
A-15 CHOICE OF LAWS
This Agreement shall be interpreted in accordance with the laws of the State of California, excluding any choice of law rules which may direct the application of the laws of another jurisdiction.
A-16 GOVERNMENTAL JURISDICTION AND AUTHORIZATION
Seller shall obtain any governmental authorization and permits required for the construction and operation of
S.O. #4 December 5, 1983
A-21

the Facility. Seller shall reimburse PGandE for any and all losses, damages claims, penalties, or liability it incurs as a result of Seller's failure to obtain or maintain such authorizations and permits.
A-17 NOTICES
Any notice, demand, or request required or permitted to be given by either Party to the other, and any instrument required or permitted to be tendered or delivered by either Party to the other, shall be in writing (except as provided in Section E-3) and so given, tendered, or delivered, as the case may be, by depositing the same in any United States Post Office with postage prepaid for transmission by certified mail, return receipt requested, addressed to the Party, or personally delivered to the Party, at the address in Article 9 of this Agreement. Changes in such designation may be made by notice similarly given.

A-18     INSURANCE

A-18.1   Comprehensive General Liability Coverage

         (a) Seller shall maintain during the performance hereof,	

Comprehensive General Liability Insurance(1) of not less than $1,000,000 if the Facility is over 100 kW,

(1) Governmental agencies which have an established record of self-insurance may provide the required coverage through self-insurance.
S.O. #4 December 5, 1983
A-22

$500,000 if the Facility is over 20 kW to 100 kW, and $100,000 if the Facility is 20 kW or below of combined single limit or equivalent for bodily injury, personal injury, and property damage as the result of any one occurrence.
(b) Comprehensive General Liability Insurance shall include coverage for Premises-Operations, Owners and Contractors Protective, Products/Completed Operations Hazard, Explosion, Collapse, Underground, Contractual Liability, and Broad Form Property Damage including Completed operations.
(c) Such insurance, by endorsement to the policy(ies), shall include PGandE as an additional insured if the Facility it over 100 kW insofar as work performed by Seller for PGandE is concerned, shall contain a severability of interest clause, shall provide that PGandE shall not by reason of its inclusion as an additional insured incur liability to the insurance carrier for payment of premium for such insurance, and shall provide for 30-days' written notice to PGandE prior to cancellation, termination, alteration, or material change of such insurance.
A-18.2 Additional Insurance Provisions
(a) Evidence of coverage described above in Section A-18.1 shall state that coverage provided is primary and is
S.O. #4 December 5, 1983
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not excess to or contributing with any insurance or self-insurance maintained by PGandE.
(b) PGandE shall have the right to inspect or obtain a copy of the original policy(ies) of insurance.
(c) Seller shall furnish the required certificates(1) and endorsements to PGandE prior to commencing operation.
(d) All insurance certificates(1), endorsements, cancellations, terminations, alterations, and material changes of such insurance shall be issued and submitted to the following:
PACIFIC GAS AND ELECTRIC COMPANY
Attention: Manager - Insurance Department 77 Beale Street, Room E280
San Francisco, CA 94106

(1) A governmental agency qualifying to maintain self-insurance should provide a statement of self-insurance.
S.O. #4 December 5, 1983
A-24

APPENDIX B
ENERGY PAYMENT OPTIONS
Energy Payment Option 1 - Forecasted Energy Prices
Pursuant to Article 4, the energy payment calculation for Seller's energy deliveries during each year of the fixed price period shall include the appropriate prices for such year in Table B-1, multiplied by the percentage Seller has specified in Article 4. If Seller has selected Curtailment Option B in Article 7, the forecasted off-peak hours' energy prices listed in Table B-1 shall be adjusted upward by 7.7% for Period A and 9.6% for Period B.
S.O. #4 December 5, 1983
B-1

TABLE B-1

                        Forecasted Energy Price Schedule

                            Forecasted Energy Prices*, cent(s)/KWh
             ---------------------------------------------------------------------
  Year of                Period A                           Period B                 Weighted
  Energy     ---------------------------------   ---------------------------------    Annual
Deliveries   On-Peak   Partial-Peak   Off-Peak   On-Peak   Partial-Peak   Off-Peak   Average
- ----------   -------   ------------   --------   -------   ------------   --------   --------
  1983         5.36        5.12         4.94       5.44       5.31          5.19       5.18
  1984         5.66        5.40         5.22       5.74       5.61          5.48       5.47
  1985         5.75        5.48         5.30       5.83       5.69          5.56       5.55
  1986         5.99        5.72         5.52       6.08       5.94          5.80       5.79
  2987         6.38        6.08         5.88       6.47       6.32          6.17       6.16
  1988         6.94        6.62         6.39       7.03       6.87          6.71       6.70
  1989         7.60        7.25         7.00       7.70       7.53          7.35       7.34
  1990         8.12        7.74         7.48       8.23       8.04          7.85       7.84
  1991         8.64        8.24         7.96       8.75       8.56          8.35       8.34
  1992         9.33        8.90         8.60       9.46       9.24          9.02       9.01
  1993        10.10        9.63         9.30      10.23      10.00          9.76       9.75
  1994        10.91       10.41        10.06      11.06      10.81         10.55      10.54
  1995        11.79       11.25        10.87      11.96      11.68         11.40      11.39
  1996        12.67       12.09        11.68      12.85      12.56         12.25      12.24
  1997        13.61       12.98        12.54      13.79      13.48         13.15      13.14	

* These prices are differentiated by the time periods as defined in Table B-4.
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B-2

Energy Payment Option 2 - Levelized Energy Prices
Pursuant to Article 4, the energy payment calculation for Seller's energy deliveries during the fixed price period shall include the appropriate prices set forth in Table B-2 for the year in which energy deliveries begin and term of agreement, multiplied by the percentage Seller has specified in Article
4. If Seller has selected Curtailment Option B in Article 7, the levelized off-peak hours' energy prices listed in Table B-2 shall be adjusted upward by 7.7% for Period A and 9.6% for Period B. The discount specified in (c)(vi) below, if applicable, will be applied to the energy payments during the fixed price period.
During the fixed price period, Seller shall be subject to the following conditions and terms:
(a) Minimum Damages
The Parties agree that the levelized energy prices which PGandE pays Seller for the energy which Seller delivers to PGandE is based on the agreed value to PGandE of Seller's energy deliveries during the entire fixed price period. In the event PGandE does not receive such full performance by reason of a termination, Seller shall pay PGandE an amount based on the difference between the net present values, at the
S.O. #4 December 5, 1983
B-3

time of termination, of the payments Seller would receive at the forecasted energy prices in Table B-1 and the payments Seller would receive at the levelized energy prices, for the remaining years of the fixed price period. This amount shall be calculated by assuming that Seller continued to generate for the remaining years of the fixed price period at a level equal to the average annual energy generation during the period of performance, and by applying the weighted annual average levelized price applicable to Seller's Facility and the weighted annual average forecasted energy prices in Table B-1 for the remaining years of the fixed price period. The following formula shall be used to make this calculation:

Y       (F(n)) (A) (W)      Y        (L) (A) (W)
Sigma                     -   Sigma
        --------------               -----------	

P= n=1 (1.15)(n) n=1 (1.15)(n)
where:

P =      amount due PGandE.

Y =      number of years remaining in the fixed price period.

F(n) =   weighted annual average forecasted energy price in the
         n(th) year after the breach, failure to perform, or
         expiration of security, as shown in Table B-1 for the
         corresponding calendar year.	

S.O. #4 December 5, 1983
B-4

L = weighted annual average levelized energy price applicable to Seller's Facility.
A = average annual energy generation by Seller during the period of performance.
n = summation index; refers to the n(th) year following termination.
W = percent of Seller's energy payments based on the levelized energy prices, as specified in Article 4.
(b) Performance Requirements
Seller shall operate and maintain the Facility in accordance with prudent electrical practices in order to maximize the likelihood that the Facility's output as delivered to PGandE during the part of the fixed price period when the levelized price is below the forecasted price ("last part") shall equal or exceed 70% of the Facility's output during the part of the fixed price period when the levelized price is above the forecasted price ("first part"). In the event that the Facility's output during any year or series of years in the last part of the fixed price period is less than 70% of the average annual production during the first part of the fixed price period, PGandE may, at its discretion (taking into consideration events occurring during such year or series of years such as curtailment by PGandE, Seller's choice not to operate
S.O. #4 December 5, 1983
B-5

during adjusted price periods, or scheduled maintenance including major overhauls, and the probability that Seller's future performance will be adequate), either request payment from Seller or immediately draw on the security posted, up to the amount equal to
P x A-B

A
where:
P and A are as defined in Section (a) above.
B = Seller's average annual energy generation during the year or series of years in which the 70% performance requirement was not met.
PGandE shall not request payment from Seller or draw on the security posted if the Facility's output during the last part of the fixed price period falls below 70% of the average annual energy generation during the first part of the fixed price period solely because of force majeure as defined in Section A-8, Appendix A or a lack of or limited availability of the primary energy resource of the Facility, if such energy resource is wind, water, or sunlight.
(c) Security
(1) As security for amounts which Seller may be obligated to pay PGandE pursuant to Sections (a) and (b) above, Seller shall provide and maintain one or more of the following in an amount as
S.O. #4 December 5, 1983
B-6

described in Section (c)(2) below.
(i) An irrevocable bank letter of credit delivered to and in favor of PGandE with terms acceptable to PGandE.
(ii) A payment bond providing for payment to PGandE in the event of any failure to meet the performance requirements set forth in Section (b) above or breach of this Agreement by Seller. Such bond shall be issued by a surety company acceptable to PGandE and shall have terms acceptable to PGandE.
(iii) Fully paid up, noncancellable Project Failure Insurance made payable to PGandE with terms of such policy(ies) acceptable to PGandE.
(iv) A performance bond providing for payment to PGandE in the event of any failure to meet the performance requirements set forth in Section (b) above or breach of this Agreement by Seller. Such bond shall be issued by a surety company acceptable to PGandE and shall have terms acceptable to PGandE.
(v) A corporate guarantee of payment to PGandE which PGandE deems, in its sole discretion,
S.O. #4 December 5, 1983
B-7

                 to provide at least the same quality of security as
                 subsections (i) through (iv) above.

        (vi)     Other forms of security which PGandE does not deem to
                 be equivalent security to those listed in subsections
                 (i) through (v) above, and which PGandE, in its sole
                 discretion, deems adequate.  Such other forms of
                 security may include, for example, a corporate
                 guarantee or a lien, mortgage or deed of trust on the
                 Facility or land upon which it is located.  A 1.5%
                 discount will be applied against the levelized energy
                 price portion of PGandE's payments to Seller during
                 the fixed price period if this type of security is
                 provided.

(2)     (i)      Commencing 90 days prior to the scheduled operation
                 date and continuing until December 1 of the following
                 calendar year, security as described in Section
                 (c)(1) above shall be in place in an amount
                 calculated in accordance with the formula set forth
                 in Section (a) above, assuming Seller delivered
                 energy through the end of the following calendar year
                 and then terminated this Agreement.  For purposes of
                 determining the	

S.O. #4 December 5, 1983
B-8

required amount of security, it shall be assumed that Seller's deliveries through the end of the following calendar year would equal R x C x H, where:
R = nameplate rating, in kW, of the Facility.
C = estimated capacity factor of the Facility, which shall be established by mutual agreement of the Parties at the time of execution of this Agreement.
H = number of hours from the scheduled operation date through the end of the following calendar year.
(ii) In the second calendar year of operation and each year thereafter until the end of the fixed price period, from December 1 through December 1 of the following year, security shall be in place in an amount calculated by the formula set forth in Section
(a) above assuming Seller continued to deliver energy in each month through the end of the following calendar year, at a level equal to the average monthly energy deliveries to date, and then terminated this Agreement.
S.O. #4 December 5, 1983
B-9

(3) Security must be maintained throughout the fixed price period as specified above. Any security with a fixed expiration date must be renewed by Seller prior to that date. If such security is not renewed at least 30 days prior to its expiration, PGandE may, at its discretion, either request payment from Seller or immediately draw on the security posted, up to the amount calculated in accordance with the formula set forth in Section (a) above.
(4) If, at any time during the fixed price period, PGandE believes Seller is in material breach of this Agreement, PGandE shall so notify Seller in writing and Seller must remedy such breach within a reasonable period of time. If Seller does not so remedy, PGandE may, at its discretion, either request payment from Seller or immediately draw upon the security posted, up to the amount calculated in accordance with the formula set forth in Section (a) above, provided that if during Seller's period to remedy, Seller disputes PGandE's conclusion that Seller is in material breach, and PGandE elects to draw upon the security, the amount drawn upon by PGandE shall be deposited in an interest earning escrow account and held in such account until the dispute is resolved in accordance with
Section (c)(5) below.
S.O. #4 December 5, 1983
B-10

(5) Upon the written request of either Party, any controversy or dispute between the Parties concerning Section (c)(4) above shall be subject to arbitration in accordance with the provisions of the California Arbitration Act, Sections 1280-1294.2 of the California Code of Civil Procedure except as provided otherwise in this section. Either Party may demand arbitration by first giving written notice of the existence of a dispute and then within 30 days of such notice giving a second written notice of the demand for arbitration.
Within ten days after receipt of the demand for arbitration, each Party shall appoint one person, who shall not be an employee of either Party, to bear and determine the dispute. After both arbitrators have been appointed, they shall within five (5) days select a third arbitrator.
The arbitration hearing shall take place in San Francisco, California, within 30 days of the appointment of the arbitrators, at such time and place as they select. The arbitrators shall give written notice of the time of the hearing to both Parties at least ten days prior to the hearing. The arbitrators shall not be authorized to alter, extend, or modify the terms of this Agreement. At
S.O. #4 December 5, 1983
B-11

the hearing, each Party shall submit a proposed written decision, and any relevant evidence may be presented. The decision of the arbitrators must consist of selection of one of the two proposed decisions, in its entirety.
The decision of any two arbitrators shall be binding and conclusive as to disputes relating to Section (c)(4) only. Upon determining the matter, the arbitrators shall promptly execute and acknowledge their decision and deliver a copy to each Party. A judgment confirming the award may be rendered by any superior court having jurisdiction. Each Party shall bear its own arbitration costs and expenses, including the cost of the arbitrator it selected, and the costs and expenses of the third arbitrator shall be divided equally between both Parties, except as provided otherwise elsewhere in this Agreement.
Pending resolution of any controversy or dispute hereunder, performance by each Party shall continue so as to maintain the status quo prior to notice of such controversy or dispute. Resolution of the controversy or dispute shall include payment of any interest accrued in the escrow account.
S.O. #4 December 5, 1983
B-12

TABLE B-2
Levelized Energy Price Schedule
For a term of agreement of 15-16 years:

   Year                         Levelized Energy Prices*, (c)/kWh
in Which      ---------------------------------------------------------------------
 Energy                   Period A                            Period B                Weighted
Deliveries    ---------------------------------   ---------------------------------    Annual
   Begin      On-Peak   Partial-Peak   Off-Peak   On-Peak   Partial-Peak   Off-Peak   Average
- ----------    -------   ------------   --------   -------   ------------   --------   --------
  1983         5.76        5.50          5.31       5.85       5.71          5.58       5.57
  1984         6.06        5.78          5.58       6.14       6.00          5.86       5.85
  1985         6.41        6.11          5.91       6.50       6.35          6.20       6.19

  1986         6.85        6.54          6.32       6.95       6.79          6.63       6.62
  1987         7.37        7.03          6.79       7.47       7.30          7.13       7.12
  1988         7.96        7.60          7.34       8.07       7.89          7.70       7.69	

For a term of agreement of 17-19 years:

   Year                         Levelized Energy Prices*, (c)/kWh
in Which      ---------------------------------------------------------------------
 Energy                   Period A                            Period B                Weighted
Deliveries    ---------------------------------   ---------------------------------    Annual
   Begin      On-Peak   Partial-Peak   Off-Peak   On-Peak   Partial-Peak   Off-Peak   Average
- ----------    -------   ------------   --------   -------   ------------   --------   --------
  1983         5.90        5.63          5.44       5.98       5.84          5.71       5.70
  1984         6.23        5.95          5.74       6.32       6.18          6.03       6.02
  1985         6.60        6.30          6.08       6.69       6.53          6.38       6.37

  1986         7.06        6.73          6.51       7.16       7.00          6.83       6.82
  1987         7.60        7.25          7.00       7.70       7.53          7.35       7.34
  1988         8.21        7.83          7.57       8.32       8.13          7.94       7.93	

For a term of agreement of 20-30 years:

   Year                         Levelized Energy Prices*, (c)/kWh
in Which      ---------------------------------------------------------------------
 Energy                   Period A                            Period B                Weighted
Deliveries    ---------------------------------   ---------------------------------    Annual
   Begin      On-Peak   Partial-Peak   Off-Peak   On-Peak   Partial-Peak   Off-Peak   Average
- ----------    -------   ------------   --------   -------   ------------   --------   --------
  1983         6.49        6.20          5.98       6.58       6.43          6.28       6.27
  1984         6.90        6.58          6.35       6.99       6.83          6.67       6.66
  1985         7.34        7.00          6.76       7.44       7.27          7.10       7.09

  1986         7.88        7.51          7.26       7.99       7.81          7.62       7.61
  1987         8.49        8.10          7.82       8.61       8.41          8.21       8.20
  1988         9.16        8.74          8.44       9.29       9.08          8.86       8.85	

* These prices are differentiated by the time periods as defined in Table B-4.
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Energy Payment Option 3 - Incremental Energy Rate
During the period specified in Article 4, annual adjustments to Seller's energy payments shall be made as described below.
Within 30 days following the end of each calendar year, the Derived Incremental Energy Rate (with units expressed in Btu/kWh) will be calculated as follows:
Derived Incremental Energy Rate (DIER) = B

                                          A x C
where:

        A  =     the total kWh delivered by Seller during the calendar
                 year, excluding any kWh delivered when Seller was
                 asked to curtail deliveries under Curtailment Option
                 A or when Seller was asked to take adjusted prices
                 under Curtailment Option B.

        B =      the total dollars paid for the energy described for A
                 above.

        C =      the weighted average price paid during the calendar
                 year by PGandE's Electric Department for oil and
                 natural gas for PGandE's fossil steam plants,
                 expressed in $/Btu on a gas Btu basis.	

S.O. #4 December 5, 1983
B-14

If the DIER is between the upper and lower Incremental Energy Rate Bounds specified for that year in Table B-3 for the curtailment option selected by Seller, no additional payment is due either Party.
If the DIER is below the lower Incremental Energy Rate Bound, PGandE shall pay Seller an amount calculated as follows:

P(S) =  (Lower Incremental - (DIER)(A)(C)
        Energy Rate Bound

where:

P(S) =  additional payment due Seller.
DIER =  Derived Incremental Energy Rate.	

PGandE shall add this payment to the first payment made to Seller following the calculation.
If the DIER is above the upper Incremental Energy Rate Bound, Seller shall pay PGandE an amount calculated as follows:
P(B) = (DIER - Upper Incremental )(A)(C) Energy Rate Bound
where:

P(B) =   amount due PGandE.
DIER =   Derived Incremental Energy Rate.

                                          S.O. #4
                                          December 5, 1983
                     B-15	

This amount shall be deducted from the first payment made to Seller following the calculation. If there is any remaining amount due PGandE, PGandE may, at its option, invoice Seller with such payment due within 30 days or deduct this amount from future payments due Seller.
S.O. #4 December 5, 1983
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TABLE B-3
Forecasted Incremental Energy Rates and
Incremental Energy Rate Bounds
Curtailment Option A:

                                        Incremental
                Forcasted                 Energy              Upper Incremental         Lower Incremental
               Incremental               Rate Band                  Energy                   Energy
                 Energy                 Width from               Rate Bound,               Rate Bound
                 Rates,                 Article 4,                 Btu/kWh                   Btu/kWh
                 Btu/kWh                  Btu/kWh                [column (a)               [column (a)
Year               (a)                      (b)                plus column (b)]         minus column(b)]
- ----           -----------             --------------          ----------------         ----------------
1984             9,000
                                       --------------          ----------------          ---------------
1985             9,050
                                       --------------          ----------------          ---------------

1986             8,840
                                       --------------          ----------------          ---------------
1987             8,850
                                       --------------          ----------------          ---------------
1988             8,960
                                       --------------          ----------------          ---------------

1989             8,820
                                       --------------          ----------------          ---------------
1990             8,540
                                       --------------          ----------------          ---------------
1991             8,540
                                       --------------          ----------------          ---------------

1992             8,540
                                       --------------          ----------------          ---------------
1993             8,540
                                       --------------          ----------------          ---------------
1994             8,540
                                       --------------          ----------------          ---------------

1995             8,540
                                       --------------          ----------------          ---------------
1996             8,540
                                       --------------          ----------------          ---------------
1997             8,S40
                                       --------------          ----------------          ---------------

1998             8,540
                                       --------------          ----------------          ---------------	

S.O. #4 December 5, 1983
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TABLE B-3 (continued)
Curtailment option B:

                                        Incremental
                Forcasted                 Energy              Upper Incremental         Lower Incremental
               Incremental               Rate Band                  Energy                   Energy
                 Energy                 Width from               Rate Bound,               Rate Bound
                 Rates,                 Article 4,                 Btu/kWh                   Btu/kWh
                 Btu/kWh                  Btu/kWh                [column (a)               [column (a)
Year               (a)                      (b)                plus column (b)]         minus column(b)]
- ----           -----------             --------------          ----------------         ----------------
1984             9,440
                                       --------------          ----------------          ---------------
1985             9,500
                                       --------------          ----------------          ---------------

1986             9,280
                                       --------------          ----------------          ---------------
1987             9,290
                                       --------------          ----------------          ---------------
1988             9,400
                                       --------------          ----------------          ---------------

1989             9,270
                                       --------------          ----------------          ---------------
1990             8,970
                                       --------------          ----------------          ---------------
1991             8,970
                                       --------------          ----------------          ---------------

1992             8,970
                                       --------------          ----------------          ---------------
1993             8,970
                                       --------------          ----------------          ---------------
1994             8,970
                                       --------------          ----------------          ---------------

1995             8,970
                                       --------------          ----------------          ---------------
1996             8,970
                                       --------------          ----------------          ---------------
1997             8,970
                                       --------------          ----------------          ---------------

1998             8,970
                                       --------------          ----------------          ---------------	

S.O. #4 December 5, 1983
B-18

TABLE B-4(1) Time Periods

                                 Monday                           Sundays
                                 through                            and
                                Friday(2)       Saturdays(2)      Holidays
                                ---------       ------------      --------
Seasonal Period A
(May 1 through September 30)

    On-Peak                     12:30 p.m.
                                    to
                                 6:30 p.m.

    Partial-Peak                 8:30 a.m.       8:30 a.m.
                                    to              to
                                12:30 p.m.      10:30 p.m.
                                 6:30 p.m.
                                    to
                                10:30 p.m.

    Off-Peak                    10:30 p.m.      10:30 p.m.        All Day
                                    to              to
                                 8:30 a.m.       8:30 a.m.

Seasonal Period B
(October 1 through April 30)

    On-Peak                      4:30 p.m.
                                    to
                                 8:30 p.m.

    Partial-Peak                 8:30 p.m.       8:30 a.m.
                                    to              to
                                10:30 p.m.      10:30 p.m.
                                 8:30 a.m.
                                    to
                                 4:30 p.m.

    Off-Peak                    10:30 p.m.      10:30 p.m.        All Day
                                    to              to
                                 8:30 a.m.       8:30 a.m.	

1 This table is subject to change to accord with the on-peak, partial-peak, and off-peak periods as defined in PGandE's own rate schedules for the sale of electricity to its large industrial customers.
2 Except the following holidays: New Year's Day, Washington's Birthday, Memorial Day, Independence Day, Labor Day, Veteran's Day, Thanksgiving, and Christmas, as said days are specified in Public Law 90-363 (5 U.S.C.A.
Section 6103(a)).
S.O. #4 December 5, 1983
B-19

TABLE B-5
Energy Prices Effective November 1 - December 31, 1983
The energy purchase price calculations which will apply to energy deliveries determined from meter readings taken during November and December 1983 are as follows:

                        Incremental                             Energy Purchase
  Time Period           Heat Rate(1)      Cost of Energy(2)         Price(3)(4)
- ----------------        ------------      -----------------     ---------------
                     (a)                (b)                     (c) = (a) x (b)

Nov. 1 - Dec. 31
  (Period B)
- ----------------
Time of
Delivery Basis:

  On-Peak               11,605 Btu/kWh    $5.3986/10(6) Btu     $0.06265/kWh
  Partial-Peak          11,341             5.3986                0.06123
  Off-Peak              11,067             5.3986                0.05975

Seasonal
Average (Period B)      11,231             5.3986                0.06063	

(1) Incremental heat rates are derived from marginal energy costs (including variable operating and maintenance expense) adopted by CPUC Decision No. 93887. They are adjusted to reflect the use of natural gas as the incremental fuel and are based upon average hydro conditions.
(2) Cost of natural gas under PGandE Gas Schedule No. G-55 applicable to steam electric plants effective October 5, 1983 per Advice No. 1237-G.
(3) Energy Purchase Price = Incremental Heat Rate x Cost of Energy.
(4) This figure excludes the applicable energy line loss adjustment factors. However, as ordered by Ordering Paragraph No. 12(j) of Decision No. 82-12-120, this figure is currently 1.0 for transmission and primary distribution loss adjustments and is equal to marginal cost line loss adjustment factors for the secondary distribution voltage level. These factors may be changed by the CPUC in the future. The currently applicable energy loss adjustment factors are shown in Table B-6.
B-20 S.O. #4 December 5, 1983

TABLE B-6
Energy Loss Adjustment Factors(1)

                                                                        Primary              Secondary
                                              Transmission            Distribution          Distribution
Seasonal Period A
(May IL through September 30)

     On-Peak                                       1.0                     1.0                 1.0201
     Partial-Peak                                  1.0                     1.0                 1.0179
     Off-Peak                                      1.0                     1.0                 1.0134

Seasonal Period B
(October 1 through April 30)

     On-Peak                                       1.0                     1.0                 1.0172
     Partial-Peak                                  1.0                     1.0                 1.0160
     Off-Peak                                      1.0                     1.0                 1.0126	

(1) The applicable energy loss adjustment factors may be revised pursuant to orders of the CPUC.
S.O. #4 December 5, 1983
B-21

APPENDIX C
CURTAILMENT OPTIONS
Seller has two options regarding curtailment of energy deliveries and Seller has made its selection in Article 7. The two options are as follows:
CURTAILMENT OPTION A - HYDRO SPILL AND
NEGATIVE AVOIDED COST
(a) In anticipation of a period of hydro spill conditions, as defined by the CPUC, PGandE may notify Seller that any purchases of energy from Seller during such period shall be at hydro savings prices quoted by PGandE. If Seller delivers energy to PGandE during any such period, Seller shall be paid hydro savings prices for those deliveries in lieu of prices which would otherwise be applicable. The hydro savings prices shall be calculated by PGandE using the following formula:

                          AQF - S                (>0)
                          -------  x PP           =
                          AQF

where:

         AQF =   Energy, in kWh, projected to be available during hydro spill
                 conditions from all qualifying facilities under agreements
                 containing hydro savings price provisions.	

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C-1

S = Potential energy, in kWh, from PGandE hydro facilities which will be spilled if all AQF is delivered to PGandE.
PP = Prices published by PGandE for purchases during other than hydro spill conditions.
PGandE shall give Seller notice of general periods when hydro spill conditions are anticipated, and shall give Seller as much advance notice as practical of any specific hydro spill period and the hydro savings price which will be applicable during such period.
(b) PGandE shall not be obligated to accept or pay for and may require Seller with a Facility with a nameplate rating of one megawatt or greater to interrupt or reduce deliveries of energy during periods when PGandE would incur negative avoided costs (as defined by the CPUC) due to continued acceptance of energy deliveries under this Agreement. Whenever possible, PGandE shall give Seller reasonable notice of the possibility that interruption or reduction of deliveries may be required.
(c) Before interrupting or reducing deliveries under subsection
(b), above, and before invoking hydro savings prices under subsection (a), above, PGandE shall take reasonable steps to make economy sales of the surplus energy giving rise to the condition. If such economy sales are made, while the surplus energy condition exists Seller shall
S.O. #4 December 5, 1983
C-2

be paid at the economy sales price obtained by PGandE in lieu of the otherwise applicable prices.
(d) If Seller is selling net energy output to PGandE and simultaneously purchasing its electrical needs from PGandE and Seller elects not to sell energy to PGandE at the hydro savings price pursuant to subsection
(a) or when PGandE curtails deliveries of energy pursuant to subsection (b), Seller shall not use such energy to meet its electrical needs but shall continue to purchase all its electrical needs from PGandE. If Seller is selling surplus energy output to PGandE, subsections (a) or (b) shall only apply to the surplus energy output being delivered to PGandE, and Seller can continue to internally use that generation it has retained for its own use.
CURTAILMENT OPTION B - ADJUSTED PRICE PERIOD
(a) In each calendar year, the price which PGandE is obligated to pay Seller for energy deliveries during 1,000 off-peak hours (as defined in Table B-4, Appendix B) may be adjusted to a price equal to, but not in excess of, PGandE's available alternative source. This adjusted price shall be effective under any of the following conditions:
(i) when PGandE's energy source at the margin is not a PGandE oil- or gas-fueled plant, and PGandE
S.O. #4 December 5, 1983
C-3

can replace Seller's energy with energy from this source at a cost less than the price paid to Seller;
(ii) when PGandE would incur negative avoided costs (as defined by the CPUC) due to continued acceptance of energy deliveries under this Agreement; or
(iii) when PGandE is experiencing minimum system operations.
During any of the conditions described above the adjusted price may be zero.
(b) Whenever possible, PGandE shall give Seller reasonable notice of any price adjustment for energy deliveries and its probable duration.
(c) If Seller is selling net energy output to PGandE and simultaneously purchasing its electrical needs from PGandE and Seller elects not to sell energy to PGandE at the adjusted price, Seller shall not use such energy to meet its electrical needs but shall continue to purchase all its electrical needs from PGandE.
(d) After Seller receives notice of the probable duration of the period during which the adjusted price will be paid, Seller may elect to perform maintenance during such
S.O. #4 December 5, 1983
C-4

period and so inform the PGandE employee in charge at the designated PGandE switching center prior to the time when the adjusted price period is expected to begin. If Seller makes such election, the number of off-peak hours of probable duration quoted in PGandE's notice to Seller shall be applied to the 1,000 hour calendar year limitation set forth in this section. After an election to do maintenance, if Seller makes any deliveries of energy during the quoted probable duration period, Seller shall be paid the adjusted price quoted in its notice from PGandE without regard to any subsequent changes on the PGandE system which may alter the adjusted price or shorten the actual duration of the condition.
(e) Where practicable, consistent with the operating requirements of its system and the circumstances which create periods in which the adjusted price will be paid, PGandE agrees to exercise reasonable efforts to limit imposition of adjusted price periods on seller primarily to periods when Seller's steam sales load requirements are low.
S.O. #4 December 5, 1983
C-5

APPENDIX D
AS-DELIVERED CAPACITY
D-1 AS-DELIVERED CAPACITY PAYMENT OPTIONS
Seller has two options for as-delivered capacity payments and Seller has made its selection in Article S. The two options are as follows:
AS-DELIVERED CAPACITY PAYMENT OPTION 1
PGandE shall pay Seller for as-delivered capacity at prices authorized from time to time by the CPUC. The as-delivered capacity prices in effect on the date of execution are calculated as shown in Exhibit D-1, with a shortage cost of $70 per kilowatt-year.
AS-DELIVERED CAPACITY PAYMENT OPTION 2
During the fixed price period, the as-delivered capacity prices will be calculated in accordance with Exhibit D-1 and the forecasted shortage costs in Table D-2.
For the remaining years of the term of agreement, PGandE shall pay Seller for as-delivered capacity at the
S.O. #4 December 5, 1983
D-1

higher of:
(i) prices authorized from time to time by the CPUC;
(ii) the as-delivered capacity prices that were paid Seller in the last year of the fixed price period; or
(iii) the as-delivered capacity prices in effect in the first year following the end of the fixed price period, provided that the annualized shortage cost from which these prices are derived does not exceed the annualized value of a gas turbine.
D-2 AS-DELIVERED CAPACITY IN EXCESS OF FIRM CAPACITY
The amount of capacity delivered in excess of firm capacity will be considered as-delivered capacity. This as-delivered capacity is based on the total kilowatt-hours delivered each month during all on-peak, partial-peak and off-peak hours excluding any energy associated with generation levels equal to or less than the firm capacity.
Seller has the two options listed in Section D-1 for payment for such as-delivered capacity. Seller has made its selection in Article 5.
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D-2

EXHIBIT D-1
The as-delivered capacity price (in cents per kW-hr) for power delivered by the Facility is the product of three factors:
(a) The shortage cost in each year the Facility is operating.
(b) A capacity loss adjustment factor which provides for the effect of the deliveries on PGandE's transmission and distribution losses based on the Seller's interconnection voltage level. The applicable capacity loss adjustment factors for non-remote(1) Facilities are presented in Table D-l(a). The Facility is non-remote.
(c) An allocation factor which accounts for the different values of as-delivered capacity in different time periods and converts dollars per kW-year to cents per kWh. The current allocation factors are presented in Table D-l(b). The time periods to which they apply are shown in Table B-4, Appendix B. The allocation factors are subject to change from time to time.

(1) As defined by the CPUC.
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D-3

TABLE D-1(a)
Capacity Loss Adjustment Factors
for Non-Remote(1) Facilities

Voltage Level                                                               Loss Adjustment Factor
-------------                                                               ----------------------
Transmission                                                                         .989
Primary Distribution                                                                 .991
Secondary Distribution                                                               .991	

TABLE D-l(b)
Allocation Factors
for As-Delivered Capacity(3)

                                                        Peak                 Partial Peak            Off-Peak
                                                  (cent(s)-yr/$-hr)        (cent(s)-yr/$-hr)     (cent(s)-yr/$-hr)
                                                  -----------------        -----------------      ----------------
Seasonal Period A                                       .09982                   .01635                .00000

Seasonal Period B                                       .02023                   .00306                .00001	

(1) As defined by the CPUC. The capacity loss adjustment factors for remote Facilities are determined individually.
(2) Determined individually.
(3) The units for the allocation factor, cent(s)-yr/$-hr, are derived from the conversion of $/kW-yr into cent(s)/kWh as follows:

cent(s)/kWh         =         cent(s)/kw-hr     =      cent(s)-yr
-----------                   -------------            ----------
$/kW-yr                       $/kW-yr                  $-hr	

The allocation factors are subject to change from time to time.
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D-4

TABLE D-2
Forecasted Shortage Cost Schedule

                                                    Forecast Shortage
Year                                                  Cost, $/kW-Yr
- ----                                                -----------------
1983                                                       70
1984                                                       76
1985                                                       81

1986                                                       88
1987                                                       95
1988                                                      102

1989                                                      110
1990                                                      118
1991                                                      126

1992                                                      135
1993                                                      144
1994                                                      154

1995                                                      164
1996                                                      176
1997                                                      188	

S.O. #4 December 5, 1983
D-5

APPENDIX E
FIRM CAPACITY
CONTENTS

Section                                                                      Page
- -------                                                                      ----
E-1     GENERAL                                                              E-2
E-2     MINIMUM PERFORMANCE REQUIREMENTS                                     E-2
E-3     SCHEDULED MAINTENANCE                                                E-4
E-4     ADJUSTMENTS TO FIRM CAPACITY                                         E-5
E-5     FIRM CAPACITY PAYMENTS                                               E-6
E-6     MINIMUM DAMAGES                                                      E-13	

S.O. #4 December 5, 1983
E-1

APPENDIX E
FIRM CAPACITY
E-1 GENERAL
This Appendix E establishes conditions and prices under which PGandE shall pay for firm capacity.
PGandE's obligation to pay for firm capacity shall begin on the firm capacity availability date. The firm capacity price shall be subject to adjustment as provided for in this Appendix E.
The firm capacity prices in Table E-2 are applicable for deliveries of firm capacity beginning after December 30, 1982.
E-2 MINIMUM PERFORMANCE REQUIREMENTS
(a) To receive full capacity payments, the firm capacity shall be delivered for all of the on-peak hours(1) in the peak months on the PGandE system, which are presently the months of June, July, and August, subject to a 20 percent allowance for forced outages in any month. Compliance with this provision shall be based on the Facility's total on-peak deliveries for each of the peak

(1) On-peak, partial-peak, and off-peak hours are defined in Table B-4, Appendix B.
S.O. #4 December 5, 1983
E-2

months and shall exclude any energy associated with generation levels greater than the firm capacity.
(b) If Seller is prevented from meeting the minimum performance requirements because of a forced outage on the PGandE system, a PGandE curtailment of Seller's deliveries, or a condition set forth in Section A-7, Appendix A, PGandE shall continue capacity payments. Firm capacity payments will be calculated in the same manner used for scheduled maintenance outages.
(c) If Seller is prevented from meeting the minimum performance requirements because of force majeure, PGandE shall continue capacity payments for ninety days from the occurrence of the force majeure. Thereafter, Seller shall be deemed to have failed to have met the minimum performance requirements. Firm capacity payments will be calculated in the same manner used for scheduled maintenance outages.
(d) If Seller is prevented from meeting the minimum performance requirements because of exteme dry year conditions, PGandE shall continue capacity payments. Extreme dry year conditions are drier than those used to establish firm capacity pursuant to Section E-8. Seller shall warrant to PGandE that the Facility is a hydroelectric facility and that such conditions are the sole cause of Seller's inability to meet its firm capacity obligations.
S.O. #4 December 5, 1983
E-3

(e) If Seller is prevented from meeting the minimum performance requirements for reasons other than those described above in Sections E-2(b),
(c), or (d):
(1) Seller shall receive the reduced firm capacity payments as provided in Section E-5 for a probationary period not to exceed 15 months, or as otherwise agreed to by the Parties.
(2) If, at the end of the probationary period Seller has not demonstrated that the Facility can meet the minimum performance requirements, PGandE may derate the firm capacity pursuant to Section E-4(b).
E-3 SCHEDULED MAINTENANCE
Outage periods for scheduled maintenance shall not exceed 840 hours (35 days) in any 12-month period. This allowance may be used in increments of an hour or longer on a consecutive or nonconsecutive basis. Seller may accumulate unused maintenance hours from one 12-month period to another up to a maximum of 1,080 hours (45 days). This accrued time must be used consecutively and only for major overhauls. Seller shall provide PGandE with the following advance notices: 24 hours for scheduled outages less than one day, one week for a scheduled outage of one day or more (except for major overhauls), and six months for a major overhaul. Seller shall not schedule major overhauls during the peak months (presently June, July and August). Seller shall make reasonable efforts to schedule or reschedule
S.O. #4 December 5, 1983
E-4

routine maintenance outside the peak months, and in no event shall outages for scheduled maintenance exceed 30 peak hours during the peak months. Seller shall confirm in writing to PGandE pursuant to Article 9, within 24 hours of the original notice, all notices Seller gives personally or by telephone for scheduled maintenance.
If Seller has selected Curtailment Option B, off-peak hours of maintenance performed pursuant to Section (d) of Curtailment Option B, Appendix C shall not be deducted from Seller's scheduled maintenance allowances set forth above.
E-4 ADJUSTMENTS TO FIRM CAPACITY
(a) Seller may increase the firm capacity with the approval of PGandE and receive payment for the additional capacity thereafter in accordance with the applicable capacity purchase price published by PGandE at the time the increase is first delivered to PGandE.
(b) Seller may reduce the firm capacity at any time prior to the firm capacity availability date by giving written notice thereof to PGandE. PGandE may derate the firm capacity in accordance with Section E-2(e) as a result of appropriate data showing Seller has failed to meet the minimum performance requirements of Section E-2.
S.O. #4 December 5, 1983
E-5

E-5 FIRM CAPACITY PAYMENTS
Once Seller's Facility has met the firm capacity availability test set forth in Appendix G, the firm capacity payments shall be calculated in the manner shown below. As used below in this section, month refers to a calendar month.
The monthly payment for firm capacity will be the product of the Period Price Factor (PPF), the Monthly Delivered Capacity (MDC), the appropriate capacity loss adjustment factor from Table E-1 based on the Facility's interconnection voltage, and the appropriate performance bonus factor, if any, from Table E-3, plus any allowable payment for outages due to scheduled maintenance. The firm capacity price shall be applied to meter readings taken during the separate times and periods as illustrated in Table B-4, Appendix B.
The PPF is determined by multiplying the firm capacity price by the following Allocation Factors(1):

                                                                     Firm                            PPF
                                Allocation Factor          x    Capacity Price       =           ($/kW-month)
Seasonal
Period A                                .16479                 ----------------                ----------------

Seasonal
Period B                                .02515                 ----------------                ----------------	

(1) All allocation factors are subject to change by PGandE based on PGandE's marginal capacity cost allocation, as determined in general rate case proceedings before the CPUC. Seasonal Periods A and B are defined in Table B-4, Appendix B.
S.O. #4 December 5, 1983
E-6

The MDC is determined in the following manner:
(1) Determine the Performance Factor (P), which is defined as the lesser of 1.0 or the following quantity:
P = A (less than or equal to) 1.0)

C x (B-S) x (O.8*)

Where:

         A  =    Total kilowatt-hours delivered during all on-peak and
                 partial-peak hours excluding any energy associated with
                 generation levels greater than the firm capacity.

         C  =    Firm capacity in kilowatts.

         B  =    Total on-peak and partial-peak hours during the month.

         S  =    Total on-peak and partial-peak hours during the month Facility
                 is out of service on scheduled maintenance.

         (2)     Determine the Monthly Capacity Factor (MCF), which is computed	

using the following expression:
M

MCF = P x (1.0 - D) Where:
M = The number of hours during the month Facility is out of service on scheduled maintenance.
D = The number of hours in the month.

* 0.8 reflects a 20% allowance for forced outage.
S.O. #4 December 5, 1983
E-7

(3) Determine the MDC by multiplying the MCF by C:
MDC (kilowatts) = MCF x C
The monthly payment for firm capacity is then determined by multiplying the PPF by the MDC, by the appropriate capacity loss adjustment factor presented from Table E-1, and by the appropriate performance bonus factor, if any, from Table E-3.
monthly payment = PPF x MDC x capacity loss performance for firm capacity adjustment factor x bonus factor
Furthermore, the payment for a month in which there is an outage for scheduled maintenance shall also include an amount equal to the product of the average hourly firm capacity payment(1) for the most recent month in the same type of Seasonal Period (i.e., Seasonal Period A or Seasonal Period B) during which deliveries were made(2) times the number of hours of outage for scheduled maintenance in the

(1) Total monthly payment divided by the total number of hours in the monthly billing period.
(2) Firm capacity payments during the first month in Period A and Period B following the Firm Capacity Availability Date will be determined by PGandE based upon the Facility's performance during those months.
S.O. #4 December 5, 1983
E-8

current month. Firm capacity payments will continue during the outage periods for scheduled maintenance provided that the provisions of Section E-3 are met.
During a probationary period Seller's monthly payment for firm capacity shall be determined by substituting for the firm capacity, the capacity at which Seller would have met the minimum performance requirements. In the event that during the probationary period Seller does not meet the minimum performance requirements at whatever firm capacity was established for the previous month, Seller's monthly payment for firm capacity shall be determined by substituting the firm capacity at which Seller would have met the minimum performance requirements. The performance bonus factor shall not be applied during probationary periods.
TABLE E-1
The Facility is non-remote.(1) The firm capacity loss adjustment factors are as follows:

                                                       Capacity Loss
Interconnection Voltage                              Adjustment Factor
- -----------------------                              -----------------
Transmission                                                 .989	

(1) As defined by the CPUC.
S.O. #4 December 5, 1983
E-9

TABLE E-1
 (Continued)

                                             Capacity Loss
Interconnection Voltage                    Adjustment Factor
-----------------------                    -----------------
Primary Distribution                             .991

Secondary Distribution                           .991	

The following shall be the performance bonus factors applicable to the calculation of the monthly payments for firm capacity delivered by the Facility after it has demonstrated a firm capacity factor in excess of 85%.

    DEMONSTRATED
FIRM CAPACITY FACTOR            PERFORMANCE
        (%)                     BONUS FACTOR
--------------------            ------------
       85                          1.000
       90                          1.059
       95                          1.118
      100                          1.176	

After the Facility has delivered power during the span of all of the peak months on the PGandE system (presently June, July, and August) in any year (span),
(i) the firm capacity factor for each such month shall be calculated in the following manner:
A

FIRM CAPACITY FACTOR (%) =  ------------ x 100
                               B x C

                     E-10                    S.O. #4
                                             December 5, 1983	

                                   TABLE E-2

                          Firm Capacity Price Schedule
                          ----------------------------

                             (Levelized $/kW-year)

  Firm
Capacity
 Avail-
ability
  Date                                       Number of Years of Firm Capacity Delivery
- --------     ---------------------------------------------------------------------------------------------------------
 (Year)       1     2     3     4     5     6     7     8     9    10    11    12    13    14    15    20    25    30
- --------     ---   ---   ---   ---   ---   ---   ---   ---   ---   ---   ---   ---   ---   ---   ---   ---   ---   ---
  1983        70    73    75    78    80    83    85    88    90    92    94    96    98   100   102   110   117   122

  1984        76    78    81    84    86    89    92    94    97    99   101   103   106   108   110   118   125   130
  1985        81    84    87    90    93    96    99   101   104   106   109   111   113   115   118   127   134   140

  1986        88    91    94    97   100   103   106   109   112   114   117   119   122   124   126   136   144   150
  1987        95    98   101   105   108   111   114   117   120   123   125   128   130   133   135   146   154   160
  1988       102   106   109   113   116   119   122   125   128   131   134   137   140   142   145   156   165   172	

E-11 S.O. #4 December 5, 1983

Where:

A   =   Total kilowatt-hours delivered by Seller in any peak month during all
        on-peak hours excluding any energy associated with generation levels
        greater than the firm capacity.

B   =   Total on-peak hours during the month.

C   =   Firm capacity in kilowatts.

        (ii) the arithmetic average of the above firm capacity factors shall be	

determined for that span,
(iii) the average of the above arithmetic average firm capacity factors for the most recent span(s), not to exceed 5, shall be calculated and shall become the Demonstrated Firm Capacity Factor.
To calculate the performance bonus factor for a Demonstrated Firm Capacity Factor not shown in Table E-3 use the following formula:
Performance Bonus Factor = Demonstrated Firm Capacity Factor (%)

85%
E-6 MINIMUM DAMAGES
(a) In the event the firm capacity is derated or Seller terminates this Agreement, the quantity by which the firm capacity is derated or the firm capacity shall be used to calculate the payments due PGandE in accordance with
E-12 S.O. #4 December 5, 1983

Section (d).
(b) Seller shall be invoiced by PGandE for all amounts due under this section. Payment shall be due within 30 days of the date of invoice.
(c) If Seller does not make payments pursuant to Section (b), PGandE shall have the right to offset any amounts due it against any present or future payments due Seller.
(d) Seller shall pay to PGandE:
(i) an amount equal to the difference between (a) the firm capacity payments already paid by PGandE, based on the original term of agreement and (b) the total firm capacity payments which PGandE would have paid based on the period of Seller's actual performance using the adjusted firm capacity price. Additionally, Seller shall pay interest, compounded monthly from the date the excess capacity payment was made until the date Seller repays PGandE, on all overpayments, at the published Federal Reserve Board three months' Prime Commercial Paper rate; plus
(ii) a sum equal to the amount by which the firm capacity is being terminated or derated times
S.O. #4 December 5, 1983
E-13

the difference between the current firm capacity price on the date of termination or deration for a term equal to the balance of the term of agreement and the firm capacity price, multiplied by the appropriate factor shown in Table E-5 below. In the event that the current firm capacity price is less than the firm capacity price, no payment under this subsection (ii) shall be due either Party.
TABLE E-5

          Amount of Firm Capacity
          Terminated or Derated           Factor
          ---------------------           ------
1,000 kW or under                          0.25
over    1,000 kW through  10,000 kW        0.75
over   10,000 kW through  25,000 kW        1.00
over   25,000 kW through  50,000 kW        3.00
over   50,000 kW through 100,000 kW        4.00
over   100,000 kW                          5.00	

S.O. #4 December 5, 1983
E-14

APPENDIX F
INTERCONNECTION
CONTENTS

Section                                                                                       Page
-------                                                                                       ----
    F-1              INTERCONNECTION TARIFFS                                                  F-2

    F-2              POINT OF INTERCONNECTION LOCATION SKETCH                                 F-3

    F-3              INTERCONNECTION FACILITIES FOR WHICH                                     F-4
                     SELLER IS RESPONSIBLE	

S.O. #4 December 5, 1983
F-1

F-1 INTERCONNECTION TARIFFS
PGandE has filed revisions to Electric Rule 21 to comply with CPUC Decision No. 83-10-093 dated October 19, 1983. The applicable rule will be appended as Appendix I to this Agreement after the CPUC's final determination of PGandE's November 17, 1983 petition for modification of said decision with regard to the interconnection tariff, and the final form of Rule 21, pursuant to that determination, is approved and effective.
S.O. #4 December 5, 1983
F-2

F-2 POINT OF INTERCONNECTION LOCATION SKETCH
To be amended upon completion of interconnection studies.
S.O. #4 December 5, 1983
F-3

F-3 INTERCONNECTION FACILITIES FOR WHICH SELLER IS RESPONSIBLE
To be amended upon completion of interconnection studies.
S.O. #4 December 5, 1983
F-4

APPENDIX H
FIRM CAPACITY AVAILABILITY TEST
Seller shall demonstrate the Facility's capability to deliver firm capacity as follows:
1. Seller shall provide a two-week advance written notice to PGandE's Vice President -- Electric Operations of the time when Seller proposes to begin the demonstration of the operation of the Facility. PGandE's Vice President -- Electric Operations shall designate a representative to coordinate the test procedure between PGandE and Seller. The demonstration shall include such test programs and procedures (as determined by PGandE's representative) necessary to determine that the facility can operate throughout the range of Power Factors described in Rule 21.
2. PGandE may have one or more designated representatives observe the Facility during all or part of the demonstration period.
3. For 10 consecutive days, the Facility shall deliver energy at the contract capacity during at least 360 of the 480 half-hour periods (i.e., 75 x 10 x 24 x 2).
S.O. #4 December 5, 1983
H-1

The PGandE representatives present at the demonstration may give informal comments to Seller's representatives and shall use the results of their observations in the event the Facility is unable in the future to meet its minimum performance requirements.
Successful completion of the above demonstration by Seller shall not be construed as PGandE confirming or endorsing the design or as warranting the safety, durability, or reliability of the Facility.
S.O. #4 December 5, 1983
H-2

APPENDIX H
SAMPLE BILLING CALCULATIONS
TO BE AMENDED
S.O. #4
December 5, 1983
1

AMENDMENT #1

FIRST AMENDMENT
TO
"LONG-TERM ENERGY AND CAPACITY
POWER PURCHASE AGREEMENT
BETWEEN
GILROY FOODS, INC.
PACIFIC THERMONETICS, INC.
AND
PACIFIC GAS AND ELECTRIC COMPANY"
DATED DECEMBER 19, 1983
WHEREAS, GILROY FOODS, INC., a California corporation, and PACIFIC THERMONETICS, INC., a California corporation, did execute an agreement as "Seller" with PACIFIC GAS AND ELECTRIC ("PG&E") entitled LONG-TERM ENERGY AND CAPACITY POWER PURCHASE AGREEMENT BETWEEN GILROY FOODS, INC., PACIFIC THERMONETICS, INC. AND PACIFIC GAS AND ELECTRIC COMPANY dated December 19, 1983 ("Agreement"); and
WHEREAS, the language of the Agreement indicated GILROY FOODS, INC. and PACIFIC THERMONETICS, INC. were partners, but GILROY FOODS, INC. represents to PG&E that in fact GILROY FOODS, INC. and PACIFIC THERMONETICS, INC. were not, and never have been partners; and
WHEREAS, GILROY FOODS, INC. represents to PG&E that PACIFIC THERMONETICS, INC. was serving as a consultant to GILROY FOODS, INC. at the time the Agreement was executed by GILROY FOODS, INC. AND PACIFIC THERMONETICS, INC.; and
WHEREAS, GILROY FOODS represents to PG&E that GILROY FOODS, INC. and PACIFIC THERMONETICS, INC. have no business relationship with each other whatsoever including in particular no relationship relative to the cogeneration project contemplated under the Agreement; and

WHEREAS, GILROY FOODS, INC. represents to PG&E that PACIFIC THERMONETICS, INC. should be removed as a party to the Agreement and all references to PACIFIC THERMONETICS, INC. should be deleted from the Agreement; and
WHEREAS, GILROY FOODS, INC. represents to PG&E that GILROY FOODS, INC., or its assignee GILROY ENERGY COMPANY, INC., a California corporation, intends to proceed with the cogeneration project contemplated under the Agreement;
NOW THEREFORE, GILROY FOODS, INC. and PG&E in consideration of the mutual agreements hereinafter set forth, and other good and valuable consideration, hereby amend said Agreement as follows:
1. On page 1 (the cover page) delete "PACIFIC THERMONETICS, INC."
2. On page 3 delete "PACIFIC THERMONETICS, INC." from the title of the Agreement at the top of the page.
3. On page 3 in the introduction before "Article 1" delete the words "and PACIFIC THERMONETICS, INC., a California corporation, as Partners" so that the introduction is as follows: "GILROY FOODS, INC., a California corporation ("Seller"), and PACIFIC GAS AND ELECTRIC COMPANY ("PG&E"), referred to collectively as "Parties" and individually as "Party", agree as follows:"
4. On page 13 in "Article 9" at the top of the page delete:
-2-

"To Seller:             President
                        Pacific Thermonetics, Inc.
                        1901 South Bascom Avenue
                        Suite 343
                        Campbell, CA 96008"	

and insert in lieu thereof the following:

"To Seller:             President
                        Gilroy Foods, Inc.
                        1350 Pacheco Pass Highway
                        Gilroy, CA 95020"	

5. In Section A-13 on Page A-20 of Appendix A to the Agreement, delete paragraph (a):
"(a) PG&E acknowledges that Seller is executing this Agreement expecting to assign its interest and obligations hereunder to a different partnership to be formed between corporate affiliates of Pacific Thermonetics, Inc. and Gilroy Foods, Inc., to construct, own and operate the Facility and that this Agreement, including all rights and duties of Seller thereunder, is to be assigned to that partnership. It is further acknowledged that to finance the Facility an assignment of the rights of Seller under this Agreement may be necessary as security for the long term debt obligations of the partnership. PG&E hereby consents to both such assignments, subject to its receiving a prior notice of any such proposed assignment," and insert in lieu thereof the following:
"(a) PG&E acknowledges that Seller is executing this Agreement expecting to assign its interest and obligations hereunder to Gilroy Energy Company, Inc., a California corporation, to construct, own and operate the Facility and that this Agreement, including all rights and duties of Seller thereunder, is to be assigned to that corporation. It is further
-3-

acknowledged that to finance the Facility an assignment of the rights of Seller under this Agreement may be necessary as security for the long term debt obligations of either corporation. PG&E hereby consents to both such assignments, subject to its receiving a prior notice of any such proposed assignment."
FURTHERMORE, the Agreement is hereby reformed in any and all other respects so as to eliminate PACIFIC THERMONETICS, INC. as an independent signatory of the Agreement and as an entity having any rights arising from the Agreement.
IN WITNESS WHEREOF, the Parties hereto have caused this First Amendment to be executed by their duly authorized representatives and it is effective as of the last date set forth below period.
GILROY FOODS. INC. PACIFIC GAS AND ELECTRIC COMPANY

By:    /s/ BYRON T. DENNIS                 By:   /s/ NOLAN H. DAINES
       -------------------                       ---------------------
       Byron T. Dennis                           Nolan H. Daines
       Secretary                                 Vice President
                                                 Planning and Research	

DATE SIGNED:  7/17/85                      DATE SIGNED: July 18, 1985
              -------                                   -------------	

-4-

INDEMNITY AGREEMENT
BETWEEN
McCORMICK & COMPANY, INCORPORATED
AND
PACIFIC GAS AND ELECTRIC COMPANY
IN CONSIDERATION of and as a condition for the First Amendment ("Amendment") which, among other things, reforms the Long-Term Energy and Capacity Power Purchase Agreement Between Gilroy Foods, Inc., Pacific Thermonetics, Inc. and Pacific Gas and Electric Company dated December 19, 1983 ("Agreement") to delete all references to PACIFIC THERMONETICS, INC. as well as deleting PACIFIC THERMONETICS, INC. as a signatory, McCORMICK & COMPANY, INCORPORATED ("McCORMICK"), warrants that each and every representation contained in the Amendment is true and correct, and as an inducement to PG&E's acceptance of the Amendment, agrees to indemnify and hold PG&E, its officers, and agents and employees harmless from any loss, claims, liabilities, or damages (including direct, indirect, special, and punitive) arising out of or in connection with the Amendment, including any legal action brought by PACIFIC THERMONETICS, INC. or by any other party against PG&E in challenging the Amendment. McCORMICK further agrees to assume the defense for any claims covered by the above indemnity and agrees to reimburse PG&E for reasonable outside attorney fees, if any, incurred by PG&E in connection with the defense of such claims; however, McCormick shall have the right to assume and direct the legal defense of PG&E in all respects relative indemnifying PG&E hereunder, and PG&E shall not

incur any such legal fees unless McCORMICK fails to provide a timely defense of PG&E as provided herein.
PG&E shall promptly notify the General Counsel of McCORMICK and the President of Gilroy Foods, Inc. of any such claims against PG&E, and McCORMICK and PG&E shall fully cooperate with each other and the legal counsel employed by McCORMICK in the defense of any such claims.
Should PG&E determine that McCORMICK is failing to provide a timely and appropriate legal defense for PG&E, then PG&E shall notify McCORMICK of such deficiency, and PG&E may then employ outside attorneys to represent it, and McCORMICK shall promptly reimburse PG&E for any such outside attorneys' fees and expenses.
McCORMICK & COMPANY, INCORPORATED PACIFIC GAS AND ELECTRIC COMPANY

BY:    /s/ SIG                             BY:   /s/ NOLAN H. DAINES
       -------------------------                 ----------------------------
       President                                 NOLAN H. DAINES
                                                 Vice President
                                                 Planning and Research

BY:    /s/ SIG
       -------------------------	

DATE SIGNED: July 16, 1985 DATE SIGNED: 7/18/85

-2-

AGREEMENT TO AMEND
GILROY ENERGY COMPANY'S (GEC) POWER PURCHASE AGREEMENT
GEC and Pacific Gas and Electric Company (PGandE)'s Power Purchase Agreement executed on December 19, 1983 (PPA) does not adequately recognize the seasonal nature of the GEC food processing facilities and PGandE's desire for increased operating flexibility. To remedy this, the parties agree to prepare and execute an Amendment to the PPA in accordance with the concepts below. The parties further agree that the energy prices herein described have been developed so that PGandE and its rate payers are not disadvantaged by PGandE's exercise of this Agreement. The parties recognize that GEC will file this Agreement in its California Energy Commission certification proceeding.
1. PGandE shall have the option, which it may or may not exercise each calendar year at its sole discretion, to gain greater operating flexibility in exchange for a modified pricing arrangement.
2. GEC is capable of reducing generating output from January 1 through April 30 and will give PGandE its option to schedule energy deliveries for this period (2880 hours), hereinafter referred to as Period 1. GEC is also capable of reducing its electrical generation to zero for up to six contiguous off-peak hours (as defined in the PPA) per day from May 1 through December 31 and is willing to give PGandE its option to reduce energy deliveries to zero during this period (1470 hours). The 1470 hours are herein referred to as Period 2. The remaining hours of the year are herein referred to as Period 3.
3. The provisions of this amendment shall be effective for all periods for each of ten consecutive calendar years at PGandE's sole option, which it shall exercise by delivering a written notice to GEC anytime during (but not later than December 15 of) the preceding calendar year. During the first year, PGandE shall exercise its option not later than thirty days after the firm capacity availability date of the PPA. The provisions of the PPA shall be in effect (i) during any calendar year(s) with respect to which PGandE does not exercise its option as provided by the Amendment, and (ii) in years eleven through thirty of the plant operation.

4. DURING PERIOD 1:
A. Subject to scheduled maintenance and forced outage as provided for in the PPA, PGandE shall schedule and GEC shall deliver energy at the following levels:
Zero energy deliveries; or
Any load point from approximately 50 percent of firm capacity to 100 percent of the Facility's capability.
B. PGandE shall pay for this energy at a price equal to the GEC heat rate obtained from the table below in Btu/Kwhr multiplied by the weighted average price paid during the month by PGandE's Electric Department for oil and natural gas for PGandE's fossil steam plants ($/Btu on a gas Btu basis). Heat rates provided in this table are subject to change based on the results of an annual test. The applicable heat rate shall be based on the level of deliveries scheduled by PGandE as follows:

At or above 100% of firm capacity             8,550 Btu/Kwhr

From 85% of firm capacity to                  8,880 Btu/Kwhr
     99% of firm capacity

From 65% of firm capacity to                  9,400 Btu/Kwhr
     85% of firm capacity

From 50% of firm capacity                    10,600 Btu/Kwhr
  to 65% of firm capacity	

In addition, PGandE shall pay GEC $6500 (1985 dollars) for each start-up. PGandE will change this start-up charge monthly, indexed to the weighted average price paid during the month by PGandE's Electric Department for oil and natural gas for PGandE's fossil steam plants ($/Btu on a gas Btu basis).
C. PGandE shall require deliveries of energy from the Facility for a minimum of 6 hours after each start-up. PGandE agrees to require the Facility to be started up no more than an average of 6 times per calendar week during Period 1.

D. Prior to December 31, PGandE shall stipulate the schedule for maintenance (scheduled annual overhaul) for Period 1 of the following year after receiving GEC input by December 20. This schedule may be changed by mutual consent if conditions change during period 1.
5. DURING PERIOD 2:
PGandE shall have the option to schedule the Facility to deliver energy at 100% of firm capacity or 0% of firm capacity for up to 6 contiguous off peak hours per day. PGandE shall pay for energy deliveries during Period 2 at a price equal to the Incremental Energy Rate provided in Table B-3, Curtailment Option B, multiplied by the weighted average price paid during the month by PGandE's Electric Department for oil and natural gas for PGandE's fossil steam plants ($/Btu on a gas Btu basis). In addition, PGandE shall pay GEC $1,000 (1985 dollars) for each shut-down, and each shut-down shall be at least 1 hour in length. PGandE will change this start-up charge monthly, indexed to the weighted average price paid during the month by PGandE's Electric Department for oil and natural gas for PGandE's fossil steam plants ($/Btu on a gas Btu basis).
6. DURING PERIOD 3:
PGandE shall accept energy deliveries up to 100% of the Facility's capability, subject to the provisions of the PPA. PGandE shall pay for energy deliveries during Period 3 at a price equal to the Incremental Energy Rate provided in Table B-3, Curtailment Option B (zero bandwidth), multiplied by the weighted average price paid during the month by PGandE's Electric Department for oil and natural gas for PGandE's fossil steam plants ($/Btu on a gas Btu basis), multiplied by a factor. Until the end of the first five full calendar years of plant operation, commencing with the completion of the Firm Capacity availability test the factor shall be 1.17; for full plant operation in calendar years six through ten, the factor shall be 1.13 (During years when the terms of this Agreement are invoked, the annual adjustment referred to on page B-14 of the PPA shall not apply).
7. In the event a force majeure (as defined in the PPA) on the GEC system prevents GEC from having its back-up boiler available to supply steam to the Gilroy Foods process, GEC shall be relieved of any obligation to reduce its electrical generation during period 2; during which time PGandE shall pay GEC for energy delivered at a price equal to 90% of the price of PGandE's available alternate source.

8. Except as provided below, payment for firm capacity and capacity bonus shall be in accordance with Appendix E of the PPA. GEC shall not be penalized if PGandE schedules its generation below the firm capacity level during Period 1 or Period 2. GEC shall not be eligible for as-delivered capacity payments pursuant to the PPA during period 1 or during period 2 when the GEC generation level is scheduled below 100% of firm capacity rating under the terms of this Agreement. Whenever GEC's generating capacity is not available for scheduling by PGandE, subject to a 20 percent allowance for forced outage in any month, the monthly firm capacity payment during Period 1 shall be reduced:
(i) when the firm capacity is available more than 50% of the total time in the month, by that proportion of the time GEC's generating capacity is available to PGandE to the total time in a month. For example, when the firm generating capacity is available 65% of the total hours in a month, the firm capacity payment shall be 75% X monthly firm capacity price X firm contract capacity;
(ii) whenever GEC's firm capacity is available less than 50% of the total time in a month, to zero.
In witness whereof, the Parties hereto have executed this Agreement to Amend GEC's Power Purchase Agreement as of the day and the date last written below.
PACIFIC GAS AND ELECTRIC COMPANY

by:    /s/ SIG
       ---------------------------

Date Signed:   7/18/85
              -----------	

GILROY ENERGY COMPANY

by:    /s/ SIG
       ---------------------------

Date Signed:
              -----------	

AMENDMENT #2

SECOND AMENDMENT
TO
"LONG-TERM ENERGY AND CAPACITY
POWER PURCHASE AGREEMENT"
DATED DECEMBER 19, 1983, AS AMENDED
 JULY 18, 1985
WHEREAS, GILROY ENERGY COMPANY, a California corporation ("Seller") has an agreement with PACIFIC GAS AND ELECTRIC COMPANY ("PGandE") entitled LONG-TERM ENERGY AND CAPACITY POWER PURCHASE AGREEMENT dated December 19, 1983, as amended July 18, 1985 (the "Agreement"); and
WHEREAS, Seller and PGandE believe that the Agreement does not adequately recognize the seasonal nature of Seller's food processing facilities and PGandE's desire for increased operating flexibility; and
WHEREAS, Seller and PGandE executed the "Agreement to Amend Gilroy Energy Company's Power Purchase Agreement" dated July 18, 1985, which contemplated the Agreement would be amended to provide PGandE with greater operating flexibility by permitting PGandE to schedule reduced deliveries at certain times in exchange for a modified pricing arrangement;
NOW THEREFORE, Seller and PGandE in consideration of the mutual agreements hereinafter set forth, and other good and valuable consideration, hereby amend said Agreement as follows:
1. On page 6 of the Agreement, the following paragraph (g) is hereby added to Article 3:
"(g) Commencing with the date on which the Facility meets the firm capacity availability test as described in Appendix G (the "Commencement Date") and continuing for the remainder of that year and for a period of ten full calendar years thereafter but not beyond December 31, 1998 PGandE may elect, at its sole option, to invoke the provisions of Appendix J (1) for the remainder of the year in which the Commencement Date occurs and/or (2) for a period of one calendar year for any and all succeeding calendar years during such period. During the year in which the Facility meets the firm capacity availability test as described in Appendix G, PGandE must make such election by delivering a written notice thereof to Seller not later than 30 days after the Commencement Date, and, for subsequent years, PGandE must deliver such notice to Seller no later than December 15 of the preceding year."

2. Appendix J is hereby added to the Agreement, and shall read as set forth herein in its entirety:
APPENDIX J
VARIABLE OPERATION OPTION
This Appendix shall amend and modify, for a period of one calendar year (or from the Commencement Date until December 31 of the year containing the Commencement Date), the "Long Term Energy and Capacity Power Purchase Agreement" and Appendices thereto (the "Agreement"), between Gilroy Energy Company ("Seller") and Pacific Gas and Electric Company ("PGandE"), referred to collectively as "Parties" and individually as "Party." Unless specifically amended as set forth herein for the period in which this Appendix is invoked, all provisions of the Agreement shall remain in full force and effect.
J-1. Article 4 of the Agreement shall be amended to read as follows:
ARTICLE 4 ENERGY DELIVERY AND PRICE
(a) From January 1 through April 30 ("Period 1") of a given year for which PGandE has elected to invoke the provisions of Appendix J, the following provisions shall govern the delivery of energy by Seller and the rates paid therefor by PGandE:
1. Subject to scheduled maintenance and forced outage as provided for in this Agreement, PGandE shall schedule and Seller shall deliver energy at the following levels:
Zero energy deliveries; or
Any load point from approximately 50 percent of the Facility's firm capacity to the Facility's full capability.
The Facility shall be scheduled in accordance with the provisions of Paragraph (c) of this Article 4.
2. Subject to the provisions of Paragraph (e) of this Article 4, and except as provided in Paragraph (d) of this Article 4, PGandE shall pay for the energy (per delivered Kwhr) at a price equal to the heat rate obtained from the table below in Btu/Kwhr multiplied by the weighted average price paid during the month by PGandE's Electric Department for oil and natural gas for PGandE's fossil steam plants ($/Btu on a gas Btu basis). Heat rates provided in this table are subject
- 2 -

to change based on the results of a test of the Facility which may be conducted once during any one calendar year at the request of either Party. Such test shall have a maximum duration of 24 hours, with readings conducted every half hour. The test shall be conducted using plant instrumentation and personnel, but either party may, at its own expense, require that other instrumentation or personnel be used. PGandE shall purchase all output produced during the test. Prior to the firm capacity availability date of the facility, the Parties shall agree upon the test procedures. Four months prior to the Facility's firm capacity availability date, Seller shall propose test procedures for PGandE's review and approval and provide the Facility's heat balance. Test procedures shall provide verifiable, auditable results and shall be consistent with generally accepted industry practices and established ASME Power Test Codes to the extent applicable and necessary. Subject to adjustment in accordance with the foregoing test (it being understood that the applicable heat rates as set forth below and as adjusted are not intended solely to represent the actual heat rate of Seller's Facility, but include the actual heat rate calculated based on the higher heating value of natural gas and verifiable chemical costs), the applicable heat rate shall be based on the level of deliveries scheduled by PGandE as follows:

                                                    Adjustment
                                        Actual      For         Resulting
                                        Heat        Chemical    Heat
                                        Rate        Costs       Rate
Level of Deliveries                     (Btu/Kwhr)  (Btu/Kwhr)  (Btu/Kwhr)
- -------------------                     ----------  ----------  ----------
At or above 100% of
  firm capacity                          8,400      150          8,550

From 85% of firm capacity to
  99% of firm capacity                   8,745      135          8,880

From 65% of firm capacity to
  84% of firm capacity                   9,245      155          9,400

From 50% of firm capacity to
  64% of firm capacity                  10,440      160         10,600	

In addition, PGandE shall pay Seller $6,500 for each start-up excluding any start-up following an outage resulting from a design defect, inadequate construction, operator error or a breakdown of the mechanical or electrical equipment of Seller's Facility that fully or partially curtails the electrical output
-3-

of the Facility. Subject to the provisions of Paragraph (e) of this Article 4, PGandE will adjust this start-up charge monthly, by multiplying this initial start-up charge by a fraction, the numerator of which is the weighted average price paid during the preceding month by PGandE's Electric Department for oil and natural gas for PGandE's fossil steam plants ($/Btu on a gas Btu basis) and the denominator of which is the weighted average price paid during July, 1985 by PGandE's Electric Department for oil and natural gas for PGandE's fossil steam plants ($/BTU on a gas BTU basis).
3. PGandE shall require deliveries of energy from the Facility for a minimum of 6 hours after each start-up. PGandE agrees to require the Facility to be started up no more than seven times in any one calendar week during Period 1.
4. For each year for which PGandE reasonably anticipates making an election to invoke the provisions of Appendix J, PGandE and Seller shall confer as early as practicable concerning maintenance schedules, output scheduling and any other matters affecting the Facility. In all events, Seller shall provide its input to PGandE concerning such matters no later than December 20 of the preceding year. Prior to December 31 of the year preceding each year for which the option to invoke the provisions of Appendix J is exercised, PGandE shall, after due consideration of the input of Seller, deliver a written maintenance schedule for both annual overhaul and other periodic overhauls, which shall be scheduled for Period 1. PGandE shall at the same time deliver to Seller a tentative, non-binding operation schedule for Period 1. If, after the maintenance schedule has been delivered, in either Party's reasonable judgment conditions change such that a change in the maintenance schedule is warranted, such Party shall deliver written notice thereof to the other Party, specifying with particularity the circumstances warranting a change in the schedule and the change requested. The maintenance schedule for Period 1 shall be changed if the responding Party consents, which consent shall not be unreasonably withheld.
(b) The hours from May 1 through December 31 of a given year for which PGandE has elected to invoke the provisions of Appendix J shall be either Period 2 or Period 3, as defined in this Paragraph (b).
1. From May 1 through December 31, PGandE shall have the option to schedule the Facility to deliver energy at 100% of the Facility's capability or 0% of firm
-4-

capacity for up to 6 contiguous off peak hours per day (such hours being referred to hereinafter as "Period 2"). Seller shall deliver energy in accordance with the schedule prepared by PGandE in accordance with the provisions of paragraph (c) of this Article 4. Subject to the provisions of Paragraph (e) of this Article 4, and except as provided in the last sentence of this Paragraph (b)1 and in Paragraph (d) of this Article 4, PGandE shall pay for energy deliveries during Period 2 at a price per delivered Kwhr equal to the Incremental Energy Rate provided in Appendix B multiplied by the weighted average price paid during the month by PGandE's Electric Department for oil and natural gas for PGandE's fossil steam plants ($/Btu on a gas Btu basis). Each period during which PGandE schedules output at 0% of firm capacity and Seller in response curtails the electrical output of the Facility as so scheduled shall be deemed a "shut-down" of the Facility for purposes of this Agreement. PGandE shall pay Seller $1,000 for each such shut-down, and each shut-down shall be at least 1 hour in length. Subject to the provisions of Paragraph (e) of this Article 4, PGandE will adjust this shut-down charge monthly by multiplying this initial shut-down charge by a fraction, the numerator of which is the weighted average price paid during the preceding month by PGandE's Electric Department for oil and natural gas for PGandE's fossil steam plants ($/Btu on a gas Btu basis) and the denominator of which is the average price paid during July, 1985 by PGandE's Electric Department for oil and natural gas for PGandE's fossil steam plants ($/Btu on a gas Btu basis). Whenever the Seller's back-up boiler is not capable of supplying steam to the Gilroy Foods process, Seller shall be relieved of any obligation to reduce its electrical generation during Period 2, provided that Seller uses its best efforts to correct the condition causing such incapability, and provided further, that during such times PGandE shall pay Seller for energy delivered at a price equal to 90% of the price of PGandE's available alternate source.
2. During on-peak, partial-peak and off-peak hours for which PGandE has made no election in the foregoing Paragraph (b)1 from May 1 through December 31 ("Period 3") (it being understood that all off-peak hours during the period from May 1 through December 31 shall be treated as Period 3 unless PGandE specifically elects to exercise its option to schedule such hours in accordance with the provisions of the foregoing paragraph (b) 1), PGandE shall accept energy deliveries subject to the provisions of this Agreement. Subject to the provisions of Paragraph
(e) of this Article 4,
- 5 -

PGandE shall pay for energy deliveries during Period 3 at a price equal to the Incremental Energy Rate provided in Appendix B multiplied by the weighted average price paid during the month by PGandE's Electric Department for oil and natural gas for PGandE's fossil steam plants ($/Btu on a gas Btu basis), multiplied by a factor as hereinafter set forth. For the remainder of the year in which the Commencement Date occurs and the next succeeding five calendar years, the factor shall be 1.17 provided that the Commencement Date is during or before 1988. For the next five succeeding calendar years, the factor shall be 1.13. In the event that the Commencement Date occurs after December 31, 1988 the factor shall be 1.17 until December 31, 1993 and 1.13 for the calendar years 1994 through 1998.
(c) During Periods 1 and 2, Seller shall deliver energy in accordance with the schedule prepared by PGandE. Such schedule shall be set in the following manner. PGandE shall prepare a non-binding tentative weekly schedule for the Facility and provide this schedule to Seller no later than 1200 hours Friday of the week preceding the week for which the schedule is prepared (which week shall be deemed to commence at 0001 hours Sunday). For Period 1, PGandE shall notify Seller at least 48 hours in advance of any period for which PGandE desires to schedule the Facility to be on-line of (i) the scheduled on-line time; (ii) the duration of the period for which the Facility is scheduled to be on-line; and (iii) the level of energy deliveries scheduled. Unless scheduled to be on-line by PGandE, the Facility shall remain off-line during Period 1. PGandE shall notify Seller at least forty-eight hours prior to each period of off-peak hours during Period 2 for which PGandE elects to schedule the Facility to deliver energy at 0% of firm capacity of 100% of the Facility's capability, as the case may be. During both Period 1 and Period 2, the Facility shall be brought on-line at the requested level of delivery or taken off-line at the time scheduled by PGandE in its 48 hour notice to Seller, unless PGandE gives contrary notice to Seller at least six hours in advance in the case of a cold start and four hours in advance in the case of a warm start or a shutdown. For purposes of this paragraph, a "warm start" of the Facility is any start up of the Facility within twelve hours of the last shutdown of the Facility, while a cold start is any start-up of the Facility more than twelve hours after the last shutdown of the Facility.
(d) Notwithstanding PGandE's right to schedule output of the Facility during Periods 1 and 2, Seller may request a schedule change in order to conduct performance tests of the Facility for purposes of the Completion Test of the Facility as set forth in Appendix K and the Extended Warranty on the Facility's performance as set forth in Appendix K. PGandE shall not unreasonably withhold its consent to such schedule change.
- 6 -

Without the prior consent of PGandE (which consent shall not be unreasonably withheld), Seller may not increase the frequency or duration of testing during the Extended Warranty term or the frequency or duration of testing for the purpose of the Completion Test of the Facility. Notwithstanding the foregoing, such tests shall be conducted no more than six times during the eighteen-month term of the Extended Warranty. PGandE shall purchase energy generated during the testing periods at prices set forth above for Periods 1 and 2, as the case may be, unless PGandE's tentative schedules provided to Seller show that at the time Seller requested a schedule change for the testing period, PGandE would not have scheduled energy deliveries. Energy delivered during testing periods which, according to the tentative schedule, would not have been scheduled by PGandE shall be purchased at a price equal to 90% of the price of PGandE's available alternate source.
(e) Whenever under this Agreement PGandE is required to make a payment (or an adjustment to a payment) on a monthly basis based upon the weighted average price paid during such month by PGandE's Electric Department for oil and natural gas for PGandE's fossil steam plants ($/Btu on a gas Btu basis), such requirement is based upon the assumption that PGandE is able to determine such weighted average price on a monthly basis promptly enough to meet the payment requirements hereunder. In the event that PGandE is incapable (due to internal administrative, accounting or technical limitations or procedures) of making such determination on a timely basis, the payment (or adjustment to a payment) to Seller shall be based upon PGandE's gas schedule number G-55 (or equivalent), and at the end of each calendar year a reconciliation will be made (through a payment to or by Seller, as appropriate) to reflect any difference between amounts actually paid to Seller during the year and amounts which would have been payable to Seller were such payments based upon the weighted average price paid during such year by PGandE's Electric Department for oil and natural gas for PGandE's fossil steam plants ($/Btu on a gas Btu basis) instead of PGandE's gas schedule number G-55 (or equivalent).
J-2. Article 6 of the Agreement shall be amended by deleting the second paragraph.
J-3. Article 7 of the Agreement shall be deleted.
J-4. Article 11 of the Agreement shall be amended to read as follows:
ARTICLE 11 TERMS AND CONDITIONS
This Agreement includes the following appendices which are incorporated by reference:
Appendix A - GENERAL TERMS AND CONDITIONS
- 7 -

Appendix B  -     INCREMENTAL ENERGY RATES
Appendix C  -     TIME PERIODS
Appendix D  -     AS-DELIVERED CAPACITY
Appendix E  -     FIRM CAPACITY
Appendix F  -     INTERCONNECTION
Appendix G  -     FIRM CAPACITY AVAILABILITY TEST
Appendix H  -     SAMPLE BILLING CALCULATIONS	

J-5. Article 12 of the Agreement shall be deleted.
J-6. The following changes to Appendix A to the Agreement shall be made:
(a) The definition of "full short-run avoided operating cost" on p. A-4 shall be deleted.
(b) Insert the following on line 3 of page A-12:
"Seller shall continue to keep PGandE informed of the Facility's availability during Period 1."
J-7. Appendix B to the Agreement shall be amended to read as follows:

             APPENDIX B
      INCREMENTAL ENERGY RATES

                         Forecasted
                         Incremental
                        Energy Rates,
Year                      Btu/kWh
----                    -------------
1984                        9,440
1985                        9,500

1986                        9,280
1987                        9,290
1988                        9,400

1989                        9,270
1990                        8,970
1991                        8,970

1992                        8,970
1993                        8,970
1994                        8,970

1995                        8,970
1996                        8,970
1997                        8,970

1998                        8,970	

- 8 -

J-8. Appendix C to the Agreement shall be amended to read as follows:
APPENDIX C
TIME PERIODS

                                 Monday                           Sundays
                                 through                            and
                                Friday(2)       Saturdays(2)      Holidays
                                ---------       ------------      --------
Seasonal Period A
(May 1 through September 30)

    On-Peak                     12:30 p.m.
                                -6:30 p.m.

    Partial-Peak                 8:30 a.m.       8:30 a.m.
                               -12:30 p.m.     -10:30 p.m.

                                 6:30 p.m.
                               -10:30 p.m.

    Off-Peak                    10:30 p.m.      10:30 p.m.        All Day
                                -8:30 a.m.      -8:30 a.m.

Seasonal Period B
(October 1 through April 30)

    On-Peak                      4:30 p.m.
                                -8:30 p.m.

    Partial-Peak                 8:30 p.m.       8:30 a.m.
                               -10:30 p.m.     -10:30 p.m.

                                 8:30 a.m.
                                -4:30 p.m.

    Off-Peak                    10:30 p.m.      10:30 p.m.        All Day
                                -8:30 a.m.      -8:30 a.m.	

1 This table is subject to change to accord with the on-peak, partial peak and off-peak periods as defined in PG&E's own rate schedules for the sale of electricity and to large industrial customers.
2 Except the following holidays: New Year's Day, Washington's Birthday, Memorial Day, Independence Day, Labor Day, Veteran's Day, Thanksgiving, and Christmas, as said days are specified in Public Law 90-363 (5 U.S.C.A.
Section 6103(a)).
-9-

J-9 Appendix D to the Agreement shall be amended by inserting the following sentence on line 5 of page D-1:
"The amount of capacity delivered in excess of firm capacity during Period 3 or scheduled and delivered in excess of firm capacity during Periods 1 and 2 will be considered as-delivered capacity and PGandE shall pay Seller for such as-delivered capacity in accordance with As-Delivered Capacity Payment Option 2 set forth herein."
J-10 Appendix E to the Agreement shall be amended as follows:
(a) Section E-1 shall be amended by inserting the following sentence on line 17 of page E-1:
In the event that any of PGandE's peak months (currently June, July and August) shift into Period 1, the parties shall use best efforts to negotiate a mutually agreeable method of satisfying minimum performance requirements and determining the performance bonus factor.
(b) Section E-3 shall be amended to read as follows:
PGandE shall schedule all outage periods for annual and periodic overhauls during Period 1. Outage periods for scheduled maintenance during any calendar year shall not exceed 840 hours (35 days) (including the number of hours of outage due to annual and periodic overhauls). This allowance may be used in increments of an hour or longer on a consecutive or nonconsecutive basis. Seller may accumulate unused maintenance hours from one 12-month period to another up to an aggregate of 1,080 hours (45 days). This accrued time must be used consecutively and may only be used for major overhauls. Seller shall provide PGandE with the following notices: 24 hours for scheduled outages of less than one day, one week for scheduled outages of one day or more (except for major overhauls), and six months for a major overhaul. Seller shall not schedule major overhaul during the peak months (presently June, July and August). Seller shall make reasonable efforts to schedule or reschedule routine maintenance outside the peak months and in no event shall outages for scheduled maintenance exceed 30 on-peak hours during the peak months. Seller shall confirm in writing to PGandE pursuant to Article 9, within 24 hours of the original notice, all notices Seller gives personally or by telephone for scheduled maintenance.
- 10 -

(c) Section E-5 shall be amended to read as follows:
E-5 FIRM CAPACITY PAYMENTS
Once Seller's Facility has met the firm capacity availability test set forth in Appendix G, the firm capacity payments shall be calculated solely in the manner shown below. As used below in this section, month refers to a calendar month.
The monthly payment for firm capacity for Periods 2 and 3 will be the product of the Period Price Factor (PPF), the Monthly Delivered Capacity (MDC), the appropriate capacity loss adjustment factor from Table E-1 based on the Facility's interconnection voltage, and the appropriate performance bonus factor, if any, from Table E-3, plus any allowable payment for outages due to scheduled maintenance.
For Period 1, the monthly payment for firm capacity will be the product of the PPF, the firm capacity, the appropriate capacity loss adjustment factor from Table E-1 based on the Facility's interconnection voltage, the appropriate performance bonus factor, if any, from Table E-3 and the appropriate availability factor.
The firm capacity price for Period 3 shall be applied to meter readings taken during the separate times and periods as illustrated in Appendix C.
For Periods 1 and 3 the PPF is determined by multiplying the firm capacity price by the following Allocation Factors*:

                Allocation                   Firm                    PPF
                                X            ----       =
                  Factor                Capacity Price          ($/kW-month)
                                        --------------

Seasonal          .18540                --------------          ------------
Period A

Seasonal          .01043
Period B	

* All allocation factors are subject to change by PGandE based on PGandE's marginal capacity cost allocation, as determined in general rate case proceedings before the CPUC. Seasonal Periods A and B are defined Appendix C.
- 11 -

For Period 3 the MDC is determined in the following manner:
(1) Determine the Performance factor (P), which is defined as the lesser of 1.0 or the following quantity:
A
P = ------------------
 C x (B-5) x (0.8*) ((less than or equal to) 1.0)
Where:
A = Total kilowatt-hours delivered during all on-peak and partial-peak hours in Period 3 excluding any energy associated with generation levels greater than the firm capacity.
C = Firm capacity in kilowatts.
B = Total on-peak and partial-peak hours in Period 3 during the month.
S = Total on-peak and partial-peak hours in Period 3 during the month Facility is out of service on scheduled maintenance.
* 0.8 reflects a 20% allowance for forced outage.
(2) Determine the Monthly Capacity Factor (MCF), which is computed using the following expression:
M
 MCF = P x (1.0 - ---)
D
Where:
M = The number of hours in Period 3 during the month Facility is out of service on scheduled maintenance.
D = the number of hours in Period 3 in the month.
(3) Determine the MDC by multiplying the MCF by C;
Where:
C = Firm capacity in kilowatts:
MDC (kilowatts) = MCF x C
-12-

For Period 1, the Availability Factor is determined as follows:
(1) Determine the availability of the Facility during Period 1:
AV = 100 (H - T - SM) / (H-SM)
H= The number of hours in the month
AV= The percent of the time the Facility is available to deliver energy as scheduled by PGandE during Period 1.
T= Number of hours of the month during Period 1, other than scheduled maintenance hours, when the Facility is not available to deliver energy as scheduled by PGandE pursuant to Section 4(c) hereof.
SM= Number of hours of the month during Period 1 when the Facility is not available to deliver energy due to scheduled maintenance.
(2) Determine the Availability Factor (AF).
When AV is less than 50 percent; then AF = 0.
When AV is greater than or equal to 50 percent; then AF is defined as the lesser of 1 or the following quantity.
AF = (AV - 50) + 0.5 (less than or equal to 1.0)

60
The monthly payment for firm capacity is then determined as follows:
For Period 1:

monthly    = PPF     X Firm       X Capacity      X Performance   X AF
payment                Capacity     Loss            Bonus
for firm                            Adjustment      Factor
capacity                            Factor	

For Periods 2 and 3:

monthly    = PPF        X MDC           X Capacity        X Performance
payment                                   Loss              Bonus
for firm                                  Adjustment        Factor
capacity                                  Factor	

Furthermore, the payment for a month in which there is an outage for scheduled maintenance in Period 3 shall also include an amount equal to the product of the average hourly firm
-13-

capacity payment(1) for the most recent month in the same type of Seasonal Period (i.e., Seasonal Period A or Seasonal Period B) during which deliveries were made(2) times the number of hours of outage for scheduled maintenance in the current month. Firm capacity payments will continue during the outage periods for scheduled maintenance provided that the provisions of Section E-3 are met.
During a probationary period Seller's monthly payment for firm capacity shall be determined by substituting for the firm capacity, the capacity at which Seller would have met the minimum performance requirements. In the event that during the probationary period Seller does not meet the minimum performance requirements at whatever firm capacity was established for the previous month, Seller's monthly payment for firm capacity shall be determined by substituting the firm capacity at which Seller would have met the minimum performance requirements. The performance bonus factor shall not be applied during probationary periods.
TABLE E-1

The Facility is non-remote(3)  The firm capacity loss adjustment factors are as
follows:

                                                Capacity Loss
        Interconnection Voltage               Adjustment Factor
        -----------------------               -----------------

        Transmission                                 .989

        Primary Distribution                         .991

        Secondary Distribution                       .991	

The following shall be the performance bonus factors applicable to the calculation of the monthly payments for firm capacity delivered by the Facility after it has demonstrated a firm capacity factor in excess of 85%.

(1) Total monthly payment divided by the total number of hours in the monthly billing period.
(2) Firm capacity payments during the first month in Period A and Period B following the Firm Capacity Availability Date will be determined by PGandE based upon the Facility's performance during those months.
(3) As defined by the CPUC.
-14-

TABLE E-3
PERFORMANCE BONUS FACTORS

    DEMONSTRATED
FIRM CAPACITY FACTOR            PERFORMANCE
         (%)                    BONUS FACTOR
--------------------            ------------
          85                       1.000
          90                       1.059
          95                       1.118
         100                       1.176	

After the Facility has delivered power during the span of all of the peak months on the PGandE system (presently June, July, and August) in any year (span),
(a) the firm capacity factor for each such month shall be calculated in the following manner:
A
FIRM CAPACITY FACTOR (%) = ----- x 100
 B x C
Where:
A = Total kilowatt-hours delivered by Seller in any peak month during all on-peak hours excluding any energy associated with generation levels greater than the firm capacity.
B = Total on-peak hours during the month. C = Firm capacity in kilowatts.
(b) the arithmetic average of the above firm capacity factors shall be determined for that span.
(c) the average of the above arithmetic average firm capacity factors for the most recent span(s), not to exceed 5, shall be calculated and shall become the Demonstrated Firm Capacity Factor.
To calculate the performance bonus factor for a Demonstrated Firm Capacity Factor not shown in Table E-3 use the following formula:
Demonstrated Firm Capacity Factor (%) Performance Bonus Factor = ------------------------------------- 85%
- 15 -

TABLE E-2
Firm Capacity Price Schedule
(Levelized $/kW-year)

    Firm
  Capacity
Availability
    Date                        Number of Years of Firm Capacity Delivery
- -------------------------------------------------------------------------------------------------------------------------
   (Year)     1     2     3     4     5     6     7     8     9     10    11    12    13    14    15    20    25    30
- -------------------------------------------------------------------------------------------------------------------------
   1983       70    73    75    78    80    83    85    88    90    92    94    96    98   100   102   110   117   122

   1984       76    78    81    84    86    89    92    94    97    99   101   103   106   108   110   118   125   130

   1985       81    84    87    90    93    96    99   101   104   106   109   111   113   115   118   127   134   140

   1986       88    91    94    97   100   103   106   109   112   114   117   119   122   124   126   136   144   150

   1987       95    98   101   105   108   111   114   117   120   123   125   128   130   133   135   146   154   160

   1988      102   106   109   113   116   119   122   125   128   131   134   137   140   142   145   156   165   172	

- 16 -

3. Appendix K is hereby added to the Agreement and shall read as set forth here in its entirety:
APPENDIX K
TESTING
The sole purpose of this Appendix is to describe the testing procedures under Seller's Contract for Generating Facility for purposes of Section J-1(e) of Appendix J. Except as provided in Paragraph (d) of Article 4 (under Appendix J), Seller may modify the testing procedures without the consent of PGandE, but Seller shall notify PGandE of any such modification.
K-1. Completion Test. The Completion Test for the Facility is satisfied when a designated representative of the construction Contractor and Seller certify all of the following:
(a) The completion of the firm capacity availability test;
(b) The achievement of mechanical completion of the Facility and the ancillary and support facilities in accordance with final plans and specifications and the successful completion of all associated construction;
(c) The achievement of successful test operations of the Facility as defined in Section K-3;
(d) The facility shall demonstrate the ability to meet the emissions requirements of the Facility's Bay Area Air quality Management District (BAAQMD) permit through the applicable BAQMD test imposed upon the Facility unless a permanent variance can be obtained from the BAAQMD to operate at demonstrated higher emissions levels while still meeting the performance requirements of Section K-1(c); and
(e) At the option of Seller, demonstration for a maximum of one hour that the gas turbine can be operated at the gas turbine manufacturer's specified oil-fired base load firing condition on No. 2 distillate fuel oil and demonstration of the capability of the fuel oil delivery system.
K-2. Definitions.
Hourly Corrected Electrical Generating Capacity (Kilowatts) is the combined gross output of the gas turbine and steam turbine-generators, measured at hourly intervals (excluding any readings rejected pursuant to Section K-3(d) at the generator terminals occurring at or corrected to the Guaranteed Operating Condition.
Average Corrected Electrical Generating Capacity is the numerical average of the Hourly Corrected Electrical Generating Capacity over the period of the test. However, for the purposes
-17-

of this definition the Hourly Corrected Electrical Generating Capacity for any hour is limited to the higher of 1) the Guaranteed Electrical Generating Capacity Band Upper Limit or 2) 103% of the resulting Average Corrected Electrical Generating Capacity.
Guaranteed Electrical Generating Capacity Band is expected KW gross plant output plus-or-minus an allowance for measurement error.
Hourly Corrected Fuel Consumption (Btu/hr) is the product of the fuel flow rate (1b/hr) measured at hourly intervals (excluding any readings rejected pursuant to Section K-3(d) and the measured fuel lower heating value (Btu/1b) for the natural gas supplied to the gas turbine when operating at or corrected to the Guaranteed Operating Condition.
Hourly Corrected Heat Rate (Btu/kwh) is the Hourly Corrected Fuel Consumption divided by the Hourly Corrected Electrical Generating Capacity.
Guaranteed Gross Plant Heat Rate Band is the expected gross plant heat rate plus-or-minus an allowance for measurement error.
Demonstrated Process Team Flow Rate (1b/hr) is the lowest ten-minute average process steam flow rate measured at the plant boundary during up to four ten-minute test periods. These tests will be made at, or the results will be corrected to, the Guaranteed Operating condition (including and adjustment for any steam delivered to the gas turbine for NOx control in excess of 82,700 1b/hr). The test periods will occur during the 40-day period of Test 2 at times which are mutually agreed to by the Seller and the contractor.
Guaranteed Process Team Flow Rate Band is the expected flow rate plus-or-minus an allowance for measurement error.
Guaranteed Operating Condition. The Guaranteed Operating condition is defined as follows:
(a) Ambient air dry bulb temperature of 59F.
(b) Ambient air wet bulb temperature of 50F.
(c) Gas turbine and steam turbine in a new and clean condition and operating at full load.
(d) Gas turbine fueled by natural gas (with heat content measured as lower heating value) as specified in the fuel specification.
(e) Process steam provided to Gilroy Foods at specified steam conditions.
-18-

(f) Steam injected into the gas turbine combuster at a specified injection rate.
(g) Return condensate received from Gilroy Foods at specified conditions.
(h) Evaporative cooler in operation (Above 50F dry bulb).
(i) Two circulating water pumps in operation.
(j) Auxiliary power consumption to include only items related to cogeneration plant operation.
(k) Generated electric power accepted by PGandE at the interface with an output power factor of not less than 0.9.
(l) Auxiliary boiler not in operation.
(m) Operation within applicable air quality standards as specified in the BAAQMD permit for the Facility.
K-3. Completion Test. The purpose of the Completion Test is to demonstrate the capability of the Facility to meet specified operating characteristics.
The Completion Test include the performance, availability and functional demonstrations as listed in Table K-1. Test 1 and Test 2, parts A, B and E will be conducted at the Guaranteed Operating Condition to the extent practical. For Test 2, parts C and D and Test 3, operating parameters will be adjusted from the Guaranteed Operating Condition as necessary to achieve the desired demonstration.
The Gas Turbine will have accumulated at least 100 fired hours of operation prior to the start of Test 1. The requirement does not apply to Test 2 or Test 3.
(a) Correction of Test Data to Guaranteed Operating Condition. For Test 1 and Test 2, parts A, B and E and Test 3, if the operating condition in any hour varies from the Guaranteed Operating condition, correction factors will be applied to calculate the Hourly Corrected Electrical Generating Capacity, Hourly Corrected Fuel Consumption and Demonstrated Process Steam Flow Rate. Correction factors will be developed by the Contractor as part of the procedure for executing the test. These will include correction factors for variation in ambient wet bulb and dry bulb temperatures and barometric pressure, process steam flow, injection steam flow and return condensate flow and temperature. Corrections for degradation in performance over time will be applied. The correction factors will be developed based on established engineering thermodynamic principles and on performance projections of Equipment Vendors.
-19-

The three tests listed in Table K-1 may be run in any sequence. Successfully completed tests are not required to be repeated following a subsequent unsuccessful attempt to pass any other of these three tests.
(b) Performance Criteria. The following criteria shall be used to determine successful completion of the Tests 1, 2 and 3.
Test 1. Test 1 has been successfully completed if the hourly Corrected Electrical Generating Capacity for each hour the 100 hour test is greater than or equal to the lower limit of the Guaranteed Electrical Generating Capacity Band and the Hourly Corrected Heat Rate for each hour the 100 hour test is less than or equal to the upper limit of the Guaranteed Gross Plant Heat Rate Band.
Test 2. Test 2 has been successfully completed if the Average Corrected Electrical Generating Capacity for the period comprised of i) Test 2, Part A,
ii) The 18 hours per day of full load operation of Test 2, Part B and iii) Test 2, Part E (852 hours total) is greater than or equal to 90% of the lower limit of the Guaranteed Electrical Generating Capacity Band.
Test 3. Test 3 has been successfully completed if the Demonstrated Process Steam Flow Rate is greater than or equal to the smaller of 1) the lower limit of the Guaranteed Process Steam Flow Rate Band or 2) the maximum steam flow which the Owner can accept, during up to four ten-minute periods during the 40-day period of Test 2.
(c) Performance Criteria for Facility Incorporating Selective Catalytic Reduction (SCR). The Guaranteed Electrical Generating Capacity Band and the Guaranteed Gross Plant Heat Rate Band will be modified if an SCR system is installed because of a failure of the General Electric Quiet Combuster.
(d) Instrumentation and Data. Permanent plant instrumentation supplemented as appropriate by temporary instrumentation supplied by the contractor shall be used for all required measurement. The contractor and Seller shall each be permitted to reject a total of five (5) hourly readings within the combined performance test period of Test 1 and Test 2, without affecting the validity of the demonstration.
(e) Test Procedures and Test Codes. At least twelve months prior to the start of the Completion Test, the Contractor shall make available a procedure outlining the execution of the test. The Completion Test method will be consistent with generally accepted industry practices and established ASME Power Test Codes to the extent applicable and necessary to accomplish the Completion Test objective.
- 20 -

K-4. Extended Warranty Performance Test. The purpose of the Extended Warranty Performance Test is to demonstrate the capability of the Facility to satisfy its Extended Warranty to performance. The Extended Warranty Performance Test will be a 100 hour test which is the same as Test 1 of the Completion Test as described in Section K-3. The measured test data will be corrected as described in Section K-3(A), including correction to account for expected degradation. The provisions of Sections K-3(d) and K-3(e) will apply to the Extended Warranty Performance Test.
(f) Performance Criteria. The Extended Warranty Performance Test has been successfully completed if the Hourly Corrected Electrical Generating Capacity of each hour of the test does not fail below the lower limit of the Guaranteed Electrical Generating Capacity Band reduced by any electrical generating capacity short fall for which the Owner has received liquidated damages and that the Hourly Corrected Heat Rate for each hour of the test does not exceed the upper limit of the Guaranteed Gross Plant Heat Rate Band increased by any excess in heat rate for which the Owner has received liquidated damages Remedy, in the case of both the electrical generating capacity and the heat rate as adjusted to expected degradation over time and adjusted for any degradation resulting from oil-fired operation.
IN WITNESS WHEREOF, the Parties hereto have caused this Second Amendment to be executed by their duly authorized representatives and it is effective as of the last date set forth below.
GILROY ENERGY COMPANY, INC. PACIFIC GAS AND ELECTRIC COMPANY

BY:       [SIG]                         BY: /s/ Robert Ohlbach
    ----------------------------            ----------------------------
    Title: President                        ROBERT OHLBACH
                                            Vice President and General Counsel

                                                    FOR

BY:       [SIG]
    ----------------------------
    Title:                                  MALCOLM H. FURBUSH
                                            Executive Vice President	

DATE SIGNED:  June 9, 1986              DATE SIGNED:  6- ???? - 86
              ------------------                      ------------------	

12928/20

AMENDMENT #3

THIRD AMENDMENT
TO
"LONG-TERM ENERGY AND CAPACITY
POWER PURCHASE AGREEMENT"
DATED DECEMBER 19, 1983, AS AMENDED
JULY 18, 1985 AND JUNE 9, 1986
PACIFIC GAS AND ELECTRIC COMPANY ("PG&E") and GILROY ENERGY COMPANY ("Seller") in consideration of the mutual agreements hereinafter set forth, and other good and valuable considerations, hereby amend said Agreement as follows:
1. Delete from Article 3(d), Page 5, Line 21, the following:
"130,000 kW"
and insert in lieu thereof --
"140,000 kW"
2. Delete from Article 3(f), Page 5, Line 27, the following:
"July 1, 1985"
and insert in lieu thereof --
"August 31, 1986"
3. Incremental Energy Rate Band Widths in Table I on Pages 9 and 10 as shown.

"Year           Incremental Energy Rate Band Widths
-----           -----------------------------------
 1987                           1600
 1988                            100
 1989                              0
 1990                              0
 1991                            100
 1992                            100
 1993                            200
 1994                            200
 1995                            200
 1996                            300
 1997                            300
 1998                            300"	

4. Insert the following information into Table B-3, Curtailment Option B, on Page B-18 as shown:

                                   "TABLE B-3

        Curtailment Option B:

                        Incremental           Upper                Lower
         Forecasted       Energy           Incremental          Incremental
        Incremental      Rate Band            Energy              Energy
          Energy        Width from          Rate Bound,         Rate Bound,
          Rates,         Article 4,           Btu/kWh             Btu/kWh
          Btu/kWh         Btu/kWh          [column (a)          [column (a)
Year        (a)             (b)         plus column (b) 1    minus column (b) 1
- ----    -----------     -----------     -----------------    ------------------
1984       9,440           -----              ------               -----
1985       9,500           -----              ------               -----

1986       9,280           -----              ------               -----
1987       9,290           1,600              10,890               7,690
1988       9,400             100               9,500               9,300

1989       9,270               0               9,270               9,270
1990       8,970               0               8,970               8,970
1991       8,970             100               9,070               8,870

1992       8,970             100               9,070               8,870
1993       8,970             200               9,170               8,770
1994       8,970             200               9,170               8,770

1995       8,970             200               9,170               8,770
1996       8,970             300               9,270               8,670
1997       8,970             300               9,270               8,670

1998       8,970             300               9,270               8,670"	

5. Pursuant to the provisions of Section F-1, the following is hereby inserted as Appendix I to the Agreement:
Attachment 1 of this Amendment 3 - PG&E Electric Rule 21 Effective June 20, 1984
6. Delete from Section F-2 the following:
"To be amended upon completion of interconnection studies."
and insert in lieu thereof --
Attachment 2 of this Amendment 3 - Point of Interconnection Location Sketch

7. Delete from Section F-3 the following:
"To be set forth herein upon completion of interconnection studies by PG&E."
and insert in lieu thereof --
"The following interconnection facilities will be installed by PG&E for Seller pursuant to the Special Facilities Agreement dated June 10, 1986 and revised on March 29, 1988. Seller's responsibility for these facilities will be in accordance with the terms and conditions of that revised Special Facilities Agreement.
o 115 kV wood pole line from the dead-end take-off structure of the Facility to our Llagas substation.
o Modifications to Llagas Substation.
o Reinforcement of the existing 115 kV tower line from Llagas substation to Metcalf substation.
o Protection modification to our system.
o Metering instruments and telemetering transmitter and receiver.
o All land right-of-say requirements for the above work.
o Other miscellaneous labor and related equipment to accomplish the above work."
8. Delete from Appendix H the following:
"TO BE AMENDED"
and insert in lieu thereof --
Attachment 3 of this Amendment - Sample Billing Calculations

IN WITNESS WHEREOF, the Parties hereto have caused this third Amendment to be executed by their duly authorized representatives and it is effective as of the last date set forth below.
PACIFIC GAS AND ELECTRIC COMPANY

By:  /s/ P. G. ROSPUT
    -------------------------------

Name:  Paula G. Rosput

Title: Manager - QF Contracts

Date:  August 18, 1988	

GILROY ENERGY COMPANY

By:  /s/ GEORGE G. PENDERGAST
    -------------------------------

Name: George G. Pendergast

Title: Cogen Operations Manager

Date:  7/20/88	

ATTACHMENT 1
OF
AMENDMENT 3
Electric Rule #21

APPENDIX I
PGandE's ELECTRIC RULE #21
Effective June 20, 1984

Pacific Gas and Electric Company            Revised Cal. P.U.C. Sheet No. 8616-E
   San Francisco, California     Canceling Original Cal. P.U.C. Sheet No. 7693-C
- --------------------------------------------------------------------------------	

RULE NO. 21 -- NONUTILITY-OWNED PARALLEL GENERATION

This describes the minimum operation, metering and interconnection requirements for any generating source or sources paralleled with the Utility's electric system. Such source or sources may include, but are not limited to, hydroelectric generators, wind-turbine generators, steam or gas driven turbine generators and photovoltaic systems.
A. GENERAL
1. The type of interconnection and voltage available at any location and the Utility's specific interconnection requirements shall be determined by inquiry at the Utility's local office.
2. The Utility's distribution and transmission lines which are an integral part of its overall system are distinguished by the voltages at which they are operated. Distribution lines are operated at voltages below 60 kv and transmission lines are operated at voltages 60 kv and higher.
3. The Power Producer (Producer) shall ascertain and be responsible for compliance with the requirements of all governmental authorities having jurisdiction.
4. The Producer shall sign the Utility's written form of power purchase agreement or parallel operation agreement before connecting or operating a generating source in parallel with the Utility's system.
5. The Producer shall be fully responsible for the costs of designing, installing, owning, operating and maintaining all interconnection facilities defined in Section B.1.
6. The Producer shall submit to the Utility, for the Utility's review and written acceptance, equipment specifications and detailed plans for the installation of all interconnection facilities to be furnished by the Producer prior to their purchase or installation. The Utility's review and written acceptance of the Producer's equipment specifications and detailed plans shall not be construed as confirming or endorsing the Producer's design or as warranting the equipment's safety, durability or reliability. The Utility shall not, be reason of such review or lack of review, be responsible for strength, details of design adequacy, or capacity of equipment built pursuant to such specifications, nor shall the Utility acceptance be deemed an endorsement of any such equipment.
7. No generating source shall be operated in parallel with the Utility's system until the interconnection facilities have been inspected by the Utility and the Utility has provided written approval to the Producer.
8. Only duly authorized employees of the Utility are allowed to connect Producer-installed interconnection facilities to, or disconnect the same from, the Utility's overhead or underground lines.
B. INTERCONNECTION FACILITIES
1. GENERAL: Interconnection facilities are all means required, and apparatus installed, to interconnect the Producer's generation with the Utility's system. Where the Producer desires to sell power to the Utility, interconnection facilities are also all means required, and apparatus installed, to enable the Utility to receive power deliveries from the Producer. Interconnection facilities may include, but are not limited to:
a. connection, transformation, switching, metering, communications, control, protective and safety equipment; and
b. any necessary additions to and reinforcements of the Utility's system by the Utility.
2. METERING

                a.      A Producer desiring to sell power to the Utility shall
                        provide, install, own and maintain all facilities
                        necessary to accommodate metering equipment specified by
                        the Utility.  Such metering equipment may include
                        meters, telemetering (applicable where deliveries to the
                        Utility exceed 10 Mt) and other recording and
                        communications devices as may be required for the
                        reporting of power delivery date to the Utility.  Except
                        as provided for in Section B.2.b following, the Utility
                        shall provide, install, own and maintain all metering
                        equipment as special facilities in accordance with
                        Section F.

                                                                (Continued)
- --------------------------------------------------------------------------------
Advice Letter No. 1025-E            Issued              Date Filed May 21, 1984
Decision No. 83-10-093           W.M. Gallavan          Effective June 20, 1984
                                 Vice-President         Resolution No._________
                          Rates and Economic Analysis	

Pacific Gas and Electric Company Revised Cal.P.U.C. Sheet NO. 8617-E San Francisco, California Cancelling Original Cal.P.U.C. Sheet No. 7696-F
RULE NO. 21 -- NONUTILITY-OWNED PARALLEL GENERATION (Cont'd.)
B. INTERCONNECTION FACILITIES (continued)
2. METERING
b. The Producer may at its option provide, install, own and maintain current and potential transformers rated above 600 volts and a non-revenue type graphic recorder where applicable. Such metering equipment, its installation and maintenance shall be in conformance with the Utility's specifications.
c. The Utility's meters shall be equipped with detents to prevent reverse registration so that power deliveries to and from the Producer's equipment can be separately recorded.
3. CONTROL, PROTECTION AND SAFETY EQUIPMENT
a. GENERAL: The Utility has established functional requirements essential for safe and reliable parallel operation of the Producer's generation. These requirements provide for control, protective and safety equipment to:
(1) sense and properly react to failure and malfunction on the Utility's system;
(2) assist the Utility in maintaining its system integrity and reliability; and
(3) protect the safety of the public and the Utility's personnel.
b. Listed below are the various devices and features generally required by the Utility as a prerequisite to parallel operation of the Producer's generation:
CONTROL, PROTECTION AND SAFETY EQUIPMENT GENERAL REQUIREMENTS(1)

                                                                    GENERATOR SIZE
                                        -----------------------------------------------------------------------
                                        10 kw or    11 kw to     41 kw to    101 kw to    401 kw to      over
Device or Feature                         Less       40 kw        100 kw      400 kw       1,000 kw    1,000 kw
- -----------------                       --------    --------     --------    ---------    ---------    --------
Dedicated Transformer                       -           X            X           X             X           X
Interconnection Disconnect Device           X           X            X           X             X           X
Generator Circuit Breaker                   X           X            X           X             X           X
Overvoltage Protection                      X           X            X           X             X           X
Undervoltage Protection                     -           -            X           X             X           X
Under/Over-frequency Protection             X           X            X           X             X           X
Ground Fault Protection                     -           -            X           X             X           X
Over-current Relay w/Voltage Restraint      -           -            -           -             X           X
Synchronizing                             Manual      Manual       Manual      Manual        Manual    Automatic
Power Factor or Voltage Regulation                                   X           X             X           X	

c. DISCONNECT DEVICE: The Producer shall provide, install, own and maintain the interconnection disconnect device required by
Section 8.3.b at a location readily accessible to the Utility. Such device shall normally be located near the Utility's meter or meters for sole operation by the Utility. The interconnection disconnect device and its precise location shall be specified by the Utility. At the Producer's option and request, the Utility will provide, install, and maintain the disconnect device on the Utility's system as special facilities is accordance with Section F.

1. Detailed requirements are specified in the Utility's current operating, metering and equipment protection publications, as revised from time to time by the Utility and available to the Producer upon request. For a particular generator application, the Utility will furnish its specific control, protective and safety requirements to the Producer after the exact location of the generator has been agreed upon and the interconnection voltage level has been established.
2. This is a transformer interconnected with no other Producers and serving no other Utility customers. Although the dedicated transformer is not a requirement for generators rated 10 kw or less, its installation is recommended by the Utility.
3. This is a requirement for synchronous and other types of generators with stand-alone capability. for all such generators, the Utility will also require the installation of "reclose blocking" features on its system to block certain operations of the Utility's automatic line restoration equipment.
Advice Letter No. 1025-E Issued By Date Filed May 21, 1984 Decision No. 83-10-093 W.M. Gallavan Effective June 20, 1984 Vice President Resolution No.
Rates and Economic Analysis

Pacific Gas and Electric Company           Original Cal. P.U.C. Sheet No. 8618-E
   San Francisco, California      Cancelling ______ Cal. P.U.C. Sheet No. ______
- --------------------------------------------------------------------------------	

RULE NO. 21 -- NONUTILITY-OWNED PARALLEL GENERATION (Cont'd.)
B. INTERCONNECTION FACILITIES (continued)
4. UTILITY SYSTEM ADDITIONS AND REINFORCEMENTS
a. Except as provided for in Section B.5, all additions to and reinforcements of the Utility's system necessary to interconnect with and receive power deliveries from the Producer's generation will be provided, installed, owned and maintained by the Utility as special facilities in accordance with Section F. Such additions and reinforcements may include the installation of a Utility distribution or transmission line extension or the increase of capacity in the Utility's existing distribution or transmission lines. The Utility shall determine whether any such additions or reinforcements shall include an increment of additional capacity for the Utility's use in furnishing service to its customers. If so, then the costs of providing, installing, owning and maintaining such additional capacity shall be borne by the Utility and/or its customers in accordance with the Utility's applicable tariffs on file with and authorized by the California Public Utilities Commission (Commission).
b. The Producer shall advance to the Utility its estimated costs of performing a preliminary or detailed engineering study as may be reasonably required to identify any Producer related Utility system additions and reinforcements. Where such preliminary or detailed engineering study involves analysis of the Utility's transmission lines (60 kv and higher), the Utility shall complete its study within twelve calendar months of receiving all necessary plans and specifications from the Producer.

        5.      PRODUCER-INSTALLED UTILITY-OWNED LINE EXTENSIONS:  The Producer
                may at its option provide and install an extension of the
                Utility's distribution or transmission lines where required to
                complete the Producer's interconnection with the Utility.  Such
                extension shall be installed by contractors approved by the
                Utility and in accordance with its design and specifications.
                The Producer shall pay the Utility its estimated costs of
                design, administration and inspection as may be reasonably
                required to assure such extension is installed in compliance
                with the Utility's requirements. Upon final inspection and
                acceptance by the Utility, the Producer shall transfer ownership
                of the line extension to the Utility where thereafter it shall
                be owned and maintained as special facilities in accordance with
                Section F.  This provision does not preclude the Producer from
                installing, owning and maintaining a distribution or
                transmission line extension as part of its other Producer-owned
                interconnection facilities.

        6.      COSTS OF FUTURE UTILITY SYSTEM ALTERATIONS:  The Producer shall
                be responsible for the costs of only those future Utility system
                alterations which are directly related to the Producer's
                presence or necessary to maintain the Producer's interconnection
                in accordance with the Utility's applicable operating, metering
                and equipment publication in effect when the Producer and the
                Utility entered into a written form of power purchase agreement.
                Alterations made at the Producer's expense shall specifically
                exclude increases of existing line capacity necessary to
                accommodate the other Producers or Utility customers.  Such
                alterations may, however, include relocation or undergrounding
                of the Utility's distribution or transmission lines as may be
                ordered by a governments(1) authority having jurisdiction.

        7.      ALLOCATION OF THE UTILITY'S EXISTING LINE CAPACITY:  For two or
                more Producers seeking to use an existing line, a first come,
                first served approach shall be used.  The first Producer to
                request an interconnection shall have the right to use the
                existing line and shall incur no obligation for costs associated
                with future line upgrades needed to accommodate other Producers
                or customers.  The Utility's power purchase agreement shall
                specify the date by which the Producer must begin construction.
                If that date passes and construction has not commenced, the
                Producer shall be given 30 days to correct the deficiency after
                receiving a reminder from the Utility that the construction
                start-up date has passed.  If construction has not commenced
                after the 30-day corrective period, the Utility shall have the
                right to withdraw its commitment to the first Producer and offer
                the right to interconnect on the existing line to the next
                Producer in order.  If two Producers establish the right of
                first-in-time simultaneously, the two Producers shall share the
                costs of any additional line upgrade necessary to facility their
                cumulative capacity requirements.  Costs shall be shared based
                on the relative proportion of capacity each Producer will add to
                the line.

                                                                     (Continued)
- --------------------------------------------------------------------------------
Advice Letter No. 1025-E         Issued By               Date Filed May 21, 1984
Decision No. 83-10-093         W. M. Gallavan            Effective June 20, 1984
                               Vice-President            Resolution No. ________
   JONE02(J18) p.3      Rates and Economic Analysis	

Pacific Gas and Electric Company            Revised Cal. P.U.C. Sheet No. 8619-E
   San Francisco, California    Cancelling Original Cal. P.U.C. Sheet No. 7695-E
- --------------------------------------------------------------------------------	

RULE NO. 21 -- NONUTILITY-OWNED PARALLEL GENERATION (Cont'd.)
C. ELECTRIC SERVICE FROM THE UTILITY: If the Producer requires regular, supplemental, interruptible or standby service from the utility, the Producer shall enter into separate contractual arrangements with the Utility in accordance with the Utility's applicable electric tariffs on file with and authorized by the Commission.
D. OPERATION
1. PREPARALLEL INSPECTION: In accordance with Section A.7, the Utility will inspect the Producer's interconnection facilities prior to providing it with written authorization to commence parallel operation. Such inspection shall determine whether or not the Producer has installed certain control, protective and safety equipment to the Utility's specifications. Where the Producer's generation has a rated output in excess of 100 kw, the Producer shall pay the Utility its estimated costs of performing the inspection.
2. JURISDICTION OF THE UTILITY'S SYSTEM DISPATCHER: The Producer's generation while operating in parallel with the Utility's system is at all times under the jurisdiction of the Utility's system dispatcher. The system dispatcher shall normally delegate such control to the Utility's designated switching center.
3. COMMUNICATIONS: The Producer shall maintain telephone service from the local telephone company to the location of the Producer's generation. In the event such location is remote or unattended, telephone service shall be provided to the nearest building normally occupied by the Producer's generator operator. The Utility and the Producer shall maintain operating communications through the Utility's designated switching center.
4. GENERATOR LOC: The Producer shall at all times keep and maintain a detailed generator operations log. Such log shall include, but not be limited to, information on unit availability, maintenance outages, circuit breaker trip operations requiring manual reset and unusual events. The Utility shall have the right to review the Producer's log.
5. REPORTING ABNORMAL CONDITIONS: The Utility shall advise the Producer of abnormal conditions which the Utility has reason to believe could affect the Utility's operating conditions or procedures. The Producer shall keep the Utility similarly informed.
6. POWER FACTOR: The Producer shall furnish reactive power as may be reasonably required by the Utility.
a. The Utility reserves the right to specify that generators with power factor control capability, including synchronous generators, be capable of operating continuously at any power factor between 95 percent leading (absorbing vars) and 90 percent lagging (producing vars) at any voltage level within a 5.0 percent of rated voltage. For other types of generators with no inherent power factor control capability, the Utility reserves the right to specify the installation of capacitors by the Producer to correct generator output to near 95 percent leading power factor. The Utility may also require the installation of switched capacitors on its system to produce reactive support equivalent to that provided by operating a synchronous generator of the same size between 95 percent leading and 90 percent lagging power factor.
b. Where either the Producer or the Utility determines that it is not practical for the Producer to furnish the Utility's required level of reactive power or when the Utility specifies switched capacitors in its system pursuant to Section D.6.o, the Utility will provide, install, own and maintain the necessary devices on its system in accordance with Section F.
E. INTERFERENCE WITH SERVICE AND COMMUNICATION FACILITIES

        1.      GENERAL:  The Utility reserves the right to refuse to connect to
                any new equipment or to remain connected to any existing
                equipment of a size or character that may be detrimental to the
                Utility's operations or service to its customers.

                                                                     (Continued)
- --------------------------------------------------------------------------------
Advice Letter No. 1025-E         Issued By               Date Filed May 21, 1984
Decision No. 83-10-093         W. M. Gallavan            Effective June 20, 1984
                               Vice-President            Resolution No. ________
   JONE02(J18) p.4      Rates and Economic Analysis	

Pacific Gas and Electric Company            Revised Cal. P.U.C. Sheet No. 8620-E
   San Francisco, California    Cancelling Original Cal. P.U.C. Sheet No. 7695-E
- --------------------------------------------------------------------------------	

RULE NO. 21 -- NONUTILITY-OWNED PARALLEL GENERATION (Cont'd.)
E. INTERFERENCE WITH SERVICE AND COMMUNICATION FACILITIES (continued)
2. The Producer shall not operate equipment that superimposes upon the Utility's system a voltage or current which causes interference with the Utility's operations, service to the Utility's customers or interference to communication facilities. If the Producer causes service interference to others, the Producer must diligently pursue and take corrective action at the Producer's expense after being given notice and reasonable time to do so by the Utility. If the Producer does not take timely corrective action, or continues to operate the equipment causing the interference without restriction or limit, the Utility may, without liability, disconnect the Producer's equipment from the Utility's system until a suitable permanent solution provided by the Producer is operational at the Producer's expense.
F. SPECIAL FACILITIES

        1.      Where the Producer requests the Utility to furnish
                interconnection facilities or where it is necessary to make
                additions to or reinforcements of the Utility's system and the
                Utility agrees to do so, such facilities shall be deemed to be
                special facilities and the costs thereof shall be borne by the
                Producer, including such continuing ownership costs as may be
                applicable.

        2.      Special facilities are (a) those facilities installed at the
                Producer's request which the Utility does not normally furnish
                under its tariff schedules, or (b) a prorata portion of existing
                facilities requested by the Producer, allocated for the sole use
                of such Producer, which would not normally be allocated for such
                sole use.  Unless otherwise provided by the Utility's filed
                tariff schedules, special facilities will be installed, owned
                and maintained or allocated by the Utility as an accommodation
                to the Producer only if acceptable for operation by the Utility
                and the reliability of service to the Utility's customers is not
                impaired.

        3.      Special Facilities will be furnished under the terms and
                conditions of the Utility's "Agreement for Installation or
                Allocation of Special Facilities for Parallel Operation of
                Nonutility-owned Generation and/or Electrical Standby Service"
                (Form 79-280, effective June 1984) and its Appendix A, "Detail
                of Special Facilities Charges" (Form 79-702, effective June
                1984).  Prior to the Producer signing such an agreement, the
                Utility shall provide the Producer with a breakdown of special
                facilities costs in a form having detail sufficient for the
                information to be reasonably understood by the Producer.  The
                special facilities agreement will include, but is not limited
                to, a binding quotation of charges to the Producer and the
                following general terms and conditions:

                a.      Where facilities are installed by the Utility for the
                        Producer's use as special facilities, the Producer shall
                        advance to the Utility its estimated installed cost of
                        the special facilities.  The amount advanced is subject
                        to the monthly ownership charge applicable to
                        customer-financed special facilities as set forth in
                        Section I of the Utility's Rule No. 2.

                b.      At the Producer's option, and where such Producer's
                        generation is a qualifying facility(4) and the Producer
                        has established credit worthiness to the Utility's
                        satisfaction, the Utility shall finance those special
                        facilities it deems to be removable and reusable
                        equipment.  Such equipment shall include, but not be
                        limited to, transformation, disconnection and metering
                        equipment.

                c.      Existing facilities allocated for the Producer's use as
                        special facilities and removable and reusable equipment
                        financed by the Utility in accordance with Section F.3.b
                        are subject to the monthly ownership charge applicable
                        to Utility-financed special facilities as set forth in
                        Section I of Rule 2.

- ------------------------
(4) A qualifying facility is one which meets the requirements established by
the Federal Energy Regulatory Commission's rules (18 Code of Federal Regulations
292) implementing the Public Utility Regulatory Policies Act of 1978 (16
U.S.C.A. 796, et seq.).

                                                                     (Continued)
- --------------------------------------------------------------------------------
Advice Letter No. 1025-E         Issued By               Date Filed May 21, 1984
Decision No. 83-10-093         W. M. Gallavan            Effective June 20, 1984
                               Vice-President            Resolution No. ________
   JONE02(J18) p.5      Rates and Economic Analysis	

Pacific Gas and Electric Company           Original Cal. P.U.C. Sheet No. 8621-E
   San Francisco, California      Cancelling ______ Cal. P.U.C. Sheet No. ______
- --------------------------------------------------------------------------------	

RULE NO. 21 -- NONUTILITY-OWNED PARALLEL GENERATION (Cont'd.)
F. SPECIAL FACILITIES (continued)

                d.      Where the Producer elects to install and deed to the
                        Utility an extension of the Utility's distribution or
                        transmission lines for use as special facilities in
                        accordance with Section 8.5, the Utility's estimate of
                        the installed cost of such extension shall be subject to
                        the monthly ownership charge applicable to
                        customer-financed special facilities as set forth in
                        Section I of the Rule No. 2.

        4.      Where payment or collection of continuing monthly ownership
                charges is not practicable, the Producer shall be required to
                make an equivalent one-time payment in lieu of such monthly
                charges.

        5.      Costs of special facilities borne by the Producer may be subject
                to downward adjustment when such special facilities are used to
                furnish permanent service to a customer of the Utility.  This
                adjustment will be based upon the extension allowance or other
                such customer allowance which the Utility would have utilized
                under its then applicable tariffs if the special facilities did
                not otherwise exist.  In no event shall such adjustment exceed
                the original installed cost of that portion of the special
                facilities used to serve a new customer.  An adjustment, where
                applicable, will consist of a refund applied to the Producer's
                initial payment for special facilities and/or a corresponding
                reduction of the ownership charge.

G.      EXCEPTIONAL CASES:  Where the application of this rule appears
        impractical or unjust, the Producer may refer the matter to the
        Commission for special ruling or for the approval of special conditions.

H.      INCORPORATION INTO POWER PURCHASE AGREEMENTS:  Pursuant to Decision No.
        83-10-093, if in accordance with Section A.4 the Producer enters into a
        written form of power purchase agreement with Utility, a copy of the
        Rule No. 21 in effect on the date of execution will be appended to, and
        incorporated by reference into, such power purchase agreement.  The Rule
        appended to such power purchase agreement shall then be applicable for
        the term of the Producer's power purchase agreement with the Utility.
        Subsequent revisions to this rule shall not be incorporated into the
        rule appended to such power purchase agreement.

- --------------------------------------------------------------------------------
Advice Letter No. 1025-E         Issued By               Date Filed May 21, 1984
Decision No. 83-10-093         W. M. Gallavan            Effective June 20, 1984
                               Vice-President            Resolution No. ________
   JONE02(J18) p.6      Rates and Economic Analysis	

ATTACHMENT 2
OF
AMENDMENT 3
Point of Interconnection Location Sketch

F-2 POINT OF INTERCONNECTION LOCATION SKETCH
[POINT OF INTERCONNECTION LOCATION SKETCH]
F-3 S.O. #4
December 5, 1983

ATTACHMENT 3
OF
AMENDMENT 3
Sample Billing Calculations

APPENDIX H
Sample Billing Calculations
1. Assumptions and Sample Billing for October 1988, Pursuant to the Standard Offer No. 4 Agreement.
2. Assumptions and Sample Calculation for the 1988 Year-End Adjustment, Pursuant to Energy Payment Option 3 of the Standard Offer No. 4 Agreement.
3. Assumptions and Sample Billing for March 1988, Pursuant to Appendix J.
4. Assumptions and Sample Billing for October 1988, Pursuant to Appendix J (Scheduled to Run During Period 2).
5. Assumptions and Sample Billing for October 1988, Pursuant to Appendix J (Scheduled not to Run During Period 2).
All sample billings and calculations represent PG&E's current interpretation of the terms and conditions of this Agreement but are not intended to be a commitment on the part of the Parties.

Standard Offer #4 Sample Billing Assumptions
Month: October, Period A (21 weekdays, 5 Saturdays & 5 Sundays)

Generation                              Hours           Gen (kW-hr)
- ----------                              -----           -----------
  On Peak               Weekday          126            15,138,432
  Part Peak             Weekday          147            17,364,672
  Off Peak              Weekday          147            17,631,821
                        Weekend          200            24,043,392
  Super Off Peak        All days         124            14,871,283
                                         ---            ----------
  Total                                  744            89,049,600	

Capacity Assumptions
 Firm: 120 MW (current allocation factors) As-Delivered in Excess of Firm: Option 2 Bonus: 4 percent
Term: 30 years
Firm Capacity Availability: 1988
Capacity Price: $172/kW-yr
Capacity Loss Adjustment: 0.989
As-Delivered Capacity Price: $102/kW-yr (current allocation) Scheduled Maintenance Hours: 0

Energy Assumption

Option 3
Curtailment Option B (no curtailment in October)
Current Assumption for G-55, Revenue Requirement for Cash Working Capital, IER and Geothermal Adder
Generation in Excess of 120,000 kW

                                                Gen. (kW-hr)
                                                -----------
                On Peak            Weekday         13,100
                Part Peak          Weekday         15,000
                Off Peak           Weekday        128,000
                Super Off Peak     All Days        36,000	

- --------------------------------------------------------------------------------
                        PACIFIC GAS AND ELECTRIC COMPANY
               STATEMENT OF CAPACITY AND ELECTRIC POWER PURCHASED
- --------------------------------------------------------------------------------
ACCOUNT NUMBER:  JTK-T2-10001                           DATE:  NOVEMBER 30, 1988
- --------------                                          ----
                 MAILING ADDRESS:       Gilroy Energy Company, Inc.
                                        Attn:  President
                                        1350 Pacheco Pass Highway
                                        Gilroy, CA 95020

                  REMIT CHECK TO:       Gilroy Energy Company, Inc.
                                        Attn:  President
                                        1350 Pacheco Pass Highway
                                        Gilroy, CA 95020
- --------------------------------------------------------------------------------	

Payment computations are in accordance with the Power Purchase Agreement between Gilroy Energy Company, Inc. (thermal facility in Gilroy) and PGandE dated December 19, 1983.
METERING INFORMATION

Net Energy Delivered
- --------------------
                        Read       Read       Diff.     Const.   Killowatthours
                        ----       ----       -----     ------   --------------

Billing Period          10/31/88   10/1/99
Meter No. 6890T7          4857.9    3621.1    1236.8    72,000     89,049,600	

Payment Calculation for Net Energy
 Billing Period: October 1 - 31, 1988
- --------------
                                Energy Delivered      Rate
                % Delivered        To PGandE        Period A      Payment
                -----------     ----------------    --------      -------
On Peak:           17.0            15,138,432        $.03100    $469,291.79
Partial Peak:      19.5            17,364,672         .03032     526,496.56
Off Peak:          46.8            41,675,213         .02916   1,215,249.21
Super Off Peak:    16.7            14,871,283         .02707     402,565.23
                                   ----------                 -------------
                                   89,049,600                 $2,613,603.49

Payment Calculation for Capacity
- --------------------------------
              32,475,004
F = ----------------------------   =         1.00
    120,000 x (275 - 0) x (1-.2)                  (F not to exceed 1.0)
     Therefore F =     1.00
          Factor =     1.00 x (1.0 - 0/744)=           1.00
Monthly Delivered Capacity =       120,000 x 1.00 = 120,000 kw

Period A:      120,000 kw x $172 x .166275 x .989 x   1.040 = $3,529,931.53

Payment Calculation for As Delivered Capacity
- ---------------------------------------------
                KWH's Delivered                         Allocation
                to PGandE Above             Loss Adj.     Factors    Payment
                Firm Capacity      F.S.C     Factor      Period A    (Cents)
                ---------------    -----    ---------   ----------   -------
On Peak:             13,100         102        .989       .11210     148,140
Partial Peak:        15,000         102        .989       .01510      22,849
Off Peak:           128,000         102        .989       .00000           0
Super Off Peak:      36,000         102        .989       .00000           0
                                                                     -------
                                                                     170,989

As Delivered Capacity Payment                                =     $1,709.85

Total Capacity Payment = $3,529,931.52 + 1,709,89            = $3,531,641.41

Total Energy Payment                                         =  2,613,603.09
                                                               -------------
Total Amount Due                                             = $6,145,244.50	

D. A. BRAND
Power Control
3/10/1987
J. Kovnas

1988 Year-End Adjustment Pursuant to Energy Payment Option 3
GILROY ENERGY COMPANY
Shown below is an example of an annual calculation of Gilroy Energy Company's energy payment adjustment in accordance with Article 4 of the Power Purchase Agreement (PPA).
B
Derived Incremental Energy Rate (DIER) = ------------- A x C
Where:
A = The total kWh delivered by Gilroy Energy Company during the calendar year, excluding any kWh delivered when Gilroy Energy Company was asked to curtail deliveries under Curtailment Option B.
B = The total kWh dollars paid for the energy described for A above.
C = The weighted average price paid during the calendar year by PG&E's Electric Department for oil and natural gas for PG&E's fossil steam plants, expressed in $/Btu on a gas Btu basis.
If the DIER is between the upper and lower Incremental Energy Rate Bounds specified for that year in Table B-3 of the PPA for the curtailment option selected by Gilroy Energy Company, no additional payment is due either Party.
If the DIER is below the lower Incremental Energy Rate Bound, PG&E shall pay Gilroy Energy Company an amount calculated as follows:
(Lower Incremental Energy Rate Bound - DIER) (A) (C)
If the DIER is above the upper Incremental Energy Rate Bound, Gilroy Energy Company shall pay PG&E an amount calculated as follows:
(DIER - Upper Incremental Energy Rate Bound) (A) (C)
Therefore, for the period covering 1/1/88 to 12/31/88, the annual calculation is as follows:
$32,328,174.00
DIER = ----------------------------
775,599,916 kWh x 2.654/MM Btu
= 10,847 Btu/kWh
Since the DIER is above the upper (9,500) Incremental Energy Rate Bound, additional payment due PG&E is calculated.
= ( 10,847 - 9,500) x 775,559,916 x 2.654 / MM Btu
= $2,772,721.61
Power Control
11/10/87

Appendix J Sample Billing Assumptions Period 1
Month: March, Period B (23 weekdays, 4 Saturdays & 4 Sundays)

Generation                              Hours           Gen (kW-hr)
- ----------                              -----           -----------
  Part Peak             Weekday          299            35,280,000
  Off Peak              Weekday          161                     0
                        Weekend          160                     0
  Super Off Peak        All days         124                     0
                                         ---            ----------
  Total                                  744            35,280,000	

Capacity Assumptions
 Firm Capacity: 120 MW (current allocation factors) Current Price: $160/kW-yr
As-Delivered in Excess of Firm: Option 2 Bonus: 4 percent (from 1987)
Term: 30 years
Firm Capacity Availability: 1987
Capacity Loss Adjustment: 0.989
As-Delivered Capacity Price: $102/kW-yr (current allocation) Delivered all hours at appropriate levels when scheduled by PGandE Forced Outage = 40 hours off peak
Scheduled Maintenance: 40 hours off peak

Energy Assumption
 Payment Heat Rate at 100%: 8,550 Btu/kW-hr G-55 = $3/MMBtu (current month)
Scheduled Dispatch: 23 days, @ 100%

Startup Assumptions
 No. Startup = 23
Price of G-55 = $3/MMBtu (preceding month) Price of gas in July 1985 = $5.229/MMBtu

- ------------------------------------------------------------------------------
                        PACIFIC GAS AND ELECTRIC COMPANY
               STATEMENT OF CAPACITY AND ELECTRIC POWER PURCHASED
- ------------------------------------------------------------------------------
ACCOUNT NUMBER:  JTK-T2-10001                   DATE:   APRIL 30, 1988
- --------------                                  ----

                 MAILING ADDRESS:       Gilroy Energy Company, Inc.
                                        Attn: President
                                        1350 Pacheco Pass Highway
                                        Gilroy, CA 95020

                 REMIT CHECK TO:        Gilroy Energy Company, Inc.
                                        Attn: President
                                        1350 Pacheco Pass Highway
                                        Gilroy, CA 95020
- ------------------------------------------------------------------------------	

Payment computations are in accordance with the Power Purchase Agreement between Gilroy Energy Company, Inc. (thermal facility in Gilroy) and PGandE dated December 19, 1983.
Billing Period: March 1 - 31, 1988
METERING INFORMATION

Net Energy Delivered
- --------------------    Read        Read      Diff.     Const.    Kilowatthours
                        ----        ----      -----     ------    -------------
Billing Period          3/31/88     3/1/88
Meter No. 6890T7          903.2      413.2     490      72,000      35,280,000	

                                      Energy Delivered
                    % Delivered          To PGandE
                    -----------       ----------------
Partial Peak:         100.0             35,280,000
Off Peak:                .0                      0
Super Off Peak:          .0                      0
                                        ----------
                                        35,280,000	

Payment Calculation for Net Energy and Start-ups during Period 1

Energy Payment

Energy Delivered                        Heat Rate
   To PGandE            $/MMBTU         BTU/KWH         Payment
- ----------------        -------         ---------       -------
    35,280,000             3            8,550           $904,932.00	

Start-up Payment
- ----------------

                        Start-up        $/MMBTU$ [div]
Total Start-ups          Charge         $5.229/MMBTU$$       Payment
- ------------------      --------        --------------       -------
        23               $6,500         3 [div] 5.229        $85,771.66	

$ Weighted average price paid during previous month by PGandE's Electric Department for oil and natural gas for PGandE's fossil steam plants.
$$ Average price paid during July 1985 by PGandE's Electric Department for oil and natural gas for PGandE's fossil steam plants.

Payment Calculation for Capacity

Firm Capacity Availability
I. AV = 100 (H-T-SM) / (H-SM) = 100 (744-40-40)/744-40) AV = 94.3%
II. AF = ((AV-50)/60) + 0.5 = ((94.3 - 50)/60) + 0.5 AF = 1.24 (AF not to exceed 1.0) Therefore; AF = 1.0

Firm Capacity Payment
- ---------------------

Capacity Payment = PPF  x  Firm  x  Capacity  x  Performance  x  AF
                         Capacity     Loss          Bonus
                                   Adjustment	

= $.06 (.0003917 x $160) x 120,000 x .989 x 1.04 x 1.0 = $7,405.63
Payment Calculation for As Delivered Capacity

                     KWH's Delivered                            Allocation
                     to PGandE Above              Loss Adj.       Factors          Payment
                      Firm Capacity     F.S.C.     Factor        Period B          (Cents)
                     ---------------    ------    ---------     -----------        -------
Partial Peak:             15,000         102        .989          .00010               151
Off Peak:                      0         102        .989          .00000                 0
Super Off Peak:                0         102        .989          .00000                 0
                                                                               -----------
                                                                                       151

As Delivered Capacity Payment                                             =    $      1.51
Total Capacity Payment  =    =   $7,405.63  +   $1.51                     =    $  7,407.14
Total Energy Payment                                                      =     904,932.00
Total Start-up Payment                                                    =      85,771.66
                                                                               -----------
                                                Total Amount Due          =    $998,110.80	

D. A. BRAND
Power Control
4/9/1987
J. Kovnas

Appendix J Sample Billing Assumptions Periods 2 and 3
Month: October, Period A (21 weekdays, 5 Saturdays & 5 Sundays)

Generation                              Hours      Gen (kW-hr)
- ----------                              -----      -----------
 On Peak                Weekday          126       15,054,480
 Part Peak              Weekday          147       17,279,280
 Off Peak               All days         347       34,261,920
 Super Off Peak         All days         124        7,564,320
                                         ---       ----------
 Total                                   744       74,160,000	

Capacity Assumptions
Firm: 120 MW (current allocation factors) As-Delivered in Excess of Firm: Option 2 Bonus: 4 percent
Term: 30 years
Firm Capacity Availability: 1988
Capacity Price: $172/kW-yr
Capacity Loss Adjustment: 0.989
As-Delivered Capacity Price: $102/kW-yr (current allocation) Delivered all hours at appropriate levels when scheduled by PGandE including 11
p.m. to 5 a.m. designated as six contiguous off peak hours (except forced outage). Forced Outage: 40 hours in super off peak Scheduled Maintenance Hours: 0
Energy Assumption
G-55 = $3/MMBtu (current month)
Scheduled at 100%, 24 hours per day
Payment IER: 9,400 Btu/kW-hr
Adder for 1988: 17 percent
Shutdown Assumptions
No. of Shutdowns: 0

- ------------------------------------------------------------------------------
                        PACIFIC GAS AND ELECTRIC COMPANY
               STATEMENT OF CAPACITY AND ELECTRIC POWER PURCHASED
- ------------------------------------------------------------------------------
ACCOUNT NUMBER:  JTK-T2-10001                   DATE:   NOVEMBER 30, 1988
- --------------                                  ----

                 MAILING ADDRESS:       Gilroy Energy Company, Inc.
                                        Attn: President
                                        1350 Pacheco Pass Highway
                                        Gilroy, CA 95020

                 REMIT CHECK TO:        Gilroy Energy Company, Inc.
                                        Attn: President
                                        1350 Pacheco Pass Highway
                                        Gilroy, CA 95020
- ------------------------------------------------------------------------------	

Payment computations are in accordance with the Power Purchase Agreement between Gilroy Energy Company, Inc. (thermal facility in Gilroy) and PGandE dated December 19, 1983.
Billing Period: October 1 - 31, 1988
METERING INFORMATION

Net Energy Delivered
- --------------------    Read        Read      Diff.     Const.    Kilowatthours
                        ----        ----      -----     ------    -------------
Billing Period         10/31/88     10/1/88
Meter No. 6890T7         2361.3      1331.3   1030.0    72,000       74,160,000	

                                      Energy Delivered
                    % Delivered          To PGandE
                    -----------       ----------------
On Peak:               20.3             15,054,480
Partial Peak:          23.3             17,279,280
Off Peak:              46.2             34,261,920
Super Off Peak:        10.2              7,564,320
                                        ----------
                                        74,160,000	

Payment Calculation for Net Energy and Shutdowns during Periods 2 and 3

Energy Payment
I. Excluding deliveries scheduled during 6 contiguous off peak hours:

Energy Delivered                          IER
   To PGandE            $/MMBTU         BTU/KWH         Adder         Payment
- ----------------        -------         ---------       -------       -------
    63,541,788             3            9,400            1.17       $2,096,497.75	

II. Deliveries scheduled during 6 contiguous off peak hours:

Energy Delivered                          IER
   To PGandE            $/MMBTU         BTU/KWH         Payment
- ----------------        -------         ---------       -------
    10,618,212             3            9,400             $299,433.58

                                Total Energy Payment    $2,395,931.33	

Shutdown Payment
- ----------------

                        Shutdown        $/MMBTU$ [div]
Total Shutdowns          Charge         $5.229/MMBTU$$       Payment
- ------------------      --------        --------------       -------
        0                $1,000         3 [div] 5.229        $.00	

$ Weighted average price paid during previous month by PGandE's Electric Department for oil and natural gas for PGandE's fossil steam plant.
$$ Average price paid during July 1985 by PGandE's Electric Department for oil and natural gas for PGandE's fossil steam plants.

Capacity Payment Calculation

P = 32,305,660 = 1.00 120,000 x (273 - 0) x (1-.2) (P not to exceed 1.0)
MCF = 1.00 x (1.0-0/744) = 1.00
Monthly Delivered Capacity = 120,000 kw x 1.00 = 120,000 kw
Firm Capacity Payment
Period A: 120,000 x $172 x .166275 x .989 x 1.040 = $3,529,931.52
Payment Calculation for As Delivered Capacity

                      KWH Delivered                             Allocation
                     to PGandE Above              Loss Adj.       Factors          Payment
                      Firm Capacity     F.S.C.     Factor        Period A          (Cents)
                     ---------------    ------    ---------     -----------        -------
On Peak:                  13,100         102        .989          .11210           148,140
Partial Peak:             15,000         102        .989          .01510            22,849
Off Peak:                128,000         102        .989          .00000                 0
Super Off Peak:                0         102        .989          .00000                 0
                                                                             -------------
                                                                                   170,989

As Delivered Capacity Payment                                             =       1,709.89
Total Capacity Payment  =    $3,529,931.52 + 1,709.89                     =  $3,531,641.41
Total Energy Payment                                                      =   2,395,931.33
Total Shutdown Payment                                                    =            .00
                                                                             -------------
                                                Total Amount Due          =  $5,927,572.74	

D. A. BRAND
Power Control
4/9/1987
J. Kovnas

Appendix J Sample Billing Assumptions Periods 2 and 3
Month: October, Period (21 weekdays, 5 Saturdays & 5 Sundays)

Generation                             Hours      Gen (kW-hr)
- ----------                             -----      -----------
On Peak                 Weekday         126       15,050,448
Part Peak               Weekday         147       17,336,592
Off Peak                All days        347       31,116,960
Super Off Peak          All days        124                0
                                        ---       ----------
Total                                   744       63,504,000	

Capacity Assumptions
Firm: 120 MW (current allocation factors) As-Delivered in Excess of Firm: Option 2 Bonus: 4 percent
Term: 30 years
Firm Capacity Availability: 1988 Capacity Price: $172/kW-yr
Capacity Loss Adjustment: 0.989 As-Delivered Capacity Price: $102/kW-yr (current allocation) Delivered all hours at appropriate levels when scheduled by PGandE (Deliveries were not made during the scheduled six contiguous off peak hours.
Forced Outage: 40 hours in super off peak
Scheduled Maintenance Hours: 0
Energy Assumption
G55 = $3 MMBtu (current month)
Scheduled at 100% except 6 hours per night each day of the month (Period 2) where no deliveries were scheduled. Payment IER: 9,400 Btu/kW-hr
Adder for 1988: 17 percent
Shutdown Assumptions
No. of Shutdowns: 31
Price of G-55: $3/MMBtu (preceding month) Price paid for oil and gas in July 1985: $5.229/MMBtu

- --------------------------------------------------------------------------------
                        PACIFIC GAS AND ELECTRIC COMPANY
               STATEMENT OF CAPACITY AND ELECTRIC POWER PURCHASED
- --------------------------------------------------------------------------------
ACCOUNT NUMBER:  JTK-T2-10001                           DATE:  NOVEMBER 30, 1988
- --------------                                          ----
                 MAILING ADDRESS:       Gilroy Energy Company, Inc.
                                        Attn:  President
                                        1350 Pacheco Pass Highway
                                        Gilroy, CA 95020

                  REMIT CHECK TO:       Gilroy Energy Company, Inc.
                                        Attn:  President
                                        1350 Pacheco Pass Highway
                                        Gilroy, CA 95020
- --------------------------------------------------------------------------------	

Payment computations are in accordance with the Power Purchase Agreement between Gilroy Energy Company, Inc. (thermal facility in Gilroy) and PGandE dated December 19, 1983.
Billing Period: October 1 - 31, 1988
METERING INFORMATION

Net Energy Delivered
- --------------------
                        Read       Read       Diff.     Const.   Killowatthours
                        ----       ----       -----     ------   --------------

Billing Period        10/31/88    10/1/88
Meter No. 6890T7         996.0      114.0     882.0     72,000     63,504,000

                                                Energy Delivered
                                % Delivered        To PGandE
                                -----------     ----------------
                On Peak:           23.7            15,050,448
                Partial Peak:      27.3            17,336,592
                Off Peak:          49.0            31,116,960
                Super Off Peak:       0                     0
                                                   ----------
                                                   63,504,000

Payment Calculation for Net Energy and Shutdowns for Period 2 and 3
- -------------------------------------------------------------------

Energy Payment
- --------------

Energy Delivered                       IER
   To PGandE            $/MMBTU      BTU/KWH     Adder          Payment
- ----------------        -------      -------     -----       -------------
   63,504,000              3          9,400       1.17       $2,095,250.98

Shutdown Payment
- ----------------

                        Shutdown        $/MMBTU$ divided by
Total Shutdowns          Charge           $5.299/MMBTU$$         Payment
- ---------------         --------        -------------------     ----------
      31                 $1,000         3 divided by 5.229      $17,785.43	

$ Weighted average price paid during previous month by PGandE's Electric Department for oil and natural gas for PGandE's fossil steam plants.
$$ Average price paid during July 1985 by PGandE's Electric Department for oil and natural gas for PGandE's fossil steam plants.

Capacity Payment Calculation
- ----------------------------

P =          32,358,940          =      1.00
    ----------------------------
    120,000 x (273 - 0) x (1-.2)        (P not to exceed 1.0)	

MCF = 1.00 x (1.0-0/744) = 1.00
Monthly Delivered Capacity = 120,000 kw x 1.00 = 120,000 kw
Firm Capacity Payment
Period A: 120,000 x .166275 x $172 x .989 x 1.040 = $3,529,931.52
Payment Calculation for As Delivered Capacity

                    KWH's Delivered                              Allocation
                    to PGandE Above                 Loss Adj.      Factor           Payment
                    Firm Capacity         F.S.C.      Factor      Period A          (Cents)
                    ---------------       ------    ---------    ----------         -------
On Peak:                13,100             102         .989        .11210              148,140
Partial Peak:           15,000             102         .989        .01510               22,849
Off Peak:              128,000             102         .989        .00000                    0
Super Off Peak:              0             102         .989        .00000                    0
                                                                                   -----------
                                                                                       170,989

As Delivered Capacity Payment                                               =        $1,709.89

Total Capacity Payment =   $3,529,931.52  +  $1,709.89                      =    $3,531,641.41

Total Energy Payment                                                        =     2,095,250.98

Total Shutdown Payment                                                      =        17,785.43
                                                                                 -------------
                           Total Amount Due                                 =    $5,644,677.82	

D. A. BRAND
Power Control
4/9/1987
J. Kovnas

AMENDMENT #4

FOURTH AMENDMENT
TO THE
LONG-TERM ENERGY AND CAPACITY
POWER PURCHASE AGREEMENT
BETWEEN
GILROY ENERGY COMPANY
AND
PACIFIC GAS AND ELECTRIC COMPANY
THIS FOURTH AMENDMENT is by and between PACIFIC GAS AND ELECTRIC COMPANY ("PG&E"), a California corporation, and GILROY ENERGY COMPANY, a California limited partnership ("Seller" or "GEC"). PG&E and Seller are sometimes referred to herein collectively as the "parties" and individually as "party."
RECITALS
A. There is a LONG-TERM ENERGY AND CAPACITY POWER PURCHASE AGREEMENT BETWEEN GILROY FOODS, INC. AND PACIFIC GAS AND ELECTRIC COMPANY, signed by Gilroy Foods, Inc. and PG&E on December 19, 1983 (the "Agreement") for the 130,000 kw gas-fired cogeneration facility located at Gilroy Foods, Inc., Pacheco Pass Highway, Gilroy, California (the "Facility"); and
B. The Agreement was amended by the FIRST AMENDMENT TO THE LONG-TERM ENERGY AND CAPACITY POWER PURCHASE AGREEMENT BETWEEN GILROY FOODS COMPANY AND PACIFIC GAS AND ELECTRIC COMPANY, signed by Gilroy Foods, Inc. on July 17, 1985 and by PG&E on July 18, 1985 (the "First Amendment"); and
C. Gilroy Foods, inc. assigned the Agreement, as amended by the First Amendment, to Seller; and

D. The Agreement was amended by the SECOND AMENDMENT TO LONG-TERM ENERGY AND CAPACITY POWER PURCHASE AGREEMENT DATED DECEMBER 19, 1983, AS AMENDED JULY 18, 1985, signed by GEC and PG&E on June 9, 1986 (the "Second Amendment"); and
E. The Agreement was amended by the THIRD AMENDMENT TO LONG-TERM ENERGY AND CAPACITY POWER PURCHASE AGREEMENT DATED DECEMBER 19, 1983, AS AMENDED JULY 18, 1985 AND JUNE 9, 1986, signed by GEC on July 20, 1988 and by PG&E on August 18, 1988 (the "Third Agreement"); and
F. On April 5, 1989, Seller filed a complaint with the California Public Utilities Commission ("CPUC"), Case No. 89-04-004 (the "Complaint"), seeking relief from certain natural gas demand charges Seller may incur pursuant to PG&E's natural gas tariffs as a result of PG&E's scheduling of the Facility under the amended Agreement; and
G. In Decision ("D.") 90-12-098, the CPUC found the Complaint without merit but ordered PG&E to negotiate and file an amendment to the Agreement whereby PG&E's ratepayers compensate Seller for demand charges incurred by Seller as a result of PG&E's scheduling of the Facility under the amended Agreement; and
H. The parties have negotiated this Fourth Amendment in response to the CPUC's directive in D. 90-12-098; and
I. PG&E and Seller have agreed that the Second Amendment shall terminate upon final CPUC approval of this Fourth Amendment; and

J. The parties have negotiated this Fourth Amendment based on the information about the new natural gas regulatory framework and Seller's likely choice of natural gas transportation service available as of the signature dates of this Fourth Amendment. Should material changes in these facts make the Fourth Amendment inappropriate, the parties shall negotiate changes pursuant to the principles of D.90-12-098; and
K. The parties have agreed that PG&E will annually provide Seller its written, non-binding estimate of whether PG&E will require the Facility to operate during the curtailable hours in the following natural gas year (August 1 through July 31); and
L. The parties have agreed that Seller shall use such non-binding estimate to plan its probable natural gas requirements for the upcoming natural gas year and to contract for sufficient natural gas; and
M. PG&E and Seller have agreed that PG&E will reimburse Seller for certain take-or-pay or use-or-pay surcharges which may be incurred by Seller under PG&E's natural gas tariffs as a direct result of PG&E's scheduling of the Facility under the amended Agreement; and
N. To minimize the possibility of take-or-pay or use-or-pay surcharges being imposed, Seller shall contract for natural gas transportation service under the full require-

ments option of PG&E's natural gas tariffs, if such option is available; and
O. PG&E and Seller have agreed that PG&E will reimburse Seller for certain costs associated with purchases of incremental quantities of natural gas on short notice made as a direct result of PG&E's rescheduling of the Facility under the amended Agreement; and
P. To minimize the likelihood that Seller will experience natural gas curtailments that may interfere with Seller's ability to operate the Facility according to the terms of this Fourth Amendment, Seller shall contract for natural gas transportation service under Service Level 2 and/or Service Level 3 of PG&E's natural gas tariffs; and
Q. The parties have agreed that Seller's energy payment option shall change from Energy Payment Option 3 - Incremental Energy Rate to Energy Payment Option 1 - Forecasted Energy Prices, 100% published prices, provided that in no event shall Seller receive any payment adders associated with the determination of PG&E's published full short-run avoided operating cost; and
R. The parties have negotiated a number of provisions intended to replace the Second Amendment's curtailment provisions with a simpler, more easily administered curtailment scheme; and
S. PG&E and Seller have agreed to condition the effectiveness of this Fourth Amendment on a final, uncondi-

tional and unappealable decision by the CPUC approving the reasonableness of the Fourth Amendment and unconditionally authorizing recovery in PG&E's rates of all payments made under the amended Agreement at the time the payments are made; and
T. It is the intention of the parties to separately negotiate a mutually-agreeable interim agreement applicable to the period between May 1, 1991 and the date the CPUC approves the Fourth Amendment. Under this interim agreement, Seller will curtail the Facility six hours a night; and
U. Upon CPUC approval of this Fourth Amendment, Seller shall request dismissal, with prejudice, of its application for rehearing of D. 90-12-098 and motion for leave to file augmented application, each dated January 25, 1991; and
V. The parties have agreed that, upon CPUC approval, the Fourth Amendment shall remain in effect until December 31, 1998, which is the end of the fixed price period.
NOW, THEREFORE, in consideration of the mutual promises and obligations stated herein, Seller and PG&E hereby agree as follows:
1. TERMINATION OF THE SECOND AMENDMENT
The Second Amendment shall terminate on the Final CPUC Approval Date, as defined in paragraph 13.1.

2. CHANGES TO THE THIRD AMENDMENT
2.1 For the term of amendment, delete paragraph 3 of the Third Amendment, regarding revised Incremental Energy Rate Band Widths.
2.2 For the term of amendment, delete paragraph 4 of the Third Amendment, regarding revised Table B-3.
3. DEFINITIONS
3.1 All underlined terms shall have the meaning stated in Appendix A, Section A-1 DEFINITIONS, of the Agreement, except as expressly amended by this Fourth Amendment.
3.2 For the term of agreement, amend the reference to PG&E at page 3, line 11, of the Agreement to read: "PACIFIC GAS AND ELECTRIC COMPANY ('PGandE' or 'PG&E')."
3.3 For the term of amendment insert the following new term and its definition in Appendix A, Section A-1 DEFINITIONS, of the Agreement, at page A-3, line 3:
Curtailable hours - The time periods listed below during which Seller shall not operate the Facility unless instructed otherwise in the estimated schedule or by PG&E's Specific Operating Orders:
Period 1: All hours.
Period 2: Six contiguous hours daily, scheduled by PG&E to include the hours of low demand on PG&E's system, including all of the super off-peak hours. In any event, the Facility shall be allowed to warm-start at least one hour prior to partial-peak hours in Period 2. Whenever the CPUC authorizes changes in the time periods listed in Table

B-4 of the interim Standard Offer No. 4 Power Purchase Agreement, PG&E may reschedule the Period 2 curtailable hours to coincide with changes in the occurrence of low demand on the PG&E system. To the extent consistent with the parties' intent that the curtailable hours coincide with PG&E's periods of low system demand, the new schedule shall follow the time periods authorized by the CPUC in Table B-4.
3.4 For the term of amendment, insert the following new term and its definition in Appendix A, Section A-1 DEFINITIONS, of the Agreement, at page A-3, line 7:
Estimated schedule - Pursuant to Appendix J, the written, nonbinding estimate(s) given to Seller by PG&E each year by May 1 and updated by July 1 as to whether or not PG&E will instruct Seller to operate the Facility during the curtailable hours in the following 12-month period beginning August 1 and ending July 31 of the next calendar year.
3.5 For the term of amendment, insert the following new terms and their definitions into Appendix A, Section A-1, Definitions, on page A-5, line 26:
Period 1 - January 1 through April 30.
Period 2 - May 1 through December 31.
3.6 For the term of amendment, insert the following new terms and their definitions in Appendix A, Section A-1 DEFINITIONS, of the Agreement, at page A-6, line 19:
Specific operating orders - A communication issued by telephone by the designated PG&E switching center to Seller at its designated telephone number regarding operation of the Facility, in-

cluding identification of the hours PG&E instructs Seller to operate the Facility.
Start-Up - Return of the Facility to operation, delivering 96 MW or more to PG&E, after being shut down pursuant to PG&E's scheduling of the Facility, excluding any starts following a forced outage.
3.7 For the term of amendment, insert the following new term and its definition in Appendix A, Section A-1, DEFINITIONS, of the Agreement, at page A-7, line 6:
Term of amendment - The period that the Fourth Amendment will be in effect, as provided in paragraph 14 of the Fourth Amendment.
4. Article 4 - ENERGY PRICE
For the term of amendment, make the following changes to Article 4, ENERGY PRICE, of the Agreement:
4.1 On page 6, line 14 of the Agreement, place an "X" on the blank space at the beginning of the line.
4.2 Delete the sentence beginning on line 16 of page 6 and ending on line 3 on page 7. Replace it with the following:
During the fixed price period, Seller shall be paid for energy delivered to PG&E in accord with the following formula, adjusted to reflect the time period during which such energy is delivered:
Energy Price ($) = I x A
Where:

I = the "Incremental Energy Rate" component of PG&E's full short run avoided operating costs; and
A = the "Average UEG Rate" component, in $/MMBtu, of PG&E's full short run avoided operating costs.
5. NOTICES
5.1 On page 12, line 26 delete:
Pacific Gas and Electric Company Attention: Vice President - Electric Operations
77 Beale Street
San Francisco, CA 94106
Replace it with the following:
Pacific Gas and Electric Company Attention: Vice President - Power Generation 245 Market Street, Room 316 San Francisco, CA 94106
5.2 Appendix A - General Terms and Conditions on page A-24, line 14 delete:
Pacific Gas and Electric Company Attention: Manager-Insurance Department 77 Beale Street, Room E280 San Francisco, CA 94106
Replace it with the following:
Pacific Gas and Electric Company Attention: Manager - QF Contracts Department 77 Beale Street
San Francisco, CA 94106
6. Article 3 - Purchase of Power
On page 6, line 8 of the Agreement, insert the following new paragraph:
(g) Seller shall operate the Facility in accordance with Appendix J for the term of amendment."

7. Article 7 - Curtailment
For the term of amendment, delete from the Agreement Article 7, beginning on page 11, line 22, and continuing to the end of line 3 on page 12, and Appendix C, pages C-1 to C-5.
8. Article 11 - Terms and Conditions
8.1 For the term of amendment, delete from Article 11 of the Agreement, page 13, line 17, the reference to "Appendix C - Curtailment Options."
8.2 For the term of amendment, add the following phrase to Article 11 of the Agreement, page 13, line 23: "Appendix J - Scheduled Operation."
9. Appendix A - General Terms and Conditions
For the term of amendment, amend Appendix A, Section A-3.4 Operating Communications, of the Agreement, by adding the following sentence to the end of paragraph (2), page A-12, line 3:
During Period 1, Seller shall inform PG&E whenever the Facility is not available.
10. Appendix E - Firm Capacity
10.1 For the term of amendment, Appendix E, Section E-1, General, of the Agreement shall be amended by inserting the following new paragraph on line 17 of page E-2:
If PG&E's peak months (currently June, July and August) are changed so that any portion of the peak months occur in Period 1, the parties shall use best efforts to

negotiate a mutually agreeable method for Seller to satisfy minimum performance requirements and to determine the performance bonus factor.
10.2 For the term of amendment, delete from Appendix E, Section E-5, Firm Capacity Payments, of the Agreement the language beginning on page E-6, line 9 and continuing through the end of line 3 on page E-9. Replace it with the following:
Period 1. The monthly payment for firm capacity delivered in Period 1 will be the product of the Period Price Factor (PPF), the firm capacity, the appropriate capacity loss adjustment factor from Table E-1 based on the Facility's interconnection voltage, the appropriate performance bonus factor, if any, from Table E-3, and the appropriate availability factor.
Period 2. The monthly payment for firm capacity delivered in Period 2 will be the product of the PPF, the Monthly Delivered Capacity (MDC), the appropriate capacity loss adjustment factor from Table E-1 based on the Facility's interconnection voltage, and the appropriate performance bonus factor, if any, from Table E-3, plus any allowable payment for outages due to scheduled maintenance. The firm capacity price for Period 2 shall be applied to meter readings taken during the separate times and periods as illustrated in Table B-4, Appendix B.
The firm capacity payment is calculated as follows:
(1) Determine the PPF. The PPF is determined by multiplying the firm capacity price by the following Allocation Factors(1):

(1) All allocation factors are subject to change by PG&E based on PG&E's marginal capacity cost allocation, as determined in general rate case proceedings before the CPUC. Seasonal Periods A and B are defined in Appendix C.

                Allocation          Firm              PPF
                              X     ----              =
                Factor              Capacity Price            ($/kw-month)
                                    --------------

Seasonal        .166275
Period A                            --------------            ------------

Seasonal        .0003917            --------------            ------------
Period B	

During Period 1, the Seasonal Period B allocation factor shall be increased by the following two adders: First, an adder of .017973 to reflect the value to PG&E of specific operating orders and second, an adder determined by the formula:
.001589(A/B)
Where:
A = The "average UEG rate" component, in dollars per MMBtu, of PG&E's most recently published full short-run avoided operating costs; and
B = 3.0837, which is the "average UEG rate" component, in $ per MMBtu, of PG&E's full short-run avoided operating costs for May 1991.
(2) Determine the MDC. The MDC is determined in the following manner:
(A) Determine the Performance Factor (P), which is defined as the lesser of 1.0 or the following quantity:
A
P = --------------------
 C x (B-S) x (0.8(2)) (less than or equal to 1.0)
Where:
A = The total kilowatt-hours delivered during all on-peak and partial-peak hours in Period 2 excluding any energy associated with generation levels greater than the firm capacity;
C = Firm capacity in kilowatts;
B = Total on-peak and partial-peak hours in Period 2 during the month; and

(2) 0.8 reflects a 20% allowance for forced outage.

S = Total on-peak and partial-peak hours in Period 2 during the month Facility is out of service on scheduled maintenance.
(B) Determine the Monthly Capacity Factor (MCF), which is computed using the following expression:
M
 MCF = P x (1.0 - ---)
D
Where:
M = The number of hours (not to exceed 729.6 hours) in the month that the Facility is out of service on scheduled maintenance; and
D = 729.6 hours.
(C) Determine the MDC by multiplying the MCF by firm capacity in kilowatts (C):
MDC (kilowatts) = MCF x C
(3) Determine the Availability Factor. The Availability Factor is determined as follows:
(A) Determine the availability of the Facility during Period 1:
AV = 100 (H - T - SM) / (H-SM)
Where:
AV = The percent of the time the Facility is available to deliver energy as scheduled by PG&E during Period 1.
H = The number of hours in the month;
T = The number of hours of the month, other than scheduled maintenance hours, when the Facility is not available to deliver energy as scheduled by PG&E pursuant to Appendix J; and
SM = The number of hours of the month when the Facility is not available to deliver energy due to scheduled maintenance.
(B) Determine the Availability Factor (AF) as follows.
AF is the lesser of 1 or the following quantity:
'

(AV) - 50)

AF = ---------- + 0.5 (less than or equal to 1.0)
60
(4) Calculate the firm capacity payment. The monthly payment for firm capacity is then determined as follows:
For Period 1:

monthly    =    PPF  X  Firm      X  Capacity    X  Performance  X  AF
payment                 Capacity     Loss           Bonus
for firm                             Adjustment     Factor
capacity                             Factor	

For Period 2:

monthly    =    PPF  X  MDC       X  Capacity    X  Performance
payment                              Loss           Bonus
for firm                             Adjustment     Factor
capacity                             Factor	

Furthermore, the payment for a month in which there is an outage for scheduled maintenance shall also include an amount equal to the product of the average hourly firm capacity payment for the most recent month in the same Seasonal Period (i.e., Seasonal Period A or Seasonal Period B) during which deliveries were made, multiplied by the number of hours of scheduled maintenance outage in the current month. For purposes of calculating the hourly firm capacity payment, the current month and the most recent month in the same seasonal period shall be considered to be of equal length; i.e., 729.6 hours (30.4 days, which is equal to one-twelfth of a 365-day year). Firm capacity payments will continue during scheduled maintenance outage periods, provided the provisions of Section E-3 are met.
11. APPENDIX J - SCHEDULED OPERATION
For the term of amendment, insert the following new Appendix J into the Agreement:

APPENDIX J
SCHEDULED OPERATION
J-1 OPERATING SCHEDULE
1.1 By May 1 of each year, PG&E will provide Seller its written, nonbinding estimate of whether or not it will instruct Seller to operate the Facility during the curtailable hours in the following natural gas year (beginning August 1 and continuing through July 31 of the following calendar year). PG&E will update this estimate, if necessary, by July 1. (Collectively, the May 1 and July 1 notices are the estimated schedule). If PG&E intends to instruct Seller to operate the Facility during curtailable hours, the estimated schedule will include a nonbinding schedule of operation. Seller shall use the estimated schedule to plan its probable natural gas requirements for the upcoming year and shall contract for sufficient natural gas to operate the Facility in accord with such estimated schedule.
1.2 Seller shall operate the Facility in accord with the applicable estimated schedule and the provisions of this Agreement, except as otherwise directed by PG&E's specific operating orders.
1.3 Specific Operating Orders. PG&E may revise the estimated schedule by giving Seller Specific Operating Orders in accord with this paragraph 3.3.

1.3.1   During Period 1, PG&E may issue specific
        operating orders at least 72 hours in advance of
        any period for which PG&E desires to change the
        estimated schedule. If PG&E is ordering the
        Facility to operate, PG&E shall specify (i) the
        scheduled on-line time; and (ii) the duration of
        the period for which the Facility shall be
        on-line.  PG&E shall require deliveries of
        energy from the Facility for a minimum of 6
        hours after each start-up.  PG&E agrees not to
        require the Facility to start-up more	

        than seven times in any one calendar week during
        Period 1.

1.3.2   During Period 2, PG&E may issue specific
        operating orders no later than 1600 hours on the
        day preceding the day to which the specific
        operating orders apply.

1.3.3   During both Period 1 and Period 2, PG&E may
        change a specific operating order by giving
        notice to Seller at least ten hours in advance
        in the case of a cold start and four hours in
        advance in the case of a warm start.  For
        purposes of this paragraph, a "warm start" of
        the Facility is any start-up of the Facility
        within twelve hours of the last shutdown of the
        Facility, and a "cold start" is any start-up of
        the Facility more than twelve hours after the
        last shutdown of the Facility.	

1.4 If PG&E experiences an emergency on its electrical system, Seller shall use best efforts to come on-line as soon as practical if called to do so by PG&E.
1.5 If, at any time during Period 2, Seller's back-up boiler is not capable of supplying steam to the Gilroy Foods process ("boiler outage"), Seller shall advice PG&E. Seller shall have no obligation to reduce its electrical generation during a boiler outage, provided Seller uses its best efforts to correct the condition causing such incapability in a timely manner. Seller shall be paid for energy delivered to PG&E during Period 2 curtailable hours as a result of boiler outage at prices equal to 90% of the price of PG&E's available alternate source. Such price shall apply until Seller notifies PG&E that the boiler outage has ended.
1.6 Each calendar year, PG&E and Seller shall confer as early as practicable concerning maintenance schedules, output scheduling and any other matters affecting the Facility. In all events, Seller shall provide its input
to

PG&E concerning such matters no later than March 31 each year. By May 1 each year, PG&E shall, after due consideration of Seller's input, deliver a written maintenance schedule for both annual overhaul and other periodic overhauls, to be scheduled during the upcoming December 1 through March 31 period.

                1.6.1   If, after the maintenance schedule has been
                        delivered, in either Party's reasonable judgment
                        conditions change such that a change in the
                        maintenance schedule is warranted, such Party
                        shall deliver written notice thereof to the
                        other Party, specifying with particularity the
                        circumstances warranting a change in the
                        schedule and the change requested. The
                        maintenance schedule for Period 1 shall be
                        changed if the responding Party consents, which
                        consent shall not be unreasonably withheld.

J-2     START-UP PAYMENT	

2.1 PG&E shall pay Seller for start-ups during Period 1 in accord with the following formula:
$3833 (N) (A/B)
Where:

N   =   the number of start-ups during the billing period;

A   =   the "average UEG rate" component, in dollars per MMBtu,
        of PG&E's most recently published full short-run avoided
        operating costs; and

B   =   3.0837, which is the "average UEG rate" component, in
        dollars per MMBtu, of PG&E's full short-run avoided
        operating costs for May 1991.

2.2     PG&E and Seller agree that Seller's failure to operate
        the Facility as specified in the estimated schedule
        and/or PG&E's specific operating orders, will damage
        PG&E and that it would be extremely difficult to fix the	

actual damages resulting from such noncompliance. Accordingly, PG&E and Seller agree that PG&E shall deduct $5,000 as liquidated damages from PG&E's payment to Seller for each noncompliance, up to a maximum of $15,000 per calendar week. For purposes of this paragraph, a "calendar week" begins at 0001 hours on Sunday, and a continuing non-compliance shall be considered a new event of noncompliance every 24 hours.
J-3 NATURAL GAS COSTS
3.1 PG&E shall reimburse Seller for certain natural gas penalties, surcharges, and extraordinary costs incurred by Seller under the terms described in this section. This section assumes that Seller will receive natural gas transportation service from PG&E pursuant to the PG&E tariffs currently anticipated to be in place as of August 1, 1991 and that Seller will receive natural gas under a PG&E transportation rate schedule that requires a contract commitment with subsequent penalties of greater than one month (currently Service Level 2 or 3). Should either or both of these assumptions provide incorrect, the parties shall negotiate appropriate amendments to this section.
3.2 Surcharges And Penalties. If PG&E issues Specific Operating Orders which require the Facility to operate a different number of hours than specified in the estimated schedule, and, as a direct result of complying with such orders, Seller incurs annual take-or-pay or use-or-pay surcharges or overbalance or underbalance penalties (collectively, "surcharges or penalties") pursuant to PG&E's natural gas tariffs, Seller shall submit an invoice to PG&E's Power Generation Department. A copy of the billing notice from PG&E shall be attached to Seller's invoice. Upon verification, and subject to the following conditions, PG&E shall make a single, lump-sum payment to Seller in an amount equal to the amount of such surcharge or penalty within 45 days from the date of receipt of Seller's invoice.

3.2.1   PG&E shall not be responsible for natural gas
        surcharges or penalties incurred by Seller (a)
        if they do not directly result from Seller's
        compliance with PG&E's Specific Operating
        Orders, (b) if PG&E's Specific Operating Orders
        have required the Facility to operate during
        Period 1 for a number of hours equal to or
        greater than 75 percent of the hours specified
        for Period 1 in the applicable estimated
        schedule, or (c) to the extent that Seller has
        not used its best efforts to eliminate imbalance
        penalties pursuant to the excess imbalance
        trading provisions of PG&E's tariff Schedule
        G-BAL.

3.2.2   Seller remains responsible for timely payment to
        PG&E of all natural gas surcharges and
        penalties.	

3.3 Incremental Purchases on Short Notice. From time to time, it may be necessary for Seller to purchase incremental quantities of natural gas on short notice in order to comply with PG&E's Specific Operating Orders. This situation potentially may occur when the Specific Operating Orders require the Facility to operate for a greater number of hours than specified in the applicable estimated schedule. PG&E shall compensate Seller for such incremental purchases to the extent that the incremental commodity costs incurred by Seller exceed the "average UEG rate" component of PG&E's full short-run avoided operating cost as of the date of the applicable incremental purchase, as follows:

3.3.1   When PG&E issues Specific Operating Orders, the
        PG&E dispatcher shall state the estimated length
        of time the Facility will be required to
        generate.  The dispatcher shall also specify the
        maximum natural gas price acceptable to PG&E.
        Within 12 hours of receiving such Specific
        Operating Orders, Seller shall notify PG&E's
        dispatcher of the price at which Seller can ob-	

        tain natural gas.  The PG&E dispatcher will then
        either confirm or rescind the Specific Operating
        Order.

3.3.2   Seller shall make reasonable efforts to obtain
        incremental quantities of natural gas at the
        lowest available price.

3.3.3   PG&E shall not be responsible for the cost of
        incremental quantities of natural gas purchased
        by Seller which (a) are not necessary to enable
        Seller to comply with PG&E's Specific Operating
        Orders; or (b) are purchased because Seller
        failed to sign supply contracts of at least one
        year in duration for sufficient natural gas to
        cover its probable needs pursuant to the
        applicable estimated schedule; or (c) are not
        purchased in accord with the provisions of this
        paragraph 3.3.

3.3.4   Seller shall invoice PG&E's Vice President -
        Power Generation on a monthly basis for
        incremental quantities of natural gas purchased
        by Seller in accord with this section.  Seller
        shall include documentation acceptable to PG&E
        of the volume and cost of such natural gas.

3.3.5   Seller shall maintain, preserve and make
        available for inspection, audit and
        reproduction, for a period of at least 60 months
        following the submission of each invoice to
        PG&E, all Seller's records used in determining
        the volume and cost of incremental quantities of
        natural gas for which Seller seeks payment from
        PG&E.  PG&E and/or its consultant may audit
        Seller's records to verify the accuracy of
        Seller's invoices.  If PG&E inspects, audits, or
        requires Seller to reproduce such records, PG&E
        shall protect from disclosure such records	

        which are clearly marked as confidential with
        the same degree of care it uses to protect its
        own confidential information.  Provided,
        however, that PG&E may disclose Seller's
        confidential information if required by law or
        if ordered or requested to do so by a
        governmental agency, the CPUC, CPUC staff
        (including the Division of Ratepayer Advocates),
        or the California Energy Commission.	

3.4 Within 30 days of PG&E's notice of the final CPUC Approval Date pursuant to paragraph 13.1, Seller shall pay PG&E all outstanding natural gas demand charges related to complaint No. 89-04-004 in the amount of $1,231,649.94.
12. NATURAL GAS TRANSPORTATION
For the term of amendment, Seller shall contract for natural gas transportation service under Service Level 2 and/or Service Level 3, full requirements option (if available) of PG&E's natural gas tariffs.
13. REGULATORY REVIEW
13.1 This Fourth Amendment is conditioned upon and shall not be effective until (a) the CPUC issues a decision that in terms satisfactory to PG&E approves the reasonableness of the Fourth Amendment and the Agreement as so amended, and unconditionally authorizes full recovery in PG&E's rates of all payments made under the Fourth Amendment and Agreement as so amended at the time the payments are made; and (b) such CPUC decision becomes final, unconditional and unappealable (including exhaustion of all administrative and judicial appeals or remedies and time periods thereof)

("Final CPUC Approval Date"). PG&E shall inform Seller of the Final CPUC Approval Date.
13.2 PG&E and Seller shall use their best efforts to support the reasonableness of the Fourth Amendment, and the Agreement as amended, before any government authority of competent jurisdiction in a proceeding involving a review of the Fourth Amendment or the Agreement for purposes of allowance or disallowance in rates charged by PG&E. Each party shall bear its own costs and expenses associated with seeking such approval.
13.3 Upon Commission approval of the Fourth Amendment as described above, Seller shall immediately request that the Commission dismiss with prejudice the following. Such dismissal shall be as to Seller and not necessarily as to BAF Energy, the joint applicant.
Application For Rehearing Of D.90-12-098 Of Gilroy Energy Company and BAF Energy, dated January 25, 1991; and
Motion For Leave to File Augmented Application Upon Further Action By the Commission. Or, In The Alternative To File Amended Application Upon Five Days Notice.
14. TERM OF AMENDMENT
This Fourth Amendment shall be binding upon execution by the authorized representatives of PG&E and Seller. It shall be effective on the final CPUC Approval Date pursuant to paragraph 13.1, and remain in effect until December 31, 1998. However, the amendments contained in paragraphs 3.2,

22 and 23 of this Fourth Amendment shall survive such termination and remain in effect for the term of agreement.
15. MUTUAL RELEASE OF CLAIMS AND DEFENSES
15.1 Release by Seller. In consideration of the promises set forth in this Fourth Amendment, Seller, its affiliates, heirs, transferees, successors, assigns, officers, directors, shareholders, agents, employees, representatives, and attorneys hereby release and forever discharge PG&E, and its affiliates, heirs, transferees, successors, assigns, officers, directors, shareholders, agents, employees, representatives, and attorneys of and from any and all claims, demands, actions or causes of action, known or unknown, arising out of or in any way connected with or resulting from the matters alleged in Seller's Complaint.
15.2 Release by PG&E. In consideration of the promises set forth in this Fourth Amendment, PG&E, its affiliates, heirs, transferees, successors, assigns, officers, directors, shareholders, agents, employees, representatives, and attorneys hereby release and forever discharge Seller, and its affiliates, heirs, transferees, successors, assigns, officers, directors, shareholders, agents, employees, representatives, and attorneys of and from any and all claims, demands, actions or causes of action, known or unknown, arising out of or in any way connected with or resulting from the matters alleged in PG&E's Answer.
-23-

15.3 This is a full and final release applying to all claims alleged in or which could have been alleged in the Complaint and the Answer. Seller and PG&E each waive any and all rights or benefits which it may now have, or in the future may have, under the terms of section 1542 of the Civil Code of the State of California, which provides:
A general release does not extend to claims which the creditor does not know or suspect to exist in his favor at the time of executing the release, which if known by him must have materially affected his settlement with the debtor.
PG&E and Seller each being aware of the significance and legal effect of section 1542, hereby each expressly waives any and all rights and benefits either party may have under section 1542 or under any other statute or common law principle of similar effect.
15.4 Each party agrees that it will not, directly or indirectly, commence or maintain in any manner whatsoever any lawsuit, regulatory proceeding, action, or any other proceeding in law, equity, or otherwise, which in any way arises of or is related, directly or indirectly, to the mutual releases set forth herein or which seeks to rescind, terminate, or invalidate these mutual releases, in whole or in part, for any reason whatsoever; provided, however, that either party may bring an action to enforce its respective rights pursuant to these mutual releases.

15.5 These mutual releases and the Fourth Amendment represent a compromise of disputed claims, and are not intended to be nor shall they ever, for any purpose, be considered evidence of or an admission by any party of any liability or fault whatsoever.
16. EFFECT ON AGREEMENT
Except as expressly modified by this Fourth Amendment, the provisions of the Agreement, as modified by the First and Third Amendments, shall remain unchanged.
17. ENTIRE AGREEMENT
This Fourth Amendment constitutes the entire agreement of the parties with respect to the subject-matter hereof and supersedes any and all prior negotiations, correspondence, understandings and agreements between the parties respecting the subject-matter of this Fourth Amendment.
18. MODIFICATION
This Fourth Amendment may be further amended or modified only by a written instrument signed by the parties hereto.
19. CAPTIONS
Captions are included herein for ease of reference only. The captions are not intended to affect the meaning of the contents or scope of this Fourth Amendment.
20. CHOICE OF LAWS
This Fourth Amendment shall be construed and interpreted in accordance with the laws of the State of Califor-

nia, excluding any choice of law rules that may direct the application of the laws of another jurisdiction.
21. NON-WAIVER
No term or provision hereof shall be deemed waived and no breach excused unless such waiver or consent is in writing and signed by the party claimed to have so waived or consented.
22. NOTICES
For the term of agreement, amend Article 9, NOTICES, at page 12, line 23, of the Agreement to change the title of PG&E's notice addressee to "Vice President - Power Generation."
23. For the term of agreement, delete from the Agreement Table B-4 in Appendix B, page B-19. Replace it with Table B-4, attached hereto and incorporated herein by this reference.
24. INTERPRETATION
This Fourth Amendment is the result of negotiation. Moreover, each party has reviewed this Amendment, and has had full and adequate opportunity to obtain legal advice regarding this Amendment from the legal counsel of its choice. Accordingly, the rule of construction in Civil Code Section 1654 to the effect that any ambiguity shall be resolved against the drafting party shall not be employed against either party in the interpretation of this Amendment.
-26-

IN WITNESS WHEREOF, the parties hereto have caused this Fourth Amendment to be executed by their authorized representatives as of the last signature date set forth below:

GILROY ENERGY COMPANY                    PACIFIC GAS AND ELECTRIC COMPANY

BY:  /s/ ROBERT P. KRAEMER               BY:  /s/ ROBERT J. HAYWOOD
    ------------------------------           ------------------------------

NAME: ROBERT P. KRAEMER                  NAME:  ROBERT J. HAYWOOD
      ----------------------------              ---------------------------

TITLE: PRESIDENT                         TITLE: Vice President,
       ---------------------------              Power Planning and Contracts
                                                ---------------------------
DATE                                     DATE
SIGNED:  6-5-91                          SIGNED:  6-6-91
         -------------------------                --------------------------

BY:  /s/ GEORGE PENDERGAST
    ------------------------------

NAME:  GEORGE PENDERGAST
       ---------------------------

TITLE: Secretary
       ---------------------------	

DATE
 SIGNED: 6-5-91
NOTICE ADDRESSES:

Attn:  George Pendergast                 Attn:  Manager, QF Contracts
       1350 Pacheco Pass Highway                77 Beale Street
       Gilroy, CA 95021-0335                    23rd Floor
                                                San Francisco, CA 94106	

-27-

TABLE B-4
TIME PERIODS

                                 Monday          Saturdays,
                                 through          Sundays,
                                Friday(2)       and Holidays
                                ---------       ------------
Seasonal Period A
(May 1 through October 31)

    Peak                        Noon            None
                                to
                                6:00 p.m.

    Partial-Peak                8:30 a.m.       None
                                to
                                noon

                                6:00 p.m.
                                    to
                                9:30 p.m.

    Off-Peak                    9:30 p.m.
                                to
                                1:00 a.m.

                                5:00 a.m.       5:00 a.m.
                                to              to
                                8:30 a.m.       1:00 a.m.

    Super Off-Peak              1:00 a.m.       1:00 a.m.
                                to              to
                                5:00 a.m.       5:00 a.m.

Seasonal Period B
(November 1 through April 30)

    Partial-Peak                8:30 a.m.       None
                                to
                                9:30 p.m.

    Off-Peak                    9:30 p.m.
                                to
                                1:00 a.m.

                                5:00 a.m.       5:00 a.m.
                                to              to
                                8:30 a.m.       1:00 a.m.

    Super Off-Peak              1:00 a.m.       1:00 a.m.
                                to              to
                                5:00 a.m.       5:00 a.m.	

(1) This table is subject to change to accord with the peak, partial-peak, off-peak, and super peak periods as defined by CPUC Decision.
(2) Except the following holidays: New Year's Day, Washington's Birthday, Memorial Day, Independence Day, Labor Day, Veteran's Day, Thanksgiving Day, and Christmas Day, as specified in Public Law 90-363 (5 U.S.C.A. Section 6103(a)).

AMENDMENT #5

1995 PAY FOR CURTAILMENT AGREEMENT
GILROY ENERGY COMPANY (PG&E Log No. 08C002)
THIS AGREEMENT is by and between GILROY ENERGY COMPANY ("Seller" or "GEC"), a California limited partnership, and PACIFIC GAS AND ELECTRIC COMPANY ("PG&E"), a California corporation. PG&E and Seller are sometimes referred to herein individually as "Party" and collectively as the "Parties."
RECITALS
A. There is a Long-Term Energy and Capacity Power Purchase Agreement between Seller and PG&E (the "PPA"), signed by PG&E on December 19, 1983, and by both Gilroy Foods, Inc. and Pacific Thermonetics, Inc. on December 19, 1983, for the 130 MW natural gas-fueled cogeneration facility (PG&E Log No. 08C002) located at Gilroy Foods, Inc., Pacheco Pass Highway, Gilroy, California (the "Facility"); and
B. The PPA has been amended by the First Amendment signed by PG&E on July 18, 1985, and by Gilroy Foods, Inc. on July 17, 1985; wherein Pacific Thermonetics, Inc. was removed as a party to the PPA; and
C. The PPA has been amended by the Second Amendment signed by PG&E on June 9, 1986, and GEC on June 9, 1986 which provided PG&E operating flexibility in exchange for a modified price arrangement; and
D. The PPA has been amended by the Third Amendment signed by PG&E on August 18, 1988, and GEC on June 20, 1988; and
Page 1 of 6

E. The PPA has been amended by the Fourth Amendment signed by PG&E on June 9, 1991, and GEC on June 5, 1995, which provided for changes in the operation flexibility of the Facility (the "Fourth Amendment"); and
F. The Facility began initial energy deliveries under the PPA on September 18, 1987, and has since regularly produced energy and capacity for sale to PG&E under the PPA, and
G. The Firm Capacity Availability Date (as defined in the PPA) occurred on February 16, 1988; and
H. The Parties have agreed that it will be to their mutual benefit to expand the shut down periods under the existing terms of the PPA, which currently directs GEC to shutdown 6 hours each day during the months of May and June. The Parties have agreed that the Facility shall shut down a total of eight and one-half hours each week day, and twenty-four hours on each weekend-day and holiday, in exchange for a curtailment payment calculated in accordance with this Curtailment Agreement.
AGREEMENT
THEREFORE, in consideration of the mutual covenants in this Agreement, the Parties agree as follows:
1. DEFINITIONS
Whenever used in this Agreement, the following terms shall have the following meanings:
1.1 Curtailment Period: All hours between 0001 hours May 1, 1995 and 2400 hours June 30, 1995.
1.2 kW: Kilowatts.
Page 2 of 6

1.3 kWh: Kilowatt hours.
1.4 Scheduled Maintenance: an outage to perform maintenance on the Facility that is scheduled in advance, is of a predetermined duration, and meets the PPA requirements for Scheduled Maintenance, including annual hour limits and notice requirements. These requirements are specified in the PPA in
Section E-3, Appendix E.
2. CURTAILMENT
2.1 During the Curtailment Period, Seller shall cease deliveries of energy and capacity to PG&E (i) between the hours of 9:30 p.m. through 6:00
a.m. Monday through Friday (44 days), and (ii) for 24 hours, on Saturday, Sunday and Memorial Day (17 days). GEC shall be allowed up to six (6) hours each Monday morning and the Tuesday morning after Memorial Day to reach full capacity and any such hours of "ramp up" time shall be excluded from the firm capacity calculation.
2.2 Curtailment Termination
Either Party may terminate this Agreement at any time by giving written notice to the other party. PG&E shall, however, have no right to terminate this Agreement after June 5, 1995. In the event that curtailment is canceled by either Party, GEC shall immediately resume the curtailment schedule previously specified by PG&E pursuant to the PPA: 6 hours curtailment every night from midnight to 6 am, through June 30, 1995.
3. CURTAILMENT PAYMENTS
3.1 PG&E agrees to pay GEC, each month, a lump sum payment of $125,000, for a total of $250,000 for May and June, 1995. This lump payment is intended to partially cover GEC's costs to: (i) startup its Facility during this Curtailment Period; and, (ii) offset its gas purchasing fees associated with this Curtailment Period. This payment is due to Gilroy when the monthly purchased power statement for the applicable month (May and June) is due to Gilroy per Section A.4 of Appendix A of the PPA.
Page 3 of 6

3.2 During the "ramp down" of the Facility, PG&E shall pay GEC PPA prices for any deliveries received after 9:30 pm each week night for up to one-half hour. Zero payments will be made for any deliveries after 10:00 pm.
3.3 If GEC's back-up boiler is not capable of supplying steam to the Gilroy Foods plant, the provisions of Appendix J, Section J-1, paragraph 1.5 of the Fourth Amendment shall apply between the hours of midnight and 6 am. During the other hours that the facility is operating because of back-up boiler problems, GEC shall receive full PPA prices. However, the lump sum payment for that month pursuant to paragraph 3.1 above shall be prorated on an hourly basis as specified in this paragraph and GEC shall be paid only for those hours in which it actually curtailed deliveries. The monthly payment shall be prorated over the following hours (i) 9:30 pm through 11:59 pm, Monday through Friday, and 6 am through 11:59 pm Saturday, Sunday and Memorial Day.
3.4 If this Agreement is terminated early pursuant to Section 2.1 above, the lump sum payment shall be prorated on an hourly as described in
Section 3.3 above.
3.5 In addition, GEC shall be allowed to operate 24 hours a day from September 1, 1995 through November 30, 1995, at prices already covered by the PPA and the provisions of Appendix J-1, paragraph 1.3, Specific Operating Orders of the fourth Amendment shall not apply to this schedule. However, in the event of an early termination of this Agreement, GEC shall be allowed to operate 24 hours a day: (i) for the entire month of November 1995 only, if this Agreement is effective for at least one week; (ii) for the entire months of October and November 1995 only, if this Agreement is effective for at least five weeks; and,
(iii) for the entire months of September, October and November only if this Curtailment Period has run its full course through the end of June 1995. In the event GEC operates its Facility under the provisions of Section 3.3 above, up to one week of such operation shall be disregarded in determining whether the requirements of paragraph 3.5 (iii) have been met.
4. MISCELLANEOUS
4.1 Entire Agreement
Page 4 of 6

This Agreement constitutes the entire agreement of the parties with respect to the subject matter hereof and supersedes any and all prior negotiations, correspondence, understandings and agreements between the Parties respecting the subject matter of this Agreement.
4.2 Modification of Agreement
This Agreement may be modified or amended only by a written instrument signed by the authorized representatives of both Parties.
4.3 Captions
Captions are included herein for ease of reference only. The captions are not intended to affect the meaning of the contents of scope of this Agreement.
4.4 Interpretation
No provision of this Agreement shall be interpreted for or against PG&E or Seller because PG&E, Seller or their respective attorneys drafted the particular provision.
4.5 Jurisdiction
This Agreement shall be construed and interpreted in accord with the laws of the State of California, excluding any choice of law rules that may direct the application of the laws of another jurisdiction.
4.6 Waiver
No term or provision herein shall be deemed waived and no breach excused unless such waiver or consent is in writing and signed by the Party claimed to have so waived or excused.
4.7 Notices
All notices under this Agreement shall be addressed as follows.
To PG&E:
Mr. Marc L. Renson
Power Contracts Department, B13E Pacific Gas and Electric Company P.O. Box 770000
San Francisco, CA 94177
Page 5 of 6

To Seller:
Mr. David Pearson
Gilroy Energy Company, Inc.
1350 Pacheco Pass Highway
Gilroy, CA 95021-0335
IN WITNESS WHEREOF, Seller and PG&E have caused this Agreement to be executed by their authorized representatives.

PACIFIC GAS AND ELECTRIC                GILROY ENERGY CORPORATION,
COMPANY, a California corporation       a California limited partnership
                                        ------------------------------------

- ------------------------------------    ------------------------------------
By                                      By

- ------------------------------------    ------------------------------------
Name                                    Name

- ------------------------------------    ------------------------------------
Title                                   Title

- ------------------------------------    ------------------------------------
Date of Signature                       Date of Signature	

Page 6 of 6

DRAFT
1995 PAY FOR CURTAILMENT AGREEMENT
GILROY ENERGY COMPANY (PG&E Log No. 08C002)
THIS AGREEMENT is by and between GILROY ENERGY COMPANY ("Seller" or "GEC"), a California limited partnership, and PACIFIC GAS AND ELECTRIC COMPANY ("PG&E"), a California corporation. PG&E and Seller are sometimes referred to herein individually as "Party" and collectively as the "Parties."
RECITALS
A. There is a Long-Term Energy and Capacity Power Purchase Agreement between Seller and PG&E (the "PPA"), signed by PG&E on December 19, 1983, and by both Gilroy Foods, Inc. and Pacific Thermonetics, Inc. on December 19, 1983, for the 130 MW natural gas-fueled cogeneration facility (PG&E Log No. 08C002) located at Gilroy Foods, Inc., Pacheco Pass Highway, Gilroy, California (the "Facility"); and
B. The PPA has been amended by the First Amendment signed by PG&E on July 18, 1985, and by Gilroy Foods, Inc. on July 17, 1985; wherein Pacific Thermonetics, Inc. was removed as a party to the PPA; and
C. The PPA has been amended by the Second Amendment signed by PG&E on June 9, 1986, and GEC on June 9, 1986 which provided PG&E operating flexibility in exchange for a modified pricing arrangement; and
Page 1 of 6
April 25, 1995

DRAFT
D. The PPA has been amended by the Third Amendment signed by PG&E on August 18, 1988, and GEC on June 20, 1988 which provides that the physical limitation of GEC's interconnection facilities was increased; and
E. The PPA has been amended by the Fourth Amendment signed by PG&E on June 9, 1991, and GEC on June 5, 1991, which provided for changes in the operation flexibility of the Facility; and
F. The Facility began initial energy deliveries under the PPA on September 18, 1987, and has since regularly produced energy and capacity for sale to PG&E under the PPA, and
G. The Firm Capacity Availability Date (as defined in the PPA) occurred on February 16, 1988; and
H. The Parties have agreed that it will be to their mutual benefit to expand the shut down periods under the existing terms of the PPA, which currently directs GEC to shutdown 6 hours each day during the months of May and June. The Parties have agreed that the Facility shall shut down a total of eight and one-half hours each week day, and twenty-four hours on each weekend-day and holiday, in exchange for a curtailment payment calculated in accordance with this Curtailment Agreement.
AGREEMENT
THEREFORE, in consideration of the mutual covenants in this Agreement, the Parties agree as follows:
1. DEFINITIONS
Whenever used in this Agreement, the following terms shall have the following meanings:
Page 2 of 6
April 25, 1995

1.1 Curtailment Period: All hours between 0001 hours May 1, 1995 and 2400 hours June 30, 1995.
1.2 kW: Kilowatts
1.3 kWh: Kilowatt hours
1.4 Scheduled Maintenance: an outage to perform maintenance on the Facility that is scheduled in advance, is of a predetermined duration and meets the PPA requirements for Scheduled Maintenance, including annual hour limits and notice requirements. These requirements are specified in the PPA in
Section E-3, Appendix E.
2. CURTAILMENT
2.1 During the Curtailment Period, Seller shall cease deliveries of energy and capacity to PG&E (i) between the hours of 9:30 p.m. through 6:00
a.m. Monday through Friday (44 days), and (ii) for 24 hours, on Saturday, Sunday and Memorial Day (17 days). GEC shall be allowed up to six (6) hours each Monday morning (Tuesday morning after Memorial Day) to reach full capacity and GEC;s "ramp up" time shall be excluded from the firm capacity calculation and, if applicable, the firm capacity bonus factor calculation.
2.2 Curtailment Termination
Either Party may terminate this Agreement at any time by giving written notice to the other party. In the event that curtailment is canceled by either Party, GEC will revert to operating its Facility 18 hours through the end of June 1995.
3. CURTAILMENT PAYMENTS
3.1 PG&E agrees to pay GEC, each month, a lump sum payment of $125,000 for a total of $250,000 for May and June. This lump payment shall cover GEC's costs to: (i) startup its Facility during this Curtailment Period; and (ii) offset its gas purchasing fees associated with this Curtailment Period. Should PG&E consider obtaining additional curtailment beyond that covered in this Agreement, the provisions listed in Amendment 4 to the PPA for startup notification and charges for excessive costs incurred for gas purchases would apply.
Page 3 of 6
April 25, 1995

3.2 During the "ramp down" of the Facility, PG&E shall pay GEC the monthly alternate price for any deliveries received after 9:30 pm each week night for up to one hour (10:30 pm). Zero payments will be made for deliveries after 10:30 pm on week nights.
3.3 GEC shall be allowed to operate its Facility at contract prices in the event of an auxiliary boiler equipment failure so that it may provide supply process steam to the Gilroy Foods plant. However in those instances, the lump sum payment for that month shall be prorated on an hourly basis and GEC shall be paid only for those hours in which it actually curtailed additional deliveries (i.e., beyond the 6 hours already provided for under the PPA.
3.4 If this Agreement is terminated early pursuant to Section 2.1 above, the lump sum payment shall be prorated on an hourly basis and GEC shall be paid only for those hours in which it actually curtailed additional deliveries (i.e., beyond the 6 hours already provided for under the PPA). This payment is due to Gilroy when the monthly purchased power statement for the applicable month (May and June) is due to Gilroy per Section A.4 of Appendix A of the PPA.
3.5 In addition, GEC shall be allowed to operate 24 hours a day from September 1, 1995 through November 30, 1995, at prices already covered by the PPA. In the event of an early termination of this Agreement, GEC shall be allowed to operate 24 hours a day: (i) for the entire month of November 1995 if this Agreement is effective for at least one week; (ii) for the entire months of October and November 1995 if this Agreement is effective for at least five weeks; and (iii) for the entire months of September, October and November only if this Curtailment Period has run its full course through the end of June 1995. Periods covered under Section 3.3 above shall be excused if they do not exceed a week's worth of operation.
4. MISCELLANEOUS
4.1 Effect on PPA
This Agreement does not modify or amend the terms of the PPA or any other agreement between the Parties.
4.2 Entire Agreement
Page 4 of 6
April 25, 1995

DRAFT
This Agreement constitutes the entire agreement of the parties with respect to the subject-matter hereof and supersedes any and all prior negotiations, correspondence, understandings and agreements between the Parties respecting the subject-matter of this Agreement.
4.3 Modification of Agreement
This Agreement may be modified or amended only by a written instrument signed by the authorized representatives of both Parties.
4.4 Captions
Captions are included herein for ease of reference only. The captions are not intended to affect the meaning of the contents or scope of this Agreement.
4.5 Interpretation
No provision of this Agreement shall be interpreted for or against PG&E or Seller because PG&E, Seller or their respective attorneys drafted the particular provision.
4.6 Jurisdiction
This Agreement shall be construed and interpreted in accord with the laws of the State of California, excluding any choice of law rules that may direct the application of the laws of another jurisdiction.
4.7 Waiver
No term or provision herein shall be deemed waived and no breach excused unless such waiver or consent is in writing and signed by the Party claimed to have so waived or excused.
4.8 Notices
All notices under this Agreement shall be addressed as follows.
To PG&E:
Mr. Marc L. Renson
Power Contracts Department, B13E Pacific Gas and Electric Company P.O. Box 770000
San Francisco, CA 94177
Page 5 of 6
April 25, 1995

DRAFT
To Seller:
Mr. David Pearson
Gilroy Energy Company, Inc.
1350 Pacheco Pass Highway
Gilroy, CA 95021-0335
IN WITNESS WHEREOF, Seller and PG&E have caused this Agreement to be executed by their authorized representatives.

PACIFIC GAS AND ELECTRIC                GILROY ENERGY CORPORATION,
COMPANY, a California corporation       a California limited partnership
                                        ------------------------------------

- ------------------------------------    ------------------------------------
By                                      By

- ------------------------------------    ------------------------------------
Name                                    Name

- ------------------------------------    ------------------------------------
Title                                   Title

- ------------------------------------    ------------------------------------
Date of Signature                       Date of Signature	

Page 6 of 6
April 25, 1995

EXHIBIT 23.2
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the use of our reports (and to all references to our Firm) included in or made a part of this Registration Statement No. 333-07497.
ARTHUR ANDERSEN LLP
San Jose, California
September 18, 1996

EXHIBIT 23.3
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
We consent to the reference to our firm under the caption "Experts" and to the use of our report dated January 19, 1996, on our audits of the consolidated financial statements of Sumas Cogeneration Company, L.P. and Subsidiary in the Calpine Corporation Registration Statement (Form S-1) dated July 3, 1996 as amended on August 22, 1996 and September 19, 1996 for the Registration of Common Stock.
Moss Adams LLP
Everett, Washington
September 19, 1996

EXHIBIT 23.4
CONSENT OF INDEPENDENT ACCOUNTANTS
We consent to the inclusion in this Registration Statement on Form S-1 of the following:
- our report dated February 3, 1995, except as to the information presented in Note 7 for which the date is March 30, 1995, on our audits of the combined financial statements of LFC No. 38 Corp. and Portsmouth Leasing Corporation and Subsidiaries as of and for the years ended December 31, 1994 and 1993.
- our report dated February 3, 1995, except as to the information presented in Note 6 for which the date is March 30, 1995, on our audits of the consolidated financial statements of LFC No. 60 Corp. and Subsidiary as of and for the years ended December 31, 1994 and 1993.
We also consent to the reference to our firm under the caption "EXPERTS".
Coopers & Lybrand L.L.P.
Philadelphia, Pennsylvania
September 18, 1996

EXHIBIT 23.5
CONSENT OF INDEPENDENT AUDITORS
We consent to the reference to our firm under the caption "Experts" and to the use of our report dated July 18, 1996, with respect to the financial statements of Gilroy Energy Company, a wholly owned subsidiary of Gilroy Foods, Inc. which in turn is a wholly owned subsidiary of McCormick & Company, Inc. as of and for the years ended November 30, 1995 and 1994 included in the Registration Statement (Form S-1, Registration No. 333-07497) and related Prospectus of Calpine Corporation for the registration of 20,751,750 shares of its common stock.
ERNST & YOUNG LLP
Baltimore, Maryland
September 17, 1996

EXHIBIT 99.1
CONSENT OF DIRECTOR NOMINEE
The undersigned hereby consents to the inclusion of his name as a nominee for director of Calpine Corporation in the Registration Statement on Form S-1 (File No. 333-07497) filed by Calpine Corporation with the Securities and Exchange Commission.

/s/  GEORGE J. STATHAKIS

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

George J. Stathakis
Dated as of September 19, 1996