<SUBMISSION>
<ACCESSION-NUMBER>0000916457-05-000089
<TYPE>10-Q
<PUBLIC-DOCUMENT-COUNT>5
<PERIOD>20050930
<FILING-DATE>20051109
<DATE-OF-FILING-DATE-CHANGE>20051109
<FILER>
<COMPANY-DATA>
<CONFORMED-NAME>CALPINE CORP
<CIK>0000916457
<ASSIGNED-SIC>4911
<IRS-NUMBER>770212977
<STATE-OF-INCORPORATION>DE
<FISCAL-YEAR-END>1231
</COMPANY-DATA>
<FILING-VALUES>
<FORM-TYPE>10-Q
<ACT>34
<FILE-NUMBER>001-12079
<FILM-NUMBER>051191197
</FILING-VALUES>
<BUSINESS-ADDRESS>
<STREET1>50 WEST SAN FERNANDO ST
<CITY>SAN JOSE
<STATE>CA
<ZIP>95113
<PHONE>4089955115
</BUSINESS-ADDRESS>
<MAIL-ADDRESS>
<STREET1>50 W SAN FERNANDO
<STREET2>SUITE 500
<CITY>SAN JOSE
<STATE>CA
<ZIP>95113
</MAIL-ADDRESS>
</FILER>
<DOCUMENT>
<TYPE>10-Q
<SEQUENCE>1
<FILENAME>q3-2005.txt
<TEXT>
================================================================================

                UNITED STATES SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549
                             ----------------------

                                    Form 10-Q


     (Mark One)
         |X|      QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
                  OF THE SECURITIES EXCHANGE ACT OF 1934

                  For the quarterly period ended September 30, 2005

                                       or

         [ ]      TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
                  OF THE SECURITIES EXCHANGE ACT OF 1934

                  For the transition period from         to

                         Commission file number: 1-12079
                             ----------------------

                               Calpine Corporation
                            (A Delaware Corporation)

                  I.R.S. Employer Identification No. 77-0212977

                           50 West San Fernando Street
                           San Jose, California 95113
                            Telephone: (408) 995-5115

     Indicate  by check mark  whether the  registrant  (1) has filed all reports
required to be filed by Section 13 or 15(d) of the  Securities  Exchange  Act of
1934  during  the  preceding  12 months  (or for such  shorter  period  that the
registrant was required to file such reports),  and (2) has been subject to such
filing requirements for the past 90 days.

                                 Yes |X| No [ ]

     Indicate by check mark whether the registrant is an  accelerated  filer (as
defined in Rule 12b-2 of the Exchange Act).

                                 Yes |X| No [ ]

     Indicate the number of shares  outstanding of each of the issuer's  classes
of common stock, as of the latest practicable date:

     569,382,412 shares of Common Stock, par value $.001 per share,  outstanding
on November 8, 2005.

================================================================================



<PAGE>
<TABLE>
<CAPTION>
                      CALPINE CORPORATION AND SUBSIDIARIES

                               REPORT ON FORM 10-Q
                    For the Quarter Ended September 30, 2005

                                      INDEX


                                                                                                              Page No.
                                                                                                              --------

<S>        <C>                                                                                                    <C>
PART I --  FINANCIAL INFORMATION
           Item 1.  Financial Statements
                      Consolidated Condensed Balance Sheets September 30, 2005 and December 31, 2004..........     5
                      Consolidated Condensed Statements of Operations for the Three and Nine Months Ended
                        September 30, 2005 and 2004...........................................................     7
                      Consolidated Condensed Statements of Cash Flows for the Nine Months Ended
                        September 30, 2005 and 2004...........................................................     9
                    Notes to Consolidated Condensed Financial Statements......................................    11
                      1.       Organization and Operations of the Company.....................................    11
                      2.       Summary of Significant Accounting Policies.....................................    11
                      3.       Strategic Initiative...........................................................    16
                      4.       Available-for-Sale Debt Securities.............................................    19
                      5.       Property, Plant and Equipment, Net and Capitalized Interest....................    20
                      6.       Unconsolidated Investments.....................................................    22
                      7.       Debt...........................................................................    25
                      8.       Discontinued Operations........................................................    29
                      9.       Derivative Instruments.........................................................    34
                      10.      Comprehensive Income (Loss)....................................................    38
                      11.      Loss Per Share.................................................................    40
                      12.      Commitments and Contingencies..................................................    42
                      13.      Operating Segments.............................................................    49
                      14.      California Power Market........................................................    50
                      15.      Subsequent Events..............................................................    52
           Item 2.  Management's Discussion and Analysis of Financial Condition and Results of Operations.....    52
                      Selected Operating Information..........................................................    53
                      Overview................................................................................    54
                      Results of Operations...................................................................    57
                      Liquidity and Capital Resources.........................................................    72
                      Performance Metrics.....................................................................    81
                      Summary of Key Activities...............................................................    84
                      California Power Market.................................................................    85
                      Financial Market Risks..................................................................    85
                      New Accounting Pronouncements...........................................................    93
           Item 3.  Quantitative and Qualitative Disclosures About Market Risk................................    93
           Item 4.  Controls and Procedures...................................................................    94

PART II -- OTHER INFORMATION
           Item 1.  Legal Proceedings.........................................................................    95
           Item 6.  Exhibits..................................................................................    95
Signatures....................................................................................................    99
</TABLE>

































                                     - 2 -
<PAGE>
                                   DEFINITIONS

     As used in this Form 10-Q,  the  abbreviations  contained  herein  have the
meanings set forth below.  Additionally,  the terms,  "Calpine,"  "we," "us" and
"our"  refer to Calpine  Corporation  and its  subsidiaries,  unless the context
clearly indicates otherwise.

<TABLE>
<CAPTION>
ABBREVIATION                            DEFINITION
------------                            ----------
<C>                                     <C>
2004 Form 10-K                          Calpine Corporation's Annual Report on Form 10-K for the year ended December 31, 2004,
                                          filed with the SEC on March 31, 2005
2006 Convertible Notes                  4% Convertible Senior Notes Due 2006
2014 Convertible Notes                  6% Contingent Convertible Notes Due 2014
2015 Convertible Notes                  7 3/4% Contingent Convertible Notes Due 2015
2023 Convertible Notes                  4 3/4% Contingent Convertible Senior Notes Due 2023
Acadia PP                               Acadia Power Partners, LLC
AELLC                                   Androscoggin Energy LLC
Agnews                                  O.L.S. Energy - Agnews, Inc.
AICPA                                   American Institute of Certified Public Accountants
AOCI                                    Accumulated Other Comprehensive Income
APB                                     Accounting Principles Board
ARB                                     Accounting Research Bulletin
Auburndale PP                           Auburndale Power Partners, Limited Partnership
Bcfe                                    Billion cubic feet equivalent
Bear Stearns                            Bear Stearns Companies, Inc.
Btu                                     British thermal units
CAISO                                   California Independent System Operator
CalBear                                 CalBear Energy, LP
CalGen                                  Calpine Generating Company, LLC, formerly Calpine Construction Finance Company II, LLC
Calpine Canada                          Calpine Canada Natural Gas Partnership
Calpine Cogen                           Calpine Cogeneration Corporation, formerly Cogen America
Calpine Jersey I                        Calpine (Jersey) Limited
Calpine Jersey II                       Calpine European Funding (Jersey) Limited
CalPX                                   California Power Exchange
CCFC I                                  Calpine Construction Finance Company, L.P
CCFC LLC                                CCFC Preferred Holdings, LLC
CCRC                                    Calpine Canada Resources Company, f/k/a/ Calpine Canada Resources Ltd.
CDWR                                    California Department of Water Resources
CES                                     Calpine Energy Services, L.P.
CFE                                     Comision Federal de Electricidad
Chubu                                   Chubu Electric Power Company, Inc.
CIP                                     Construction in Progress
CMSC                                    Calpine Merchant Services Company, Inc.
CNEM                                    Calpine Northbrook Energy Marketing, LLC
CNGT                                    Calpine Natural Gas Trust
Cogen America                           Cogeneration Corporation of America, now called Calpine Cogeneration Corporation
COR                                     Cost of revenue
CPIF                                    Calpine Power Income Fund
CPLP                                    Calpine Power, L.P.
CPUC                                    California Public Utilities Commission
CTA                                     Cumulative Translation Adjustment
DB London                               Deutsche Bank AG London
Deer Park                               Deer Park Energy Center Limited Partnership
Diamond                                 Diamond Generating Corporation
DOL                                     United States Department of Labor
E&S                                     Electricity and steam
EITF                                    Emerging Issues Task Force
Enron                                   Enron Corp
Enron Canada                            Enron Canada Corp.
Entergy                                 Entergy Services, Inc.
EOB                                     Electricity Oversight Board
EPS                                     Earnings per share
ERISA                                   Employee Retirement Income Security Act
ESA                                     Energy Services Agreement
FASB                                    Financial Accounting Standards Board
FERC                                    Federal Energy Regulatory Commission
FFIC                                    Fireman's Fund Insurance Company
FIN                                     FASB Interpretation Number
First Priority Notes                    9 5/8% First Priority Senior Secured Notes Due 2014
GAAP                                    Generally accepted accounting principles
GE                                      General Electric International, Inc.
Geysers                                 Geysers Power Company, LLC
Grays Ferry                             Grays Ferry Cogeneration Partnership
Hawaii Fund                             Hawaii Structural Ironworkers Pension Trust Fund
HBO                                     Hedging, balancing and optimization
Heat rate                               A measure of the amount of fuel required to produce a unit of electricity
HIGH TIDES                              Convertible Preferred Securities, Remarketable Term Income Deferrable Equity Securities
                                          (HIGH TIDES SM)
IP                                      International Paper Company
KW                                      Kilowatt(s)
KWh                                     Kilowatt hour(s)
LCRA                                    Lower Colorado River Authority



                                     - 3 -
<PAGE>

ABBREVIATION                            DEFINITION
------------                            ----------
LIBOR                                   London Inter-Bank Offered Rate
LNG                                     Liquid natural gas
LTSA                                    Long Term Service Agreement
Metcalf                                 Metcalf Energy Center, LLC
Mitsui                                  Mitsui & Co., Ltd.
MLCI                                    Merrill Lynch Commodities, Inc.
MMBtu                                   Million Btu
Mmcfe                                   Million net cubic feet equivalent
Morris                                  Morris Cogeneration, LLC, formerly known as Calpine Morris, LLC
MW                                      Megawatt(s)
MWh                                     Megawatt hour(s)
NESCO                                   National Energy Systems Company
NOL                                     Net operating loss
NPC                                     Nevada Power Company
O&M                                     Operations and maintenance
OCI                                     Other Comprehensive Income
Oneta                                   Oneta Energy Center
Ontelaunee                              Ontelaunee Energy Center
OPA                                     Ontario Power Authority
Panda                                   Panda Energy International, Inc., and related party PLC II, LLC
PCF                                     Power Contract Financing, L.L.C.
PCF III                                 Power Contract Financing III, LLC
PJM                                     Pennsylvania-New Jersey-Maryland
Plan                                    Calpine Corporation Retirement Savings Plan
POX                                     Plant operating expense
PPA(s)                                  Power purchase agreement(s)
PSM                                     Power Systems MFG., LLC
PUCN                                    Public Utilities Commission of Nevada
QF                                      Qualifying Facilities
Reliant                                 Reliant Energy Services, Inc.
RMR Contracts                           Reliability must run contracts
Rosetta                                 Rosetta Resources Inc.
SAB                                     Staff Accounting Bulletin
Saltend                                 Saltend Energy Centre
SEC                                     Securities and Exchange Commission
Second Priority Notes                   Calpine  Corporation's  Second  Priority  Senior  Secured  Floating  Rate  Notes  due  2007,
                                          8.500%  Second  Priority  Senior  Secured  Notes due 2010,  8.750% Second Priority  Senior
                                          Secured Notes due 2013 and 9.875% Second  Priority  Senior Secured Notes due 2011
Second Priority Secured Debt            The Indentures between the Company and Wilmington Trust Company, as Trustee, relating to the
Instruments                               Company's  Second  Priority  Senior  Secured  Floating  Rate Notes due 2007, 8.500% Second
                                          Priority  Senior  Secured  Notes due 2010, 8.750% Second Priority Senior Secured Notes due
                                          2013,  9.875% Second Priority Senior Secured Notes due 2011 and the Credit Agreement among
                                          the  Company,  as  Borrower,  Goldman Sachs Credit Partners L.P., as Administrative Agent,
                                          Sole  Lead  Arranger  and  Sole  Book Runner,  The Bank of Nova  Scotia,  as Arranger  and
                                          Syndication Agent, TD Securities (USA) Inc., ING (U.S.) Capital LLC and Landesbank Hessen-
                                          Thuringen,  as Co-Arrangers, and  Credit  Lyonnais  New  York  Branch  and  Union  Bank of
                                          California, N.A.,  as  Managing Agent, relating to the Company's Senior Secured Term Loans
                                          Due 2007, in each case as such instruments may be amended from time to time.
Securities Act                          Securities Act of 1933, as amended
Senior Secured Noteholders              Holders of the First Priority Notes and the Second Priority Notes
SFAS                                    Statement of Financial Accounting Standards
Siemens-Westinghouse                    Siemens-Westinghouse  Power  Corporation  (changed  to  "Siemens  Power  Generation, Inc. on
                                          August 1, 2005)
SkyGen                                  SkyGen Energy LLC, now called Calpine Northbrook Energy, LLC
SPE                                     Special-Purpose Entities
SPPC                                    Sierra Pacific Power Company
TAC                                     Third Amended Complaint
TNAI                                    Thermal North America, Inc.
TSA(s)                                  Transmission service agreement(s)
TTS                                     Thomassen Turbine Systems, B.V.
Valladolid                              Compania de Generacion Valladolid S.de R.L. de C.V. partnership
VIE(s)                                  Variable interest entity(ies)
Westcoast                               Westcoast Energy Inc.
Whitby                                  Whitby Cogeneration Limited Partnership
Williams                                The Williams Companies, Inc.
</TABLE>



















                                     - 4 -
<PAGE>
                         PART I -- FINANCIAL INFORMATION

Item 1.  Financial Statements.

                      CALPINE CORPORATION AND SUBSIDIARIES

                      CONSOLIDATED CONDENSED BALANCE SHEETS
                    September 30, 2005 and December 31, 2004
<TABLE>
<CAPTION>
                                                                                                      September 30,   December 31,
                                                                                                          2005            2004
                                                                                                     --------------  ---------------
                                                                                                     (In thousands, except share and
                                                                                                            per share amounts)
                                                                                                              (Unaudited)
                      ASSETS
<S>                                                                                                  <C>             <C>
Current assets:
Cash and cash equivalents.........................................................................   $      843,136  $      718,023
Accounts receivable, net..........................................................................        1,537,620       1,043,061
Margin deposits and other prepaid expense.........................................................          415,331         437,593
Inventories.......................................................................................          151,672         171,639
Restricted cash...................................................................................        1,106,685         593,304
Current derivative assets.........................................................................          703,665         324,206
Current assets held for sale......................................................................           47,152         142,096
Other current assets..............................................................................          232,741         133,643
                                                                                                     --------------  --------------
    Total current assets..........................................................................        5,038,002       3,563,565
                                                                                                     --------------  --------------
Restricted cash, net of current portion...........................................................          204,433         157,868
Notes receivable, net of current portion..........................................................          194,076         203,680
Project development costs.........................................................................          135,291         150,179
Unconsolidated investments........................................................................          348,058         373,108
Deferred financing costs..........................................................................          363,513         406,844
Prepaid lease, net of current portion.............................................................          467,658         424,586
Property, plant and equipment, net................................................................       18,542,923      18,397,743
Goodwill..........................................................................................           45,160          45,160
Other intangible assets, net......................................................................           66,410          68,423
Long-term derivative assets.......................................................................          925,251         506,050
Long-term assets held for sale....................................................................          210,213       2,260,401
Other assets......................................................................................          547,249         658,481
                                                                                                     --------------  --------------
     Total assets.................................................................................   $   27,088,237  $   27,216,088
                                                                                                     ==============  ==============
             LIABILITIES & STOCKHOLDERS' EQUITY
Current liabilities:
  Accounts payable................................................................................   $    1,192,408  $      980,280
  Accrued payroll and related expense.............................................................           85,205          87,659
  Accrued interest payable........................................................................          406,752         385,794
  Income taxes payable............................................................................           64,562          57,234
  Notes payable and borrowings under lines of credit, current portion.............................          208,145         200,076
  Preferred interests, current portion............................................................          159,453           8,641
  Capital lease obligation, current portion.......................................................            7,143           5,490
  CCFC I financing, current portion...............................................................            3,208           3,208
  Construction/project financing, current portion.................................................           85,891          93,393
  Senior notes and term loans, current portion....................................................          967,892         718,449
  Current derivative liabilities..................................................................          974,097         356,030
  Current liabilities held for sale...............................................................            6,623          86,458
  Other current liabilities.......................................................................          355,790         302,680
                                                                                                     --------------  --------------
    Total current liabilities.....................................................................        4,517,169       3,285,392
                                                                                                     --------------  --------------
Notes payable and borrowings under lines of credit, net of current portion........................          586,770         769,490
Convertible debentures payable to Calpine Capital Trust III.......................................               --         517,500
Preferred interests, net of current portion.......................................................          283,615         497,896
Capital lease obligation, net of current portion..................................................          281,045         283,429
CCFC I financing, net of current portion..........................................................          780,901         783,542
CalGen/CCFC II financing..........................................................................        2,396,720       2,395,332
Construction/project financing, net of current portion............................................        2,361,716       1,905,658
Convertible Notes.................................................................................        1,833,790       1,255,298
Senior notes and term loans, net of current portion...............................................        7,231,719       8,532,664
Deferred income taxes, net of current portion.....................................................        1,109,073         885,754
Deferred revenue..................................................................................          139,834         114,202
Long-term derivative liabilities..................................................................        1,215,463         516,230
Long-term liabilities held for sale...............................................................               --         176,299
Other liabilities.................................................................................          217,257         316,284
                                                                                                     --------------  --------------
    Total liabilities.............................................................................       22,955,072      22,234,970
                                                                                                     --------------  --------------
Minority interests................................................................................          403,197         393,445
                                                                                                     --------------  --------------

                               (table continues)



                                     - 5 -
<PAGE>
                                                                                                      September 30,   December 31,
                                                                                                          2005            2004
                                                                                                     --------------  ---------------
                                                                                                     (In thousands, except share and
                                                                                                            per share amounts)
                                                                                                              (Unaudited)
                       LIABILITIES & STOCKHOLDERS' EQUITY

Commitments and Contingencies (Note 12)
Stockholders' equity:
  Preferred stock, $.001 par value per share; authorized 10,000,000 shares; none issued and
   outstanding in 2005 and 2004...................................................................               --              --
  Common stock, $.001 par value per share; authorized 2,000,000,000 shares; issued and
   outstanding 569,382,412 shares in 2005 and 536,509,231 shares in 2004..........................              569             537
  Additional paid-in capital......................................................................        3,262,604       3,151,577
  Additional paid-in capital, loaned shares.......................................................          258,100         258,100
  Additional paid-in capital, returnable shares...................................................         (258,100)       (258,100)
  Retained earnings...............................................................................          642,169       1,326,048
  Accumulated other comprehensive income (loss)...................................................         (175,374)        109,511
                                                                                                     --------------  --------------
       Total stockholders' equity.................................................................        3,729,968       4,587,673
                                                                                                     --------------  --------------
       Total liabilities and stockholders' equity.................................................   $   27,088,237  $   27,216,088
                                                                                                     ==============  ==============
</TABLE>

              The accompanying notes are an integral part of these
                  Consolidated Condensed Financial Statements.





























































                                     - 6 -
<PAGE>
                      CALPINE CORPORATION AND SUBSIDIARIES

                 CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS
         For the Three and Nine Months Ended September 30, 2005 and 2004
<TABLE>
<CAPTION>
                                                                                  Three Months Ended            Nine Months Ended
                                                                                     September 30,                September 30,
                                                                           --------------------------    ---------------------------
                                                                               2005           2004           2005           2004
                                                                           -----------    -----------    -----------    ------------
                                                                                    (In thousands, except per share amounts)
                                                                                                 (Unaudited)
<S>                                                                        <C>            <C>            <C>            <C>
Revenue:
  Electric generation and marketing revenue
    Electricity and steam revenue ......................................   $ 2,096,323    $ 1,544,329    $ 4,625,078    $ 3,851,914
    Transmission sales revenue .........................................         1,902          4,427          8,791         14,152
    Sales of purchased power for hedging and optimization ..............       413,281        427,737      1,193,537      1,301,585
                                                                           -----------    -----------    -----------    -----------
     Total electric generation and marketing revenue ...................     2,511,506      1,976,493      5,827,406      5,167,651
  Oil and gas production and marketing revenue
    Oil and gas sales ..................................................            --          2,690             --          4,707
    Sales of purchased gas for hedging and optimization ................       696,850        423,733      1,574,067      1,258,441
                                                                           -----------    -----------    -----------    -----------
     Total oil and gas production and marketing revenue ................       696,850        426,423      1,574,067      1,263,148
  Mark-to-market activities, net .......................................        40,854         (5,229)        40,197        (15,316)
  Other revenue ........................................................        32,380         14,046         84,558         50,849
                                                                           -----------    -----------    -----------    -----------
       Total revenue ...................................................     3,281,590      2,411,733      7,526,228      6,466,332
                                                                           -----------    -----------    -----------    -----------
Cost of revenue:
  Electric generation and marketing expense
    Plant operating expense ............................................       180,336        159,957        555,433        522,237
    Transmission purchase expense ......................................        23,088         22,706         63,770         53,783
    Royalty expense ....................................................         9,988          8,343         28,348         21,067
    Purchased power expense for hedging and optimization ...............       343,778        348,380        960,110      1,165,674
                                                                           -----------    -----------    -----------    -----------
     Total electric generation and marketing expense ...................       557,190        539,386      1,607,661      1,762,761
  Oil and gas operating and marketing expense
    Oil and gas operating expense ......................................         1,393          1,837          4,318          5,824
    Purchased gas expense for hedging and optimization .................       724,351        429,373      1,623,692      1,243,781
                                                                           -----------    -----------    -----------    -----------
     Total oil and gas operating and marketing expense .................       725,744        431,210      1,628,010      1,249,605
  Fuel expense .........................................................     1,567,504      1,052,309      3,336,248      2,671,860
  Depreciation, depletion and amortization expense .....................       131,006        117,391        371,340        324,871
  Operating lease expense ..............................................        28,792         25,805         79,097         80,567
  Other cost of revenue ................................................        32,227         19,187        102,547         68,177
                                                                           -----------    -----------    -----------    -----------
       Total cost of revenue ...........................................     3,042,463      2,185,288      7,124,903      6,157,841
                                                                           -----------    -----------    -----------    -----------
        Gross profit ...................................................       239,127        226,445        401,325        308,491
(Income) loss from unconsolidated investments ..........................        (5,384)        11,202        (14,644)        12,174
Equipment cancellation and impairment cost .............................           761          7,820            689         10,187
Long-term service agreement cancellation charge ........................           553          3,981         34,445          3,981
Project development expense ............................................        10,098          3,366         71,639         15,114
Research and development expense .......................................         3,342          3,982         15,502         12,921
Sales, general and administrative expense ..............................        54,593         53,770        176,318        156,008
                                                                           -----------    -----------    -----------    -----------
  Income from operations ...............................................       175,164        142,324        117,376         98,106
Interest expense .......................................................       380,994        285,446      1,027,382        791,242
Interest (income) ......................................................       (26,640)       (16,957)       (57,417)       (37,996)
Minority interest expense ..............................................        10,977          9,990         31,763         23,149
(Income) from repurchase of debt .......................................       (15,530)      (167,154)      (166,456)      (170,548)
Other expense (income), net ............................................        50,311         22,446         71,446       (168,934)
                                                                           -----------    -----------    -----------    -----------
  Income (loss) before benefit for income taxes ........................      (224,948)         8,553       (789,342)      (338,807)
Provision (benefit) for income taxes ...................................        17,487        (20,324)      (167,866)      (144,332)
                                                                           -----------    -----------    -----------    -----------
  Income (loss) before discontinued operations .........................      (242,435)        28,877       (621,476)      (194,475)
Discontinued operations, net of tax provision of $170,514, $102,282,
  $137,629 and $92,061 .................................................        25,746        112,248        (62,403)       235,710
                                                                           -----------    -----------    -----------    -----------
        Net income (loss) ..............................................   $  (216,689)   $   141,125    $  (683,879)   $    41,235
                                                                           ===========    ===========    ===========    ===========
Basic earnings (loss) per common share:
  Weighted average shares of common stock outstanding...................       478,461        444,380        458,483        425,682
  Income (loss) before discontinued operations..........................   $     (0.51)   $      0.07    $     (1.36)   $     (0.45)
  Discontinued operations, net of tax...................................   $      0.06    $      0.25    $     (0.13)   $      0.55
                                                                           -----------    -----------    -----------    -----------
        Net income (loss)...............................................   $     (0.45)   $      0.32    $     (1.49)   $      0.10
                                                                           ===========    ===========    ===========    ===========

                               (table continues)




                                     - 7 -
<PAGE>
                                                                                  Three Months Ended            Nine Months Ended
                                                                                     September 30,                September 30,
                                                                           --------------------------    ---------------------------
                                                                               2005           2004           2005           2004
                                                                           -----------    -----------    -----------    ------------
                                                                                    (In thousands, except per share amounts)
                                                                                                 (Unaudited)
Diluted earnings per common share:
  Weighted average shares of common stock outstanding...................       478,461        446,922        458,483        425,682
  Income (loss) before discontinued operations..........................   $     (0.51)   $      0.07    $     (1.36)   $     (0.45)
  Discontinued operations, net of tax...................................   $      0.06    $      0.25    $     (0.13)   $      0.55
                                                                           -----------    -----------    -----------    -----------
        Net income (loss)...............................................   $     (0.45)   $      0.32    $     (1.49)   $      0.10
                                                                           ===========    ===========    ===========    ===========
</TABLE>
              The accompanying notes are an integral part of these
                  Consolidated Condensed Financial Statements.







































































                                     - 8 -
<PAGE>
                      CALPINE CORPORATION AND SUBSIDIARIES

                 CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
              For the Nine Months Ended September 30, 2005 and 2004
<TABLE>
<CAPTION>
                                                                                                             Nine Months Ended
                                                                                                               September 30,
                                                                                                       -----------------------------
                                                                                                           2005             2004
                                                                                                       ------------     ------------
                                                                                                              (In thousands)
                                                                                                                (Unaudited)
<S>                                                                                                    <C>              <C>
Cash flows from operating activities:
  Net income (loss) ..............................................................................     $  (683,879)     $    41,235
  Adjustments to reconcile net income (loss) to net cash used in operating activities:
  Depreciation, depletion and amortization (1) ...................................................         596,118          598,856
  Impairment charges on power projects............................................................         261,532               --
  Development cost write-off .....................................................................          46,958               --
  Deferred income taxes, net .....................................................................         (30,237)         (52,272)
  Gain on sale of assets .........................................................................        (351,950)        (348,053)
  Stock compensation expense .....................................................................          16,430           15,190
  Foreign exchange losses ........................................................................          57,182            7,521
  (Income) from repurchase of debt ...............................................................        (166,456)        (170,548)
  Change in net derivative assets and liabilities ................................................          17,041           40,782
  (Income) loss from unconsolidated investments ..................................................         (14,804)          11,663
  Distributions from unconsolidated investments ..................................................          16,862           22,263
  Other ..........................................................................................          32,452           74,573
  Change in operating assets and liabilities, net of effects of acquisitions:
    Accounts receivable ..........................................................................        (416,488)        (104,787)
    Other current assets .........................................................................          15,788           (1,202)
    Other assets .................................................................................         (35,587)         (66,224)
    Accounts payable and accrued expense .........................................................         205,737          218,862
    Other liabilities ............................................................................          25,328          (57,989)
                                                                                                       -----------      -----------
      Net cash provided by (used in) operating activities ........................................        (407,973)         229,870
                                                                                                       -----------      -----------
Cash flows from investing activities:
  Purchases of property, plant and equipment .....................................................        (675,714)      (1,184,352)
  Disposals of property, plant and equipment .....................................................       1,860,981        1,065,834
  Disposal of subsidiary .........................................................................              --           85,412
  Disposal of investment .........................................................................          36,900               --
  Acquisitions, net of cash acquired .............................................................              --         (187,786)
  Advances to unconsolidated investments .........................................................              --           (8,833)
  Project development costs ......................................................................         (13,095)         (23,605)
  Investment in HIGH TIDES .......................................................................              --         (111,550)
  Disposal of HIGH TIDES investment ..............................................................         132,500               --
  Sale of collateral securities ..................................................................              --           93,963
  Increase in restricted cash ....................................................................        (559,946)        (124,153)
  Decrease in notes receivable ...................................................................             759            9,979
  Other ..........................................................................................          40,304            3,157
                                                                                                       -----------      -----------
      Net cash provided by (used in) investing activities ........................................         822,689         (381,934)
                                                                                                       -----------      -----------
Cash flows from financing activities:
  Borrowings from notes payable and lines of credit ..............................................           6,488           97,191
  Repayments of notes payable and lines of credit ................................................        (808,784)        (328,943)
  Borrowings from project financing ..............................................................         620,956        3,477,854
  Repayments of project financing ................................................................        (176,799)      (2,942,272)
  Repayments and repurchases of senior notes .....................................................        (821,252)        (630,275)
  Repurchase of convertible senior notes .........................................................             (15)        (586,926)
  Proceeds from issuance of convertible senior notes .............................................         650,000          867,504
  Proceeds from issuance of senior debt offerings ................................................              --          878,815
  Proceeds from preferred interests (2) ..........................................................         565,000               --
  Repayment of convertible debentures to Calpine Capital Trust III ...............................        (517,500)              --
  Proceeds from prepaid commodity contract (3) ...................................................         290,571               --
  Financing and transaction costs ................................................................         (89,318)        (175,802)
  Other ..........................................................................................         (28,318)         (23,443)
                                                                                                       -----------      -----------
      Net cash provided by (used in) financing activities ........................................        (308,971)         633,703
                                                                                                       -----------      -----------
Effect of exchange rate changes on cash and cash equivalents .....................................             741           14,377
Net decrease in cash and cash equivalents including discontinued operations cash .................         106,486          496,016
Change in discontinued operations cash classified as current assets held for sale ................          18,627            7,694
                                                                                                       -----------      -----------
  Net increase in cash and cash equivalents ......................................................         125,113          503,710
                                                                                                       -----------      -----------
Cash and cash equivalents, beginning of period ...................................................         718,023          954,827
Cash and cash equivalents, end of period .........................................................     $   843,136      $ 1,458,537
                                                                                                       ===========      ===========
Cash paid during the period for:
  Interest, net of amounts capitalized ...........................................................     $   962,866      $   674,875
  Income taxes ...................................................................................     $    23,653      $    21,863
------------

                               (table continues)

                                     - 9 -
<PAGE>

<FN>
(1)  Includes  depreciation  and  amortization  that is also  charged  to sales,
     general  and  administrative   expense  and  to  interest  expense  in  the
     Consolidated Condensed Statements of Operations.

(2)  Relates to the $260.0 million Calpine Jersey II, $155.0 million Metcalf and
     $150.0 million CCFC LLC offerings of redeemable preferred  securities.  See
     Note 7 of the accompanying notes.

(3)  Relates  to the Deer Park  prepaid  commodity  contract.  See Note 9 of the
     accompanying notes.

Schedule of non-cash investing and financing activities:

     2005 Issuance of 27.5 million  shares of common stock in exchange for $94.3
          million in principal amount at maturity of 2014 Convertible Notes

     2004 Acquired the  remaining 50% interest in the Aries power plant for $3.7
          million cash and $220.0 million of assumed liabilities, including debt
          of $173.2 million.

     2004 Issuance of 24.3 million  shares of common stock in exchange for $40.0
          million  par  value of HIGH  TIDES I  preferred  securities  and $75.0
          million par value of HIGH TIDES II preferred securities.

     2004 Capital  lease  entered into for the King City facility for an initial
          asset balance of $114.9 million.

     2004 Issuance of 89 million  shares of Calpine  common stock  pursuant to a
          Share Lending  Agreement.  See Note 11 of the  accompanying  notes for
          more information regarding the 89 million shares issued.

     2004 Exchange  of a $177.0  million  note for  $266.2  million of our 4.75%
          Contingent Convertible Senior Notes Due 2023.

              The accompanying notes are an integral part of these
                  Consolidated Condensed Financial Statements.
</FN>
</TABLE>
















































                                     - 10 -
<PAGE>
                      CALPINE CORPORATION AND SUBSIDIARIES

              NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
                               September 30, 2005
                                   (Unaudited)

1.   Organization and Operations of the Company

     Calpine   Corporation,    a   Delaware   corporation,    and   subsidiaries
(collectively,  "Calpine"  or the  "Company")  is engaged in the  generation  of
electricity  predominantly  in the United  States of  America  and  Canada.  The
Company is involved in the development, construction, ownership and operation of
power  generation  facilities  and the sale of electricity  and its  by-product,
thermal  energy,  primarily  in the form of steam.  In the  United  States,  the
Company has ownership interests in, and operates, gas-fired power generation and
cogeneration facilities, pipelines, geothermal steam fields and geothermal power
generation  facilities.  In Canada, the Company has ownership  interests in, and
operates,  gas-fired power generation facilities.  In Mexico, Calpine is a joint
venture participant in a gas-fired power generation facility under construction.
In addition,  at June 30, 2005, the Company owned and operated a gas-fired power
cogeneration  facility in the United Kingdom, but sold this facility on July 28,
2005. The Company markets electricity  produced by its generating  facilities to
utilities  and other  third party  purchasers.  Thermal  energy  produced by the
gas-fired power  cogeneration  facilities is primarily sold to industrial users.
The Company offers to third parties  energy  procurement,  liquidation  and risk
management   services,   combustion  turbine  component  parts  and  repair  and
maintenance  services  world-wide.   The  Company  also  provides   engineering,
procurement,  construction  management,  commissioning  and  O&M  services.  The
Company  previously  owned oil and gas exploration and production  assets in the
United  States and  Canada.  In  September  2004,  the  Company  sold all of its
Canadian  and a portion of its United  States oil and gas assets and, on July 7,
2005, the Company  completed the sale of substantially  all of its remaining oil
and gas exploration and production assets.

2.   Summary of Significant Accounting Policies

     Basis  of  Interim  Presentation  --  The  accompanying  unaudited  interim
Consolidated Condensed Financial Statements of the Company have been prepared by
the Company  pursuant to the rules and regulations of the SEC. In the opinion of
management,   the  Consolidated   Condensed  Financial  Statements  include  the
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
in the  United  States of America  have been  condensed  or  omitted  from these
statements  pursuant  to such  rules and  regulations  and,  accordingly,  these
financial statements should be read in conjunction with the audited Consolidated
Financial  Statements  of the  Company  for the year ended  December  31,  2004,
included in the Company's  Current  Report on Form 8-K dated  December 31, 2004,
filed with the SEC on October 17, 2005. The results for interim  periods are not
necessarily indicative of the results for the entire year.

     Reclassifications  -- Certain  prior  years'  amounts  in the  Consolidated
Condensed  Financial  Statements  have been  reclassified to conform to the 2005
presentation.   This  includes  a   reclassification   to  separately   disclose
transmission  sales revenue  (formerly in other  revenue).  The Company has also
made restatements for discontinued operations.  See Note 8 for more information.
In  addition,  the  Company had certain  reclassifications  on its  Consolidated
Condensed Statement of Cash Flows to conform to the 2005 presentation.

     Use of Estimates in Preparation of Financial  Statements -- The preparation
of  financial  statements  in  conformity  with  generally  accepted  accounting
principles in the United States of America 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 revenue and expense during the reporting
period.  Actual results could differ from those estimates.  The most significant
estimates with regard to these financial  statements  relate to useful lives and
carrying  values  of  assets  (including  the  carrying  value  of  projects  in
development, construction and operation), provision for income taxes, fair value
calculations of derivative  instruments and associated reserves,  capitalization
of interest,  impairment assessments,  primary beneficiary determination for the
Company's  investments in VIEs, the outcome of pending  litigation and estimates
of oil and gas reserve quantities used to calculate depletion,  depreciation and
impairment  of oil and gas  property  and  equipment  (prior  to the  July  2005
disposition).

     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.

     The Company has certain  project  finance  facilities and lease  agreements
that establish  segregated  cash  accounts.  These accounts have been pledged as
security in favor of the lenders to such project finance facilities, and the use
of certain cash balances on deposit in such  accounts with our project  financed



                                     - 11 -
<PAGE>

subsidiaries  is  limited  to the  operations  of the  respective  projects.  At
September 30, 2005, and December 31, 2004,  $423.5  million and $284.4  million,
respectively, of the cash and cash equivalents balance that was unrestricted was
subject to such project finance facilities and lease agreements. In addition, at
September 30, 2005,  and December 31, 2004,  $50.9  million and $232.4  million,
respectively,  of the  Company's  cash  and  cash  equivalents  was held in bank
accounts outside the United States.

     Restricted  Cash -- The Company is required to maintain  cash balances that
are  restricted by  provisions  of its debt  agreements,  lease  agreements  and
regulatory  agencies.  These  amounts are held by  depository  banks in order to
comply with the contractual  provisions  requiring reserves for payments such as
for debt service,  rent service,  major maintenance and debt repurchases.  Funds
that can be used to satisfy  obligations  due during the next twelve  months are
classified  as  current  restricted  cash,  with  the  remainder  classified  as
non-current  restricted cash.  Restricted cash is generally invested in accounts
earning market rates; therefore the carrying value approximates fair value. Such
cash is excluded from cash and cash equivalents in the  consolidated  statements
of cash flows.

     In addition,  in connection  with disputes  concerning  the use of proceeds
from the Company's sales of Saltend and of its remaining oil and gas assets (see
Notes 8 and 12 for more  information)  approximately  $609.2  million of the net
proceeds  of such sales has been  classified  as Current  restricted  cash as of
September 31, 2005, until these disputes are resolved.

     Effective Tax Rate -- For the three months ended  September  30, 2005,  the
effective  rate from  continuing  operations  increased to (7.8)% as compared to
(237.6)%  for the three  months ended  September  30, 2004.  For the nine months
ended  September 30, 2005, and 2004, the effective tax rate was 21.3% and 42.6%,
respectively.  The tax  rates on  continuing  operations  for the three and nine
months ended  September  30, 2005,  were  adversely  affected due to a valuation
allowance  recorded against certain NOL deferred tax assets associated with CCFC
LLC in the amount of approximately $143.4 million. The variance in the effective
tax rate for the three  months  ended  September  30, 2005  compared to the same
period in 2004 was significantly  impacted by the nominal absolute dollar amount
of the  Company's  pre-tax  income  (loss) in each period.  For the three months
ended  September  30,  2004,  the  Company's   pre-tax  income  from  continuing
operations  was $8.6 million.  Therefore,  due to the near  break-even  absolute
value of this amount,  the tax benefit for the period translated into a high tax
rate percentage, even though the benefit was only $20.3 million. Conversely, for
the three  months  ended  September  30,  2005,  pre-tax  loss  from  continuing
operations  was $224.9  million  and the tax  provision  for the period was only
$17.5 million.  Excluding the effects of the valuation allowance associated with
CCFC LLC, the Company would have  recognized a tax benefit of $125.9 million for
the three months ended  September 30, 2005 resulting in an effective tax rate of
56.0%.  While this tax  benefit  (excluding  the effects of CCFC LLC) was $105.6
million  higher  than the tax  benefit  recognized  for the three  months  ended
September  30, 2004,  the effective  tax rate was  significantly  higher for the
three  months  ended  September  30, 2004 due to the nominal  absolute  value of
pre-tax  income from  continuing  operations.  Also, the tax rates on continuing
operations  for the three and nine months ended  September  30, 2004,  have been
restated in  accordance  with FIN 18,  "Accounting  for Income  Taxes in Interim
Periods - an Interpretation  of APB Opinion No. 28," as amended,  to reflect the
effects  of  classifying  the sale of the  Company's  Canadian  and  U.S.  Rocky
Mountain oil and gas assets, and the Saltend, Morris and Ontelaunee power plants
as  discontinued  operations  due  to the  Company's  commitment  to a  plan  of
divesture in the second quarter of 2005. See Note 8 for more  information.  This
effective tax rate on continuing  operations  is based on the  consideration  of
estimated  year-end  earnings in estimating  the quarterly  effective  rate, the
effect of permanent  non-taxable items and establishment of valuation allowances
on certain deferred tax assets.

     Preferred Interests -- As outlined in SFAS No. 150, "Accounting for Certain
Financial  Instruments with Characteristics of both Liabilities and Equity," the
Company classifies  preferred interests that embody obligations to transfer cash
to the preferred  interest  holder,  in short-term  and  long-term  debt.  These
instruments  require the Company to make  priority  distributions  of  available
cash, as defined in each preferred interest agreement,  representing a return of
the preferred interest holder's  investment over a fixed period of time and at a
specified  rate of return in priority to certain other  distributions  to equity
holders.  The return on  investment  is recorded as interest  expense  under the
interest method over the term of the priority period.

     Long-Lived Assets and Impairment  Evaluation -- In accordance with SFAS No.
144,  "Accounting  for the  Impairment  or Disposal of  Long-Lived  Assets," the
Company evaluates the impairment of long-lived  assets,  including  construction
and development projects by first estimating projected undiscounted pre-interest
expense  and  pre-tax   expense  cash  flows  whenever   events  or  changes  in
circumstances  indicate  that the  carrying  amounts  of such  assets may not be
recoverable.   The  significant   assumptions  that  the  Company  uses  in  its
undiscounted  future cash flow  estimates  include the future  supply and demand
relationships  for electricity  and natural gas, the expected  pricing for those
and  that  the  Company  will  hold  these  assets  over their depreciable lives



                                     - 12 -
<PAGE>

commodities  and the resultant  spark  spreads in the various  regions where the
Company  generates  and that the  Company  will hold  these  assets  over  their
depreciable  lives.  In the  event  such  cash  flows  are  not  expected  to be
sufficient to recover the recorded  value of the assets,  the assets are written
down to their estimated fair values.  Certain of the Company's generating assets
are located in regions  with  depressed  demands and market spark  spreads.  The
Company's  forecasts  assume that spark spreads will increase in future years in
these regions as the supply and demand  relationships  improve.  There can be no
assurance  that this will occur.  See Note 8 for a discussion of the  impairment
charge  related  to  Ontelaunee,  which  met the  held-for-sale  criteria  as of
September 30, 2005, and was subsequently sold on October 6, 2005.

     Stock-Based  Compensation -- On January 1, 2003, the Company  prospectively
adopted  the  fair  value  method  of  accounting   for   stock-based   employee
compensation pursuant to SFAS No. 123, "Accounting for Stock-Based Compensation"
as  amended  by  SFAS  No.  148,  "Accounting  for  Stock-Based  Compensation  -
Transition  and  Disclosure."  SFAS No.  148  amended  SFAS No.  123 to  provide
alternative  methods of transition for companies that  voluntarily  change their
accounting for stock-based  compensation from the less preferred intrinsic value
based  method  to the more  preferred  fair  value  based  method.  Prior to its
amendment,  SFAS No. 123 required that companies  enacting a voluntary change in
accounting  principle  from the  intrinsic  value  methodology  provided  by APB
Opinion No. 25,  "Accounting  for Stock  Issued to  Employees,"  and its related
implementation  guidance could only do so on a prospective basis; no adoption or
transition  provisions  were  established  to allow for a  restatement  of prior
period  financial  statements.  SFAS No. 148 provided two additional  transition
options to report the change in accounting  principle--the  modified prospective
method  and the  retroactive  restatement  method.  Additionally,  SFAS No.  148
amended  the  disclosure  requirements  of SFAS  No.  123 to  require  prominent
disclosures in both annual and interim financial  statements about the method of
accounting for stock-based  employee  compensation  and the effect of the method
used on reported  results.  The Company  elected to adopt the provisions of SFAS
No. 123 on a prospective basis; consequently, the Company is required to provide
a pro-forma disclosure of net income and EPS as presented in the table below, as
if SFAS No.  123  accounting  had been  applied to all prior  periods  presented
within its  financial  statements  until  SFAS No.  123-R  (discussed  below) is
adopted  in  January  2006.  As  disclosed  in the table  below,  the  Company's
prospective  adoption of SFAS No. 123 has had a material impact on the Company's
financial  statements.  The  table  below  reflects  the  pro  forma  impact  of
stock-based  compensation  on the  Company's net loss and loss per share for the
three and nine months ended September 30, 2005 and 2004, had the Company applied
the accounting  provisions of SFAS No. 123 to its financial  statements in years
prior to its adoption of SFAS No. 123 (in thousands, except per share amounts):

<TABLE>
<CAPTION>
                                                                               Three Months Ended            Nine Months Ended
                                                                                  September 30,                September 30,
                                                                           --------------------------    --------------------------
                                                                               2005          2004           2005           2004
                                                                           -----------    -----------    -----------    -----------
<S>                                                                        <C>            <C>            <C>           <C>
Net income (loss)
  As reported...........................................................   $  (216,689)   $   141,125    $  (683,879)  $     41,235
  Pro Forma.............................................................      (216,751)       140,102       (684,678)        37,288
Income (loss) per share data:
  Basic earnings per share
    As reported.........................................................   $     (0.45)   $      0.32    $     (1.49)   $      0.10
    Pro Forma...........................................................         (0.45)          0.32          (1.49)          0.09
  Diluted earnings per share
    As reported.........................................................   $     (0.45)   $      0.32    $     (1.49)   $      0.10
    Pro Forma...........................................................         (0.45)          0.31          (1.49)          0.09
Stock-based compensation cost, net of tax,
  included in income (loss), as reported................................   $     2,711    $     3,308    $     9,963    $     9,388
Stock-based compensation cost, net of tax,
  included in income (loss), pro forma..................................         2,773          4,331         10,762         13,335
</TABLE>

New Accounting Pronouncements

  SFAS No. 123-R

     In December  2004,  FASB issued SFAS No. 123 (revised  2004),  "Share Based
Payments." This statement,  referred to as SFAS No. 123-R, revises SFAS No. 123,
and supersedes APB Opinion No. 25 and its related implementation  guidance. This
statement  requires a public  entity to measure  the cost of  employee  services
received in exchange for an award of equity  instruments based on the grant-date
fair value of the award (with limited exceptions), which must be recognized over
the  requisite  service  period  (usually  the vesting  period)  during which an
employee is required to provide service in exchange for the award. The statement
applies to all  share-based  payment  transactions  in which an entity  acquires
goods or services by issuing (or offering to issue) its shares,  share  options,
or other equity instruments or by incurring  liabilities to an employee or other
supplier (a) in amounts  based,  at least in part,  on the price of the entity's
shares or other equity instruments or (b) that require or may require settlement
by issuing the entity's equity shares or other equity instruments.

                                     - 13 -
<PAGE>

     The  statement  requires the  accounting  for any excess tax benefits to be
consistent  with the  existing  guidance  under SFAS No. 123,  which  provides a
two-transaction model summarized as follows:

     o    If  settlement  of an  award  creates  a tax  deduction  that  exceeds
          compensation  cost,  the additional tax benefit would be recorded as a
          contribution to paid-in-capital.

     o    If the  compensation  cost  exceeds  the  actual  tax  deduction,  the
          write-off of the unrealized excess tax benefits would first reduce any
          available paid-in capital arising from prior excess tax benefits,  and
          any remaining amount would be charged against the tax provision in the
          income statement.

     The Company is still  evaluating  the impact of adopting  and  subsequently
accounting for excess tax benefits under the two-transaction  model described in
SFAS No. 123,  but does not expect its  consolidated  net income,  cash flows or
financial position to be materially  affected upon adoption of SFAS No. 123-R on
January 1, 2006.

     The  statement  also  amends  SFAS No. 95,  "Statement  of Cash  Flows," to
require that excess tax benefits be reported as a financing  cash inflow  rather
than as an operating  cash inflow.  However,  the statement  does not change the
accounting guidance for share-based payment transactions with parties other than
employees  provided  in SFAS No.  123 as  originally  issued  and EITF Issue No.
96-18,  "Accounting  for  Equity  Instruments  That Are  Issued  to  Other  Than
Employees for  Acquiring,  or in Conjunction  with Selling,  Goods or Services."
Further,  this  statement  does not address the  accounting  for employee  share
ownership  plans,  which  are  subject  to AICPA  Statement  of  Position  93-6,
"Employers' Accounting for Employee Stock Ownership Plans."

     The statement  applies to all awards  granted,  modified,  repurchased,  or
cancelled  after  January 1,  2006,  and to the  unvested  portion of all awards
granted  prior to that  date.  Public  entities  that used the  fair-value-based
method for either  recognition  or disclosure  under SFAS No. 123 may adopt SFAS
123-R  using a modified  version of  prospective  application  pursuant to which
compensation  cost for the portion of awards for which the employee's  requisite
service has not been  rendered,  which awards are  outstanding  as of January 1,
2006,  must be recognized as the requisite  service is rendered on or after that
date. The  compensation  cost for that portion of those awards shall be based on
the original grant-date fair value of those awards as calculated for recognition
under SFAS No. 123.  The  compensation  cost for those  earlier  awards shall be
attributed  to  periods  beginning  on  or  after  January  1,  2006  using  the
attribution method that was used under SFAS No. 123. Furthermore,  the method of
recognizing  forfeitures  must now be based on an estimated  forfeiture rate and
can no longer be based on forfeitures as they occur.

     Adoption  of SFAS No.  123-R  is not  expected  to  materially  impact  the
Company's consolidated results of operations,  cash flows or financial position,
due to the Company's  prior adoption of SFAS No. 123 as amended by SFAS No. 148,
"Accounting  for  Stock-Based  Compensation  -- Transition  and  Disclosure"  on
January 1, 2003.  SFAS No. 148 allowed  companies to adopt the  fair-value-based
method  for  recognition  of  compensation  expense  under  SFAS No.  123  using
prospective application.  Under that transition method, compensation expense was
recognized  in the  Company's  Consolidated  Statement  of  Operations  only for
stock-based  compensation  granted  after the adoption  date of January 1, 2003.
Furthermore,  as we have chosen the  multiple  option  approach  in  recognizing
compensation  expense  associated  with the fair value of each  option  granted,
nearly 94% of the total fair value of the stock option is  recognized by the end
of the third year of the vesting period,  and therefore  remaining  compensation
expense  associated  with options granted before January 1, 2003, is expected to
be immaterial.

  SFAS No. 128-R

     FASB is expected to revise  SFAS No. 128,  "Earnings  Per Share" to make it
consistent with International  Accounting Standard No. 33, "Earnings Per Share,"
so that EPS computations will be comparable on a global basis. This new guidance
is  expected  to be issued by the end of 2005 and will  require  restatement  of
prior periods diluted EPS data. The proposed changes will affect the application
of the treasury  stock method and  contingently  issuable  (based on  conditions
other than market price) share guidance for computing  year-to-date diluted EPS.
In addition to modifying the year-to-date  calculation  mechanics,  the proposed
revision to SFAS No. 128 would  eliminate a  company's  ability to overcome  the
presumption of share  settlement for those  instruments or contracts that can be
settled, at the issuer or holder's option, in cash or shares.  Under the revised
guidance, FASB has indicated that any possibility of share settlement other than
in an event of bankruptcy  will require a presumption of share  settlement  when
calculating   diluted  EPS.  The  Company's  2023  Convertible  Notes  and  2014
Convertible Notes contain  provisions that would require share settlement in the
event of conversion  under certain events of default,  including but not limited
to a  bankruptcy-related  event of default.  Additionally,  the 2023 Convertible
Notes include a provision allowing the Company to meet a put with either cash or
shares of stock. The Company's 2015 Convertible Notes allow for share settlement



                                     - 14 -
<PAGE>

of the  principal  only in the  case of  certain  bankruptcy-related  events  of
default.  Therefore,  a presumption of share settlement is required for the 2014
Convertible  Notes and the 2023  Convertible  Notes, but is not required for the
2015  Convertible  Notes.  The revised  guidance  will  result in a  significant
increase in the potential  dilution to the Company's EPS,  particularly when the
price of the Company's  common stock is low,  since SFAS No. 128-R requires that
the more dilutive of calculations be used considering both:

     o    normal  conversion  assuming a combination of cash and variable number
          of shares; and

     o    conversion  during  events of default other than  bankruptcy  assuming
          100%  shares at the  fixed  conversion  rate,  or, in the case of 2023
          Convertible Notes, meeting a put entirely with shares of stock.

  SFAS No. 151

     In November 2004, FASB issued SFAS No. 151,  "Inventory Costs, an amendment
of ARB No. 43,  Chapter 4." This  statement  amends the  guidance in ARB No. 43,
Chapter 4, "Inventory  Pricing," to clarify the accounting for abnormal  amounts
of  idle  facility  expense,   freight,  handling  costs,  and  wasted  material
(spoilage).  Paragraph  5 of ARB 43,  Chapter 4,  previously  stated that ". . .
under  some  circumstances,  items  such as  idle  facility  expense,  excessive
spoilage,  double freight, and rehandling costs may be so abnormal as to require
treatment as current period charges.  . . ." This statement requires those items
to be recognized as a current-period  charge regardless of whether they meet the
criterion of "so abnormal." In addition,  SFAS No. 151 requires that  allocation
of fixed production  overheads to the costs of conversion be based on the normal
capacity  of the  production  facilities.  The  provisions  of SFAS No.  151 are
applicable to inventory  costs incurred during fiscal years beginning after June
15, 2005.  Adoption of this  statement did not  materially  impact the Company's
consolidated results of operations, cash flows or financial position.

  SFAS No. 153

     In December  2004,  FASB issued SFAS No.  153,  "Exchanges  of  Nonmonetary
Assets."  This  statement  eliminates  the  exception  in APB  Opinion  No.  29,
"Accounting for Nonmonetary  Transactions" for nonmonetary  exchanges of similar
productive  assets and  replaces it with a general  exception  for  exchanges of
nonmonetary assets that do not have commercial substance.  It requires exchanges
of productive assets to be accounted for at fair value, rather than at carryover
basis,  unless (1) neither the asset  received nor the asset  surrendered  has a
fair value that is determinable  within reasonable limits or (2) the transaction
lacks commercial  substance (as defined).  A nonmonetary exchange has commercial
substance  if the  future  cash  flows of the  entity  are  expected  to  change
significantly as a result of the exchange.

     The new statement will not apply to the transfers of interests in assets in
exchange for an interest in a joint venture and amends SFAS No. 66,  "Accounting
for Sales of Real  Estate" to clarify  that  exchanges  of real  estate for real
estate should be accounted for under APB Opinion No. 29. It also amends SFAS No.
140, to remove the  existing  scope  exception  relating to  exchanges of equity
method  investments for similar productive assets to clarify that such exchanges
are within the scope of SFAS No. 140 and not APB Opinion No. 29. SFAS No. 153 is
effective for nonmonetary asset exchanges  occurring in fiscal periods beginning
after June 15, 2005.  Adoption of this statement did not  materially  impact the
Company's consolidated results of operations, cash flows or financial position.

  SFAS No. 154

     In May 2005,  FASB  issued  SFAS No.  154,  "Accounting  Changes  and Error
Corrections." This statement replaces APB Opinion No. 20, "Accounting  Changes,"
and FASB Statement No. 3,  "Reporting  Accounting  Changes in Interim  Financial
Statements,"  and changes the  requirements for the accounting for and reporting
of a change in  accounting  principle.  SFAS No. 154  applies  to all  voluntary
changes in accounting  principle.  APB Opinion No. 20  previously  required that
most voluntary changes in accounting principle be recognized by including in net
income for the period of the change the cumulative effect of changing to the new
accounting principle.  SFAS No. 154 requires retrospective  application to prior
periods' financial statements of changes in accounting  principle,  unless it is
impracticable to determine either the period-specific  effects or the cumulative
effect of the change.  When it is  impracticable  to  determine  the  cumulative
effect of applying a change in accounting  principle to all prior periods,  SFAS
No. 154  requires  that the new  accounting  principle  be applied as if it were
adopted prospectively from the earliest date practicable.

     SFAS No. 154 also requires that a change in depreciation,  amortization, or
depletion  method for  long-lived,  nonfinancial  assets be  accounted  for as a
change in accounting estimate effected by a change in accounting principle. SFAS
No. 154 is  effective  for fiscal  years  beginning  after  December  15,  2005.
Adoption of this  statement is not expected to  materially  impact the Company's
consolidated results of operations, cash flows or financial position.





                                     - 15 -
<PAGE>

  EITF Issue No. 03-13

At the November 2004 EITF meeting, the final consensus was reached on EITF Issue
No. 03-13, "Applying the Conditions in Paragraph 42 of FASB Statement No. 144 in
Determining Whether to Report Discontinued  Operations." EITF Issue No. 03-13 is
effective  prospectively for disposal transactions entered into after January 1,
2005,  and provides a model to assist in evaluating  (a) which cash flows should
be  considered  in the  determination  of  whether  cash  flows of the  disposal
component  have been or will be  eliminated  from the ongoing  operations of the
entity and (b) the types of continuing  involvement that constitute  significant
continuing involvement in the operations of the disposal component.  The Company
has applied the model  outlined in EITF Issue No. 03-13 in its evaluation of the
September  2004 sale of the Canadian and U.S. Rocky Mountain oil and gas assets,
the July 2005 sales of the  Company's  remaining  oil and gas assets and Saltend
facility,  the sale of the Morris  facility  in August  2005 and the sale of the
Ontelaunee  facility in October  2005 (which met the  criteria  necessary  to be
classified as  held-for-sale  at September 30, 2005), in determining  whether or
not the cash flows related to these  components have been or will be permanently
eliminated from the ongoing operations of the Company.

3.  Strategic Initiative

     The Company's business is capital  intensive.  Its ability to capitalize on
growth  opportunities  and to service  the debt it  incurred  to  construct  and
operate  its  current  fleet of  power  plants  is  dependent  on the  continued
availability of capital. The availability of such capital in today's environment
remains  uncertain.  To date, the Company has obtained cash from its operations;
borrowings  under  credit  facilities;  issuances  of  debt,  equity,  preferred
securities,  convertible and contingent  convertible  securities;  proceeds from
sale/leaseback transactions; sale or partial sale of certain assets; prepayments
received for power sales; contract  monetizations;  and project financings.  The
Company has utilized this cash to fund operations,  service,  repay or refinance
debt  obligations,  fund  acquisitions,  develop and construct power  generation
facilities,   finance  capital   expenditures,   support   hedging,   balancing,
optimization and trading activities, and meet other cash and liquidity needs.

     While the  Company  has been able to access  the  capital  and bank  credit
markets since 2002, it has been on significantly different terms than before. In
particular,  the senior  working  capital  facilities  and term loan  financings
entered into,  and the majority of the debt  securities  offered and sold by the
Company  have been  secured by certain of the  Company's  assets and  subsidiary
equity  interests.  The Company has also  provided  security to support  prepaid
commodity   transactions   and,  as  the  Company's  credit  ratings  have  been
downgraded,  it has been  required to post  collateral  to support its  hedging,
balancing and optimization  activities.  In the aggregate,  the average interest
rate on the Company's new debt  instruments,  especially on recent  issuances of
subsidiary  preferred stock and on debt incurred to refinance existing debt, has
been  higher.  The terms of capital  available  now and in the future may not be
attractive  to the  Company or its access to the capital  markets may  otherwise
become restricted. The timing of the availability of capital is uncertain and is
dependent,  in part, on market  conditions that are difficult to predict and are
outside  of the  Company's  control.  Consistent  with the  Company's  strategic
initiative announced in May 2005, it expects to rely to a greater extent than in
the past on asset  sales to reduce  debt and  related  interest  expense  and to
improve its liquidity position.

     At September 30, 2005,  the Company had working  capital of $520.8  million
which  increased  approximately  $242.7  million from  December  31,  2004.  The
increase was primarily due to increases of $494.6 million,  $513.4 million,  and
$379.5 million in accounts  receivable,  restricted cash, and current derivative
assets, respectively,  offset by increases of $212.1 million, $249.4 million and
$618.1 million in accounts  payable,  Senior Notes,  current portion and current
derivative liabilities,  respectively,  from December 31, 2004, to September 30,
2005. The increase in accounts  receivable  period over period was primarily due
to the significant  increase in power prices during the three-month period ended
September 30, 2005, and to a lesser  extent,  an increase in megawatt hours sold
(due to additional generating capacity). Restricted cash increased primarily due
to the addition of $607.5 in remaining net proceeds from the sale of Saltend and
the Company's  remaining oil and gas assets in July 2005. The Company's  current
derivative assets and liabilities increased  significantly primarily as a result
of  significantly  higher  electricity  and natural gas prices at the end of the
third  quarter  in 2005.  Cash  flow used in  operating  activities  during  the
nine-month period ended September 30, 2005 was $408.0 million and is expected to
continue  to be  negative  at least for the near term and  possibly  longer.  On
September  30,  2005,  our cash  and cash  equivalents  on hand  totaled  $843.1
million.  The current portion of restricted cash totaled $1,106.7  million.  See
Note 2 for more  information  on the  Company's  cash and cash  equivalents  and
restricted cash.

     Satisfying all obligations  under the Company's  outstanding  indebtedness,
and funding  anticipated capital  expenditures and working capital  requirements
for the next twelve months presents the Company with several  challenges as cash
requirements are expected to exceed the sum of cash on hand permitted to be used
to satisfy such requirements and cash from operations. Additionally, the Company



                                     - 16 -
<PAGE>

has significant  near-term  maturities of debt in periods subsequent to the next
twelve  months  including  $1.4  billion  in  2006  (including  use of  proceeds
obligations  described in Note 7), $1.9 billion in 2007 and $1.4 billion in 2008
(see Note 7 for  further  discussion  of  future  maturities  and other  matters
impacting the Company's debt). Accordingly, the Company has in place a strategic
initiative,  as  discussed  further  below,  which  includes  possible  sales or
monetizations of certain of its assets. Whether the Company will have sufficient
liquidity will depend, in part, on the success of that program. No assurance can
be  given  that  the  program  will  be  successful.  If it is  not  successful,
additional asset sales, refinancings, monetizations and other items beyond those
included  in the  strategic  initiative  would  likely need to be made or taken,
depending on market  conditions.  The Company's ability to reduce debt will also
depend on its ability to  repurchase  debt  securities  through  open market and
other transactions, and the principal amount of debt able to be repurchased will
be  contingent  upon  market  prices and other  factors.  Even if the program is
successful,  there can be no assurance that the Company will be able to continue
work on its projects in  development  and suspended  construction  that have not
successfully obtained project financing, and it could possibly incur substantial
impairment losses as a result.  In addition,  even if the program is successful,
until there are significant sustained improvements in spark spreads, the Company
expects that it will not have  sufficient cash flow from operations to repay all
of its  indebtedness  at  maturity  or to fund its other  liquidity  needs.  The
Company expects that it will need to extend or refinance all or a portion of its
indebtedness on or before maturity. While the Company currently believes that it
will be successful in repaying, extending or refinancing all of its indebtedness
on or before  maturity,  there can be no assurance that it will be able to do so
on attractive terms or at all.

     As part of the  Company's  efforts to improve its financial  strength,  the
Company announced a strategic initiative in May 2005 aimed at:

     o    Optimizing  the value of the Company's core North American power plant
          portfolio  by selling  certain  power and natural gas assets to reduce
          debt and lower  annual  interest  cost,  and to increase  cash flow in
          future  periods.  At September 30, 2005, the Company had completed the
          sales of Saltend in the United  Kingdom,  Morris in  Illinois  and its
          interest in Grays Ferry in Pennsylvania. Additionally, in October 2005
          the  Company  completed  the  sale  of  Ontelaunee  and in  July  2005
          completed  the  sale of  substantially  all of its  remaining  oil and
          natural gas assets.  The Company is also in discussions with potential
          buyers for, or is  considering,  the sale of  additional  assets.  See
          Notes 8 and 15 for further information on these transactions.

     o    Taking  actions  to  decrease  operating  and  maintenance  costs  and
          lowering  fuel  costs to  improve  the  operating  performance  of the
          Company's  power  plants,  which would boost  operating  cash flow and
          liquidity.  In  addition,  to further  reduce  costs,  the Company has
          temporarily shut down two power plants and is considering  others with
          negative cash flow, until market conditions  warrant starting back up,
          to  further  reduce  costs.  See  Note  12  for a  discussion  of  the
          restructuring of certain LTSAs.

     o    Reducing  collateral  requirements.  On September 8, 2005, the Company
          and Bear Stearns announced an agreement to form a new energy marketing
          and trading venture to develop a third party customer business focused
          on  physical  natural gas and power  trading  and  related  structured
          transactions.  Regulatory approval for this new entity was received on
          October 31, 2005, and it is anticipated  that operations will begin in
          the  fourth  quarter  of 2005.  The  transaction  will  include a $350
          million  credit  intermediation   agreement  between  CalBear,  a  new
          subsidiary  of Bear  Stearns,  and CES.  It is  anticipated  that this
          credit intermediation  agreement will, among other things,  positively
          impact  Calpine's  working  capital  position by making  possible  the
          return of cash and LCs currently posted as collateral.

     o Reducing total debt, net of new construction financings,  by more than $3
billion from debt levels at year-end  2004,  which the Company  estimates  would
provide $275 million of annual interest  savings.  Calpine  continues to advance
its May 2005 strategic initiative aimed at optimizing its power plant portfolio,
reducing debt and enhancing the Company's financial strength.  While the company
continues to make progress  toward its goal of reducing  total debt by more than
$3 billion by year-end  2005 and  achieving an estimated  $275 million of annual
interest  savings,  the timing of  accomplishing  this goal may be delayed  into
2006. The cash and other consideration needed to reduce debt by that amount will
be a  function  of the  timing of asset  sales,  the  Company's  ability  to use
proceeds of such  sales to reduce  debt  (we are  currently  involved in various
litigations  with the holders of certain series of our  outstanding  secured and
unsecured bonds as described in Note 12 of the Notes to  Consolidated  Condensed
Financial  Statements),  the prices at which the  Company is able to  repurchase
debt,  and other factors.  At September 30, 2005,  total  consolidated  debt was
$17.2 billion, a reduction of $0.9 billion from the $18.1 billion level at March
31, 2005, before the strategic initiative was announced. Excluding the effect of
new  construction  financing of $178.7 million,  the Company has reduced debt by
approximately $1.1 billion.  However,  regardless of whether or not the specific
$3 billion debt reduction


                                     - 17 -
<PAGE>

          goal can be  achieved  by  December  31,  2005,  the  Company  remains
          committed to achieving that goal as soon as practicable.

     In addition, as noted above, the Company seeks to identify opportunities to
capture value in the skills and  knowledge  that it has  developed,  not only to
improve the  operating  performance  of its  facilities  but also to develop new
sources of revenues,  for example,  by  utilizing  its hedging and  optimization
skills  to  develop  the  CalBear  business  and by  expanding  its  third-party
combustion   turbine  component  parts  and  retail  and  maintenance   services
businesses.  The Company also actively explores possible  alternative sources of
natural gas (such as LNG and Alaskan pipeline  projects) to increase the natural
gas supply in the  continental  United States,  as well as other sources of fuel
for its natural gas-fired generation facilities, such as projects to convert pet
coke, an oil refinery waste product, into gas suitable for combustion in its gas
turbines.  There can be no  assurance  that the Company  will be  successful  in
developing  such  alternative or additional  sources of fuel in the near term or
otherwise.

     While there can be no  assurance  that the Company  will be  successful  in
achieving  the goals of its  strategic  initiative  and  meeting  its  financing
obligations,  progress in the quarter  ended  September  30, 2005,  included the
following:

     o    Issued $150.0 million of Class A Redeemable  Preferred Shares due 2006
          through its indirect subsidiary, CCFC LLC, which is an indirect parent
          of CCFC I, which owns a portfolio of six operating  natural  gas-fired
          power plants (not  including  Ontelaunee,  which met the held for sale
          criteria as of  September  30, 2005) with the  generation  capacity of
          more than 3,600  megawatts.  The Redeemable  Preferred  Shares bear an
          initial  dividend  rate of  LIBOR  plus  950  basis  points  and  were
          redeemable  in  whole  or in part at any  time by CCFC LLC at par plus
          accrued dividends. The Redeemable Preferred Shares were repurchased in
          full on October 14, 2005.

     o    Completed the sale of  substantially  all of its remaining oil and gas
          exploration  and  production  properties and assets for $1.05 billion,
          less   adjustments,   transaction   fees   and   expenses,   and  less
          approximately  $75 million to reflect the value of certain oil and gas
          properties  for which the  Company  was unable to obtain  consents  to
          assignment  prior  to  closing.  Certain  of the  consents  have  been
          received  subsequent to September 30, 2005, and the remaining consents
          are expected to be received by December 31, 2005. As further discussed
          in Note 12, the Company  initiated a lawsuit seeking access to blocked
          proceeds remaining from this sale.

     o    Completed  the  sale of  Saltend,  a  1,200-MW  power  plant  in Hull,
          England,  generating  total gross proceeds of $862.9 million.  Of this
          amount,  approximately  $647.1  million  was used to redeem the $360.0
          million  Two-Year  Redeemable  Preferred  Shares issued by our Calpine
          Jersey I  subsidiary  on October  26,  2004,  and the  $260.0  million
          Redeemable Preferred Shares issued by our Calpine Jersey II subsidiary
          on January 31, 2005,  including interest and termination fees of $16.3
          million and $10.8  million,  respectively.  As  discussed  in Note 12,
          certain  bondholders  initiated  a lawsuit  concerning  the use of the
          proceeds remaining from the sale of Saltend.

     o    Completed  the  sale of the  Company's  Inland  Empire  Energy  Center
          development  project  to GE,  for  approximately  $30.9  million.  The
          project will be financed, owned and operated by GE and will be used to
          launch GE's most advanced gas turbine technology, the "H System (TM)."
          The Company will manage plant construction, market the plant's output,
          and  manage  its fuel  requirements.  The  Company  has an  option  to
          purchase the facility in years seven  through  fifteen  following  the
          commercial  operation  date and GE can require the Company to purchase
          the facility for a limited  period of time in the fifteenth  year, all
          subject  to  satisfaction  of  various  terms and  conditions.  If the
          Company purchases the facility under the call or put, GE will continue
          to  provide  critical  plant  maintenance   services   throughout  the
          remaining estimated useful life of the facility. Because of continuing
          involvement  related  to the  purchase  option  and put,  the  Company
          deferred the gain generated from the sale of the  development  company
          of  approximately  $10 million  until the call or put option is either
          exercised or expires.

     o    Completed the sale of Company's 50% interest in the 175-MW Grays Ferry
          power plant for gross proceeds of $37.4 million.  The Company recorded
          an impairment  charge of $18.5 million related to its interest in this
          facility in the quarter ended June 30, 2005.

     o    Completed  the sale of the  Company's  156-MW  Morris  power plant for
          approximately  $84.5 million. In the three months ended June 30, 2005,
          the Company recorded a $106.2 million impairment charge related to its
          commitment  to  a  plan  of  divesture  of  this  facility  which  was
          reclassified  to  discontinued  operations  in the three month  period
          ending September 30, 2005, upon completion of the sale.


                                     - 18 -
<PAGE>

     o    Repurchased  approximately  $138.9  million  of First  Priority  Notes
          pursuant to a tender  offer.  Following  the  completion of the tender
          offer,  the Company now has  approximately  $641.5  million  aggregate
          principal amount of First Priority Notes outstanding.

     o    Announced a 15-year  Master  Products and Services  Agreement with GE,
          which is expected to lower operating costs in the future.  As a result
          of 9 GE LTSA  cancellations,  the Company  recorded  $33.3  million in
          charges in the quarter ended June 30, 2005.

     o    Signed an  agreement  with  Siemens-Westinghouse  to  restructure  the
          long-term  relationship,  which  is  expected  to  provide  additional
          flexibility to self-perform maintenance work in the future.

     Additionally,  subsequent to September 30, 2005, the Company  completed the
following transactions (see Note 15 for more information):

     o    Completed the sale of the Company's 561-MW  Ontelaunee power plant for
          $225.0 million, less transaction costs and working capital adjustments
          of  approximately  $125.0 million.  The Company recorded an impairment
          charge of $136.8  million as of September  30, 2005 which is reflected
          in discontinued  operations.  The sale of Ontelaunee closed October 6,
          2005.  See Notes 5 and 8 for more  information.  CCFC I made offers to
          purchase its outstanding debt with the proceeds of the Ontelaunee sale
          in accordance  with the  instruments  governing  such debt. The offers
          have  expired,  and none of the  holders of such debt  elected to have
          their debt repurchased.

     o    Received  funding on CCFC LLC's $300.0 million  offering of Redeemable
          Preferred Shares due 2011.

     o    Repurchased  the CCFC LLC $150.0 million Class A Redeemable  Preferred
          Shares due 2006.

     While the  Company has  recognized  a pre-tax  gain  overall on asset sales
completed during the three and nine months ended September 30, 2005, the Company
has recognized  significant impairment charges or losses with respect to certain
asset sales,  including the sale of the Morris facility,  as well as the sale of
the Ontelaunee  facility in October 2005. The Company is considering the sale of
additional assets in connection with its strategic initiative program, and it is
possible that some or all of the additional asset sales  contemplated could lead
to material impairment charges or losses upon sale.

     The sale of assets  to  reduce  debt and  lower  annual  interest  costs is
expected to  materially  lower the  Company's  revenues,  spark spread and gross
profit  (loss)  and the final mix of assets  actually  sold will  determine  the
degree of impact on operating  results.  While lowering debt, the accomplishment
of the strategic  initiative  program, in and of itself, will likely not lead to
improvement  in certain  measures of interest  and  principal  coverage  without
significant  improvement in market  conditions.  The amount of offsetting future
interest  savings will be a function of the principal amount of debt retired and
the interest  rate born by such debt.  The amount that the Company will spend to
reduce debt will depend on the market price of such debt and other factors,  and
the final net future earnings impact of the initiatives is still uncertain.

4.   Available-for-Sale Debt Securities

     On September 30, 2004, the Company  repurchased $115.0 million in par value
of HIGH TIDES III preferred  securities for cash of $111.6  million.  Due to the
deconsolidation  of Calpine  Capital Trust III, the issuer of the HIGH TIDES III
preferred  securities,  upon the adoption of FIN 46 as of December 31, 2003, and
the terms of the  underlying  convertible  debentures  issued by  Calpine to the
Trust, the repurchased  HIGH TIDES III preferred  securities could not be offset
against the convertible  subordinated  debentures and, accordingly,  the Company
accounted  for  the   repurchased   HIGH  TIDES  III  preferred   securities  as
available-for-sale  securities.  On July 13,  2005,  the Company  completed  the
redemption of all of the outstanding HIGH TIDES III preferred  securities and of
the underlying convertible debentures. Accordingly, the HIGH TIDES III preferred
securities repurchased by the Company are no longer outstanding, and the Company
has no available-for-sale debt securities recorded in the Consolidated Condensed
Balance Sheet at September 30, 2005. See Note 7 for additional information.
















                                     - 19 -
<PAGE>

5.   Property, Plant and Equipment, Net and Capitalized Interest

     As of  September  30,  2005,  and December  31,  2004,  the  components  of
property, plant and equipment, net, stated at cost less accumulated depreciation
and depletion are as follows (in thousands):

<TABLE>
<CAPTION>
                                                                                           September 30,     December 31,
                                                                                               2005              2004
                                                                                           -------------     ------------
<S>                                                                                        <C>               <C>
Buildings, machinery, and equipment ........................................               $ 16,521,482      $ 14,615,907
Pipelines ..................................................................                     82,398            90,625
Geothermal properties ......................................................                    481,255           474,869
Other ......................................................................                    182,183           206,049
                                                                                           ------------      ------------
                                                                                             17,267,318        15,387,450
Less: accumulated depreciation and depletion ...............................                 (1,798,377)       (1,416,586)
                                                                                           ------------      ------------
                                                                                             15,468,941        13,970,864
Land .......................................................................                     94,219           104,972
Construction in progress ...................................................                  2,979,763         4,321,907
                                                                                           ------------      ------------
Property, plant and equipment, net .........................................               $ 18,542,923        18,397,743
                                                                                           ============      ============
</TABLE>

Capital Spending -- Construction and Development

     Construction and Development costs in process consisted of the following at
September 30, 2005 (in thousands):

<TABLE>
<CAPTION>
                                                                            Equipment      Project
                                                    # of                   Included in   Development   Unassigned
                                                  Projects        CIP          CIP          Costs      Equipment
                                                  --------    ----------   ----------    ----------    ----------
<S>                                                  <C>      <C>          <C>           <C>           <C>
Projects in active construction (1) ......            4       $  803,004   $  291,709    $       --    $       --
Projects in suspended construction .......            3        1,130,364      391,505            --            --
Projects in advanced development .........           10          721,381      545,458        89,942            --
Projects in suspended development ........            4          309,928       77,624        36,397            --
Projects in early development ............            2               --           --         8,952            --
Other capital projects ...................           NA           15,086           --            --            --
Unassigned equipment .....................           NA               --           --            --        67,691
                                                              ----------   ----------    ----------    ----------
  Total construction and development costs                    $2,979,763   $1,306,296    $  135,291    $   67,691
                                                              ==========   ==========    ==========    ==========
------------
<FN>
(1)  There were a total of four consolidated  projects in active construction at
     September  30,  2005.  Additionally,  the Company has one project in active
     construction  that is recorded  in  unconsolidated  investments  and is not
     included in the table above.
</FN>
</TABLE>

     Construction  in Progress -- CIP is  primarily  attributable  to  gas-fired
power projects under construction including prepayments on gas and steam turbine
generators and other long lead-time  items of equipment for certain  development
projects not yet in construction.  Upon  commencement of plant operation,  these
costs are transferred to the applicable property category,  generally buildings,
machinery and equipment.

     Projects in Active Construction -- The four projects in active construction
are  projected  to come on line  from  November  2005 to  November  2007.  These
projects will bring on line approximately  1,247 MW of base load capacity (1,478
MW with peaking capacity).  Interest and other costs related to the construction
activities  necessary  to bring these  projects to their  intended use are being
capitalized.  At September 30, 2005, the total projected costs to complete these
projects was $586.2 million.

     Projects in Suspended  Construction -- Work and  capitalization of interest
on the three  projects in suspended  construction  has been suspended or delayed
due  to  current  market   conditions.   These  projects  would  bring  on  line
approximately  1,769 MW of base load capacity (2,035 MW with peaking  capacity).
The Company expects to finance the remaining  $324.7 million  projected costs to
complete these projects when construction resumes.

     Projects in  Advanced  Development  -- There were ten  projects in advanced
development  at  September  30,  2005.   These  projects  would  bring  on  line
approximately  4,151 MW of base load capacity (5,361 MW with peaking  capacity).



                                     - 20 -
<PAGE>

Interest  and other costs  related to the  development  activities  necessary to
bring these projects to their intended use are being capitalized.  However,  the
capitalization  of  interest  has been  suspended  on four  projects  for  which
development  activities are  substantially  complete but  construction  will not
commence until a PPA and financing are obtained. During the quarter, the Company
sold Inland Empire Energy Center, a project previously accounted for in advanced
development,  to a third party and moved the  Wawayanda  project  from  advanced
development  to suspended  development.  See Note 3 for more  information on the
sale of Inland  Empire to GE. The  estimated  cost to complete the remaining ten
projects in advanced development was approximately $2.6 billion at September 30,
2005.  The Company's  current plan is to finance these project costs as PPAs are
executed.

     Suspended  Development Projects --The Company has ceased  capitalization of
additional  development costs and interest expense on four development  projects
on which work has been  suspended  due to current  electric  market  conditions.
Capitalization  of costs may  recommence as work on these projects  resumes,  if
certain  milestones  and  criteria  are met  indicating  that it is again highly
probable that the costs will be recovered through future operations.  As is true
for all of the  Company's  projects,  the  suspended  projects  are reviewed for
impairment whenever there is an indication of potential reduction in a project's
fair value.  Further, if it is determined that it is no longer probable that the
projects will be completed and all capitalized  costs  recovered  through future
operations,  the carrying  values of the projects would be written down to their
recoverable  value.  The four projects in suspended  development  would bring on
line  approximately  1,365  MW of base  load  capacity  (1,555  MW with  peaking
capacity). The estimated cost to complete these projects is approximately $837.6
million.

     Projects  in Early  Development  -- Costs  for  projects  that are in early
stages of development are capitalized  only when it is highly probable that such
costs  are  ultimately   recoverable  and  significant  project  milestones  are
achieved.  Until then all costs,  including  interest costs,  are expensed.  The
projects in early  development with capitalized costs relate to two projects and
include geothermal drilling costs and equipment purchases.

     Other  Capital  Projects -- Other  capital  projects  primarily  consist of
enhancements  to operating power plants,  pipelines and geothermal  resource and
facilities development, as well as software developed for internal use.

     Unassigned  Equipment  -- As of September  30,  2005,  the Company had made
progress  payments  on four  turbines  and  other  equipment  with an  aggregate
carrying value of $67.7 million.  This unassigned equipment is classified on the
Consolidated  Condensed  Balance  Sheet  as  "Other  assets"  because  it is not
assigned to  specific  development  and  construction  projects.  The Company is
holding this equipment for potential use on future projects. It is possible that
some of this  unassigned  equipment  may  eventually  be  sold,  potentially  in
combination with the Company's engineering and construction services.

     Capitalized  Interest  --  The  Company  capitalizes  interest  on  capital
invested  in  projects  during  the  advanced  stages  of  development  and  the
construction period in accordance with SFAS No. 34,  "Capitalization of Interest
Cost," as amended by SFAS No. 58,  "Capitalization of Interest Cost in Financial
Statements  That  Include  Investments  Accounted  for by the Equity  Method (an
Amendment of FASB  Statement No. 34)." The Company's  qualifying  assets include
CIP,  certain   pipelines  under   development,   geothermal   properties  under
construction,  certain costs for information systems  development,  construction
costs  related  to   unconsolidated   investments   in  power   projects   under
construction,  and advanced stage development  costs. For the three months ended
September 30, 2005 and 2004, the total amount of interest  capitalized was $36.5
million  and  $86.6  million,  respectively,  including  $7.8  million  and $9.4
million,  respectively,  of interest  incurred on funds  borrowed  for  specific
construction  projects and $28.7  million and $77.4  million,  respectively,  of
interest  incurred on general  corporate  funds used for the advanced  stages of
development and  construction.  For the nine months ended September 30, 2005 and
2004,  the total amount of interest  capitalized  was $170.9  million and $296.9
million, respectively,  including $30.4 million and $43.3 million, respectively,
of interest  incurred on funds borrowed for specific  construction  projects and
$140.5 million and $253.6 million, respectively, of interest incurred on general
corporate funds used for  construction.  Upon  commencement of plant  operation,
capitalized  interest,  as a  component  of the  total  cost  of the  plant,  is
amortized  over the  estimated  useful  life of the plant.  The  decrease in the
amount of interest  capitalized during the three and nine months ended September
30, 2005,  reflects the completion of construction for several power plants, the
suspension of certain of the Company's  development and  construction  projects,
and a  reduction  in the  Company's  development  and  construction  program  in
general.

     In  accordance  with  SFAS  No.  34,  the  Company  determines  which  debt
instruments  best  represent  a  reasonable  measure  of the  cost of  financing
construction assets in terms of interest cost incurred that otherwise could have
been avoided.  These debt instruments and associated  interest cost are included
in the calculation of the weighted  average  interest rate used for capitalizing
interest on general  funds.  The primary debt  instruments  included in the rate



                                     - 21 -
<PAGE>

calculation of interest  incurred on general  corporate  funds are the Company's
Senior  Notes and term loans.

     Impairment  Evaluation -- All  construction  and  development  projects and
unassigned  turbines are reviewed for impairment whenever there is an indication
of potential reduction in fair value. Equipment assigned to such projects is not
evaluated for  impairment  separately,  as it is integral to the assumed  future
operations of the project to which it is assigned.  If it is determined  that it
is no longer  probable that the projects  will be completed and all  capitalized
costs recovered through future  operations,  the carrying values of the projects
would be written down to the recoverable value in accordance with the provisions
of SFAS No. 144. The Company  reviews its  unassigned  equipment  for  potential
impairment based on probability-weighted alternatives of utilizing the equipment
for future  projects versus selling the equipment.  Utilizing this  methodology,
the  Company  does not  believe  that the  equipment  held for use is  impaired.
However,  during the three month periods ending September 30, 2005 and 2004, and
the nine month periods  ended  September  30, 2005 and 2004,  respectively,  the
Company recorded to the "Equipment cancellation and impairment cost" line of the
Consolidated  Condensed  Statement of Operations  $0.8 million and $7.8 million,
and $0.7 million and $10.2  million,  respectively,  in net losses in connection
with equipment  cancellations,  and it may incur further losses should it decide
to cancel more equipment  contracts or sell unassigned  equipment in the future.
In the event the Company  were unable to obtain  PPAs or project  financing  and
suspension or abandonment were to result,  the Company could suffer  substantial
impairment losses on such projects.

     Based on an evaluation  of the  probability-weighted  expected  future cash
flows,  giving  consideration  to the  continued  ownership and operation of the
Morris power plant or  consummating  the potential sale  transaction at June 30,
2005,  the Company  determined  that the  carrying  amount of the  facility  was
impaired due to the high  probability  of  consummating  the sale.  As a result,
during the three months ended June 30, 2005, the Company  recorded to the "Power
plant impairment" line of the Consolidated  Condensed  Statement of Operations a
$106.2  million  impairment  charge  representing  the  difference  between  the
proposed sale price and the facility's book value at June 30, 2005. On August 2,
2005,  the Company  completed the sale of the facility for  approximately  $84.5
million  in  cash  and  reclassified  the  impairment   charge  to  discontinued
operations. See Note 8 for more information on this sale.

     At September  30, 2005,  the Company had  committed to a plan to divest the
Ontelaunee power plant. In accordance with SFAS No. 144, the Company recorded an
impairment  charge of $136.8  million for the  difference  between the estimated
sale price (less  estimated  selling costs) and the facility's  book value as of
September 30, 2005. This charge is reflected in  discontinued  operations in the
Consolidated  Condensed  Statement of  Operations  for the three and  nine-month
periods ended September 30, 2005. The sale was completed on October 6, 2005. See
Notes 5 and 8 for a discussion of the  Company's  sale of the  Ontelaunee  power
plant.

     See Note 6 for a discussion of the impairment charge in connection with the
Grays Ferry  power plant and Note 3 for a  discussion  of  potential  additional
material impairment charges arising from the possible sale of additional assets.

6.   Unconsolidated Investments

     The Company's  unconsolidated  investments  are integral to its operations.
The Company's joint venture investments were evaluated under FASB Interpretation
No. 46  "Consolidation  of Variable Interest Entities - An Interpretation of ARB
51" as amended,  to determine  which, if any,  entities were VIEs. Based on this
evaluation,  the Company  determined  that Acadia PP,  Valladolid,  Grays Ferry,
Whitby and AELLC were VIEs,  in which the Company  held a  significant  variable
interest.  However,  all of the entities except for Acadia PP met the definition
of a business  and  qualified  for the  business  scope  exception  provided  in
paragraph  4(h) of FIN  46-R,  and  consequently  were  not  subject  to the VIE
consolidated model. Further, based on a qualitative and quantitative  assessment
of the  expected  variability  in Acadia PP,  the  Company  was not the  Primary
Beneficiary.  Consequently,  the  Company  continues  to  account  for its joint
venture investments in accordance with APB Opinion No. 18, "The Equity Method of
Accounting For  Investments in Common Stock" and FIN 35,  "Criteria for Applying
the  Equity  Method  of  Accounting   for   Investments   in  Common  Stock  (An
Interpretation of APB Opinion No. 18)." However,  in the fourth quarter of 2004,
the Company changed from the equity method to the cost method to account for its
investment in AELLC as discussed below.

     Acadia  PP  is  the  owner  of a  1,210-MW  electric  wholesale  generation
facility,  Acadia  Energy  Center,  located in Louisiana  and is a joint venture
between the Company and Cleco Corporation. The Company's involvement in this VIE
began  upon  formation  of the  entity  in March  2000.  The  Company's  maximum
potential exposure to loss from its equity investment at September 30, 2005, was
limited to the book value of its  investment of  approximately  $215.7  million,
plus any loss that may accrue  from a tolling  agreement  between  Acadia PP and
CES.





                                     - 22 -
<PAGE>

     Valladolid  is the owner of the  Valladolid  III Energy  Center,  a 525-MW,
natural  gas-fired  energy center  currently  under  construction at Valladolid,
Mexico in the Yucatan  Peninsula.  The facility will deliver  electricity to CFE
under a 25-year power sales  agreement.  The project is a joint venture  between
the Company and Mitsui, and Chubu, both headquartered in Japan. The Company owns
45% of the entity while Mitsui and Chubu each own 27.5%.  Construction  began in
May 2004 and the  project is  expected to achieve  commercial  operation  in the
summer of 2006. The Company's  maximum  potential  exposure to loss at September
30, 2005, was limited to the book value of its investment of approximately $82.7
million.

     Grays  Ferry  is the  owner of a 175-MW  gas-fired  cogeneration  facility,
located  in  Pennsylvania  and was a  joint  venture  between  the  Company  and
Trigen-Schuylkill Cogeneration, Inc. The Company's involvement in this VIE began
with its  acquisition of the  independent  power  producer,  Cogen America,  now
called  Calpine Cogen,  in December 1999. The Grays Ferry joint venture  project
was part of the portfolio of assets owned by Cogen America. On July 8, 2005, the
Company  completed the sale of the Grays Ferry power plant, in which it held 50%
interest,  for gross  proceeds  of $37.4  million.  In June  2005,  the  Company
recorded to the "Other expense (income), net" line of the Consolidated Condensed
Statement of Operations a $18.5 million impairment charge.  This transaction did
not  qualify as a  discontinued  operation  under the  guidance of SFAS No. 144,
which specifically excludes equity method investments from its scope, unless the
investment is part of a larger disposal group.

     Whitby is the owner of a 50-MW gas-fired cogeneration facility,  located in
Ontario,  Canada and is a joint venture between the Company and a privately held
enterprise.  The Company's involvement in this VIE began with its acquisition of
a portfolio  of assets from  Westcoast  in September  2001,  which  included the
Whitby joint venture project.  The Company's maximum potential  exposure to loss
at  September  30,  2005,  was  limited to the book value of its  investment  of
approximately $49.6 million.

     AELLC  is  the  owner  of  a  136-MW   gas-fired   cogeneration   facility,
Androscoggin Energy Center,  located in Maine and is a joint venture between the
Company, and affiliates of Wisvest Corporation and IP. The Company's involvement
in this VIE  began  with its  acquisition  of the  independent  power  producer,
SkyGen,  in October  2000.  The AELLC joint venture was part of the portfolio of
assets owned by SkyGen. On November 3, 2004, a jury verdict was rendered against
AELLC in a breach of contract  dispute  with IP. The Company  recorded its $11.6
million  share of the award amount in the third quarter of 2004. On November 26,
2004,  AELLC  filed a  voluntary  petition  for relief  under  Chapter 11 of the
Bankruptcy Code. As a result of the bankruptcy, the Company has lost significant
influence  and  control  of the  project  and has  adopted  the cost  method  of
accounting  for its  investment  in AELLC.  Also,  in December  2004 the Company
determined that its investment in AELLC,  including outstanding notes receivable
and O&M receivable,  was impaired and recorded a $5.0 million impairment charge.
The facility had  third-party  debt of $63.4 million  outstanding as of December
31, 2004,  primarily  consisting of $60.3 million in construction debt. The debt
was  non-recourse to Calpine  Corporation.  On April 12, 2005,  AELLC sold three
fixed-price gas contracts to Merrill Lynch Commodities  Canada,  ULC, and used a
portion of the  proceeds  to pay down its  remaining  construction  debt.  As of
September  30, 2005,  the  facility had  third-party  debt  outstanding  of $3.1
million. See Note 12 for an update on this investment.

     The following  investments are accounted for under the equity method except
for Androscoggin Energy Center, which is accounted for under the cost method (in
thousands):

<TABLE>
<CAPTION>
                                                                                   Ownership             Investment Balance at
                                                                                Interest as of     --------------------------------
                                                                                 September 30,     September 30,       December 31,
                                                                                     2005              2005                2004
                                                                                ----------------   -------------       ------------
<S>                                                                                  <C>              <C>                  <C>
Acadia Energy Center ..........................................                      50.0%            $215,657             $214,501
Valladolid III Energy Center ..................................                      45.0%              82,661               77,401
Grays Ferry Power Plant (1) ...................................                      50.0%                  --               48,558
Whitby Cogeneration (2) .......................................                      15.0%              49,615               32,528
Androscoggin Energy Center (3) ................................                      32.3%                  --                   --
Other .........................................................                        --                  125                  120
                                                                                                      --------             --------
  Total unconsolidated investments ............................                                       $348,058             $373,108
                                                                                                      ========             ========
------------
<FN>
(1)  On July 8, 2005,  the Company  completed  the sale of the Grays Ferry power
     plant. Please see the above paragraph for a discussion of this sale.

(2)  Whitby  is  owned  50% by  the  Company  but a 70%  economic  share  in the
     Company's  ownership  interest  has been  effectively  transferred  to CPLP
     through a loan from CPLP to the Company's entity which holds the investment
     interest in Whitby.


                                     - 23 -
<PAGE>

(3)  Excludes certain Notes Receivable.
</FN>
</TABLE>

     The third-party debt on the books of the unconsolidated  investments is not
reflected on the Company's  balance  sheet.  At September 30, 2005, and December
31, 2004, third party investee debt was approximately  $200.2 million and $133.9
million,  respectively.  Of these  amounts,  $3.1  million  and  $63.4  million,
respectively,  relate to the Company's  investment in AELLC,  for which the cost
method of accounting was used.  Based on the Company's pro rata ownership  share
of each of the  investments,  the Company's share would be  approximately  $74.3
million and $46.6 million for the respective periods.  These amounts include the
Company's share for AELLC of $1.0 million and $20.5 million,  respectively.  All
such debt is non-recourse to the Company.  The increase in investee debt between
periods is primarily  due to  borrowings  for the  Valladolid  III Energy Center
currently under construction.

     The  following  details  the  Company's  income  and   distributions   from
unconsolidated investments (in thousands):
<TABLE>
<CAPTION>
                                                                   Income (Loss) from
                                                                     Unconsolidated
                                                                       Investments           Distributions
                                                                 ----------------------  ---------------------
                                                                    For the Nine Months Ended September 30,
                                                                 ---------------------------------------------
                                                                   2005        2004         2005       2004
                                                                 --------    --------     --------    --------
<S>                                                              <C>         <C>          <C>         <C>
Acadia Energy Center .........................................   $ 14,052    $  9,490     $ 12,896    $ 14,438
Aries Power Plant ............................................         --      (4,265)          --          --
Grays Ferry Power Plant ......................................       (739)     (2,436)          --          --
Whitby Cogeneration ..........................................      1,608         870        3,768       1,515
Calpine Natural Gas Trust ....................................         --          --           --       6,127
Androscoggin Energy Center ...................................         --     (16,680)          --          --
Valladolid III Energy Center .................................       (213)         --           --          --
Other ........................................................        (64)          7          198         183
                                                                 --------    --------     --------    --------
  Total ......................................................   $ 14,644    $(13,014)    $ 16,862    $ 22,263
                                                                 ========    ========     ========    ========
Interest income on notes receivable from power projects (1) ..   $     --    $    840
                                                                 --------    --------
  Total ......................................................   $ 14,644    $(12,174)
                                                                 ========    ========
------------
<FN>
(1)  At September 30, 2005, and December 31, 2004,  notes  receivable from power
     projects  represented an outstanding  loan to AELLC, in the amounts of $4.0
     million and $4.0 million, after impairment reserves, respectively.
</FN>
</TABLE>

     The Company provides for deferred taxes on its share of earnings.

Related-Party Transactions with Unconsolidated Investments

     The  Company  and  certain of its equity and cost  method  affiliates  have
entered into various  service  agreements with respect to power projects and oil
and gas  properties.  Following is a general  description of each of the various
agreements:

     O&M  Agreements  -- The  Company  operates  and  maintains  the  Acadia and
Androscoggin Energy Centers.  This includes routine  maintenance,  but not major
maintenance,  which is typically  performed under  agreements with the equipment
manufacturers.  Responsibilities  include  development  of  annual  budgets  and
operating plans.  Payments include  reimbursement of costs,  including Calpine's
internal personnel and other costs, and annual fixed fees.

     Construction   Management  Services  Agreements  --  The  Company  provides
construction  management services to the Valladolid III Energy Center.  Payments
include  reimbursement of costs,  including the Company's internal personnel and
other costs.

     Administrative  Services  Agreements -- The Company handles  administrative
matters such as bookkeeping for certain unconsolidated  investments.  Payment is
on a cost  reimbursement  basis,  including  Calpine's  internal costs,  with no
additional fee.

     Power Marketing  Agreements -- Under  agreements with AELLC, CES can either
market  the  plant's  power  as the  power  facility's  agent  or buy the  power
directly.  Terms of any direct  purchase  are to be agreed  upon at the time and
incorporated into a transaction  confirmation.  Historically,  CES has generally
bought the power from the power facility rather than acting as its agent.



                                     - 24 -
<PAGE>

     Gas  Supply  Agreement  --  CES  can  be  directed  to  supply  gas  to the
Androscoggin  Energy  Center  facility  pursuant  to  transaction  confirmations
between  the  facility  and CES.  Contract  terms are  reflected  in  individual
transaction confirmations.

     The power marketing and gas supply  contracts with CES are accounted for as
either purchase and sale arrangements or as tolling arrangements.  In a purchase
and sale arrangement, title and risk of loss associated with the purchase of gas
is transferred  from CES to the project at the gas delivery  point. In a tolling
arrangement,  title to fuel provided to the project does not  transfer,  and CES
pays the project a capacity and a variable  fee based on the  specific  terms of
the power  marketing  and gas supply  agreements.  In addition to the  contracts
specified above,  CES maintains two tolling  agreements with the Acadia facility
which are  accounted  for as leases.  All of the other power  marketing  and gas
supply contracts are accounted for as purchases and sales.

     The related party  balances as of September 30, 2005 and December 31, 2004,
reflected in the accompanying  Consolidated  Condensed  Balance Sheets,  and the
related  party  transactions  for the three and nine months ended  September 30,
2005, and 2004, reflected in the accompanying  Consolidated Condensed Statements
of Operations are summarized as follows (in thousands):

                                                September 30,     December 31,
                                                     2005             2004
                                                -------------     ------------
Accounts receivable..........................    $      541        $      765
Accounts payable.............................         5,679             9,489
Note receivable..............................         4,037             4,037
Other receivables............................           428                --

                                                     2005             2004
                                                -------------     ------------
For the Three Months Ended September 30,
Revenue......................................    $      143        $       40
Cost of revenue..............................        17,962            25,504
Interest income..............................            --               347
For the Nine Months Ended September 30,
Revenue......................................    $      279        $      953
Cost of revenue..............................        72,820            89,623
Interest income..............................            --               840
Gain on sale of assets.......................            --             6,240

7.  Debt

     Repurchase of $138.9 million of 9 5/8% First Priority  Senior Secured Notes
due 2014 -- On July 12, 2005,  pursuant to a tender offer in connection with the
sale of the  Company's  remaining  oil and gas  assets  and the  related  use of
proceeds under the Company's indentures (see Notes 8 and 12 for more information
regarding  this asset sale and the  subsequent  use of  proceeds),  the  Company
repurchased  for cash (at par) $138.9 million in principal  amount of its 9 5/8%
First Priority  Senior  Secured Notes due 2014.  Following the completion of the
tender offer, the Company has approximately  $641.5 million aggregate  principal
amount of First Priority Notes outstanding as of September 30, 2005.

     As discussed in Note 12, the  Collateral  Trustee for the Company's  Senior
Secured Noteholders informed the Company of disagreements  purportedly raised by
certain holders of its First Priority Notes regarding the Company's reinvestment
of the  proceeds  from the sale of  domestic  gas  assets.  As a result of these
concerns,  the  Collateral  Trustee  informed  the  Company  that  they  will be
withholding  further  withdrawals from the gas sale proceeds account until these
disagreements  can be resolved.  In  addition,  the  Collateral  Trustee has not
released liens on certain  properties for which consents were received after the
closing of the sale and,  accordingly,  the Company has not received payment for
such properties.  On September 26, 2005, the Company filed a lawsuit against the
Collateral  Trustee and the Trustee for the First  Priority Notes seeking access
to the proceeds in the gas sale proceeds  account.  See  "Indenture and Debt and
Lease Covenant  Compliance" below, and Note 12 for further discussion  regarding
the use of the  proceeds  of the sale of the gas  assets  and the  status of the
related legal matter.

     Issuance  of  Mandatorily  Redeemable  Preferred  Interest -- On August 12,
2005, the Company issued $150.0 million of Class A Redeemable  Preferred  Shares
due 2006 through its indirect subsidiary,  CCFC LLC, which is an indirect parent
of CCFC I. CCFC I owns a portfolio  of six  operating  natural  gas-fired  power
plants (not  including  Ontelaunee,  which met the held for sale  criteria as of
September 30, 2005) with the generation  capacity of more than 3,600  megawatts.
The Redeemable  Preferred Shares bear an initial dividend rate of LIBOR plus 950
basis  points and may be  redeemed in whole or in part at any time by the issuer
at par plus accrued dividends.  The Redeemable Preferred Shares were repurchased
in full on October 14, 2005. Net proceeds of  approximately  $144.2 million from
the sale will be used in accordance with the Company's existing bond indentures.






                                     - 25 -
<PAGE>

     Extinguishment  of HIGH TIDES III -- On July 13, 2005,  the Company  repaid
the convertible  debentures  payable to Calpine Capital Trust III, the issuer of
the HIGH TIDES III  preferred  securities.  The Trust then used the  proceeds to
redeem the  outstanding  HIGH TIDES III  preferred  securities  totaling  $517.5
million, of which $115.0 million was held by Calpine.  See Note 4 for additional
information regarding  available-for-sale debt securities.  The redemption price
paid per each $50 principal  amount of HIGH TIDES III preferred  securities  was
$50 plus accrued and unpaid  distributions  to the redemption date in the amount
of $0.50. All rights of holders of the HIGH TIDES III preferred  securities have
ceased,  except the right of such holders to receive the redemption price, which
was deposited with The Depository Trust Company on July 13, 2005.

     Senior Note  Repurchases  -- During the three  months ended  September  30,
2005, the Company repurchased Senior Notes in open market transactions  totaling
$263.5 million in principal amount. The Company repurchased the Senior Notes for
cash of $233.9 million plus accrued interest as follows (in thousands):

Senior Notes                                 Principal        Cash Payment
------------                             -----------------  ----------------
8 1/4% due 2005........................  $        4,000.0   $        3,985.0
10 1/2 % due 2006......................          10,005.0            9,671.0
7 5/8% due 2006........................           8,051.0            7,648.4
8 3/4% due 2007........................           2,000.0            1,570.0
7 7/8% due 2008........................          53,500.0           39,598.8
8 1/2% due 2008........................          41,000.0           28,632.5
7 3/4% due 2009........................           6,000.0            3,900.0
9 5/8% due 2014........................         138,895.0          138,895.0
                                         ----------------   ----------------
   Total repurchases...................  $      263,451.0   $      233,900.7
                                         ================   ================

     For the three months ended  September  30,  2005,  the Company  recorded an
aggregate  pre-tax  gain of $15.5  million  on the above  debt  repurchases  and
extinguishment  of HIGH TIDES III after the  write-off of  unamortized  deferred
financing costs, legal fees and unamortized discounts.

     Annual Debt Maturities -- The annual principal  repayments or maturities of
notes payable and borrowings under lines of credit, preferred interests, capital
lease  obligation,  CCFC I  financing,  CalGen  financing,  construction/project
financing,  convertible  notes, and senior notes and term loans, as of September
30, 2005, are as follows (in thousands):

October through December 2005.................................   $       35,978
2006..........................................................        1,427,080
2007..........................................................        1,857,780
2008..........................................................        1,374,781
2009..........................................................        1,630,211
Thereafter....................................................       11,058,266
                                                                 --------------
Total debt....................................................       17,384,096
(Discount) / Premium..........................................         (196,088)
                                                                 --------------
  Total.......................................................   $   17,188,008
                                                                 ==============

<TABLE>
<CAPTION>
                                                                                  Due                 Due                   Total
                                                                         October - December   January - September          Current
                                                                                 2005                2006                  Debt (1)
                                                                         ------------------   -------------------        -----------
                                                                                                 (In thousands)
<C>                                                                           <C>                   <C>                   <C>
10 1/2% Senior Notes Due 2006 ....................................            $       --            $  139,205            $  139,205
6 5/8% Senior Notes Due 2006 .....................................                    --               102,194               102,194
6 7/8% Senior Notes Due 2007 .....................................                 3,125                 9,375                12,500
Other scheduled debt maturities ..................................                32,853               283,505               316,358
Estimated debt repurchase obligation (2) .........................               150,020               714,000               864,000
                                                                              ----------            ----------            ----------
                                                                              $  185,998            $1,248,279            $1,434,257
                                                                              ==========            ==========            ==========
------------
<FN>
(1)  Excludes net discounts of $2,523.7

(2)  See  "Indenture  and  Debt  and  Lease  Covenant  Compliance"  below  for a
     discussion of this obligation.
</FN>
</TABLE>

     Indenture  and Debt and  Lease  Covenant  Compliance  -- The  covenants  in
certain of the Company's debt agreements  currently  impose  restrictions on its
activities, including those discussed below:




                                     - 26 -
<PAGE>

     Certain of the  Company's  indentures  place  conditions  on its ability to
issue indebtedness if the Company's interest coverage ratio (as defined in those
indentures) is below 2:1.  Currently,  the Company's interest coverage ratio (as
so defined) is below 2:1. As such, the Company generally would not be allowed to
issue new debt,  except for certain  types of  permitted  debt,  such as (i) new
indebtedness  that  refinances  or  replaces  existing   indebtedness  and  (ii)
non-recourse  debt  and  preferred  equity  interests  issued  by the  Company's
subsidiaries  for purposes of financing  certain types of capital  expenditures,
including plant development, construction and acquisition costs and expenses. In
addition,  if and so long as the Company's interest coverage ratio is below 2:1,
the Company's ability to invest in unrestricted  subsidiaries and non-subsidiary
affiliates and make certain other types of restricted  payments will be limited.
Moreover,  certain  of  the  Company's  indentures  will  prohibit  any  further
investments  in  non-subsidiary  affiliates  if and for so long as its  interest
coverage  ratio (as defined  therein) is below 1.75:1 and, as of  September  30,
2005, such interest coverage ratio was below 1.75:1.  The Company currently does
not expect this limitation on its ability to make investments in  non-subsidiary
affiliates to have a material impact on its business.

     Certain of the Company's  indebtedness  issued in the last half of 2004 was
incurred  in  reliance  on  provisions  in  certain of its  existing  indentures
pursuant to which the Company is able to incur  indebtedness  if,  after  giving
effect  to the  incurrence  and the  repayment  of other  indebtedness  with the
proceeds  therefrom,  the Company's interest coverage ratio (as defined in those
indentures) is greater than 2:1. In order to satisfy the interest coverage ratio
requirement  in  connection  with such  issuances,  the  proceeds  thereof  were
required to be used to  repurchase  or redeem other  existing  indebtedness.  As
previously reported in the Company's 2004 10-K and its Quarterly Reports on Form
10-Q for the first two  quarters of 2005,  the Company  completed a  substantial
portion of such repurchases  during the fourth quarter of 2004 and the first six
months of 2005.  The  Company  completed  the  remaining  required  repurchases,
spending approximately $248.4 million in the third quarter of 2005 to repurchase
debt, and has now fully satisfied this  requirement.  The amount the Company was
required to spend exceeded its estimate of $184.0  million  because the required
principal  amount of debt was  repurchased  at  prices  higher  than  originally
anticipated.

     When the Company or one of its  subsidiaries  sells a significant  asset or
issues preferred equity, the Company's indentures generally require that the net
proceeds of the  transaction  be used to make capital  expenditures,  to acquire
permitted  assets or capital stock, or to repurchase or repay  indebtedness,  in
each case within 365 days of the closing date of the transaction.  To the extent
that $50 million or more of such net  proceeds  are not so used,  the Company is
required  under the terms of its secured  debt  instruments  to make an offer to
purchase its  outstanding  senior secured  indebtedness  up to the amount of the
unused  net  proceeds.  This  general  requirement  contains  certain  customary
exceptions,  and, in the case of certain assets  defined as "designated  assets"
under  some  of the  Company's  indentures,  including  the gas  portion  of the
Company's oil and gas assets sold in July 2005, there are additional  provisions
discussed further below that apply to the use of the proceeds of a sale of those
assets. In light of these requirements, and after taking into account the amount
of  capital  expenditures  currently  budgeted  for the  remainder  of 2005  and
forecasted for 2006, the Company anticipates that, in the fourth quarter of 2005
and the first three quarters of 2006, it will need to use  approximately  $195.5
million and $668.5  million,  respectively,  of the  remaining net proceeds from
four series of preferred  equity issued by subsidiaries of the Company and three
asset  sale  transactions,  all  completed  prior  to  September  30,  2005,  to
repurchase or repay indebtedness or acquire assets or capital stock. The Company
has, subsequent to September 30, 2005,  fulfilled the portion of this obligation
as required to be completed in the fourth quarter of 2005. Accordingly, assuming
that the Company would  fulfill  these  remaining  obligations  by  repurchasing
indebtedness,  an aggregate  amount of  approximately  $714.0  million of Senior
notes and term loan,  net of current  portion,  and $150.0  million of Preferred
interest,  net  of  current  portion,  related  to  this  use  of  net  proceeds
requirement has been classified as Senior Notes,  current portion, and Preferred
interest, current portion, respectively, on the Company's Consolidated Condensed
Balance  Sheet as of September  30, 2005.  The actual amount of the net proceeds
that will be required to be used to repurchase or repay debt will depend,  among
other  things,  upon the actual  amount of the net proceeds that is used to make
capital expenditures or acquire other assets or capital stock, which may be more
or less than the  amount  currently  budgeted  and/or  forecasted.  This  amount
includes $207.5 million of the net proceeds of the sale of Saltend. As discussed
in Note  12,  certain  bondholders  filed a  lawsuit  concerning  the use of the
proceeds from the sale of Saltend. In connection with that lawsuit,  the Company
is prohibited from repatriating this amount due to an order of the Court in that
matter  requiring  such proceeds to be held at or in the control of CCRC. To the
extent  repatriation  of  such  net  proceeds  is  ultimately   permitted,   the
repatriated  net  proceeds  will be  applied  pursuant  to the  use of  proceeds
provisions  of the  Company's  indentures  described  herein  as if the  sale of
Saltend had occurred on the date of repatriation.

     In addition,  the net proceeds from an issuance of preferred  equity and an
asset sale completed  after September 30, 2005 will similarly be subject to such
use of  proceeds  provisions  of  the  Company's  indentures,  and  the  Company



                                     - 27 -
<PAGE>

     anticipates that, on the basis described above (after  considering  capital
expenditures),  an  additional  $452.1  million  will need to be used to acquire
other  assets or capital  stock,  or to  repurchase  or repay  indebtedness,  as
applicable, within 365 days of the consummation of the applicable transaction.

     As noted above,  the Company sold its  remaining oil and gas assets on July
7, 2005, with the gas component of such sale  constituting  "designated  assets"
under certain of the Company's indentures.  These indentures require the Company
to make an offer to purchase its First Priority Notes with the net proceeds of a
sale of  designated  assets not otherwise  applied in accordance  with the other
permitted uses under such  indentures and, to the extent any proceeds (above $50
million)  remain  thereafter,  to make an offer to purchase its second  priority
senior  secured  debt.  Accordingly,  the Company  made an offer to purchase the
First Priority Notes in June 2005. On July 12, 2005, the Company purchased, with
proceeds of the sale of the gas assets,  $138.9  million in principal  amount of
the First  Priority  Notes  tendered in  connection  with the offer to purchase.
Having  completed the tender offer,  the Company has used  approximately  $308.2
million of the $708.5 million of the remaining net proceeds from the sale of its
gas assets to acquire natural gas and/or  geothermal  energy assets permitted to
be acquired under its Second Priority Secured Debt Instruments.  There can be no
assurance  that the Company will be successful in  identifying  or acquiring any
additional  such assets on acceptable  terms or at all. If the Company does not,
within 180 days of receipt of the net proceeds  from the sale of its gas assets,
use all of the  remaining  net  proceeds  to  acquire  such  assets,  and/or  to
repurchase or repay (through open market or privately  negotiated  transactions,
tender offers or otherwise) any or all of the $641.5 million aggregate principal
amount of First Priority Notes remaining  outstanding after  consummation of the
offer to purchase  discussed above (either of which actions the Company may, but
is not  required,  to take),  then the  Company  will,  to the  extent  that the
remaining net proceeds from the sale, together with other applicable asset sales
and issuances of preferred equity,  exceed $50.0 million,  be required under the
terms  of its  Second  Priority  Secured  Debt  Instruments  to make an offer to
purchase its outstanding second priority senior secured  indebtedness,  of which
$3.7 billion is outstanding,  up to the amount of the remaining net proceeds. As
described further in Note 12, on September 26, 2005, the Company filed a lawsuit
seeking  access to  blocked  proceeds  remaining  from  this sale of  designated
assets. If the Company does not ultimately prevail in this lawsuit, particularly
if the Company is compelled to return  previously  withdrawn  amounts to the gas
sale  proceeds  account  as more  fully  described  in Note 12, it could  have a
material adverse effect on the Company and its liquidity.

     In  connection   with  several  of  our   subsidiaries'   lease   financing
transactions (Agnews, Geysers,  Pasadena, Broad River, RockGen, and South Point)
the insurance  policies we have in place do not comply in every respect with the
insurance  requirements  set forth in the financing  documents.  The Company has
requested  from the  relevant  financing  parties,  and is expecting to receive,
waivers of this  noncompliance.  While failure to have the required insurance in
place is listed in the financing documents as an event of default, the financing
parties may not  unreasonably  withhold their  approval of the Company's  waiver
request so long as the required insurance  coverage is not reasonably  available
or commercially feasible, and a report is delivered from the Company's insurance
consultant  to that effect.  The Company has  delivered  the required  insurance
consultant reports to the relevant  financing parties and therefore  anticipates
that the necessary waivers will be executed shortly.

     In connection with the  sale/leaseback  transaction of Agnews,  the Company
has  not  fully  complied  with  covenants  pertaining  to  the  operations  and
maintenance  agreement,  which noncompliance is technically an event of default.
The  Company  is in the  process of  addressing  this by  seeking  the  lessor's
approval to renew and extend the  operations and  maintenance  agreement for the
Agnews facility.

     In  connection  with the  sale/leaseback  transaction  of Calpine  Monterey
Cogeneration, Inc., the Company has not fully complied with covenants pertaining
to amendments  to gas and power  purchase  agreements  and the  requirements  to
provide a detailed  accounting  report,  which  noncompliance  is technically an
event of default.  The Company is in the process of addressing this by seeking a
consent and waiver.

     2014  Convertible  Notes -- The Company received a letter dated October 24,
2005,  on behalf of  Whitebox  Convertible  Arbitrage  Fund,  L.P.  and  Harbert
Convertible  Arbitrage Master Fund, Ltd. (and certain  affiliated funds of each)
that,  collectively,  claim to hold at least 25% of the 2014 Convertible  Notes.
The letter  purports to be a notice of default,  which the Company would have 30
days to cure,  under the indenture  governing the 2014  Convertible  Notes.  The
basis of the claimed  default is the Company's  decision not to instruct the Bid
Solicitation  Agent for the 2014  Convertible  Notes to begin to  determine  the
"Trading Price" of the 2014  Convertible  Notes after (i) the Company received a
July 5, 2005 letter from Harbert Convertible  Arbitrage Master Fund, Ltd. and/or
its  affiliates  (the  "Harbert  Funds")  and (ii) the Harbert  Funds  served an
affidavit on July 19, 2005 in the litigation  described in Note 12, in each case
claiming  that the  Trading  Price was below a threshold  specified  in the 2014
Convertible  Notes. The Company  maintains that the information  provided by the




                                     - 28 -
<PAGE>

Harbert Funds in the July 5 letter did not constitute the "reasonable  evidence"
required to be provided under the 2014  Convertible  Notes indenture  before the
Company  would be required to instruct  the Bid  Solicitation  Agent to begin to
determine  the  Trading  Price.  The  Company  also  maintains  that the July 19
affidavit was not a proper notice under the indenture, and in any event likewise
did not  constitute  "reasonable  evidence"  as  required  under the  indenture.
Accordingly,  the  Company  maintains  that there is no  default  under the 2014
Convertible  Notes indenture.  The basis of the claimed default is currently the
subject of litigation as further described in Note 12.

     Unrestricted  Subsidiaries -- The information in this paragraph is required
to be provided  under the terms of the Company's  Second  Priority  Secured Debt
Instruments.   The  Company  has  designated  certain  of  its  subsidiaries  as
"unrestricted  subsidiaries" under the Second Priority Secured Debt Instruments.
A subsidiary with "unrestricted"  status thereunder generally is not required to
comply with the covenants  contained  therein that are applicable to "restricted
subsidiaries." The Company has designated Calpine Gilroy 1, Inc., Calpine Gilroy
2, Inc.  and Calpine  Gilroy  Cogen,  L.P. as  "unrestricted  subsidiaries"  for
purposes of the Second Priority Secured Debt Instruments.

8.  Discontinued Operations

     Set forth below are all of the  Company's  asset  disposals  by  reportable
segment that impacted the Company's  Consolidated Condensed Financial Statements
as of September 30, 2005, due to reclassifications to discontinued operations to
reflect  the sales or "held for sale"  designations  of the assets sold or to be
sold.

Oil and Gas Production and Marketing

     On September 1, 2004, the Company,  together with Calpine Natural Gas L.P.,
a Delaware  limited  partnership,  completed the sale of its U.S. Rocky Mountain
gas reserves that were  primarily  concentrated  in two  geographic  areas:  the
Colorado  Piceance  Basin and the New Mexico  San Juan  Basin.  Together,  these
assets  represented  approximately  120 Bcfe of proved gas  reserves,  producing
approximately  16.3  Mmcfe per day of gas.  Under  the  terms of the  agreement,
Calpine received net cash payments of approximately $218.7 million, and recorded
a pre-tax gain of approximately $103.7 million.

     On  September  2, 2004,  the  Company  completed  the sale of its  Canadian
natural gas reserves and petroleum  assets.  These Canadian  assets  represented
approximately 221 Bcfe of proved reserves,  producing approximately 61 Mmcfe per
day.  Included in this sale was the Company's 25% interest in  approximately  80
Bcfe of proved  reserves (net of  royalties)  and 32 Mmcfe per day of production
owned by CNGT. In accordance  with SFAS No. 144, the Company's 25% equity method
investment  in CNGT was  considered  part of the larger  disposal  group  (i.e.,
assets to be disposed of together as a group in a single transaction to the same
buyer),  and therefore  evaluated and accounted for as discontinued  operations.
Under  the  terms  of  the   agreement,   Calpine   received  cash  payments  of
approximately  Cdn$808.1  million,  or approximately  US$626.4 million.  Calpine
initially recorded a pre-tax gain of approximately $104.5 million on the sale of
these Canadian  assets net of $20.1 million in foreign  exchange losses recorded
in connection with the settlement of forward  contracts entered into to preserve
the US dollar value of the  Canadian  proceeds.  Subsequent  to the close of the
sale,  the Company  recognized  an  adjustment  to the pre-tax  gain  related to
working  capital;  this  adjustment  reduced the pre-tax  gain by $3.2  million,
resulting in a total pre-tax gain of $101.3 million.

     In  connection  with  the sale of the oil and gas  assets  in  Canada,  the
Company entered into a seven-year gas purchase agreement  beginning on March 31,
2005, and expiring on October 31, 2011, that allows,  but does not require,  the
Company to  purchase  gas from the buyer at current  market  index  prices.  The
agreement is not asset  specific and can be settled by any  production  that the
buyer has available.

     In connection  with the sale of the U.S. Rocky  Mountain gas reserves,  the
New Mexico San Juan Basin sales  agreement  allows for the buyer and the Company
to execute a ten-year  gas purchase  agreement  for 100% of the  underlying  gas
production  of sold  reserves,  at market index prices.  Any agreement  would be
subject to mutually agreeable collateral  requirements and other customary terms
and provisions.

     The Company  believes  that all final terms of the gas purchase  agreements
described  above are on a market  value and arm's length  basis.  If the Company
elects in the future to exercise a call option over production from the disposed
components, the Company will consider the call obligation to have been met as if
the actual  production  delivered to the Company  under the call was from assets
other than those constituting the disposed components.

     On July 7, 2005, the Company completed the sale of substantially all of its
remaining oil and gas assets to Rosetta for $1.05  billion,  less  approximately
$60 million of estimated  transaction fees and expenses.  The Company recorded a
pre-tax gain of approximately $340.2 million, which is reflected in discontinued
operations in the three and nine-months ended September 30, 2005.  Approximately



                                     - 29 -
<PAGE>

$75 million of the purchase  price was withheld  pending the transfer of certain
properties  for which  consents had not yet been  obtained at the closing  date.
Subsequent  to September  30,  2005,  the Company had received a number of these
consents but none of the $75 million had been released to the Company due to the
refusal of the Collateral Trustee to release liens on the applicable properties.
The Company has brought a lawsuit  against the  Collateral  Trustee as discussed
below and in Note 12. It is  anticipated  that consents will be obtained for the
remaining  properties  by December 31, 2005.  These assets are  reflected in the
September 30, 2005 and December 31, 2004  Consolidated  Condensed Balance Sheets
as other current assets held for sale in the Summary section below.  The portion
of any amount  received  in respect of these  properties  for natural gas assets
will constitute proceeds of a sale of "designated assets" and will be subject to
the  requirements  described  in Note 7 under  "Indenture  and  Debt  and  Lease
Covenant Compliance."

     As discussed in Note 12, the  Collateral  Trustee for the Company's  Senior
Secured Noteholders informed the Company of disagreements  purportedly raised by
certain holders of its First Priority Notes regarding the Company's reinvestment
of the  proceeds  from this sale of domestic  gas  assets.  As a result of these
concerns,  the  Collateral  Trustee  informed  the  Company  that  they  will be
withholding  further  withdrawals from the gas sale proceeds account until these
disagreements can be resolved. In addition,  the Collateral Trustee not released
liens on certain  properties  for which consents were received after the closing
of the sale and,  accordingly,  the  Company has not  received  payment for such
properties.  On September  26,  2005,  the Company  filed a lawsuit  against the
Collateral Trustee and the Trustee for the First Priority Notes. See Notes 7 and
12 for further  discussion  regarding the use of the proceeds of the sale of the
gas assets and the status of the related legal matter.

     In  connection  with the sale of the oil and gas  assets  to  Rosetta,  the
Company entered into a four and one-half year gas purchase agreement expiring on
December 31, 2009, for 100% of the  production of the  Sacramento  Basin assets,
which  represent  approximately  44% of the reserve assets sold to Rosetta.  The
Company will pay prevailing current market index prices for all amounts acquired
under the  agreement.  The  Company  believes  the gas  purchase  agreement  was
negotiated  on  an  arm's  length  basis  and  represents  fair  value  for  the
production.   Therefore,  the  agreement  does  not  provide  the  Company  with
significant influence over the buyer's ability to realize the economic risks and
rewards of owning the assets.

Electric Generation and Marketing

     On January 15, 2004,  the Company  completed  the sale of its 50% undivided
interest in the 545-MW Lost Pines 1 Power  Project to GenTex Power  Corporation,
an affiliate of the LCRA. Under the terms of the agreement, the Company received
a cash  payment of $148.6  million  and  recorded a gain  before  taxes of $35.3
million.  In addition,  CES entered into a tolling agreement with LCRA providing
for the option to purchase 250 MW of electricity through December 31, 2004.

     On July 28, 2005,  the Company  completed the sale of its 1,200-MW  Saltend
Energy Centre for approximately  $862.9 million,  $14.5 million of which related
to the estimated  working capital  adjustments.  The Company  recorded a pre-tax
gain for the three and nine months  ended  September  30, 2005 of  approximately
$23.7 million, which is reflected in discontinued operations, as a result of the
disposal of its UK  operations.  As  described in Note 12,  certain  bondholders
filed a  lawsuit  concerning  the  remaining  use of  proceeds  from the sale of
Saltend.

     In the three months ended  September 30, 2005,  the Company  committed to a
plan to divest its 561-MW Ontelaunee power plant in Pennsylvania.  On October 6,
2005,  the  Company  completed  the  sale  for  $225  million,   less  estimated
transaction  fees and expenses and closing  adjustments of  approximately  $13.0
million.  While the transaction  closed October 6, 2005, the Company had met the
criteria necessary to classify the assets and liabilities  related to Ontelaunee
as held for sale under SFAS No. 144 at  September  30,  2005.  These  assets and
liabilities  are  reflected  in the  September  30, 2005 and  December  31, 2004
Consolidated  Condensed  Balance  Sheets as  current  and  long-term  assets and
liabilities  held  for sale and  identified  by  balance  sheet  caption  in the
"Summary"  section  below.  Also, in  accordance  with SFAS No. 144, the Company
recorded an impairment  charge of $136.8 million for the difference  between the
estimated sale price (less  estimated  selling  costs) and the  facility's  book
value as of  September  30,  2005.  This  charge is  reflected  in  discontinued
operations in the Consolidated  Condensed  Statement of Operations for the three
and nine-month  periods ended September 30, 2005. See Note 5 for a discussion of
the Company's impairment  evaluation relating to the sale of Ontelaunee and Note
3 for a discussion of possible  additional  material impairment charges relating
to the sale of other assets.  In connection  with the sale of Ontelaunee  and in
accordance with the instruments governing its indebtedness,  on October 6, 2005,
CCFC I commenced offers to purchase its outstanding secured term loans and notes
in an amount up to the net proceeds received from the Ontelaunee sale. The offer
to purchase  term loans  expired on October 28, 2005,  and the offer to purchase
notes  expired on November 4, 2005,  without any term loans or notes having been
tendered for purchase.  Any remaining proceeds from this asset sale will be used
in accordance with the Company's existing bond indentures.



                                     - 30 -
<PAGE>

     In  connection  with the sale of  Ontelaunee,  the Company  entered  into a
ten-year parts and supplies  service  agreement,  referred to as an LTSA,  under
which the Company will provide major  maintenance  services and parts supply for
the significant  equipment of the facility,  and a five-year O&M agreement under
which the Company will provide services related to the day-to-day operations and
maintenance  of the facility.  Pricing of the LTSA and O&M service  contracts is
based on actual cost plus a margin and will  result in  estimated  annual  gross
cash outflows of approximately $3.3 million and $2.7 million,  respectively. The
Company  also entered  into a six-month  ESA under which CES will provide  power
management  services,  fuel management services,  risk management services,  and
other  services  related to the  Ontelaunee  facility,  with expected gross cash
inflows of approximately $0.4 million annually. The ESA can be renewed after six
months upon the mutual  agreement of both  Calpine and the new owner.  Under the
terms of the ESA,  CES  functions in an agency role and has no delivery or price
risk and has no economic  risk or reward of ownership in the  operations  of the
Ontelaunee facility.  The gross cash flows associated with the LTSA, O&M and ESA
agreements are  insignificant  to the ongoing entity  (Calpine)and the component
and are considered  indirect cash flows under EITF No. 03-13.  Also, the Company
has no significant continuing involvement in the financial and economic decision
making of the disposed component.

     On August 2, 2005,  the Company  completed  the sale of its interest in the
156-MW  Morris  power  plant in  Illinois  for $84.5  million.  The  Company had
previously  determined that the facility was impaired at June 30, 2005, upon the
Company's  commitment  to a plan of divesture of the  facility,  and recorded an
impairment  charge  to  continuing  operations  of $106.2  million  based on the
difference  between  the  estimated  sale price and the  facility's  book value.
During the three months ended September 30, 2005,  this charge was  reclassified
to discontinued operations once the sale had closed. The Company also recorded a
pre-tax loss on the sale of $0.4  million,  which is  reflected in  discontinued
operations.Net proceeds from this asset sale will be used in accordance with the
Company's existing bond indentures.

     In connection with the sale of Morris,  the Company entered into an ESA and
a gas purchase  contract under which CES will provide Morris with certain energy
scheduling  services and gas brokerage  services to facilitate gas purchases for
the new owner on a  month-to-month  basis until the new owner can  establish the
necessary  infrastructure  to secure its own gas supply.  It is anticipated that
these  agreements  will be assigned to the new CalBear  entity by year end 2005.
Under the terms of the ESA, CES  functions in an agency role and has no delivery
or price risk and has no economic risk or reward of ownership in the  operations
of  the  Morris  facility.  Estimated  gross  cash  inflows  from  the  ESA  are
approximately  $30,000 per month.  Under the terms of the gas purchase contract,
CES serves as a broker  executing  back-to-back  purchase/sale  transactions  on
behalf of Morris.  However,  CES bears only credit risk in the transaction,  the
nature  of  which is  financial  rather  than  operational  and is  sufficiently
different  in nature than the  previous  activities  with the  component.  Gross
estimated cash flows from the gas purchase contract is approximately $19 million
on an annualized  basis.  The cash flows  associated  with these  agreements are
insignificant to the ongoing entity (Calpine) and are considered indirect. Also,
the Company has no significant  continuing  involvement in the operations of the
disposed component.

Summary

     The Company made  reclassifications  to current and prior period  financial
statements  to reflect the sale or  designation  as "held for sale" of these oil
and gas and power plant assets and  liabilities  and to separately  classify the
operating  results of the assets sold and gain on sale of those  assets from the
operating results of continuing operations to discontinued operations.



























                                     - 31 -
<PAGE>

     The table  below  presents  the  assets  and  liabilities  held for sale by
segment as of September 30, 2005 (in thousands).

<TABLE>
<CAPTION>
                                                                                                September 30, 2005
                                                                                ----------------------------------------------------
                                                                                   Electric           Oil and Gas
                                                                                  Generation          Production
                                                                                and Marketing        and Marketing          Total
                                                                                -------------        -------------        ----------
<S>                                                                             <C>                    <C>                <C>
Assets
  Cash and cash equivalents .........................................           $        1             $       --         $        1
  Accounts receivable, net ..........................................                   --                     --                 --
  Inventories .......................................................                2,007                     --              2,007
  Other current assets ..............................................                   --                 44,842             44,842
  Prepaid expenses ..................................................                  302                     --                302
                                                                                  --------             ----------         ----------
    Total current assets held for sale ..............................                2,310                 44,842             47,152
                                                                                  --------             ----------         ----------
  Property, plant and equipment .....................................              210,213                     --            210,213
  Other assets ......................................................                   --                     --                 --
                                                                                  --------             ----------         ----------
     Total long-term assets held for sale ...........................           $  210,213             $       --           $210,213
                                                                                ==========             ==========         ==========
Liabilities
  Accounts payable ..................................................           $      718             $       --         $      718
  Current derivative liabilities ....................................                   --                     --                 --
  Other current liabilities .........................................                5,905                     --              5,905
                                                                                  --------             ----------         ----------
    Total current liabilities held for sale .........................                6,623                     --              6,623
                                                                                  --------             ----------         ----------
  Deferred income taxes, net of current portion .....................                   --                     --                 --
  Long-term derivative liabilities ..................................                   --                     --                 --
  Other liabilities .................................................                   --                     --                 --
                                                                                ----------             ----------         ----------
     Total long-term liabilities held for sale ......................           $       --             $       --         $       --
                                                                                ==========             ==========         ==========
</TABLE>

<TABLE>
<CAPTION>
                                                                                                   December 31, 2004
                                                                                ----------------------------------------------------
                                                                                   Electric           Oil and Gas
                                                                                  Generation          Production
                                                                                and Marketing        and Marketing          Total
                                                                                -------------        -------------        ----------
<S>                                                                             <C>                    <C>                <C>
Assets
  Cash and cash equivalents .........................................           $   65,405             $       --         $   65,405
  Accounts receivable, net ..........................................               54,095                     --             54,095
  Inventories .......................................................                7,756                     --              7,756
  Prepaid expenses ..................................................               14,840                     --             14,840
                                                                                ----------             ----------         ----------
    Total current assets held for sale ..............................              142,096                     --            142,096
                                                                                ----------             ----------         ----------
  Property, plant and equipment .....................................            1,632,131                606,520          2,238,651
  Other assets ......................................................               20,826                    924             21,750
                                                                                ----------             ----------         ----------
     Total long-term assets held for sale ...........................           $1,652,957             $  607,444         $2,260,401
                                                                                ==========             ==========         ==========
Liabilities
  Accounts payable ..................................................           $   34,070             $       --         $   34,070
  Current derivative liabilities ....................................                8,935                     --              8,935
  Other current liabilities .........................................               42,186                  1,267             43,453
                                                                                ----------             ----------         ----------
    Total current liabilities held for sale .........................               85,191                  1,267             86,458
                                                                                ----------             ----------         ----------
  Deferred income taxes, net of current portion .....................              135,985                     --            135,985
  Long-term derivative liabilities ..................................               10,368                     --             10,368
  Other liabilities .................................................               21,562                  8,384             29,946
                                                                                ----------             ----------         ----------
     Total long-term liabilities held for sale ......................           $  167,915             $    8,384         $  176,299
                                                                                ==========             ==========         ==========
</TABLE>










                                     - 32 -
<PAGE>

     The tables below presents  significant  components of the Company's  income
from  discontinued  operations for the three and nine months ended September 30,
2005 and 2004, respectively, (in thousands).
<TABLE>
<CAPTION>
                                                                                Three Months Ended September 30, 2005
                                                                    ----------------------------------------------------------------
                                                                      Electric        Oil and Gas       Corporate
                                                                     Generation       Production           and
                                                                    and Marketing    and Marketing        Other            Total
                                                                    -------------    -------------    -------------    -------------
<S>                                                                 <C>              <C>              <C>              <C>
Total revenue ....................................................  $      73,186    $       3,261    $          --    $  76,447
                                                                    =============    =============    =============   === =========
Gain on disposal before taxes ....................................  $      25,843    $     339,591    $          --    $    365,434
Operating income (loss) from discontinued operations
  before taxes ...................................................      (173,414)            4,240               --        (169,174)
                                                                    ------------     -------------    -------------    ------------
Income (loss) from discontinued operations before taxes ..........  $   (147,571)    $     343,831    $          --    $    196,260
Income tax provision (benefit) ...................................        39,896           130,618               --         170,514
                                                                    ------------     -------------    -------------    ------------
Income from discontinued operations, net of tax ..................  $   (187,467)    $     213,213    $          --    $     25,746
                                                                    ============     =============    =============    ============
</TABLE>
<TABLE>
<CAPTION>
                                                                                Three Months Ended September 30, 2004
                                                                    ----------------------------------------------------------------
                                                                      Electric        Oil and Gas       Corporate
                                                                     Generation       Production           and
                                                                    and Marketing    and Marketing        Other            Total
                                                                    -------------    -------------    -------------    -------------
<S>                                                                 <C>              <C>              <C>              <C>
Total revenue.....................................................  $    130,471     $      22,573    $          --    $    153,044
                                                                    ============     =============    =============    ============
Gain on disposal before taxes.....................................  $         --     $     203,533    $          --    $    203,533
Operating income (loss) from discontinued operations
  before taxes....................................................        (6,701)           17,698               --          10,997
                                                                    ------------     -------------    -------------    ------------
Income (loss) from discontinued operations before taxes...........  $     (6,701)    $     221,231    $          --    $    214,530
Income tax provision (benefit)....................................        (2,666)          104,948               --         102,282
                                                                    ------------     -------------    -------------    ------------
Income from discontinued operations, net of tax...................  $     (4,035)    $     116,283    $          --    $    112,248
                                                                    ============     =============    =============    ============
</TABLE>
<TABLE>
<CAPTION>
                                                                                Nine Months Ended September 30, 2005
                                                                    ----------------------------------------------------------------
                                                                      Electric        Oil and Gas       Corporate
                                                                     Generation       Production           and
                                                                    and Marketing    and Marketing        Other            Total
                                                                    -------------    -------------    -------------    -------------
<S>                                                                 <C>              <C>              <C>              <C>
Total revenue.....................................................  $    368,274     $      25,101    $          --    $    393,375
                                                                    ============     =============    =============    ============
Gain on disposal before taxes.....................................  $     23,260     $     337,012    $          --    $    360,272
Operating income (loss) from discontinued operations
before taxes......................................................      (318,701)           33,655               --        (285,046)
                                                                    ------------     -------------    -------------    ------------
Income (loss) from discontinued operations before taxes...........  $   (295,441)    $     370,667    $          --    $     75,226
Income tax provision (benefit)....................................        (3,186)          140,815               --         137,629
                                                                    ------------     -------------    -------------    ------------
Income from discontinued operations, net of tax...................  $   (292,255)    $     229,852    $          --    $    (62,403)
                                                                    ============     =============    =============    ============


                                                                                Nine Months Ended September 30, 2004
                                                                    ----------------------------------------------------------------
                                                                      Electric        Oil and Gas       Corporate
                                                                     Generation       Production           and
                                                                    and Marketing    and Marketing        Other            Total
                                                                    -------------    -------------    -------------    -------------
Total revenue.....................................................  $    387,289     $      71,207    $          --    $    458,496
                                                                    ============     =============    =============    ============
Gain on disposal before taxes.....................................  $     35,327     $     207,120    $          --    $    242,447
Operating income (loss) from discontinued operations before
  taxes...........................................................         7,962            77,362               --          85,324
                                                                    ------------     -------------    -------------    ------------
Income from discontinued operations before taxes..................  $     43,289     $     284,482    $          --    $    327,771
Income tax provision (benefit)....................................         8,457            83,604               --          92,061
                                                                    ------------     -------------    -------------    ------------
Income from discontinued operations, net of tax...................  $     34,832     $     200,878    $          --    $    235,710
                                                                    ============     =============    =============    ============
</TABLE>


                                     - 33 -
<PAGE>

     The Company  allocates  interest to  discontinued  operations in accordance
with EITF Issue No. 87-24, "Allocation of Interest to Discontinued  Operations."
The Company includes  interest expense on debt which is required to be repaid as
a result of a disposal  transaction in  discontinued  operations.  Additionally,
other  interest  expense that cannot be  attributed  to other  operations of the
Company is allocated  based on the ratio of net assets to be sold less debt that
is required  to be paid as a result of the  disposal  transaction  to the sum of
total net assets of the Company plus consolidated debt of the Company, excluding
(a) debt of the  discontinued  operation that will be assumed by the buyer,  (b)
debt that is required to be paid as a result of the disposal transaction and (c)
debt that can be directly attributed to other operations of the Company.

<TABLE>
<CAPTION>
                                                                   Three Months Ended September 30,  Nine Months Ended September 30,
                                                                   --------------------------------  -------------------------------
Interest Expense Allocation                                             2005              2004             2005              2004
---------------------------                                         ------------     -------------    -------------    -------------
<S>                                                                 <C>              <C>              <C>             <C>
Electric generation and marketing
   Saltend Energy Centre..........................................  $      6,225     $       1,178    $      45,080    $      5,170
   Morris and Ontelaunee Power Plants.............................         2,955             4,896           14,549          14,797
                                                                    ------------     -------------    -------------    ------------
      Total.......................................................  $      9,180     $       6,074    $      59,629    $     19,967
                                                                    ============     =============    =============    ============
Oil and gas production and marketing
   Canadian and Rockies...........................................  $         --     $       5,158    $          --    $     17,893
   Remaining oil and gas assets...................................           357             3,138           10,295           7,864
                                                                    ------------     -------------    -------------    ------------
      Total.......................................................  $        357     $       8,296    $      10,295    $     25,757
                                                                    ============     =============    =============    ============
</TABLE>

9.   Derivative Instruments

Summary of Derivative Values

     The table  below  reflects  the  amounts  that are  recorded  as assets and
liabilities at September 30, 2005, for the Company's derivative  instruments (in
thousands):
<TABLE>
<CAPTION>
                                                                                                 Commodity
                                                                       Interest Rate            Derivative                 Total
                                                                         Derivative             Instruments             Derivative
                                                                        Instruments                 Net                 Instruments
                                                                       -------------            -----------             -----------
<S>                                                                     <C>                     <C>                     <C>
Current derivative assets ..................................            $        --             $   703,665             $   703,665
Long-term derivative assets ................................                  1,959                 923,292                 925,251
                                                                        -----------             -----------             -----------
  Total assets .............................................            $     1,959             $ 1,626,957             $ 1,628,916
                                                                        ===========             ===========             ===========
Current derivative liabilities .............................            $   (15,135)            $  (958,962)            $  (974,097)
Long-term derivative liabilities ...........................                (48,530)             (1,166,933)             (1,215,463)
                                                                        -----------             -----------             -----------
  Total liabilities ........................................            $   (63,665)            $(2,125,895)            $(2,189,560)
                                                                        ===========             ===========             ===========
  Net derivative liabilities ...............................            $   (61,706)            $  (498,938)            $  (560,644)
                                                                        ===========             ===========             ===========
</TABLE>
     Of the  Company's  net  derivative  liabilities,  $202.1  million and $34.6
million are net derivative assets of PCF and CNEM,  respectively,  each of which
is an entity with its existence separate from the Company and other subsidiaries
of the  Company.  The Company  fully  consolidates  CNEM,  and the Company  also
records the net derivative assets of PCF in its balance sheet.

     On March 31, 2005,  Deer Park,  an indirect,  wholly  owned  subsidiary  of
Calpine,  entered into  agreements  to sell power to and buy gas from MLCI.  The
agreements  cover  650 MW of Deer  Park's  capacity,  and  deliveries  under the
agreements  began on April 1, 2005, and continue  through  December 31, 2010. To
assure  performance  under the  agreements,  Deer Park granted MLCI a collateral
interest in the Deer Park Energy Center.  The power and gas  agreements  contain
terms as follows:

   Power Agreements

     Under the terms of the power agreements,  Deer Park will sell power to MLCI
at fixed and index  prices with a discount to  prevailing  market  prices at the
time the agreements were executed.  In exchange for the discounted pricing, Deer
Park received an initial cash payment of $195.8 million, net of $17.3 million in
transaction  costs during the first quarter if 2005, and  subsequently  received
additional  cash payments of $76.4  million,  net of $2.9 million in transaction
costs,  as  additional  power  transactions  were  executed  with  discounts  to



                                     - 34 -
<PAGE>

prevailing market prices.  The cash received by Deer Park is sufficiently  small
compared to the amount  that would be required to fully  prepay for the power to
be delivered under the agreements that the agreements have been determined to be
derivatives  in their  entirety  under SFAS No. 133. The value of the derivative
liability at September 30, 2005,  was $297.4  million.  As Deer Park makes power
deliveries   under  the  agreements,   the  liability  will  be  satisfied  and,
accordingly, the derivative liability will be reduced, and Deer Park will record
corresponding  gains in income,  supplementing the revenues  recognized based on
discounted  pricing as deliveries take place. The upfront  payments  received by
Deer Park  from the  transaction  are  recorded  as cash  flows  from  financing
activity in accordance  with guidance  contained in SFAS No. 149,  "Amendment of
Statement 133 on Derivative  Instruments and Hedging Activities" (SFAS No. 149).
SFAS No. 149 requires that companies  present cash flows from  derivatives  that
contain  an  "other-than-insignificant"  financing  element  as cash  flows from
financing  activities.  Under SFAS No.  149, a  contract  that at its  inception
includes  off-market  terms,  or requires an up-front cash  payment,  or both is
deemed to contain an "other-than-insignificant" financing element.

   Gas Agreements

     Under the terms of the gas agreements, Deer Park will receive quantities of
gas such that,  when  combined  with fuel supply  provided by Deer Park's  steam
host,  Deer Park will have sufficient  contractual  fuel supply to meet the fuel
needs required to generate the power under the power agreements.  Deer Park will
pay both fixed and variable prices under the gas agreements.  To the extent that
Deer  Park  receives   fixed  prices  for  power,   Deer  Park  will  receive  a
volumetrically  proportionate  quantity  of gas supply at fixed  prices  thereby
fixing the spread  between the revenue Deer Park receives  under the fixed price
power  sales and the cost it pays under the fixed  price gas  purchases.  To the
extent that Deer Park receives  index-based  prices for its power sales, it will
pay  index-based  prices for a  volumetrically  proportionate  amount of its gas
supply.

Relationship of Net Derivative Assets or Liabilities to AOCI

     At any  point in time,  it is highly  unlikely  that  total net  derivative
assets or liabilities  will equal AOCI, net of tax from  derivatives,  for three
primary reasons:

     o    Tax effect of OCI -- When the values and subsequent  changes in values
          of derivatives that qualify as effective hedges are recorded into OCI,
          they are initially offset by a derivative asset or liability.  Once in
          OCI,  however,  these values are tax  effected  against a deferred tax
          liability or asset account,  thereby creating an imbalance between net
          OCI and net derivative assets and liabilities.

     o    Derivatives   not   designated   as  cash   flow   hedges   and  hedge
          ineffectiveness  -- Only  derivatives  that qualify as effective  cash
          flow  hedges  will  have  an  offsetting   amount   recorded  in  OCI.
          Derivatives  not  designated  as cash flow hedges and the  ineffective
          portion of derivatives designated as cash flow hedges will be recorded
          into  earnings  instead of OCI,  creating  a  difference  between  net
          derivative assets and liabilities and pre-tax OCI from derivatives.

     o    Termination  of  effective  cash  flow  hedges  prior to  maturity  --
          Following  the  termination  of a  cash  flow  hedge,  changes  in the
          derivative  asset or liability are no longer  recorded to OCI. At this
          point,  an AOCI  balance  remains that is not  recognized  in earnings
          until the forecasted initially hedged transactions occur. As a result,
          there will be a temporary difference between OCI and derivative assets
          and  liabilities  on the books  until the  remaining  OCI  balance  is
          recognized in earnings.

     Below is a  reconciliation  of the Company's net derivative  liabilities to
its accumulated other comprehensive loss, net of tax from derivative instruments
at September 30, 2005 (in thousands):
<TABLE>
<CAPTION>
<S>                                                                                                                 <C>
Net derivative liabilities......................................................................................    $      (560,644)
Derivatives not designated as cash flow hedges and recognized hedge ineffectiveness.............................            226,718
Cash flow hedges terminated prior to maturity...................................................................            (24,408)
Deferred tax asset attributable to accumulated other comprehensive loss on cash flow hedges.....................            119,451
AOCI from unconsolidated investees..............................................................................             19,806
                                                                                                                    ---------------
Accumulated other comprehensive loss from derivative instruments, net of tax (1)................................    $      (219,077)
                                                                                                                    ===============
------------
<FN>
(1)  Amount represents one portion of the Company's total AOCI balance. See Note
     10 for further information.
</FN>
</TABLE>




                                     - 35 -
<PAGE>

     Presentation  of Revenue  Under EITF Issue No.  03-11  "Reporting  Realized
Gains and Losses on Derivative  Instruments That Are Subject to SFAS No. 133 and
Not `Held for  Trading  Purposes'  As Defined in EITF  Issue No.  02-3:  "Issues
Involved in Accounting  for Derivative  Contracts Held for Trading  Purposes and
Contracts  Involved in Energy  Trading and Risk  Management  Activities"  -- The
Company  accounts  for certain of its power sales and  purchases  on a net basis
under EITF Issue No. 03-11,  which the Company adopted on a prospective basis on
October 1, 2003.  Transactions with either of the following  characteristics are
presented net in the Company's Consolidated Condensed Financial Statements:  (1)
transactions  executed in a back-to-back buy and sale pair, primarily because of
market protocols;  and (2) physical power purchase and sale  transactions  where
the  Company's  power  schedulers  net the physical  flow of the power  purchase
against the physical  flow of the power sale (or "book out" the  physical  power
flows) as a matter of scheduling  convenience  to eliminate the need to schedule
actual  power  delivery.  These  book out  transactions  may occur with the same
counterparty or between different counterparties where the Company has equal but
offsetting physical purchase and delivery  commitments.  In accordance with EITF
Issue No. 03-11,  the Company  netted the purchases of $335.8 million and $563.3
million  against  sales in the  three  months  ended  September  30,  2005,  and
September  30, 2004,  respectively.  The Company  netted the purchases of $912.1
million and $1,255.8  million  against sales in the nine months ended  September
30, 2005, and September 30, 2004, respectively.

     The asset and  liability  balances for the Company's  commodity  derivative
instruments  represent the net totals after  offsetting  certain  assets against
certain  liabilities under the criteria of FIN 39. For a given contract,  FIN 39
will allow the offsetting of assets against liabilities so long as four criteria
are met: (1) each of the two parties under contract owes the other  determinable
amounts;  (2) the party  reporting  under the offset method has the right to set
off the amount it owes against the amount owed to it by the other party; (3) the
party  reporting  under the offset  method  intends to exercise its right to set
off;  and (4) the right of  set-off  is  enforceable  by law.  The  table  below
reflects both the amounts (in thousands)  recorded as assets and  liabilities by
the Company  and the amounts  that would have been  recorded  had the  Company's
commodity  derivative  instrument  contracts not qualified for  offsetting as of
September 30, 2005.
<TABLE>
<CAPTION>
                                                                                                          September 30, 2005
                                                                                                  ----------------------------------
                                                                                                        Gross              Net
                                                                                                  ---------------   ----------------
<S>                                                                                               <C>               <C>
Current derivative assets.......................................................................  $     4,766,711   $       703,665
Long-term derivative assets.....................................................................        2,097,589           923,292
                                                                                                  ---------------   ---------------
  Total derivative assets.......................................................................  $     6,864,300   $     1,626,957
                                                                                                  ===============   ===============
Current derivative liabilities..................................................................  $    (5,022,008)  $      (958,962)
Long-term derivative liabilities................................................................       (2,341,230)       (1,166,933)
                                                                                                  ---------------   ---------------
  Total derivative liabilities..................................................................  $    (7,363,238)  $    (2,125,895)
                                                                                                  ===============   ===============
  Net commodity derivative liabilities..........................................................  $      (498,938)  $      (498,938)
                                                                                                  ===============   ===============
</TABLE>

     The table above excludes the value of interest rate and currency derivative
instruments.

     The tables  below  reflect the impact of  unrealized  mark-to-market  gains
(losses)  on  the  Company's  pre-tax  earnings,   both  from  cash  flow  hedge
ineffectiveness  and  from the  changes  in  market  value  of  derivatives  not
designated  as  hedges  of cash  flows,  for the  three  and nine  months  ended
September 30, 2005 and 2004, respectively (in thousands):
<TABLE>
<CAPTION>
                                                                     Three Months Ended September 30,
                                             ---------------------------------------------------------------------------------------
                                                                2005                                        2004
                                             ------------------------------------------   ------------------------------------------
                                                  Hedge       Undesignated                     Hedge      Undesignated
                                             Ineffectiveness  Derivatives       Total     Ineffectiveness  Derivatives       Total
                                             ---------------  ------------    ---------   ---------------  -----------    ----------
<S>                     <C>                     <C>            <C>            <C>            <C>           <C>            <C>
Natural gas derivatives (1) ...............     $   9,651      $  94,546      $ 104,197      $     777     $  (8,508)     $  (7,731)
Power derivatives (1) .....................        (1,643)      (127,642)      (129,285)         1,142       (17,173)       (16,031)
Interest rate derivatives (2) .............           524             --            524          2,369            --          2,369
Currency derivatives ......................            --             --             --             --       (12,897)       (12,897)
                                                ---------      ---------      ---------      ---------     ---------      ---------
  Total ...................................     $   8,532      $ (33,096)     $ (24,564)     $   4,288     $ (38,578)     $ (34,290)
                                                =========      =========      =========      =========     =========      =========
</TABLE>




                                     - 36 -
<PAGE>

<TABLE>
<CAPTION>
                                                                      Nine Months Ended September 30,
                                             ---------------------------------------------------------------------------------------
                                                                2005                                        2004
                                             ------------------------------------------   ------------------------------------------
                                                  Hedge       Undesignated                     Hedge      Undesignated
                                             Ineffectiveness  Derivatives       Total     Ineffectiveness  Derivatives       Total
                                             ---------------  ------------    ---------   ---------------  -----------    ----------
<S>                     <C>                     <C>            <C>            <C>            <C>           <C>            <C>
Natural gas derivatives (1) ...............     $  10,417      $  58,123      $  68,540      $   6,540     $ (11,610)     $  (5,070)
Power derivatives (1) .....................        (1,947)      (123,413)      (125,360)         1,268       (53,818)       (52,550)
Interest rate derivatives (2) .............          (316)            --           (316)         1,421         6,035          7,456
Currency derivatives ......................            --             --             --             --       (12,897)       (12,897)
                                                ---------      ---------      ---------      ---------     ---------      ---------
  Total ...................................     $   8,154      $ (65,290)     $ (57,136)     $   9,229     $ (72,290)     $ (63,061)
                                                =========      =========      =========      =========     =========      =========
------------
<FN>
     (1) Represents the unrealized portion of mark-to-market activity on gas and
power  transactions.  The  unrealized  portion  of  mark-to-market  activity  is
combined with the realized portions of mark-to-market  activity and presented in
the Consolidated Statements of Operations as "mark-to-market activities, net."

     (2)  Recorded  within  "Other  Income" in the  Consolidated  Statements  of
Operations.
</FN>
</TABLE>

     The table below reflects the  contribution of the Company's cash flow hedge
activity to pre-tax earnings based on the  reclassification  adjustment from OCI
to earnings  for the three and nine months  ended  September  30, 2005 and 2004,
respectively (in thousands):
<TABLE>
<CAPTION>
                                                                                                   Three Months Ended September 30,
                                                                                                  ----------------------------------
                                                                                                         2005              2004
                                                                                                  ----------------- ----------------
<S>                                                                                               <C>               <C>
Natural gas and crude oil derivatives...........................................................  $        27,589   $        (1,746)
Power derivatives...............................................................................         (297,481)          (26,975)
Interest rate derivatives.......................................................................           (6,665)           (1,320)
Foreign currency derivatives....................................................................             (498)             (501)
                                                                                                  ---------------   ---------------
  Total derivatives.............................................................................  $      (277,055)  $       (30,542)
                                                                                                  ===============   ===============


                                                                                                    Nine Months Ended September 30,
                                                                                                  ----------------------------------
                                                                                                         2005              2004
                                                                                                  ----------------- ----------------
Natural gas and crude oil derivatives...........................................................  $        44,906   $        23,487
Power derivatives...............................................................................         (336,922)          (69,998)
Interest rate derivatives.......................................................................          (20,570)          (11,286)
Foreign currency derivatives....................................................................           (1,499)           (1,513)
                                                                                                  ---------------   ---------------
  Total derivatives.............................................................................  $      (314,085)  $       (59,310)
                                                                                                  ===============   ===============
</TABLE>
     These tables include pre-tax losses of $175.3 million and $10.4 million for
the three months ended  September  30, 2005 and 2004,  respectively,  and $199.4
million and $1.4 million for the nine months ended  September 30, 2005 and 2004,
respectively,  which are  included in  discontinued  operations  for all periods
presented.

     As of September 30, 2005, the maximum length of time over which the Company
was hedging its exposure to the  variability in future cash flows for forecasted
transactions  was 7 and 11 years for  commodity  and  interest  rate  derivative
instruments,  respectively.  The Company estimates that pre-tax losses of $242.7
million would be  reclassified  from OCI into earnings  during the twelve months
ended September 30, 2006, as the hedged  transactions  affect earnings  assuming
constant gas and power prices,  interest  rates,  and exchange  rates over time;
however,  the actual amounts that will be reclassified will likely vary based on
the probability that gas and power prices as well as interest rates and exchange
rates will, in fact, change. Therefore, management is unable to predict what the
actual  reclassification from OCI to earnings (positive or negative) will be for
the next twelve months.

     The table below presents the pre-tax gains  (losses)  currently held in OCI
that will be recognized annually into earnings,  assuming constant gas and power
prices, interest rates, and exchange rates over time (in thousands):




                                     - 37 -
<PAGE>

<TABLE>
<CAPTION>
                                                                                                              2010 &
                                         2005          2006          2007          2008          2009         After         Total
                                      ----------    ----------    ----------    ----------    ----------    ----------    ----------
<S>                                   <C>           <C>           <C>           <C>           <C>           <C>           <C>
Gas OCI ..........................    $ 124,750     $ 340,855     $  16,035     $   2,975     $   2,036     $   2,621     $ 489,272
Power OCI ........................     (227,309)     (510,504)      (33,390)       (6,465)       (5,210)       (4,283)     (787,161)
Interest rate OCI ................       (1,744)       (5,860)       (3,876)       (3,169)       (3,027)      (18,775)      (36,451)
Foreign currency OCI .............         (498)       (1,993)       (1,603)          (94)           --            --        (4,188)
                                      ---------     ---------     ---------     ---------     ---------     ---------     ---------
  Total pre-tax OCI ..............    $(104,801)    $(177,502)    $ (22,834)    $  (6,753)    $  (6,201)    $ (20,437)    $(338,528)
                                      =========     =========     =========     =========     =========     =========     =========
</TABLE>

10.  Comprehensive Income (Loss)

     Comprehensive income (loss) is the total of net income (loss) and all other
non-owner changes in equity.  Comprehensive income (loss) includes the Company's
net income (loss),  unrealized gains and losses from derivative instruments that
qualify as cash flow hedges, unrealized gains and losses from available-for-sale
securities which are marked to market,  the Company's share of its equity method
investee's OCI, and the effects of foreign currency translation adjustments. The
Company reports AOCI in its Consolidated  Balance Sheet. The tables below detail
the changes  during the nine  months  ended  September  30, 2005 and 2004 in the
Company's AOCI balance and the components of the Company's  comprehensive income
(loss) (in thousands):


<TABLE>
<CAPTION>
                                                                                                                     Comprehensive
                                                                                                                     Income (Loss)
                                                                                                                     for the Three
                                                                                                                      Months Ended
                                                                                                          Total      March 31, 2005,
                                                                                                       Accumulated   June 30, 2005,
                                                                           Available-      Foreign        Other           and
                                                             Cash Flow      for-Sale      Currency    Comprehensive   September 30,
                                                              Hedges       Investments   Translation  Income (Loss)       2005
                                                            -----------    -----------   -----------  -------------  ---------------
<S>                                                         <C>            <C>           <C>           <C>            <C>
Accumulated other comprehensive income (loss)
  at January 1, 2005 .....................................  $  (140,151)   $       582   $   249,080   $   109,511
Net loss for the three months ended March 31, 2005 .......                                                            $  (168,731)
  Cash flow hedges:
   Comprehensive pre-tax loss on cash flow hedges
    before reclassification adjustment during the
    three months ended March 31, 2005 ....................      (90,719)
   Reclassification adjustment for gain included in
    net loss for the three months ended
    March 31, 2005 .......................................       (4,044)
   Income tax benefit for the three months ended
    March 31, 2005 .......................................       29,998
                                                            -----------
                                                                (64,765)                                   (64,765)       (64,765)
  Available-for-sale investments:
   Pre-tax gain on available-for-sale investments
    for the three months ended March 31, 2005 ............                       1,150
   Income tax provision for the three months
    ended March 31, 2005 .................................                        (451)
                                                                           -----------
                                                                                   699                         699            699
   Foreign currency translation loss for the three
    months ended March 31, 2005 ..........................                                   (12,830)      (12,830)       (12,830)
                                                                                         -----------   -----------    -----------
Total comprehensive loss for the three months
  ended March 31, 2005 ...................................                                                            $  (245,627)
                                                                                                                      ===========
Accumulated other comprehensive income (loss)
  at March 31, 2005 ......................................  $  (204,916)   $     1,281   $   236,250   $    32,615
                                                            ===========    ===========   ===========   ===========
Net loss for the three months ended June 30, 2005 ........                                                            $  (298,458)
Cash flow hedges:
Comprehensive pre-tax loss on cash flow hedges
  before reclassification adjustment during the
  three months ended June 30, 2005 .......................     (134,289)
Reclassification adjustment for loss included in
  net loss for the three months ended
  June 30, 2005 ..........................................       41,074
Income tax benefit for the three months ended
  June 30, 2005 ..........................................       27,872
                                                            -----------
                                                                (65,343)                                   (65,343)       (65,343)

                               (table continues)

                                     - 38 -
<PAGE>

Available-for-sale investments:
Pre-tax gain on available-for-sale investments
  for the three months ended June 30, 2005 ...............                       2,415
Income tax provision for the three months
  ended June 30, 2005 ....................................                        (947)
                                                                           -----------
                                                                                 1,468                                      1,468
Foreign currency translation loss for the three
  months ended June 30, 2005 .............................                                   (20,860)      (20,860)       (20,860)
                                                                                         -----------   -----------    -----------
Total comprehensive loss for the three months
  ended June 30, 2005 ....................................                                                            $  (383,193)
                                                                                                                      ===========
Total comprehensive loss for the six months
  ended June 30, 2005 ....................................                                                            $  (628,820)
                                                                                                                      ===========
Accumulated other comprehensive income (loss)
  at June 30, 2005 .......................................  $  (270,259)   $     2,749   $   215,390   $   (52,120)
                                                            ===========    ===========   ===========   ===========
Net loss for the three months ended
  September 30, 2005 .....................................                                                            $  (216,689)

  Cash flow hedges:
   Comprehensive pre-tax loss on cash flow hedges
    before reclassification adjustment during the
    three months ended September 30, 2005 ................     (209,814)
   Reclassification adjustment for loss included in
    net loss for the three months ended
    September 30, 2005 ...................................      277,055
   Income tax provision for the three months ended
    September 30, 2005 ...................................      (16,059)
                                                            -----------
                                                                 51,182                                     51,182         51,182
  Available-for-sale investments:
   Pre-tax loss on available-for-sale investments for
    the three months ended September 30, 2005 ............                      (4,523)
   Income tax benefit for the three months ended
    September 30, 2005 ...................................                       1,774
                                                                           -----------
                                                                                (2,749)                     (2,749)        (2,749)
   Foreign currency translation loss for the three
    months ended September 30, 2005 ......................                                  (171,687)     (171,687)      (171,687)
                                                                                         -----------   -----------    -----------
Total comprehensive loss for the three months
  ended September 30, 2005 ...............................                                                            $  (339,943)
                                                                                                                      ===========
Total comprehensive loss for the nine months
  ended September 30, 2005 ...............................                                                            $  (968,763)
                                                                                                                      ===========
Accumulated other comprehensive income (loss)
  at September 30, 2005 ..................................  $  (219,077)   $        --   $    43,703   $  (175,374)
                                                            ===========    ===========   ===========   ===========

Accumulated other comprehensive income (loss)
  at January 1, 2004 .....................................  $  (130,419)   $        --   $   187,013   $    56,594
Net loss for the three months ended March 31, 2004 .......                                                            $   (71,192)
  Cash flow hedges:
   Comprehensive pre-tax gain on cash flow hedges
    before reclassification adjustment during the
    three months ended March 31, 2004 ....................        4,426
   Reclassification adjustment for loss included in net
    loss for the three months ended March 31, 2004 .......       15,863
   Income tax provision for the three months ended
    March 31, 2004 .......................................       (7,224)
                                                            -----------
                                                                 13,065                                     13,065         13,065
  Available-for-sale investments:
   Pre-tax gain on available-for-sale investments for
    the three months ended March 31, 2004 ................                      19,526
   Income tax provision for the three months ended
    March 31, 2004 .......................................                      (7,709)
                                                                           -----------
                                                                                11,817                      11,817         11,817
   Foreign currency translation gain for the three
    months ended March 31, 2004 ..........................                                     2,078         2,078          2,078
                                                                                         -----------   -----------    -----------
Total comprehensive loss for the three months
  ended March 31, 2004 ...................................                                                            $   (44,232)
                                                                                                                      ===========
Accumulated other comprehensive income (loss)
  at March 31, 2004 ......................................  $  (117,354)   $    11,817   $   189,091   $    83,554
                                                            ===========    ===========   ===========   ===========
Net loss for the three months ended June 30, 2004 ........                                                            $   (28,698)

                               (table continues)


                                     - 39 -
<PAGE>
                                                                                                                     Comprehensive
                                                                                                                     Income (Loss)
                                                                                                                     for the Three
                                                                                                                      Months Ended
                                                                                                          Total      March 31, 2005,
                                                                                                       Accumulated   June 30, 2005,
                                                                           Available-      Foreign        Other           and
                                                             Cash Flow      for-Sale      Currency    Comprehensive   September 30,
                                                              Hedges       Investments   Translation  Income (Loss)       2005
                                                            -----------    -----------   -----------  -------------  ---------------
Cash flow hedges:
Comprehensive pre-tax loss on cash flow hedges
  before reclassification adjustment during the
  three months ended June 30, 2004 .......................  $   (54,414)
Reclassification adjustment for loss included in net
  loss for the three months ended June 30, 2004 ..........       12,905
Income tax benefit for the three months ended
  June 30, 2004 ..........................................       13,369
                                                            -----------
                                                                (28,140)                                   (28,140)       (28,140)
Available-for-sale investments:
Pre-tax loss on available-for-sale investments for
  the three months ended June 30, 2004 ...................                     (19,762)
Income tax benefit for the three months ended
  June 30, 2004 ..........................................                       7,802
                                                                           -----------
                                                                               (11,960)                    (11,960)       (11,960)
Foreign currency translation loss for the three
  months ended June 30, 2004 .............................                                   (21,399)      (21,399)       (21,399)
                                                                                         -----------   -----------    -----------
Total comprehensive loss for the three months
  ended June 30, 2004 ....................................                                                            $   (90,197)
                                                                                                                      ===========
Total comprehensive loss for the six months
  ended June 30, 2004 ....................................                                                            $  (134,429)
                                                                                                                      ===========
Accumulated other comprehensive income (loss)
  at June 30, 2004 .......................................  $  (145,494)   $      (143)  $   167,692   $    22,055
                                                            ===========    ===========   ===========   ===========
Net income for the three months ended
  September 30, 2004 .....................................                                                            $   141,125
  Cash flow hedges:
   Comprehensive pre-tax loss on cash flow hedges
    before reclassification adjustment during the
    three months ended September 30, 2004 ................  $   (76,611)
   Reclassification adjustment for loss included in
    net loss for the three months ended
    September 30, 2004 ...................................       30,542
   Income tax benefit for the three months ended
    September 30, 2004 ...................................       11,773
                                                            -----------
                                                                (34,296)                                   (34,296)       (34,296)
  Available-for-sale investments:
   Pre-tax gain on available-for-sale investments for
    the three months ended September 30, 2004 ............                       6,183
   Income tax provision for the three months
    ended September 30, 2004 .............................                      (2,427)
                                                                           -----------
                                                                                 3,756                       3,756          3,756
   Foreign currency translation gain for the three
    months ended September 30, 2004 ......................                                    24,941        24,941         24,941
                                                                                         -----------   -----------    -----------
Total comprehensive income for the three months
  ended September 30, 2004 ...............................                                                            $   135,526
                                                                                                                      ===========
Total comprehensive income for the nine months
  ended September 30, 2004 ...............................                                                            $     1,097
                                                                                                                      ===========
Accumulated other comprehensive income (loss)
  at September 30, 2004 ..................................  $  (179,790)   $     3,613   $   192,633   $    16,456
                                                            ===========    ===========   ===========   ===========
</TABLE>


11.  Loss Per Share

     Basic  loss per  common  share was  computed  by  dividing  net loss by the
weighted average number of common shares outstanding for the respective periods.
The dilutive effect of the potential exercise of outstanding options to purchase
shares of common  stock is  calculated  using the  treasury  stock  method.  The
dilutive effect of the assumed conversion of certain convertible securities into
the Company's common stock is based on the dilutive common share equivalents and
the after tax distribution  expense avoided upon conversion.  The reconciliation
of basic and diluted loss per common share is shown in the  following  table (in
thousands, except per share data).



                                     - 40 -
<PAGE>

<TABLE>
<CAPTION>
                                                                                Periods Ended September 30,
                                                 -----------------------------------------------------------------------------------
                                                                    2005                                      2004
                                                 -----------------------------------------   ---------------------------------------
                                                                  Weighted                                   Weighted
                                                  Net Income      Average                                    Average
                                                    (Loss)        Shares         EPS         Net Income       Shares         EPS
                                                 -------------   ---------   -------------   -------------   ---------   -----------
<S>                                              <C>               <C>        <C>            <C>              <C>        <C>
THREE MONTHS:
Basic earnings (loss) per common share:
  Income (loss) before discontinued operations
   and cumulative effect of a change in
   accounting principle......................... $   (242,435)     478,461    $     (0.51)   $    28,877      444,380    $     0.07
  Discontinued operations, net of tax...........       25,746           --           0.06        112,248           --          0.25
                                                 ------------    ---------    -----------    -----------     --------    ----------
      Net income (loss)......................... $   (216,689)     478,461    $     (0.45)   $   141,125      444,380    $     0.32
                                                 ============    =========    ===========    ===========     ========    ==========
  Diluted earnings (loss) per common share:
  Common shares issuable upon exercise of stock
   options using treasury stock method..........                        --                                      2,542
  Income (loss) before discontinued operations
   and cumulative effect of a change in
   accounting principle......................... $   (242,435)     478,461    $     (0.51)   $    28,877     446,922  $      0.07
  Discontinued operations, net of tax...........       25,746           --           0.06        112,248           --         0.25
                                                 ------------    ---------    -----------    -----------     --------    ----------
      Net income (loss)......................... $   (216,689)     478,461    $     (0.45)   $   141,125     446,922  $      0.32
                                                 ============    =========    ===========    ===========     ========    ==========

                                                                                Periods Ended September 30,
                                                 -----------------------------------------------------------------------------------
                                                                    2005                                      2004
                                                 -----------------------------------------   ---------------------------------------
                                                    Net Loss       Shares         EPS          Net Loss        Shares        EPS
                                                 -------------   ---------   -------------   -------------   ---------   -----------
NINE MONTHS:
Basic and diluted loss per common share:
  Loss before discontinued operations........... $   (621,476)     458,483    $     (1.36)   $  (194,475)     425,682    $    (0.45)
  Discontinued operations, net of tax...........      (62,403)          --          (0.13)       235,710           --          0.55
                                                 ------------    ---------    -----------    -----------     --------    ----------
      Net income (loss).........................  $  (683,879)     458,483    $     (1.49)   $    41,235      425,682    $     0.10
                                                 ============    =========    ===========    ===========     ========    ==========
</TABLE>

     The Company incurred losses before discontinued operations for the quarters
ended  September 30, 2005 and 2004.  As a result,  basic shares were used in the
calculations  of fully  diluted  loss per  share for  these  periods,  under the
guidelines of SFAS No. 128 as using the basic shares  produced the more dilutive
effect on the loss per share.  Potentially convertible securities,  shares to be
purchased  under the Company's  ESPP and  unexercised  employee stock options to
purchase  a weighted  average  of 7.7  million  and 55.1  million  shares of the
Company's  common stock were not included in the  computation  of diluted shares
outstanding   during  the  nine  months  ended  September  30,  2005  and  2004,
respectively, because such inclusion would be antidilutive.

     For  the  three  and  nine  months  ended  September  30,  2005  and  2004,
approximately 0.1 million and 4.0 million, respectively,  weighted common shares
of the Company's outstanding 2006 Convertible Notes, respectively, were excluded
from the diluted EPS  calculations  as the  inclusion  of such shares would have
been antidilutive.

     In connection  with the convertible  debentures  payable to Calpine Capital
Trust III, net of repurchases, for the three months ended September 30, 2005 and
2004,  and the nine months  ended  September  30, 2005 and 2004,  there were 0.0
million,  11.9 million,  6.1 million and 11.9 million  weighted  average  common
shares potentially issuable,  respectively,  that were excluded from the diluted
EPS  calculation  as their  inclusion  would be  antidilutive.  The  convertible
debentures were redeemed in full on July 13, 2005.

     For the three and nine months ended September 30, 2005 and 2004,  under the
net share  settlement  method and in  accordance  with the new  guidance of EITF
04-08 there were no shares potentially issuable and thus potentially included in
the diluted EPS calculation  under the Company's 2023  Convertible  Notes,  2014
Convertible Notes and 2015 Convertible Notes issued in November 2003,  September
2004 and June 2005,  respectively,  because the Company's closing stock price at
each period end was below the conversion  price.  However,  in future  reporting
periods where the Company's  closing stock price is above the  conversion  price
for any of these  convertible  instruments  and the  Company  has income  before
discontinued  operations  and  cumulative  effect  of  a  change  in  accounting
principle,  the holders of each note will  receive the  conversion  value of the
note payable in cash up to the principal  amount of the note, and Calpine common
stock for the notes  conversion  value in  excess  of such  princpal  amount.The



                                     - 41 -
<PAGE>

maximum  potential shares issuable under the conversion  provisions of the notes
would be as presented  below.  The actual number of potential shares will depend
on the closing stock price at conversion.

     o    2023  Convertible  Notes -- If the  Company's  closing  stock price is
          above  the  instrument's  conversion  price of  $6.50,  a  maximum  of
          approximately  97.5 million  shares would be included (if dilutive) in
          the diluted EPS calculation;

     o    2014  Convertible  Notes -- If the  Company's  closing  stock price is
          above  the  instrument's  conversion  price of  $3.85,  a  maximum  of
          approximately  166.7 million shares would be included (if dilutive) in
          the diluted EPS calculation;

     o    2015  Convertible  Notes -- If the  Company's  closing  stock price is
          above  the  instrument's  conversion  price of  $4.00,  a  maximum  of
          approximately  163.0 million shares would be included (if dilutive) in
          the diluted EPS calculation;

     For the three  and nine  months  ended  September  30,  2005,  1.2  million
weighted average common shares of the Company's contingently issuable (unvested)
restricted  stock was excluded from the  calculation  of diluted EPS because the
Company's  closing  stock  price has not  reached  the price at which the shares
vest, and, as discussed above, inclusion would have been anti-dilutive.

     In conjunction with the offering of the 2014 Convertible Notes in September
2004,  the Company  entered  into a ten-year  Share  Lending  Agreement  with DB
London,  under  which the  Company  loaned DB London 89 million  shares of newly
issued  Calpine  common  stock in exchange for a loan fee of $.001 per share and
other  consideration.  The Company has excluded the 89 million  shares of common
stock subject to the Share Lending Agreement from the EPS calculation.

     See Note 2 for a discussion  of the  potential  impact of SFAS No. 128-R on
the calculation of diluted EPS.

12.  Commitments and Contingencies

LTSA Cancellations

     On July 5, 2005, Calpine and Siemens-Westinghouse  executed an agreement to
settle various  matters  related to certain  warranty  disputes and to terminate
certain  LTSAs.  The  Company  received  approximately  $25.5  million  as a net
settlement  payment  related to these  matters,  a portion  of which  related to
events in existence prior to June 30, 2005. Consequently,  $3.6 million and $7.2
million were recorded in the three months ended June 30, 2005, and September 30,
2005,  respectively,  as a  reduction  in plant  operating  expense  relating to
warranty  recoveries and contract  settlements of prior period repair  expenses.
The remaining  settlement  proceeds  were applied as a reduction to  capitalized
turbine costs in the three months ended September 30, 2005.

     On July 7, 2005,  the Company  announced that it had entered into a 15-year
Master Products and Services Agreement with GE. A related agreement replaces the
nine remaining  LTSAs  covering the Company's GE 7FA turbine fleet.  The Company
expects to benefit from improved  power plant  performance  and  operations  and
maintenance   flexibility   to  service  its  plants  to  further  lower  costs.
Historically,  GE provided  full-service turbine maintenance for a select number
of Calpine power plants.  Under the new agreement,  Calpine will  supplement its
operations with a variety of GE services.  As of September 30, 2005, the Company
operates  44 power  plants  that are  powered by GE gas  turbines,  representing
approximately  10,000 MW of capacity.  The Company  recorded  LTSA  cancellation
expense of $33.3  million in the three months  ended June 30,  2005,  as the key
terms and provisions of the cancellation  agreement were finalized prior to June
30, 2005.

Turbines

     The table below sets forth future  turbine  payments for  construction  and
development projects, as well as for unassigned turbines. It includes previously
delivered  turbines,  payments  and  delivery by year for the last turbine to be
delivered as well as payment  required for the potential  cancellation  costs of
the  remaining 28 gas and steam  turbines.  The table does not include  payments
that would result if the Company were to release for  manufacturing any of these
remaining 28 turbines.

                                                                   Units to Be
                Year                                Total           Delivered
--------------------------------------          ----------         -----------
                                                        (In thousands)
October through December 2005................   $   11,220                1
2006.........................................        4,480               --
2007.........................................        2,332               --
2008.........................................        2,699               --
                                                ----------             ----
  Total......................................   $   20,731                1
                                                ==========             ====


                                     - 42 -
<PAGE>

Litigation

     The  Company  is party to various  litigation  matters  arising  out of the
normal course of business,  the more significant of which are summarized  below.
The ultimate  outcome of each of these matters  cannot  presently be determined,
nor can the liability that could  potentially  result from a negative outcome be
reasonably  estimated  presently  for every case.  The liability the Company may
ultimately  incur  with  respect  to any one of these  matters in the event of a
negative outcome may be in excess of amounts  currently  accrued with respect to
such matters and, as a result of these matters,  may  potentially be material to
the Company's Consolidated Financial Statements.

     Securities  Class Action  Lawsuits.  Beginning  on March 11, 2002,  fifteen
securities class action complaints were filed in the U.S. District Court for the
Northern  District of California  against  Calpine and certain of its employees,
officers, and directors.  All of these actions were ultimately assigned to Judge
Saundra Brown Armstrong,  and Judge Armstrong  ordered the actions  consolidated
for  all  purposes  on  August  16,  2002,  as In re  Calpine  Corp.  Securities
Litigation, Master File No. C 02-1200 SBA. In mid-October, 2005, an agreement in
principle to settle this case was reached.  The proposed settlement will resolve
the only claim remaining in these consolidated actions,  which is a claim by two
plaintiffs for an alleged violation of Section 11 of the Securities Act of 1933.
All of the other claims brought in the consolidated  actions were dismissed with
prejudice  in  February  2004.  Judge  Armstrong  denied  the  motion  for class
certification  on August  10,  2005.  The  settlement  amount  is being  paid by
insurance.  The Company  currently expects the settlement to be finalized before
the end of 2005.

     Hawaii Structural  Ironworkers Pension Fund v. Calpine, et al. This case is
a Section 11 case brought as a class action on behalf of purchasers in Calpine's
April  2002 stock  offering.  This case was filed in San Diego  County  Superior
Court on March 11, 2003.  Defendants  won a motion to transfer the case to Santa
Clara County.  Defendants  in this case are Calpine,  Peter  Cartwright,  Ann B.
Curtis, John Wilson, Kenneth Derr, George Stathakis, Credit Suisse First Boston,
Banc of America Securities,  Deutsche Bank Securities,  and Goldman, Sachs & Co.
The Hawaii Fund alleges that the prospectus and  registration  statement for the
April 2002  offering had false or  misleading  statements  regarding:  Calpine's
actual  financial  results  for 2000 and  2001;  Calpine's  projected  financial
results for 2002;  Mr.  Cartwright's  agreement  not to sell or purchase  shares
within 90 days of the  offering;  and  Calpine's  alleged  involvement  in "wash
trades." A central  allegation of the complaint is that a March 2003 restatement
concerning  the accounting for two  sales-leaseback  transactions  revealed that
Calpine had misrepresented its financial results in the  prospectus/registration
statement for the April 2002 offering.

     There is no trial date in this action.  The next  scheduled  court  hearing
will be a case  management  conference  on January 10,  2006,  at which time the
court may set a trial date.  We consider  this  lawsuit to be without  merit and
intend to continue to defend vigorously against the allegations.

     Phelps v. Calpine Corporation, et al. On April 17, 2003, James Phelps filed
a class action complaint in the Northern District of California, alleging claims
under the ERISA. On May 19, 2003, a nearly  identical class action complaint was
filed in the Northern  District by Lenette  Poor-Herena.  The parties  agreed to
have both of the ERISA  actions  assigned to Judge  Armstrong,  who oversees the
above-described federal securities class action and the Gordon derivative action
(see below).  On August 20, 2003,  pursuant to an agreement between the parties,
Judge  Armstrong  ordered that the two ERISA actions be  consolidated  under the
caption,  In re Calpine Corp.  ERISA Litig.,  Master File No. C 03-1685 SBA (the
"ERISA  Class  Action").  Plaintiff  James  Phelps  filed a  consolidated  ERISA
complaint on January 20, 2004 ("Consolidated Complaint"). Ms. Poor-Herena is not
identified as a plaintiff in the Consolidated Complaint.

     The  Consolidated  Complaint  defines the class as all participants in, and
beneficiaries  of, the Plan for whose accounts  investments were made in Calpine
stock during the period from January 5, 2001 to the  present.  The  Consolidated
Complaint  names as defendants  Calpine,  the members of its Board of Directors,
the Plan's Advisory  Committee and its members (Kati Miller,  Lisa Bodensteiner,
Rick Barraza, Tom Glymph,  Patrick Price, Trevor Thor, Bob McCaffrey,  and Bryan
Bertacchi),  signatories of the Plan's Annual  Return/Report of Employee Benefit
Plan Forms 5500 for 2001 and 2002 (Pamela J. Norley and Marybeth Kramer-Johnson,
respectively),  an  employee  of a  consulting  firm  hired by the  Plan  (Scott
Farris),  and unidentified  fiduciary  defendants.  The  Consolidated  Complaint
alleges that defendants  breached their fiduciary  duties involving the Plan, in
violation of ERISA, by  misrepresenting  Calpine's actual financial  results and
earnings  projections,  failing to disclose certain transactions between Calpine
and Enron that allegedly inflated Calpine's  revenues,  failing to disclose that
the shortage of power in California  during  2000-2001 was due to withholding of
capacity by certain power  companies,  failing to  investigate  whether  Calpine
common stock was an  appropriate  investment  for the Plan,  and failing to take
appropriate actions to prevent losses to the Plan. In addition, the Consolidated
Complaint  alleges  that  certain of the  individual  defendants  suffered  from
conflicts  of  interest  due to their  sales of Calpine  stock  during the class
period.



                                     - 43 -
<PAGE>

     Defendants  moved to dismiss the  Consolidated  Complaint.  Judge Armstrong
granted the motion and dismissed  three of the four claims with  prejudice.  The
remaining  claim,  for  misrepresentation,  was  dismissed  with leave to amend.
Plaintiff filed an Amended  Consolidated  Complaint on June 3, 2005. The Amended
Consolidated  Complaint names as defendants Calpine  Corporation and the members
of the Advisory Committee for the Plan. Defendants have filed motions to dismiss
the Amended Consolidated Complaint, which are currently scheduled for hearing on
December 6, 2005.  We consider  this  lawsuit to be without  merit and intend to
continue to defend vigorously against the allegations.

     Johnson v. Peter  Cartwright,  et al. On December 17,  2001, a  shareholder
filed a derivative lawsuit on behalf of Calpine against its directors and one of
its senior officers. This lawsuit is styled Johnson vs. Cartwright,  et al. (No.
CV803872)  and is pending in  California  Superior  Court in Santa Clara County,
California. Calpine is a nominal defendant in this lawsuit, which alleges claims
relating to purportedly  misleading  statements about Calpine and stock sales by
certain of the director defendants and the officer defendant.  In December 2002,
the court  dismissed  the  complaint  with  respect to  certain of the  director
defendants for lack of personal  jurisdiction,  though plaintiff may appeal this
ruling.  In early February 2003,  plaintiff filed an amended  complaint,  naming
additional  officer  defendants.  Calpine and the  individual  defendants  filed
demurrers  (motions to dismiss) and a motion to stay the case in March 2003.  On
July 1, 2003, the Court granted  Calpine's  motion to stay this proceeding until
In re Calpine Corporation  Securities  Litigation is resolved,  or until further
order of the Court.  The Court did not rule on the  demurrers.  We consider this
lawsuit  to be  without  merit  and  intend  to defend  vigorously  against  the
allegations if the stay is lifted.

     Gordon v. Peter Cartwright, et al. On August 8, 2002, a shareholder filed a
derivative suit in the United States District Court for the Northern District of
California  on behalf of Calpine  against  its  directors,  captioned  Gordon v.
Cartwright,  et al.  similar  to Johnson v.  Cartwright.  Motions  were filed to
dismiss the action against certain of the director  defendants on the grounds of
lack of personal  jurisdiction,  as well as to dismiss the complaint in total on
other grounds.  In February  2003,  plaintiff  agreed to stay these  proceedings
until In re  Calpine  Corporation  Securities  Litigation  is  resolved,  and to
dismiss without prejudice certain director defendants. The Court did not rule on
the motions to dismiss the complaint on non-jurisdictional  grounds. On March 4,
2003,  plaintiff  filed  papers with the court  voluntarily  agreeing to dismiss
without prejudice his claims against three of the outside directors. We consider
this  lawsuit to be without  merit and intend to defend  vigorously  against the
allegations if the stay is lifted.

     International  Paper Company v.  Androscoggin  Energy LLC. In October 2000,
International  Paper Company filed a complaint against  Androscoggin  Energy LLC
("AELLC") alleging that AELLC breached certain  contractual  representations and
warranties  arising  out of an  Amended  Energy  Services  Agreement  ("ESA") by
failing to disclose facts surrounding the termination, effective May 8, 1998, of
one of AELLC's  fixed-cost  gas supply  agreements.  The steam  price paid by IP
under  the ESA is  derived  from  AELLC's  price  of gas  under  its gas  supply
agreements.  We had  acquired  a 32.3%  economic  interest  and a  49.5%  voting
interest  in AELLC as part of the Skygen  transaction,  which  closed in October
2000.  On November 7, 2002,  the court issued an opinion on the  parties'  cross
motions for summary  judgment finding in AELLC's favor on certain matters though
granting summary judgment to International Paper Company on the liability aspect
of a particular  claim against AELLC.  On December 11, 2003, the court denied in
part IP's summary judgment motion pertaining to damages and determined that, (i)
IP was entitled to pursue an action for damages,  and (ii) ruled that sufficient
questions of fact remain to deny IP summary  judgment on the measure of damages.
On November 3, 2004, a jury verdict in the amount of $41 million was rendered in
favor of IP. AELLC was held liable on the  misrepresentation  claim,  but not on
the breach of contract claim.  AELLC has made an additional accrual to recognize
the jury verdict,  and the Company has recognized its 32.3% share. AELLC filed a
post-trial  motion  challenging both the  determination of its liability and the
damages award and, on November 16, 2004,  the court entered an order staying the
execution of the judgment.  The order staying  execution of the judgment has not
expired.  On September 30, 2005,  the district  court denied  AELLC's Motion for
Judgment as a Matter of Law, or, in the Alternative,  Remittitur or a New Trial.
AELLC intends to appeal the judgment.

     Additionally,  on November 26, 2004,  AELLC filed a voluntary  petition for
relief  under  Chapter  11 of  the  Bankruptcy  Code.  AELLC  is  continuing  in
possession  of its property and is operating and  maintaining  its business as a
debtor in  possession,  pursuant to Section  1107(a) and 1108 of the  Bankruptcy
Code. AELLC filed its, (i) Plan of Reorganization, and (ii) Disclosure Statement
regarding such plan, on September 30, 2005.

     Finally,  AELLC  filed a Demand for  Arbitration  on July 8, 2005,  seeking
damages from IP regarding  three  separate  ESA billing  disputes.  IP filed its
Answering  Statement and  Counterclaim  on July 29, 2005. The parties are in the
preliminary stages of the AAA arbitration procedures.






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<PAGE>

     Panda Energy International,  Inc., et al. v. Calpine Corporation, et al. On
November 5, 2003, Panda Energy International,  Inc. and certain related parties,
including PLC II, LLC, (collectively "Panda") filed suit against the Company and
certain  of its  affiliates  alleging,  among  other  things,  that the  Company
breached  duties  of care and  loyalty  allegedly  owed to Panda by  failing  to
correctly  construct  and  operate  the Oneta  power  plant,  which the  Company
acquired from Panda,  in accordance with Panda's  original plans.  Panda alleges
that it is  entitled to a portion of the profits of the Oneta plant and that the
Company's  actions  have  reduced the  profits  from Oneta  thereby  undermining
Panda's ability to repay monies owed to the Company on December 1, 2003, under a
promissory note on which  approximately  $38.6 million  (including  interest) is
currently outstanding. The Company has filed a counterclaim against Panda Energy
International,  Inc. (and PLC II, LLC) based on a guaranty, and has also filed a
motion  to  dismiss  as to the  causes  of  action  alleging  federal  and state
securities laws  violations.  The court recently granted the Company's motion to
dismiss  the above  claims,  but allowed  Panda an  opportunity  to replead.  We
consider Panda's lawsuit to be without merit and intend to vigorously defend it.
Discovery is currently in progress. The Company stopped accruing interest income
on the  promissory  note due  December  1, 2003,  as of the due date  because of
Panda's  default on  repayment of the note.  Trial is currently  set for May 22,
2006.

     California  Business & Professions  Code Section 17200 Cases,  of which the
lead case is T&E Pastorino Nursery v. Duke Energy Trading and Marketing, L.L.C.,
et al. This purported class action complaint filed in May 2002 against 20 energy
traders and energy companies,  including CES, alleges that defendants  exercised
market  power and  manipulated  prices in  violation  of  California  Business &
Professions   Code  Section  17200  et  seq.,  and  seeks   injunctive   relief,
restitution,  and  attorneys'  fees.  The  Company was also named in eight other
similar  complaints for violations of Section 17200. The Company  considered the
allegations  to be  without  merit,  and  filed a motion to  dismiss.  The court
granted the motion,  and  plaintiffs  appealed.  The Ninth  Circuit has issued a
decision   affirming  the  dismissal  of  the  Pastorino  group  of  cases.  The
Plaintiff's did not attempt to appeal the Ninth Circuit's  ruling to the Supreme
Court so the matter is resolved.

     Prior to the motion to dismiss being granted, one of the actions, captioned
Millar v.  Allegheny  Energy  Supply  Co.,  LLP, et al.,  was  remanded to state
superior court of Alameda County, California. On January 12, 2004, CES was added
as a defendant in Millar.  This action includes similar allegations to the other
Section 17200 cases,  but also seeks rescission of the long-term power contracts
with the California Department of Water Resources. Millar was removed to federal
court,  but has now been  remanded  back to state  superior  court for handling.
Hearings on multiple demurrers were held on September 7, 2005 at which time, the
Judge  dismissed  the case  without  leave to amend.  Millar did not  attempt to
appeal the dismissal ruling. Thus, the entire case is now resolved.

     Nevada Power Company and Sierra  Pacific  Power  Company v. Calpine  Energy
Services,  L.P. before the FERC,  filed on December 4, 2001,  Nevada Section 206
Complaint.  On December 4, 2001,  NPC and SPPC filed a complaint with FERC under
Section 206 of the Federal  Power Act against a number of parties to their power
sales  agreements,  including  Calpine.  NPC and SPPC allege in their complaint,
that the prices  they  agreed to pay in certain of the power  sales  agreements,
including those signed with Calpine, were negotiated during a time when the spot
power market was dysfunctional  and that they are unjust and  unreasonable.  The
complaint   therefore   sought   modification  of  the  contract   prices.   The
administrative  law judge issued an Initial  Decision on December 19, 2002, that
found for Calpine and the other  respondents in the case and denied NPC and SPPC
the relief that they were seeking.  In a June 26, 2003 order,  FERC affirmed the
judge's findings and dismissed the complaint,  and subsequently denied rehearing
of that order. The matter is pending on appeal before the United States Court of
Appeals for the Ninth  Circuit.  The Company has  participated  in briefing  and
arguments before the Ninth Circuit defending the FERC orders, but the Company is
not able to predict at this time the outcome of the Ninth Circuit appeal.

     Transmission  Service Agreement with Nevada Power Company. On September 30,
2004,  Nevada Power Company ("NPC") filed a complaint in state district court of
Clark County,  Nevada  against  Calpine  Corporation  ("Calpine"),  Moapa Energy
Center,  LLC,  Fireman's Fund  Insurance  Company  ("FFIC") and unnamed  parties
alleging,  among  other  things,  breach by Calpine of its  obligations  under a
Transmission Service Agreement ("TSA") between Calpine and NPC for 400 megawatts
of transmission  capacity and breach by FFIC of its  obligations  under a surety
bond,  which  surety  bond  was  issued  by  FFIC  to NPC to  support  Calpine's
obligations  under the TSA.  This  proceeding  was  removed  from state court to
United States  District Court for the District of Nevada.  On December 10, 2004,
FFIC filed a Motion to Dismiss,  which was granted on May 25, 2005 with  respect
to claims  asserted  by NPC that FFIC had  breached  its  obligations  under the
surety bond by not honoring NPC's demand that the full amount of the surety bond
($33,333,333.00)  be  paid to NPC in  light  of  Calpine's  failure  to  provide
replacement  collateral  upon the  expiration of the surety bond on May 1, 2004.
NPC has filed a Motion to Amend the Complaint  and a Motion for  Reconsideration
of the above dismissal.  The above dismissal is specific to NPC's claims against
FFIC and does not address NPC's specific  claims against Calpine or Moapa Energy
Center, LLC. Discovery is proceeding. At this time, Calpine is unable to predict
the outcome of this proceeding.


                                     - 45 -
<PAGE>

     Calpine Canada Natural Gas Partnership v. Enron Canada Corp. On February 6,
2002,  Calpine  Canada filed a complaint in the Alberta  Court of Queens  Branch
alleging that Enron Canada owed it approximately US$1.5 million from the sale of
gas in  connection  with two Master Firm gas  Purchase and Sale  Agreements.  To
date, Enron Canada has not sought  bankruptcy  relief and has  counterclaimed in
the amount of US$18  million.  We have  finished  discovery and are currently in
settlement discussions. The Company believes that Enron Canada's counterclaim is
without merit and intends to vigorously defend against it.

     Estate of Jones,  et al. v.  Calpine  Corporation.  On June 11,  2003,  the
Estate of  Darrell  Jones and the  Estate of  Cynthia  Jones  filed a  complaint
against Calpine in the United States District Court for the Western  District of
Washington. Calpine purchased Goldendale Energy, Inc., a Washington corporation,
from Mr.  Darrell Jones of NESCO.  The agreement  provided,  among other things,
that upon "Substantial Completion" of the Goldendale facility, Calpine would pay
Mr. Jones (i) $6.0 million and (ii) $18.0  million less $0.2 million per day for
each  day  that  elapsed  between  July 1,  2002,  and the  date of  substantial
completion.  Substantial  completion  of the  Goldendale  facility  occurred  in
September  2004 and the daily  reduction  in the payment  amount has reduced the
$18.0  million  payment to zero.  The  complaint  alleged that by not  achieving
substantial  completion by July 1, 2002,  Calpine breached its contract with Mr.
Jones, violated a duty of good faith and fair dealing, and caused an inequitable
forfeiture.  On July 28, 2003,  Calpine  filed a motion to dismiss the complaint
for failure to state a claim upon which relief can be granted. The court granted
Calpine's motion to dismiss the complaint on March 10, 2004.  Plaintiffs filed a
motion for reconsideration of the decision, which was denied.  Subsequently,  on
June 7, 2004,  plaintiffs  filed a notice of appeal.  Calpine  filed a motion to
recover  attorneys'  fees from NESCO,  which was  recently  granted at a reduced
amount.  Calpine  held back  $100,000  of the $6 million  payment to the estates
(which  has been  remitted)  to ensure  payment  of these  fees.  The  matter is
currently on appeal,  both parties have filed briefs with the  appellate  court,
and oral  arguments  were heard by the court on October 17, 2005. We are waiting
for the court to issue its decision.

     Calpine  Energy  Services v. Acadia Power  Partners.  Calpine  Corporation,
through its subsidiaries,  owns 50% of Acadia Power Partners,  LLC ("APP") which
company owns the Acadia Energy Center near Eunice, Louisiana (the "Facility"). A
Cleco Corporation subsidiary owns the other 50% of the Facility.  Calpine Energy
Services,  LP ("CES") is the purchaser under two power purchase  agreements with
APP  pursuant to which CES has the right to purchase  all of the output from the
Facility.  During the summer of 2003 certain transmission constraints previously
unknown to CES and APP began to severely  limit the ability of CES to obtain all
of the energy from the Facility. CES had asserted that it is entitled to certain
relief from the purchase  agreements,  and that APP had to cure certain defaults
under the purchase agreements, to which assertions APP disagrees. After engaging
in the  initial  alternative  dispute  resolution  steps  set forth in the power
purchase agreements the parties settled their disputes.

     In addition,  CES and APP had been discussing  certain billing  calculation
disputes that relate to efficiency  matters.  The dispute covers the time period
from June 2002 (COD of the  plant) to June 2004.  The  parties  have  completely
resolved this matter.

     Hulsey,  et al. v. Calpine  Corporation.  On September 20, 2004,  Virgil D.
Hulsey,  Jr. (a current  employee)  and Ray Wesley (a former  employee)  filed a
class action wage and hour lawsuit  against  Calpine  Corporation and certain of
its  affiliates.  The complaint  alleges that the  purported  class members were
entitled to overtime pay and Calpine  failed to pay the purported  class members
at legally required overtime rates. The matter has been transferred to the Santa
Clara  County  Superior  Court and  Calpine  filed an answer on January 7, 2005,
denying plaintiffs' claims. This case has tentatively been settled.

     Michael Portis v. Calpine Corp. - Complaint Filed with Department of Labor.
On January 25, 2005,  Michael Portis  ("Portis"),  a former employee of Calpine,
brought a  complaint  to the United  States  Department  of Labor  (the  "DOL"),
alleging that his employment with the Company was wrongfully terminated.  Portis
alleged  that Calpine and its  subsidiaries  evaded sales and use tax in various
states  and in doing so filed  false tax  reports  and that his  employment  was
terminated in retaliation for having  reported these  allegations to management.
Portis claimed that the Company's alleged actions  constitute  violations of the
employee  protection  provisions of the Sarbanes Oxley Act of 2002. On April 27,
2005, the DOL determined  that Portis'  retaliatory  discharge  complaint had no
merit  and  dismissed  it.  On June 13,  2005,  Portis  filed an  objection  and
requested a hearing before an Administrative Law Judge. After an initial hearing
with the ALJ, and a failed attempt to elicit a settlement,  Portis  withdrew the
objection and hearing  request.  On August 12, 2005,  the DOL's initial  finding
(that the complaint had no merit) was reinstated and made final.

     Auburndale Power Partners and Cutrale. Calpine Corporation owns an interest
in the Auburndale PP cogeneration  facility,  which provides steam to Cutrale, a
juice  company.  The  Auburndale PP facility  currently  operates on a "cycling"
basis  whereby the plant  operates  only a portion of the day.  During the hours
that the Auburndale PP facility is not operating, Auburndale PP does not provide
steam to Cutrale.  Cutrale has filed an arbitration claim alleging that they are



                                     - 46 -
<PAGE>

entitled to damages due to Auburndale PP's failure to provide them with steam 24
hours a day.  Auburndale  PP  disagreed  with  Cutrale's  position  based on its
interpretation  of the  contractual  language  in the  Steam  Supply  Agreement.
Binding arbitration was conducted on the contractual  interpretation  issue only
(reserving the  remedy/damage  issue for a second phase to the  arbitration) and
the  arbitrator  found in favor of  Cutrale's  contractual  interpretation.  The
proceeding now turns to the second phase,  the resolution of the issue regarding
the   appropriate   remedy/damage   determination.   To  preserve  our  positive
relationship with Cutrale,  Auburndale PP continues to try to resolve the matter
through a commercial settlement.

     Harbert  Distressed  Investment  Master Fund, Ltd. v. Calpine Canada Energy
Finance II ULC,  et al. On May 5, 2005,  Harbert  Distressed  Investment  Master
Fund, Ltd. (the "Harbert Fund") filed an Originating  Notice  (Application) (the
"Original  Application")  in the Supreme  Court of Nova Scotia  against  Calpine
Corporation  and certain of its  subsidiaries,  including  Calpine Canada Energy
Finance II ULC ("Finance II"), the issuer of certain bonds (the "Bonds") held by
the Harbert  Fund and CCRC,  the parent  company of Finance II and the  indirect
parent  company of  Saltend.  The Bonds have been  guaranteed  by  Calpine.  The
Harbert  Fund  alleged  that  Calpine,  CCRC and Finance II violated the Harbert
Fund's  rights  under Nova  Scotia laws in  connection  with  certain  financing
transactions  completed  by CCRC  or  subsidiaries  of  CCRC.  Wilmington  Trust
Company,  the trustee under the indenture  governing the Bonds (the  "Trustee"),
was a  co-applicant  in the suit on behalf of all holders of Bonds.  The hearing
was conducted on July 6, 7 and 8, 2005 before the Nova Scotia Supreme Court. The
claims as against Calpine European Funding (Jersey) Limited and Calpine (Jersey)
Limited, were discontinued by Consent Order dated July 20, 2005,

     On August 2, 2005, the Court  dismissed the Harbert Fund's  application for
relief and denied all relief to the Harbert Fund and all other  bondholders that
purchased Bonds on or after September 1, 2004. However,  the Court stated that a
remedy should be granted to any  bondholder,  other than the Calpine  respondent
companies, that purchased Bonds prior to September 1, 2004 and that continues to
hold those Bonds on August 2, 2005 (the "Eligible Bondholders").

     The Court  directed  the Trustee to provide  the face amount of  qualifying
Bonds  and the  identity  of the  holders  of such  Bonds  by  August  31,  2005
(subsequently  modified by the Bond Indemnification Order described below). Upon
receipt of such  information,  the Court will then issue a final order requiring
Calpine to maintain in the control of CCRC sufficient  proceeds from the sale of
Saltend  to cover the face  amount  of such  Bonds.  If there  are  insufficient
proceeds for this  purpose,  Calpine will be required to place in the control of
CCRC an additional  amount which,  when added to the net Saltend sale  proceeds,
will cover the face value of all such Bonds.  On September  20, 2005,  the Court
issued a Bond Identification Order confirming a process for determining the list
of Eligible  Bondholders  and further  required the Indenture  Trustee to file a
report of such  determination  on or before  November 18, 2005.  The final order
will further provide that CCRC shall diligently conduct its business in a proper
and  efficient  manner so as to preserve  and protect its  business  and assets.
Pending the final order,  the Court issued an interim  order under which Calpine
must maintain the net Saltend sale proceeds in the control of CCRC.

     Any party to the  proceeding has the right to appeal the final order to the
Nova Scotia Court of Appeal.

     On October 6, 2005, the Trustee and the Harbert Fund issued a demand letter
to Finance II and its directors  demanding that Finance II commence  proceedings
against CCRC to enforce various rights under a Term Debenture due 2021 issued by
CCRC to Finance II. On October 7, 2005,  the Trustee and the Harbert  Fund filed
an Originating Notice  (Application) in the Supreme Court of Nova Scotia against
CCRC and sought leave to commence a derivative  proceeding  on behalf of Finance
II (the "Harbert/WTC  Leave  Application")  seeking to enforce such rights under
the  Term  Debenture.  On  October  11,  2005,  Finance  II and  CCRC  filed  an
Interlocutory  Notice Application  seeking either a dismissal of the Harbert/WTC
Leave  Application or,  alternatively,  a stay of such pending the completion of
the process set out in the Bond Identification  Order, issuance of a final order
in the  Original  Application  and  disposition  of any appeals in the  Original
Application ("Calpine Cross-Application") on the bases of res judicata and abuse
of process,  arguing that the claims and relief sought by the  applicants in the
Harbert/WTC  Leave  Application are the same, or arise out of the same facts and
circumstances,  as the claims and relief that those applicants  sought, and were
denied, in the Original Application.  The Calpine Cross-Application is scheduled
to be heard as a preliminary  application on November 22 and 23, 2005. The final
order in the Original Application,  as well as the Harbert/WTC Leave Application
(if necessary), are scheduled to be heard on December 19 and 20, 2005.

     Harbert  Convertible   Arbitrage  Master  Fund,  Ltd.  et  al.  v.  Calpine
Corporation.  Plaintiff Harbert Convertible  Arbitrage Master Fund, Ltd. and two
affiliated  funds filed this action on July 11, 2005, in Supreme Court, New York
County,  State of New York, and filed an amended  complaint on July 19, 2005. In
their  amended  complaint,  plaintiffs  allege  that in a July 5, 2005 letter to
Calpine they  provided  "reasonable  evidence" as required  under the  indenture
governing the 2014 Convertible Notes that, on one or more days beginning on July
1, 2005,  the Trading Price of the 2014  Convertible  Notes was less than 95% of



                                     - 47 -
<PAGE>

the product of the Common Stock Price  multiplied  by the  Conversion  Rate,  as
those  terms are  defined  in the  indenture,  and that  Calpine  therefore  was
required to instruct the Bid Solicitation  Agent for the 2014 Convertible  Notes
to determine the Trading Price beginning on the next Trading Day. If the Trading
Price as determined by the Bid Solicitation  Agent were below 95% of the product
of the Common Stock Price  multiplied by the  Conversion  Rate for the next five
consecutive   Trading  Days,  then  the  2014  Convertible  Notes  would  become
convertible into cash and common stock for a limited period of time.  Plaintiffs
have asserted a claim for breach of contract, seeking unspecified damages, based
on Calpine's not  instructing the Bid  Solicitation  Agent to begin to calculate
the Trading  Price.  In  addition,  plaintiffs  have sought a  declaration  that
Calpine had a duty,  based on the  statements in the July 5 letter,  to commence
the bid solicitation  process,  and also have sought  injunctive relief to force
Calpine to instruct the Bid Solicitation Agent to determine the Trading Price of
the Notes.  Plaintiffs  made,  but later  withdrew,  a request for a preliminary
injunction.  Calpine's  motion to  dismiss  was  served on  September  6,  2005,
opposition  and  reply  papers  were  subsequently  served,  and the  Court  has
scheduled  argument  on the motion for  November 9, 2005.  Harbert has  informed
Calpine  and the court that  Wilmington  Trust  Company,  as  trustee  under the
indenture for the 2014  Convertible  Notes,  intends to seek to intervene in the
case and/or to file a similar  action for the benefit of all holders of the 2014
Convertible Notes.

     Whitebox  Convertible  Arbitrage Fund, L.P., et al. v. Calpine Corporation.
Plaintiff Whitebox  Convertible  Arbitrage Fund, L.P. and seven affiliated funds
filed an action in the Supreme  Court,  New York County,  State of New York, for
breach of contract on October 17, 2004. The factual  allegations and legal basis
for the claims set forth in that action are nearly  identical to those set forth
in the  Harbert  Convertible  filings  detailed  above.  On  October  19,  2005,
plaintiffs filed a motion for preliminary  injunctive  relief,  but withdrew the
motion on November 7, 2005.  Whitebox  has  informed  Calpine and the court that
Wilmington  Trust  Company,   as  trustee  under  the  indenture  for  the  2014
Convertible  Notes,  intends to seek to  intervene  in the case and/or to file a
similar action for the benefit of all holders of the 2014 Convertible Notes.

     SEC Informal Inquiry and Request for Documents and Information.  On June 9,
2005,  the Company  filed a Current  Report on Form 8-K with the SEC to disclose
that, in April 2005, the Division of Enforcement of the SEC informed the Company
that it was conducting an informal  inquiry and asked the Company to voluntarily
provide  documents  and  information  related  to:  (a) the  Company's  downward
revision  of its  proved  oil and gas  reserve  estimates  at  year-end  2004 as
compared to such estimates at year-end 2003, and a  corresponding  impairment of
the value of certain  assets,  all  previously  disclosed  by the  Company,  (b)
certain  statements made to various  regulatory  agencies by Michael  Portis,  a
terminated former employee, regarding the Company's determination of state sales
and use taxes,  and (c) the Company's  upward  restatement  in April 2005 of its
previously  disclosed  net income  for the third  quarter,  and the first  three
quarters,  of 2004.  The Company  fully  cooperated  with the SEC's  request for
documents and information.

     Calpine Corporation v. The Bank of New York,  Collateral Trustee for Senior
Secured Note  Holders,  et al. In September of 2005,  Calpine  received a letter
from The Bank of New York, the Collateral Trustee (the "Collateral Trustee") for
Calpine's  senior  secured  debt  holders,  informing  Calpine of  disagreements
purportedly  raised by certain  holders of First  Priority  Notes  regarding the
Company's  reinvestment  of the  proceeds  from its recent  sale of natural  gas
assets  to  Rosetta.  As a result  of these  concerns,  the  Collateral  Trustee
informed the Company that it would not allow  further  withdrawals  from the gas
sale proceeds account until these  disagreements are resolved.  On September 26,
2005,  Calpine  filed a  Declaratory  Relief  Action  in the  Delaware  Court of
Chancery against the Collateral Trustee and Wilmington Trust Company, as trustee
for  the  First  Priority  Notes  (the  "First  Priority  Trustee"),  seeking  a
declaration that Calpine's past and proposed purchases of natural gas assets are
permitted by the indenture for the First Priority  Notes and related  documents,
and also seeking an  injunction  compelling  the  Collateral  Trustee to release
funds requested to be withdrawn.  The First Priority Trustee has counterclaimed,
seeking an order compelling the Company to, among other things,  (i) pay damages
in an amount not less than $365 million plus prejudgment  interest either to the
First Priority Trustee or into the gas sale proceeds account; (ii) return to the
gas sale proceeds account all amounts previously withdrawn from such account and
used by the Company to purchase natural gas in storage;  and (iii) indemnify the
First Priority  Trustee for all expenses  incurred in connection  with defending
the  lawsuit  and  pursuing  counterclaims.  The  Company  has filed a motion to
dismiss the  counterclaims on the grounds that the holders of the First Priority
Notes  (and the First  Priority  Trustee  on behalf of the  holders of the First
Priority  Notes) have no right under the indenture  governing the First Priority
Notes to compel the return of such  amounts or otherwise to object to the use of
the  proceeds of the gas sale  because the Company made an offer to purchase all
of the First Priority Notes with the proceeds of the gas sale and the holders of
the First  Priority  Notes declined such offer.  In addition,  Wilmington  Trust
Company,  as  trustee  for the  Second  Priority  Notes  (the  "Second  Priority
Trustee"),  has  intervened  in the  lawsuit.  The Second  Priority  Trustee has





                                     - 48 -
<PAGE>

counterclaimed  seeking to compel the Company to return to the gas sale proceeds
account all amounts  previously  withdrawn  therefrom and used by the Company to
purchase gas in storage.  In its trial brief,  the Company plans to request that
these  counterclaims  be  dismissed  on the bases that they were filed after the
deadline and without the Court's permission.

     Discovery in this lawsuit commenced on a fast track and is near completion.
Pre-trial  submissions were filed with the Court on November 7, 2005 and a bench
trial is scheduled to begin on November 11, 2005.  The Company  expects that the
trial  will be  completed  in one day and that the Court  will  issue an opinion
shortly  thereafter.  The Company  maintains that its use of the proceeds of the
natural  gas  sale to  purchase  natural  gas in  storage  was  appropriate  and
permitted under the instruments governing its senior secured debt, including the
indenture  governing  the First  Priority  Notes  and the  Senior  Secured  Debt
Instruments, however, no assurance can be given that the Company will prevail in
this litigation.

     Scott,  et al. v.  Calpine  Corporation.  On September  13,  2005,  Calpine
received a letter  from an  attorney  representing  one  current  and six former
employees  located in the Houston,  Texas office.  The letter  alleges claims of
racial  discrimination,  retaliation,  slander,  a hostile work  environment and
constructive discharge.  The seven individuals have also filed Notices of Charge
of Discrimination with the U.S. Equal Employment Opportunity Commission. Outside
counsel has been retained and has  investigated  the claims in  anticipation  of
threatened  litigation.  We consider these claims to be without merit and intend
to defend vigorously against the allegations.

     In  addition,  the Company is involved  in various  other  claims and legal
actions  arising out of the normal course of its business.  The Company does not
expect that the outcome of these proceedings will have a material adverse effect
on its financial position or results of operations.

13.  Operating Segments

     The  Company is first and  foremost  an  electric  generating  company.  In
pursuing this  business  strategy,  it was the Company's  objective to produce a
portion of its fuel consumption  requirements  from its own natural gas reserves
("equity gas").  However, with the July 2005 sale of the Company's remaining oil
and gas  production and marketing  activity,  the Company now has one reportable
segment,  Electric Generation and Marketing. No other components of the business
had reached the  quantitative  criteria to be  considered a  reportable  segment
under SFAS No. 131. See Note 8 for a discussion of the sale of the Company's oil
and gas assets.  Consequently,  the  revenue  and  expense  from the Oil and Gas
Production  and  Marketing   reportable   segment  has  been   reclassified   to
discontinued operations and the remaining pipeline assets have been reflected in
the table below within Corporate, Eliminations, and Other.

     Electric  Generation and Marketing  includes the development,  acquisition,
ownership  and operation of power  production  facilities,  hedging,  balancing,
optimization,  and trading activity  transacted on behalf of the Company's power
generation  facilities.  Corporate and other activities necessary to support the
Electric  Generation  and  Marketing  reporting  segment  consists  primarily of
financing   transactions,   activities  of  the  Company's  parts  and  services
businesses, and general and administrative costs.
<TABLE>
<CAPTION>
                                                              Electric Generation   Corporate, Eliminations,
                                                                 and Marketing              and Other                  Total
                                                           ------------------------ ------------------------ -----------------------
                                                               2005         2004        2005        2004         2005        2004
                                                           ------------ ----------- ----------- ------------ ----------- -----------
                                                                                         (In thousands)
<S>                                                        <C>          <C>         <C>         <C>          <C>         <C>
For the three months ended September 30,
  Total revenue from external customers..................  $3,255,141   $2,396,483  $   26,449  $   15,250   $3,281,590  $2,411,733
  Segment profit/(loss) before provision for
   income taxes..........................................    (154,256)     (15,426)    (70,692)     23,979     (224,948)      8,553


                                                              Electric Generation   Corporate, Eliminations,
                                                                 and Marketing              and Other                  Total
                                                           ------------------------ ------------------------ -----------------------
                                                               2005         2004        2005        2004         2005        2004
                                                           ------------ ----------- ----------- ------------ ----------- -----------
                                                                                         (In thousands)
For the nine months ended September 30,
  Total revenue from external customers..................  $7,451,404   $6,414,619  $   74,824  $   51,713   $7,526,228  $6,466,332
  Segment profit/(loss) before provision
   for income taxes......................................    (758,894)    (244,918)    (30,448)     93,889)    (789,342)   (338,807)
</TABLE>







                                     - 49 -
<PAGE>

<TABLE>
<CAPTION>
                                                                            Electric
                                                                           Generation    Corporate, Eliminations,
                                                                          and Marketing         and Other             Total
                                                                         --------------  ------------------------  ----------------
                                                                                             (In thousands)
<S>                                                                      <C>                 <C>                     <C>
Total assets:
  September 30, 2005..................................................   $   25,381,709      $    1,706,528          $   27,088,237
  December 31, 2004...................................................   $   25,187,414      $    2,028,674          $   27,216,088
</TABLE>


14.  California Power Market

     California  Refund  Proceeding/June  19 FERC Order.  On August 2, 2000, the
California  Refund  Proceeding  was initiated by a complaint made at FERC by San
Diego Gas & Electric  Company and under  Section  206 of the  Federal  Power Act
alleging,  among  other  things,  that the markets  operated  by the  California
Independent   System  Operator  ("CAISO")  and  the  California  Power  Exchange
("CalPX") were dysfunctional. In addition to commencing an inquiry regarding the
market structure, FERC established a refund effective period of October 2, 2000,
to June 19, 2001, for sales made into those markets.

     On December 12, 2002, the  Administrative  Law Judge issued a Certification
of Proposed Finding on California Refund Liability ("December 12 Certification")
making an initial  determination  of refund  liability.  On March 26, 2003, FERC
also  issued  an order  adopting  many of the  ALJ's  findings  set forth in the
December 12 Certification  (the "March 26 Order").  In addition,  as a result of
certain findings by the FERC staff concerning the  unreliability or misreporting
of  certain  reported  indices  for gas prices in  California  during the refund
period,  FERC ordered that the basis for calculating a party's  potential refund
liability be modified by substituting a gas proxy price based upon gas prices in
the producing areas plus the tariff  transportation  rate for the California gas
price indices previously adopted in the refund proceeding. The Company believes,
based on the  available  information,  that  any  refund  liability  that may be
attributable to it could total  approximately  $10.1 million (plus interest,  if
applicable),  after taking the appropriate set-offs for outstanding  receivables
owed by CalPX and CAISO to Calpine.  The Company has fully  reserved  the amount
referenced above. The final  determination of the refund liability is subject to
further   Commission   proceedings   to  ascertain  the  allocation  of  payment
obligations  among the numerous  buyers and sellers in the  California  markets.
Furthermore,  it is possible that there will be further  proceedings  to require
refunds  from certain  sellers for periods  prior to the  originally  designated
Refund Period. In addition,  the FERC orders  concerning the Refund Period,  the
method for calculating refund liability and numerous other issues are pending on
appeal before the U.S. Court of Appeals for the Ninth Circuit. At this time, the
Company is unable to predict the timing of the  completion of these  proceedings
or the final refund  liability.  The final  outcome of this  proceeding  and the
impact on the Company's business is uncertain at this time.

     On April 26, 2004,  Dynegy Inc. entered into a settlement of the California
Refund  Proceeding and other proceedings with California  governmental  entities
and the three California  investor-owned  utilities. The California governmental
entities  include  the  Attorney   General,   the  California  Public  Utilities
Commission,  the  California  Department of Water  Resources  ("CDWR"),  and the
California  Electricity  Oversight Board.  Also, on April 27, 2004, The Williams
Companies,  Inc. ("Williams") entered into a settlement of the California Refund
Proceeding  and  other  proceedings  with the  three  California  investor-owned
utilities;  previously,  Williams  had  entered  into a  settlement  of the same
matters with the California  governmental entities. The Williams settlement with
the California  governmental entities was similar to the settlement that Calpine
entered into with the Governor of the State of  California,  acting on behalf of
the executive  branch of the State of  California,  the  California  Electricity
Oversight  Board,  the  California  Public  Utilities   Commission   (California
Commission),  and the  People  of the State of  California  by and  through  the
Attorney  General (the "AG")  (collectively,  the  "California  State  Releasing
Parties") on April 22, 2002. Calpine's settlement resulted in an order issued on
March 26, 2004,  which partially  dismissed  Calpine from the California  Refund
Proceeding  to the extent that any refunds are owed for power sold by Calpine to
CDWR or any of the other California State Releasing Parties. On June 30, 2004, a
settlement  conference  was  convened at the FERC to explore  settlements  among
additional  parties.  On December 7, 2004,  FERC approved the  settlement of the
California Refund Proceeding and other proceedings among Duke Energy Corporation
and its  affiliates,  the three  California  investor-owned  utilities,  and the
California governmental entities.

     On September 9, 2004,  the Ninth Circuit Court of Appeals issued a decision
on appeal  (State of  California,  Ex. Rel. Bill  Lockyer,  Attorney  General v.
Federal  Energy  Regulatory  Commission)  of a  Petition  for Review of an order
issued by FERC in FERC Docket No.  EL02-71  wherein the AG had filed a complaint
(the "AG  Complaint")  under  Sections 205 and 206 of the Federal Power Act (the
"FPA")  alleging that parties who  misreported or did not properly report market
based  transactions were in violation of their market based rate tariff and as a
result  were  not  accorded  protection  under  section  206  of  the  FPA  from

                                     - 50 -
<PAGE>

retroactive  refund liability.  The Ninth Circuit remanded the order to FERC for
rehearing.  FERC is required to determine whether refunds should be required for
violation of reporting  requirements prior to October 2, 2000. The proceeding on
remand has not yet been established. In connection with its settlement agreement
with various State of California  entities  (including the AG),  Calpine and its
affiliates settled all claims related to the AG Complaint.

     FERC  Investigation  into the Western  Markets.  On February 13, 2002, FERC
initiated an investigation of potential manipulation of electric and natural gas
prices in the western  United  States.  This  investigation  was  initiated as a
result of  allegations  that Enron and others,  through their  affiliates,  used
their market  position to distort  electric and natural gas markets in the West.
The  scope of the  investigation  is to  consider  whether,  as a result  of any
manipulation  in the short-term  markets for electric  energy or natural gas, or
other undue  influence on the  wholesale  markets by any party since  January 1,
2000, the rates of the long-term contracts subsequently entered into in the West
are  potentially  unjust and  unreasonable.  On August 13, 2002,  the FERC staff
issued the Initial Report on Company-Specific  Separate  Proceedings and Generic
Reevaluations;  Published  Natural Gas Price Data; and Enron Trading  Strategies
(the "Initial Report")  summarizing its initial findings in this  investigation.
There were no findings or  allegations of wrongdoing by the Company set forth or
described  in the Initial  Report.  On March 26,  2003,  the FERC staff issued a
final  report  in this  investigation  (the  "Final  Report").  The  FERC  staff
recommended  that  FERC  issue a show  cause  order  to a number  of  companies,
including  Calpine,  regarding  certain  power  scheduling  practices  that  may
potentially be in violation of the CAISO or CalPX tariffs.  The Company believes
that it did not  violate  these  tariffs  and that,  to the  extent  that such a
finding could be made, any potential liability would not be material.  The Final
Report also  recommended  that FERC modify the basis for  determining  potential
liability in the California Refund Proceeding discussed above. On June 25, 2003,
FERC  issued a  number  of  orders  associated  with  these  investigations.  In
particular,  based on the FERC  staff's  earlier  recommendations  in the  Final
Report,  FERC  issued  two  show  cause  orders  each  naming  certain  industry
participants. The show cause orders have initiated proceedings wherein the named
parties must demonstrate that certain market behavior did not violate either the
CAISO or CalPX tariffs as prohibited market manipulative behavior.  FERC did not
subject  the  Company to either of the show cause  orders.  FERC also  issued an
order   directing  the  FERC  staff  to  investigate   further   whether  market
participants  who bid a price in excess of $250 per  megawatt  hour into markets
operated may have violated  CAISO and CalPX tariff  prohibitions.  No individual
market participant was identified.  The Company believes that it did not violate
the CAISO and  CalPX  tariff  prohibitions  referred  to by FERC in this  order;
however,  we are  unable  to  predict  at this time the  final  outcome  of this
proceeding or its impact on Calpine.

     CPUC  Proceeding  Regarding  QF  Contract  Pricing  for Past  Periods.  Our
Qualifying  Facilities  ("QF")  contracts with Pacific Gas and Electric  Company
("PG&E")  provide that the CPUC has the authority to determine  the  appropriate
utility  "avoided  cost"  to be used  to set  energy  payments  for  certain  QF
contracts  by  determining  the short run avoided  cost  ("SRAC")  energy  price
formula.  In mid 2000, our QF facilities elected the option set forth in Section
390 of the California  Public  Utilities  Code,  which provided QFs the right to
elect to receive energy  payments based on the California  Power Exchange ("PX")
market  clearing price instead of the price  determined by SRAC.  Having elected
such option, we were paid based upon the PX zonal day-ahead  clearing price ("PX
Price") from summer 2000 until January 19, 2001, when the PX ceased  operating a
day-ahead market. The CPUC has conducted proceedings  (R.99-11-022) to determine
whether the PX Price was the  appropriate  price for the energy  component  upon
which to base payments to QFs which had elected the PX-based pricing option.  In
late 2000,  the CPUC  Commissioner  assigned  to this  matter  issued a proposed
decision  to the effect that the PX Price was the  appropriate  price for energy
payments  under the  California  Public  Utilities  Code but the CPUC has yet to
issue a final  decision.  Therefore,  it is possible that the CPUC could order a
retroactive payment adjustment based on a different energy price  determination.
On April 29, 2004 PG&E, The Utility Reform Network, which is a consumer advocacy
group, and the Office of Ratepayer  Advocates,  which is an independent consumer
advocacy  department of the CPUC,  (collectively,  the "PG&E  Parties")  filed a
Motion for Briefing Schedule  Regarding True-Up of Payments to QF Switchers (the
"April 29 Motion").  The April 29 Motion  requested that the CPUC set a briefing
schedule in the R.99-11-022  docket to determine refund liability of the QFs who
had switched to the PX Price during the period of June 1, 2000 until January 19,
2001.  The PG&E Parties  alleged that refund  liability be determined  using the
methodology that has been developed thus far in the California Refund Proceeding
discussed  above. On August 16, 2005, the  Administrative  Law Judge assigned to
hear the April 29 Motion issued a ruling  setting  October 11, 2005, as the date
for filing prehearing conference statements and October 17, 2005, as the date of
the prehearing conference.  In our response, filed on October 11, 2005, we urged
that the April 29 Motion should be dismissed, but if dismissal were not granted,
then  discovery,   testimony  and  hearings  would  be  required.  The  assigned
Administrative  Law  Judge  has not yet  issued a formal  ruling  following  the
October 17, 2005  prehearing  conference.  We believe  that the PX Price was the
appropriate  price  for  energy  payments  and that  the  basis  for any  refund
liability  based on the  interim  determination  by the  FERC in the  California
Refund Proceeding is unfounded,  but there can be no assurance that this will be
the outcome of the CPUC proceedings.


                                     - 51 -
<PAGE>

     Reliability  Must Run Contracts  with Geysers.  The CAISO,  the  California
Electricity  Oversight Board, the CPUC, PG&E, San Diego Gas & Electric  Company,
and  Southern  California  Edison  (collectively  referred  to  as  the  "Buyers
Coalition")  filed a complaint  on November 2, 2001 at the FERC  requesting  the
commencement  of a Federal  Power Act Section 206  proceeding  to challenge  one
component of a number of separate  settlements  previously  reached on the terms
and  conditions of  "reliability  must run"  contracts  ("RMR  Contracts")  with
certain  generation  owners,  including  Geysers,  which  settlements  were also
previously approved by the FERC. RMR Contracts require the owner of the specific
generation unit to provide energy and ancillary  services when called upon to do
so by the  CAISO to meet  local  transmission  reliability  needs  or to  manage
transmission  constraints.  The  Buyers  Coalition  asked  FERC to find that the
availability  payments  under these RMR Contracts  are not just and  reasonable.
Geysers filed an answer to the complaint in November 2001. On June 3, 2005, FERC
issued an order dismissing the Buyers  Coalition's  complaint  against all named
generation owners,  including  Geysers.  On August 2, 2005, FERC issued an order
rejecting  requests for rehearing of its order.  The proceeding is now concluded
at FERC. On September 23, 2005, the Buyers  Coalition (with the exclusion of the
CAISO) filed a Petition  for Review with the United  States Court of Appeals for
the District of Columbia Circuit,  seeking review of FERC's order dismissing the
complaint.

15.  Subsequent Events

     On October 6, 2005,  the  Company  completed  the sale of its  561-megawatt
Ontelaunee  Energy  Center to LS Power Equity  Partners for $225  million,  less
transaction fees, costs and working capital  adjustments of approximately  $13.0
million.  The  Ontelaunee  sale is the third of four  planned  power plant sales
announced by the Company in June 2005.  Net proceeds from the sale of Ontelaunee
will be used in accordance with the Company's indentures. Upon its commitment to
a plan of  divesture  of  Ontelaunee  and in  accordance  with SFAS No. 144, the
Company  recorded an  impairment  charge of $136.8  million in the three  months
ended  September 30, 2005. The sale of Ontelaunee  closed October 6, 2005.  This
impairment  charge is reflected in  discontinued  operations in the three months
ended September 30, 2005. See Note 5 for more information.

     In  connection  with  the sale of  Ontelaunee  and in  accordance  with the
instruments  governing its indebtedness,  on October 6, 2005, CCFC LLC commenced
offers to purchase its outstanding  secured term loans and notes in an amount up
to the net proceeds  received from the  Ontelaunee  sale.  The offer to purchase
term loans expired on October 28, 2005,  and the offer to purchase notes expired
on November 4, 2005,  without any term loans or notes  having been  tendered for
purchase.

     On October 14, 2005, the Company's  indirect  subsidiary,  CCFC LLC, issued
$300.0 million of 6-Year Redeemable  Preferred Shares Due 2011 at LIBOR plus 950
basis points. Net proceeds from the offering of the Redeemable  Preferred Shares
will be used as permitted by Calpine's existing bond indentures.

     On October 14, 2005,  CCFC LLC  repurchased  its $150.0  million in Class A
Redeemable Preferred Shares due February 13, 2006.

     Repurchased  $93.3 million of 8 1/2% Senior Notes due 2008 in October 2005,
in open market  transactions  for cash  totaling  $55.7  million,  plus  accrued
interest.

Item 2. Management's Discussion and Analysis ("MD&A") of Financial Condition and
     Results of Operations.

     In addition to historical information, this report contains forward-looking
statements  within the meaning of Section 27A of the  Securities Act of 1933, as
amended,  and Section 21E of the Securities Exchange Act of 1934, as amended. We
use words such as "believe,"  "intend," "expect,"  "anticipate,"  "plan," "may,"
"will" and similar  expressions  to identify  forward-looking  statements.  Such
statements  include,  among  others,  those  concerning  our expected  financial
performance  and strategic and operational  plans,  as well as all  assumptions,
expectations,  predictions,  intentions or beliefs about future events.  You are
cautioned that any such forward-looking  statements are not guarantees of future
performance  and that a number of risks and  uncertainties  could  cause  actual
results to differ  materially  from  those  anticipated  in the  forward-looking
statements.  Such risks and uncertainties  include,  but are not limited to, (i)
the  timing  and  extent of  deregulation  of energy  markets  and the rules and
regulations  adopted on a  transitional  basis with  respect  thereto,  (ii) the
timing  and  extent of changes in  commodity  prices  for  energy,  particularly
natural gas and electricity, and the impact of related derivatives transactions,
(iii)  unscheduled  outages  of  operating  plants,  (iv)  unseasonable  weather
patterns that reduce demand for power, (v) economic slowdowns that can adversely
affect   consumption  of  power  by  businesses  and  consumers,   (vi)  various
development  and  construction  risks  that  may  delay  or  prevent  commercial
operations  of new plants,  such as failure to obtain the  necessary  permits to
operate,  failure  of  third-party  contractors  to  perform  their  contractual
obligations or failure to obtain project  financing on acceptable  terms,  (vii)
uncertainties  associated with cost  estimates,  that actual costs may be higher
than estimated, (viii) development of lower-cost power plants or of a lower cost



                                     - 52 -
<PAGE>

means of  operating  a fleet of power  plants  by our  competitors,  (ix)  risks
associated  with  marketing  and selling power from power plants in the evolving
energy  market,  (x) factors  that  impact the  exploitation  of our  geothermal
resource,  (xi) uncertainties  associated with estimates of geothermal reserves,
(xii) the  effects on our  business  resulting  from  reduced  liquidity  in the
trading and power generation industry,  (xiii) our ability to access the capital
markets  on  attractive  terms or at all,  (xiv)  our  ability  to  successfully
implement  the  various  components  of our  strategic  initiative  to  increase
liquidity, reduce debt and reduce operating costs, (xv) uncertainties associated
with estimates of sources and uses of cash, that actual sources may be lower and
actual uses may be higher than estimated,  (xvi)  implementation of our strategy
to expand our third party  service  businesses  and  diversify  our fuel source,
(xvii)  the direct or  indirect  effects on our  business  of a lowering  of our
credit  rating (or actions we may take in response  to  changing  credit  rating
criteria),  including increased collateral requirements,  refusal by our current
or potential counterparties to enter into transactions with us and our inability
to obtain credit or capital in desired  amounts or on favorable  terms,  (xviii)
present and possible future claims,  litigation and enforcement  actions,  (xix)
effects of the application of regulations,  including  changes in regulations or
the interpretation  thereof, and (xx) other risks identified in this report. You
should also carefully  review the risks  described in other reports that we file
with the Securities and Exchange  Commission,  including without  limitation our
Annual Report on Form 10-K for the year ended December 31, 2004, and our Current
Report  on  Form  8-K  filed  with  the SEC on July 1,  2005.  We  undertake  no
obligation to update any forward-looking statements,  whether as a result of new
information, future developments or otherwise.

     We file annual,  quarterly and periodic reports, proxy statements and other
information  with the SEC. You may obtain and copy any document we file with the
SEC  at the  SEC's  public  reference  room  at 100 F  Street,  NE,  Room  1580,
Washington, D.C. 20549. You may obtain information on the operation of the SEC's
public  reference  facilities  by  calling  the SEC at  1-800-SEC-0330.  You can
request copies of these documents, upon payment of a duplicating fee, by writing
to the SEC at its principal office at 100 F Street,  NE, Room 1580,  Washington,
D.C.  20549-1004.  The SEC maintains an Internet  website at  http://www.sec.gov
that contains reports, proxy and information  statements,  and other information
regarding  issuers  that file  electronically  with the SEC. Our SEC filings are
accessible through the Internet at that website.

     Our reports on Forms 10-K,  10-Q and 8-K, and  amendments to those reports,
are available for download,  free of charge,  as soon as reasonably  practicable
after these  reports are filed with the SEC, at our website at  www.calpine.com.
The content of our website is not a part of this report.  You may request a copy
of our SEC filings,  at no cost to you, by writing or telephoning us at: Calpine
Corporation, 50 West San Fernando Street, San Jose, California 95113, attention:
Lisa M. Bodensteiner, Assistant Secretary, telephone: (408) 995-5115.

     We will not  send  exhibits  to the  documents,  unless  the  exhibits  are
specifically requested and you pay our fee for duplication and delivery.

Selected Operating Information

     Set forth below is certain  selected  operating  information  for our power
plants  for  which  results  are  consolidated  in  our  Consolidated  Condensed
Statements  of  Operations.  Electricity  revenue is composed of fixed  capacity
payments,  which are not related to production,  and variable  energy  payments,
which are related to production.  Capacity revenues include, besides traditional
capacity  payments,  other revenues such as  Reliability  Must Run and Ancillary
Service  revenues.  The  information  set forth under  thermal and other revenue
consists of host steam sales and other thermal revenue.
<TABLE>
<CAPTION>
                                                                       Three Months Ended                  Nine Months Ended
                                                                          September 30,                      September 30,
                                                               ---------------------------------------------------------------------
                                                                      2005             2004             2005              2004
                                                               ---------------  ---------------   ---------------   ----------------
                                                                                 (In thousands, except pricing data)
<S>                                                            <C>              <C>               <C>               <C>
Power Plants:
E&S revenues:
  Energy.....................................................  $     1,634,372  $     1,133,557   $     3,430,720   $     2,814,915
  Capacity...................................................          317,754          312,649           840,020           763,234
  Thermal and other..........................................          144,197           98,123           354,338           273,765
                                                               ---------------  ---------------   ---------------   ---------------
  Subtotal...................................................  $     2,096,323  $     1,544,329   $     4,625,078   $     3,851,914
Spread on sales of purchased power (1).......................           69,503           79,355           233,427           135,912
                                                               ---------------  ---------------   ---------------   ---------------
Adjusted E&S revenues before mark-to-market
  activities, net (non-GAAP).................................  $     2,165,826  $     1,623,684   $     4,858,505   $     3,987,826
MWh produced.................................................           28,709           26,604            68,240            64,357
All-in electricity price per MWh generated before
  mark-to-market activities, net.............................  $         75.44  $         61.03   $         71.20   $         61.96
----------

                               (table continues)

                                     - 53 -
<PAGE>

<FN>
(1)  From  hedging,   balancing  and  optimization  activities  related  to  our
     generating assets.
</FN>
</TABLE>

     Set forth below is a table  summarizing  the dollar amounts and percentages
of our total revenue for the three and nine months ended  September 30, 2005 and
2004,  that  represent  purchased  power and purchased gas sales for hedging and
optimization  and the costs we incurred  to  purchase  the power and gas that we
resold during these periods (in thousands, except percentage data):
<TABLE>
<CAPTION>
                                                                       Three Months Ended                  Nine Months Ended
                                                                          September 30,                      September 30,
                                                               ---------------------------------------------------------------------
                                                                      2005             2004             2005              2004
                                                               ---------------  ---------------   ---------------   ----------------
<S>                                                            <C>              <C>               <C>               <C>
Total revenue...............................................   $     3,281,590  $     2,411,733   $     7,526,228   $     6,466,332
Sales of purchased power for hedging and optimization (1)...           413,281          427,737         1,193,537         1,301,585
As a percentage of total revenue............................            12.6%            17.7%             15.9%             20.1%
Sale of purchased gas for hedging and optimization..........           696,850          423,733         1,574,067         1,258,441
As a percentage of total revenue............................            21.2%            17.6%             20.9%             19.5%
Total COR...................................................         3,042,463        2,185,288         7,124,903         6,157,841
Purchased power expense for hedging and optimization (1)....           343,778          348,380           960,110         1,165,674
As a percentage of total COR................................            11.3%            15.9%             13.5%             18.9%
Purchased gas expense for hedging and optimization..........           724,351          429,373         1,623,692         1,243,781
As a percentage of total COR................................            23.8%            19.6%             22.8%             20.2%
------------
<FN>
(1)  On October 1, 2003, we adopted on a prospective  basis EITF Issue No. 03-11
     "Reporting  Realized  Gains and Losses on Derivative  Instruments  That Are
     Subject to FASB  Statement  No. 133 and Not `Held for Trading  Purposes' As
     Defined  in EITF  Issue  No.  02-3:  "Issues  Involved  in  Accounting  for
     Derivative  Contracts Held for Trading  Purposes and Contracts  Involved in
     Energy Trading and Risk Management Activities" and netted certain purchases
     of power  against  sales of  purchased  power.  See Note 2 of the  Notes to
     Consolidated  Condensed  Financial  Statements  for  a  discussion  of  our
     application of EITF Issue No. 03-11.
</FN>
</TABLE>

     The primary reasons for the significant  levels of these sales and costs of
revenue  items  include:  (a)  significant  levels  of  hedging,  balancing  and
optimization  activities by our CES risk management  organization;  (b) volatile
markets for  electricity  and natural gas, which prompt us to frequently  adjust
our hedge  positions  by  buying  power and gas and  reselling  it;  and (c) the
accounting  requirements  under SAB No. 101,  "Revenue  Recognition in Financial
Statements," and EITF Issue No. 99-19,  "Reporting  Revenue Gross as a Principal
versus Net as an Agent," under which we show many of our hedging  contracts on a
gross basis (as opposed to netting sales and cost of revenue).

Overview

     Our core  business  and  primary  source of revenue is the  generation  and
delivery of electric  power in North  America.  We provide power to our U.S. and
Canadian   customers  through  the  integrated   development,   construction  or
acquisition,  and operation of efficient and  environmentally  friendly electric
power plants fueled  primarily by natural gas and, to a much lesser  degree,  by
geothermal  resources.  We protect  and  enhance  the value of our assets with a
sophisticated risk management organization. We also protect our power generation
assets and control  certain of our costs by producing  certain of the combustion
turbine  replacement  parts  that we use at our power  plants,  and we  generate
revenue by providing  combustion  turbine parts to third  parties.  Finally,  we
offer  services to third parties to capture value in the skills we have honed in
building, commissioning, repairing and operating power plants.

     While we have been able to access the capital and bank credit markets since
2002, it has been on  significantly  different  terms than before 2002. This has
been due to a range of factors,  including uncertainty arising from the collapse
of Enron and a surplus supply of electric  generating capacity in certain of our
market areas.  These factors  coupled with an extended period of decreased spark
spreads (the differential  between power revenues and fuel costs) have adversely
impacted our capacity utilization rates,  liquidity and earnings.  Additionally,
natural gas prices have been volatile and, on average,  have  increased over the
last several  years.  The impact of rising  natural gas prices on the Company is
discussed  below. We recognize that the terms of capital  available to us in the
future may not be attractive or our access to the capital  markets may otherwise
be restricted.  To protect  against this  possibility  and due to current market
conditions,  during  the past  several  years we have  scaled  back our  capital
expenditure program and have taken other steps to enhance our liquidity,  reduce
our  debt  and   otherwise   conserve  our  capital   resources.   See  "Capital
Availability" in Liquidity and Capital Resources below for a further discussion.



                                     - 54 -
<PAGE>

     As part of our efforts to improve our  financial  strength,  we announced a
strategic initiative in May 2005 aimed at:

     o    Optimizing the value of our core North American power plant  portfolio
          by selling  certain  power and  natural  gas assets to reduce debt and
          lower  annual  interest  cost,  and to  increase  cash  flow in future
          periods.  At September 30, 2005, we had completed the sales of Saltend
          in the United  Kingdom,  Morris in Illinois  and our interest in Grays
          Ferry in Pennsylvania. Additionally, in October 2005, we completed the
          sale  of  Ontelaunee   and  in  July  2005,   completed  the  sale  of
          substantially  all of our remaining oil and natural gas assets. We are
          in discussions with potential buyers for, or are considering, the sale
          of additional  assets. See Notes 8 and 15 of the Notes to Consolidated
          Condensed  Financial  Statements  for  further  information  on  these
          transactions.  There  can be no  assurance  that the  Company  will be
          successful in developing  such  alternative  or additional  sources of
          fuel in the near term or otherwise.

     o    Taking  actions  to  decrease  operating  and  maintenance  costs  and
          lowering fuel costs to improve the operating  performance of our power
          plants,  which  would  boost  operating  cash flow and  liquidity.  In
          addition,  to further reduce cost, we have  temporarily  shut down two
          power plants with  negative  cash flow,  and are  considering  others,
          until market conditions  warrant starting back up. See also Note 12 of
          the  Notes  to  Consolidated  Condensed  Financial  Statements  for  a
          discussion of the restructuring of certain of our LTSAs.

     o    Reducing  collateral  requirements.  On September 8, 2005, we and Bear
          Stearns  announced  an agreement  to form a new energy  marketing  and
          trading venture to develop a third party customer  business focused on
          physical  natural  gas  and  power  trading  and  related   structured
          transactions.  Regulatory approval for this new entity was received on
          October 31, 2005, and it is anticipated  that operations will begin in
          the  fourth  quarter  of 2005.  The  transaction  will  include a $350
          million  credit  intermediation   agreement  between  CalBear,  a  new
          subsidiary  of Bear  Stearns,  and CES.  It is  anticipated  that this
          credit intermediation  agreement will, among other things,  positively
          impact our working  capital  position by making possible the return of
          cash and LCs currently posted as collateral.

     o    Reducing total debt, net of new construction financings,  by more than
          $3 billion from debt levels at year-end 2004,  which we estimate would
          provide  $275  million of annual  interest  savings.  We  continue  to
          advance our May 2005  strategic  initiative  aimed at  optimizing  our
          power plant  portfolio,  reducing  debt and  enhancing  our  financial
          strength.  While  we  continue  to make  progress  toward  our goal of
          reducing  total  debt by more than $3  billion  by  year-end  2005 and
          achieving an estimated $275 million of annual  interest  savings,  the
          timing of  accomplishing  this goal may be delayed into 2006. The cash
          and other consideration needed to reduce debt by that amount will be a
          function of the timing of asset sales,  our ability to use proceeds of
          such  sales to  reduce  debt (we are  currently  involved  in  various
          litigations  with the  holders  of certain  series of our  outstanding
          secured and  unsecured  bonds as  described in Note 12 of the Notes to
          Consolidated Condensed Financial  Statements),  the prices at which we
          are able to repurchase debt and other factors.  At September 30, 2005,
          total consolidated debt was $17.2 billion, a reduction of $0.9 billion
          from the $18.1 billion  level at March 31, 2005,  before the strategic
          initiative  was  announced.  Excluding the effect of new  construction
          financing of $178.7  million,  we have  reduced debt by  approximately
          $1.1 billion during this period. However, regardless of whether or not
          the  specific  $3  billion  debt  reduction  goal can be  achieved  by
          December 31, 2005, we remain  committed to achieving that goal as soon
          as practicable.

     In addition,  as noted above, we seek to identify  opportunities to capture
value in the skills and knowledge  that we have  developed,  not only to improve
the operating  performance  of our facilities but also to develop new sources of
revenues  by, for  example,  utilizing  our hedging and  optimization  skills to
develop the CalBear business and by expanding our third-party combustion turbine
component  parts and retail and  maintenance  services  businesses.  We are also
actively exploring possible  alternative sources of natural gas (such as LNG and
Alaskan pipeline projects) to increase the natural gas supply in the continental
United  States,  as well as  other  sources  of fuel for our  natural  gas-fired
generation  facilities,  such as projects to convert pet coke,  an oil  refinery
waste product,  into gas suitable for combustion in our gas turbines.  There can
be no assurance  that we will be successful in developing  such  alternative  or
additional sources of fuel in the near term or otherwise.

     Other key opportunities and challenges for us include:

     o    preserving  and  enhancing  our  liquidity  while  spark  spreads  are
          depressed,




                                     - 55 -
<PAGE>

     o    selectively  adding new  load-serving  entities and power users to our
          customer list as we increase our power contract portfolio,

     o    continuing  to  add  value  through   prudent  risk   management   and
          optimization activities, and

     o    managing our exposure to volatile natural gas prices.

     The price of natural gas has been  volatile over the last several years and
has, on average,  increased. We are one of the largest gas consumers (if not the
largest) in the United States, and therefore,  we carefully evaluate and seek to
optimally  manage our gas position.  In markets where gas-fired power generation
is "on the margin"  (based on the  profile of  available  capacity,  incremental
electricity  generation is likely to be produced by natural gas plants), and the
Company has open  generation  capacity for sale,  higher natural gas prices can,
and  do,  produce  higher  spark  spreads  for  us  when  dispatched  due to our
efficient,  low heat rate fleet of generation  plants. In other situations,  the
impact of higher gas prices on us is neutral (or potentially positive),  such as
in cases where we have  entered  into  tolling  arrangements  or heat rate index
contracts with customers.  In tolling arrangements,  the customer is responsible
for buying and delivering  natural gas to one of our generating  plants,  and we
receive  a  tolling   payment  to  convert  the  customer's   natural  gas  into
electricity.  In heat rate index  contracts,  the price for energy  produced  is
priced by  multiplying a contractual  heat rate times the market fuel price over
the contract  term. To the extent that the contract heat rate is higher than our
actual  generation heat rate, we would,  and do, realize  improved spark spreads
from higher natural gas prices.  However, in situations where we have sold fixed
price power and do not maintain a 100% hedged gas position,  higher  natural gas
prices  can,  and do,  reduce  our  spark  spread  to the  extent  of any  short
fixed-price  gas position.  In the third quarter of 2005,  following the sale of
our remaining oil and gas assets in early July 2005,  we were  thereafter  short
fixed-price  gas and could  remain in a short  position  for some period of time
until the position can be rebalanced.

     In addition,  by eliminating the equity gas benefit that we had enjoyed due
to the fact that our costs of  producing  natural gas were  significantly  lower
than natural gas prices in recent years  through the sale of our  remaining  oil
and gas  assets to Rosetta in July  2005,  we expect an  increase  in the future
effective  fuel  expense  (and lower spark  spread)  for our fleet of  gas-fired
generating plants. Also, we expect that purchasing additional volumes from third
party producers will increase our  requirements to post collateral or prepay for
gas.  However,  the negative impacts on spark spread and gross profit (loss) are
expected to be offset to some extent by lower interest  expense in the future to
the extent the  proceeds of the sale are able to be used to repay debt.  We also
expect to use other hedging  approaches in managing our natural gas requirements
to  compensate  for the loss of the natural  hedge  position that equity gas had
afforded  us. In the past,  when we sold  fixed  price  power,  we could use our
equity gas reserves as a hedge against rising gas prices.  Other techniques have
included  purchase of  fixed-for-floating  gas price swap contracts,  purchasing
physical gas on a  fixed-price  basis,  or  potentially  buying back fixed price
power  contracts.  In the  future  we  will  be  more  reliant  on  these  other
techniques,  the use of which may be limited by our current credit  constraints.
From a  physical  gas  purchase  perspective,  we will be  purchasing  Rosetta's
California  production  at  market  prices  under  industry  standard  margining
provisions.  We estimate that our  collateral  requirements  at the date of sale
increased by approximately $25 million for a typical payment cycle. From a fixed
price gas exposure perspective, we will not have any fixed price hedges in place
with Rosetta,  so our position will need to be managed with financial  swaps and
fixed price physical gas purchases. In addition, we may use proceeds of the sale
to purchase natural gas assets as permitted by our indentures.

     Overview of Results -- In the third quarter of 2005,  generation volume was
up 7.9%  from the  prior  year due  primarily  to four  new  facilities  and one
expansion  project coming online in the twelve months ended  September 30, 2005.
Also, spark spread  increased by approximately 6% in the same period.  Even with
the new  capacity,  our average  baseload  capacity  factor for the three months
ended  September 30, 2005, was 54.0% compared to 55.4% in the prior year period.
Demand was  stronger in  virtually  all of the  Company's  key  markets,  except
Northern  California  due to below normal  temperatures  in September  2005, and
market  on-peak spark  spreads  improved  significantly  in the third quarter of
2005. However,  off-peak market spark spreads did not show similar improvements.
Also,  we estimate  that our spark spread margin was reduced in the quarter as a
result of being in a short  fixed-price  gas position  following the sale of our
remaining oil and gas assets in July 2005. We may be  susceptible  to diminished
spark  spreads when  natural gas prices rise until we are ablt to rebalance  our
fixed-price  gas position.  Further,  in the 12 months ended September 30, 2005,
average  natural gas prices  (with Henry Hub  delivery)  increased  by 147% from
$4.99 per million BTU to $12.35 per million BTU.  While this current price spike
is largely  attributable to the damage caused by hurricane's Katrina and Rita in
August and September 2005, natural gas prices  historically had a winter peak in
demand due to home heating usage;  however,  partly as a result of increased use
as a fuel  for  electric  power  generation,  demand  is  less  seasonal  and is
developing a summer peak in addition to the winter peak.




                                     - 56 -
<PAGE>

     Set forth below are the Results of Operations for the three and nine months
ended  September  30,  2005  and  2004,  which  reflect   reclassifications  for
discontinued  operations.  See  Note 8 of the  Notes to  Consolidated  Condensed
Financial Statements.

Results of Operations

     Three  Months  Ended  September  30,  2005,  Compared to Three Months Ended
September 30, 2004

     (In  millions  unless   indicated   otherwise,   except  for  unit  pricing
information,  percentages  and MW volumes).  In the  comparative  tables  below,
increases in  revenue/income or decreases in expense  (favorable  variances) are
shown  without  brackets.  Decreases in  revenue/income  or increases in expense
(unfavorable variances) are shown with brackets.

     Revenue
<TABLE>
<CAPTION>
                                                                                  Three Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                 <C>
Total revenue..............................................................  $    3,281.6  $    2,411.7  $      869.9        36.1%
</TABLE>

     The change in total revenue is explained by category below.
<TABLE>
<CAPTION>
                                                                                  Three Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                <C>
Electricity and steam revenue..............................................  $    2,096.3  $    1,544.3  $      552.0        35.7%
Transmission sales revenue.................................................           1.9           4.4          (2.5)      (56.8)%
Sales of purchased power for hedging and optimization......................         413.3         427.7         (14.4)       (3.4)%
                                                                             ------------  ------------  ------------
   Total electric generation and marketing revenue.........................  $    2,511.5  $    1,976.4  $      535.1        27.1%
                                                                             ============  ============  ============
</TABLE>

     Electricity  and steam revenue  increased as we completed the  construction
and brought into operation  four  additional  baseload power  facilities and one
expansion project  subsequent to September 30, 2004, and realized an increase in
our  average  electric  price  before the  effects  of  hedging,  balancing  and
optimization,  from $58.05/MWh for the three months ended September 30, 2004, to
$73.02/MWh for the same period in 2005.  Average total megawatts in operation of
our  consolidated  plants  increased by 7.8% to 26,126 MW, which was  consistent
with  our  increase  in total  generation  of 7.9%.  However,  average  baseload
megawatts  in operation  increased by 8.8%  compared to an increase of only 6.1%
for baseload generation. The increase in generation,  resulting in a drop in our
baseload  capacity  factor dropped to 54.0% in the three months ended  September
30,  2005,  from 55.4% in the three months ended  September  30, 2004.  This was
primarily due to the increased occurrence of unattractive  off-peak market spark
spreads in certain areas reflecting  oversupply conditions which are expected to
gradually  improve over the next several years, but which caused us to cycle-off
certain of our merchant plants without contracts in off-peak hours.

     We purchase transmission capacity so that power can move from our plants to
our customers.  Transmission capacity can be purchased on a long term basis and,
in many of the markets in which the company operates, can be resold if we do not
need it and some other  party can use it. If the  generation  from our plants is
less than we anticipated when we purchased the transmission capacity, we can and
do realize revenue by selling the unused portion of the transmission capacity.

     We also, in many cases,  bill our customers for transmission  costs that we
incur in serving their accounts.  This is especially true in the case of many of
our retail  contracts.  When we bill our  customers  for  transmission  expenses
incurred  on  their  behalf  we  recognize  these  billings  as a  component  of
transmission  revenue. For the three months ended September 30, 2005 as compared
to the same period in 2004 transmission revenues have declined as we have seen a
reduction in transmission billings relating our retail customers.

     Sales of  purchased  power for hedging and  optimization  decreased  in the
three months ended September 30, 2005, due primarily to lower volumes which were
partially offset by higher prices, as compared to the same period in 2004.







                                     - 57 -
<PAGE>

<TABLE>
<CAPTION>
                                                                                  Three Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>               <C>
Oil and gas sales..........................................................  $        --   $        2.7  $       (2.7)     (100.0)%
Sales of purchased gas for hedging and optimization........................         696.9         423.7         273.2        64.5%
                                                                             ------------  ------------  ------------
   Total oil and gas production and marketing revenue......................  $      696.9  $      426.4  $      270.5        63.4%
                                                                             ============  ============  ============
</TABLE>

     We reclassified  our remaining oil and gas  operations,  which were sold in
July 2005, to  discontinued  operations in the quarter ended June 30, 2005, upon
our commitment to a plan of divesture of the component.  Activity in prior years
relates to minor  assets sold in prior years that did not meet the  criteria for
reclassification  to discontinued  operations at the time of sale. See Note 8 of
the Notes to Consolidated Condensed Financial Statements for more information.

     Sales of purchased gas for hedging and  optimization  increased during 2005
due  primarily  to higher  liquidation  prices  of  natural  gas and a  moderate
increase in volumes compared to the same period in 2004.
<TABLE>
<CAPTION>
                                                                                  Three Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                <C>
Mark-to-market activities, net.............................................  $       40.9  $       (5.2) $       46.1       886.5%
</TABLE>

     Mark-to-market  activities,  which are shown on a net  basis,  result  from
general market price movements against our open commodity derivative  positions,
These  commodity  positions  represent a small portion of our overall  commodity
contract position.

     The net gain  from  mark-to-market  activities  in the three  months  ended
September  30, 2005,  as compared to the same period in 2004 is due primarily to
gains on our Deer Park transaction which are recorded on a mark-to-market basis,
and gains  attributable to gas contracts that lost hedge accounting  eligibility
for the quarter.  In order to qualify for hedge  accounting  under SFAS No. 133,
price movements in the hedge contract and the hedged  transaction must move in a
manner  whereby  changes in value of the hedge  contract and hedged  transaction
sufficiently  offset. As a result of significant  volatility in the gas markets,
certain of our gas  contracts  did not meet these  requirements  and we recorded
approximately  $18.3 million in  mark-to-market  gains that would have otherwise
been recorded through other comprehensive income.
<TABLE>
<CAPTION>
                                                                                  Three Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                <C>
Other revenue..............................................................  $       32.4  $       14.0  $       18.4       131.4%
</TABLE>

     Other revenue  increased due primarily to higher revenues at PSM associated
with sales of gas  turbine  components  and at TTS for gas  turbine  maintenance
services and the sale of spare turbine parts and components.

     Cost of Revenue
<TABLE>
<CAPTION>
                                                                                  Three Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                <C>
Cost of revenue............................................................  $    3,042.5  $    2,185.3  $     (857.2)      (39.2)%
</TABLE>









                                     - 58 -
<PAGE>

     The increase in total cost of revenue is explained by category below.
<TABLE>
<CAPTION>
                                                                                  Three Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                <C>
Plant operating expense....................................................  $      180.3  $      160.0  $      (20.3)      (12.7)%
Transmission purchase expense..............................................          23.1          22.7          (0.4)       (1.8)%
Royalty expense............................................................          10.0           8.3          (1.7)      (20.5)%
Purchased power expense for hedging and optimization.......................         343.8         348.4           4.6         1.3%
                                                                             ------------  ------------  ------------
   Total electric generation and marketing expense.........................  $      557.2  $      539.4  $      (17.8)       (3.3)%
                                                                             ============  ============  ============
</TABLE>

     Plant operating expense increased primarily due to four additional baseload
power facilities and one expansion project in operation  subsequent to September
30, 2004, which was partially offset by lower major maintenance  spending versus
prior year, largely due to the timing of such work.

     In many cases,  we incur  transmission  costs that result from  serving the
accounts of our  customers.  This is especially  true in the case of many of our
retail contracts. When we incur transmission expenses on behalf of our customers
we recognize these amounts as a component of transmission  purchase expense. For
the three months ended September 30, 2005 as compared to the same period in 2004
transmission  purchase  expenses  have  declined as we have seen a reduction  in
transmission purchases relating to our retail customers.

     Royalty expense increased primarily due to an increase in electric revenues
at The Geysers  geothermal  plants and an increase in contingent  purchase price
payments to the previous  owners of our Texas City and Clear Lake power  plants.
At The  Geysers,  royalties  are  paid  mostly  as a  percentage  of  geothermal
electricity revenues and royalties associated with Texas City and Clear Lake are
based on a percentage of gross revenues earned at the plants.

     Purchased power expense for hedging and  optimization  decreased during the
three months ended  September  30, 2005,  as compared to the same period in 2004
due  primarily to a reduction in volumes  which wer  partially  offset by higher
prices, as compared to the same period in 2004.
<TABLE>
<CAPTION>
                                                                                  Three Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                <C>
Oil and gas operating expense..............................................  $        1.4  $        1.8  $        0.4        22.2%
Purchased gas expense for hedging and optimization.........................         724.3         429.4        (294.9)      (68.7)%
                                                                             ------------  ------------  ------------
   Total oil and gas operating and marketing expense.......................  $      725.7  $      431.2  $     (294.5)      (68.3)%
                                                                             ============  ============  ============
</TABLE>

     The  Company   reclassified   its  remaining  oil  and  gas  operations  to
discontinued  operations  ("held for sale") in the three  months  ended June 30,
2005.  Remaining  activity in  continuing  operations  relates  primarily to gas
pipeline  activities  which  were not  sold and  activity  in prior  years  also
includes  the results of minor  assets sold in prior years that did not meet the
criteria for  reclassification  to discontinued  operations at the time of sale.
See Note 8 of the Notes to Consolidated  Condensed Financial Statements for more
information.

     Purchased  gas expense for hedging and  optimization  increased  during the
three months ended  September  30,  2005,  due to higher  natural gas prices and
higher volumes as compared to the same period in 2004.
<TABLE>
<CAPTION>
                                                                                  Three Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                <C>
Fuel expense...............................................................  $    1,567.5  $    1,052.3  $     (515.2)      (49.0)%
</TABLE>

     Fuel expense increased during the three months ended September 30, 2005, as
compared to the same period in 2004 due  primarily to higher  natural gas prices
and an  increase  of 7.9% in  generation  due  largely to the  addition  of four
baseload  power  facilities  and  one  expansion  project  to  our  consolidated



                                     - 59 -
<PAGE>

operating  portfolio  subsequent to September 30, 2004. Our average fuel expense
before the effects of hedging,  balancing and optimization increased by 41% from
$5.88/MMBtu for the three months ended September 30, 2004 to $8.28/MMBtu for the
same period in 2005.
<TABLE>
<CAPTION>
                                                                                  Three Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                <C>
Depreciation, depletion and amortization expense...........................  $      131.0  $      117.4  $      (13.6)      (11.6)%
</TABLE>

     Depreciation, depletion and amortization expense increased primarily due to
the  additional  power  facilities  in  consolidated  operations  subsequent  to
September 30, 2004.
<TABLE>
<CAPTION>
                                                                                  Three Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                <C>
Operating lease expense....................................................  $       28.8  $       25.8  $       (3.0)      (11.6)%
</TABLE>

     Operating lease expense  increased from the prior year due to an additional
non-cash adjustment, which was necessary due to a revision in our estimated cost
to dismantle our Watsonville facility at the end of the lease term in 2010.
<TABLE>
<CAPTION>
                                                                                  Three Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                <C>
Other cost of revenue......................................................  $       32.2  $       19.2  $      (13.0)      (67.7)%
</TABLE>

     Other cost of revenue increased during the three months ended September 30,
2005,  as  compared  to the same period in 2004,  due to  increased  gas turbine
maintenance services activity and spare turbine parts and component sales at TTS
and increased gas turbine component sales by PSM.

(Income)/Expenses
<TABLE>
<CAPTION>
                                                                                  Three Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                <C>
(Income) loss from unconsolidated investments..............................  $       (5.4) $       11.2  $       16.6       148.2%
</TABLE>

     The increase in income was  primarily due to an increase in income from the
Acadia PP investment (due mostly to lower major  maintenance costs and decreased
LTSA  costs),  and the  non-recurrence  of  losses  recorded  in 2004  from  our
investment  in the AELLC power plant.  We ceased to  recognize  our share of the
operating  results of AELLC as we began to account for our  investment  in AELLC
using the cost method  following loss of effective  control when AELLC filed for
bankruptcy  protection in November 2004. In September 2004 prior to AELLC filing
for  bankruptcy  protection,  we  recognized  our share of an adverse jury award
related to a dispute with IP. Our share of that expense was $11.6.
<TABLE>
<CAPTION>
                                                                                  Three Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                 <C>
Equipment cancellation and impairment cost.................................  $        0.8  $        7.8  $        7.0        89.7%
</TABLE>

     During the three months ended  September 30, 2005,  equipment  cancellation
and asset impairment  charge decreased by $7.0 as compared to the same period in
2004 primarily as a result of two  non-recurring  charges we incurred during the
third  quarter of 2004.  During the three months ended  September  30, 2004,  we



                                     - 60 -
<PAGE>

incurred a loss of $4.3 recognized in connection with the impairment  charge for
one HRSG and a loss on the sale of 12 tube bundles in the amount of $3.5.
<TABLE>
<CAPTION>
                                                                                  Three Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                 <C>
Long-term service agreement cancellation charge............................  $        0.6  $        4.0  $        3.4        85.0%
</TABLE>

     During the three months ended  September 30, 2004,  we recorded  charges of
$7.6  related to the  cancellation  and  settlement  of four LTSAs with  Siemens
Westinghouse. During the three months ended September 30, 2005, we retroactively
reclassified  $3.6  of  these  charges  to  discontinued  operations  due to our
commitment to a plan to divest the Ontelaunee Energy Center.
<TABLE>
<CAPTION>
                                                                                  Three Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>               <C>
Project development expense................................................  $       10.1  $        3.4  $       (6.7)     (197.1)%
</TABLE>

     Project development expense increased by $6.7 during the three months ended
September  30,  2005,  compared to the same period in 2004  primarily  due to an
increase  of  $6.3  in  site  preservation   costs  related  to  projects  whose
development/construction has been suspended.
<TABLE>
<CAPTION>
                                                                                  Three Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                 <C>
Research and development expense...........................................  $        3.3  $        4.0  $        0.7        17.5%
</TABLE>

     Research and development  expense  decreased  during the three months ended
September 30, 2005, as compared to the same period in 2004  primarily due to the
timing of  personnel  expenses and  consulting  fees related to new research and
development programs and testing at PSM.
<TABLE>
<CAPTION>
                                                                                  Three Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                 <C>
Sales, general and administrative expense..................................  $       54.6  $       53.8  $       (0.8)       (1.5)%
</TABLE>

     Sales, general and administrative expense increased during the three months
ended September 30, 2005, primarily due to an increase in information technology
and employee  compensation  costs offset by  decreases  in  consulting  fees and
facilities costs.
<TABLE>
<CAPTION>
                                                                                  Three Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                <C>
Interest expense...........................................................  $      381.0  $      285.4  $      (95.6)      (33.5)%
</TABLE>

     Interest expense increased primarily as a result of higher average interest
rates and lower  capitalization of interest  expense.  Our average interest rate
increased  from 8.4% for the three months ended  September 30, 2004, to 9.4% for
the three months ended September 30, 2005, primarily due to the impact of rising
U.S.  interest  rates  and  their  effect  on our  existing  variable  rate debt
portfolio and higher average  interest  rates  incurred on new debt  instruments
that were entered into to replace  and/or  refinance  existing debt  instruments
during  2005.  Interest  capitalized  decreased  from $86.7 for the three months
ended  September  30, 2004,  to $36.0 for the three months ended  September  30,
2005, as new plants entered commercial operations (at which point capitalization
of interest expense ceases) and because of suspended  capitalization of interest
on three  partially  completed  construction  projects.  During the three months
ended  September  30, 2005,  (i) interest  expense  related to our Senior Notes,
contingent  convertible  notes,  and term loans increased by $7.4; (ii) interest
expense related to our CalGen subsidiary increased $11.4; (iii) interest expense
related to our construction/project  financing increased by $17.3; (iv) interest
expense  related to our CCFC I subsidiary  increased  by $3.8;  and (v) interest
expense related to preferred  interests  increased by $12.2 primarily due to the
June 2005 closing of the $15.5  offering of redeemable  preferred  securities by
our indirect  subsidiary,  Metcalf, the August 2005 closing of the $150 offering



                                     - 61 -
<PAGE>

of redeemable  preferred  securities by our indirect  subsidiary,  CCFC LLC, the
October 2004 closing of the $360 offering of redeemable  preferred securities by
our indirect subsidiary,  Calpine Jersey I, and the $260 offering on January 31,
2005, of redeemable  preferred  securities by our indirect  subsidiary,  Calpine
Jersey  II  (the  Calpine  Jersey  I  and  Calpine  Jersey  II  securities  were
repurchased with proceeds from the sale of Saltend in July 2005). These interest
cost increases are partially  offset by a decrease of $15.6 in interest  expense
on the convertible  debentures payable to the Calpine Capital Trusts, which have
been redeemed.
<TABLE>
<CAPTION>
                                                                                  Three Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                 <C>
Interest (income)..........................................................  $      (26.6) $      (17.0) $        9.6        56.5%
</TABLE>

     Interest  (income)  increased  during the three months ended  September 30,
2005, due primarily to higher  interest earned on margin deposits and collateral
posted to secure letters of credit and due to higher interest rates.
<TABLE>
<CAPTION>
                                                                                  Three Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                <C>
Minority interest expense..................................................  $       11.0  $       10.0  $       (1.0)      (10.0)%
</TABLE>

     Minority interest expense increased during the three months ended September
30, 2005, as compared to the same period in 2004 primarily due to an increase in
income at CPLP,  which is 70% owned by CPIF.  The  variance is largely due to an
increase in steam  revenue at the Island  Cogen plant which was driven by higher
gas prices; the price of gas is a component of the steam revenue calculation.
<TABLE>
<CAPTION>
                                                                                  Three Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                <C>
(Income) from repurchase of debt...........................................  $      (15.5) $     (167.2) $     (151.7)      (90.7)%
</TABLE>

     The  decrease  in income  from  repurchase  of debt is due to  considerably
higher  volumes  of Senior  Notes  repurchased  during  the three  months  ended
September 30, 2004, compared to the same period in 2005. See Note 7 of the Notes
to Consolidated Condensed Financial Statements for further information.
<TABLE>
<CAPTION>
                                                                                  Three Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>               <C>
Other expense (income), net................................................  $       50.3  $       22.4  $      (27.9)     (124.6)%
</TABLE>

     Other  expense  increased  for the three months ended  September  30, 2005,
compared  to the same  period  in 2004,  primarily  due to a $31.5  increase  in
non-cash  foreign  currency   transaction  losses.  See  the  "foreign  currency
transaction gain (loss)"  discussion within "Financial Market Risks" for further
information.







                                     - 62 -
<PAGE>

<TABLE>
<CAPTION>
                                                                                  Three Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                <C>
Provision (benefit) for income taxes.......................................  $       17.5  $      (20.3) $      (37.8)     (186.2)%
</TABLE>

     During  the three  months  ended  September  30,  2005,  our tax  provision
increased  by $37.8  as  compared  to the  benefit  in the  three  months  ended
September 30, 2004,  despite the fact that our pre-tax loss increased  $233.5 in
2005. The effective tax rate increased to (7.8)% in 2005 compared to (237.6)% in
the same period in 2004 largely due to a valuation allowance recorded on certain
deferred  tax assets  associated  with CCFC which had the effect of reducing the
tax  benefit  on our  pre-tax  loss by  approximately  $143.4.  The tax rates on
continuing  operations for the three months ended  September 30, 2004, have been
restated to reflect the  reclassification to discontinued  operations of certain
tax expense related to the sale of oil and gas reserves, Saltend, and the Morris
and Ontelaunee power plants.  See Note 8 of the Notes to Consolidated  Condensed
Financial Statements for further information.
<TABLE>
<CAPTION>
                                                                                  Three Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                <C>
Discontinued operations, net of tax provision..............................  $       25.7  $      112.2  $      (86.5)      (77.1)%
</TABLE>

     During the three months ended September 30, 2005,  discontinued  operations
activity primarily consisted of the pre-tax gain on the sale of Saltend of $26.3
and the pre-tax gain on the sale of  substantially  all of our remaining oil and
gas assets of $342.8;  both dispositions  closed in July 2005.  Offsetting these
gains is a pre-tax  impairment  charge of $136.8  related to the pending sale of
Ontelaunee,  which met the discontinued operations criterion as of September 30,
2005  under  SFAS  No.  144.  On  a  pre-tax  basis,  we  recorded  income  from
discontinued operations for the three months ended September 30, 2005 of $196.3.
Our effective  tax rate on  discontinued  operations  for the three months ended
September 30, 2005, however,  was 86.9% due primarily to a large tax return gain
on  the  sale  of  Saltend  and,  as a  consequence,  our  after-tax  gain  from
discontinued  operations was only $25.7.  Discontinued  operations for the three
months ended September 30, 2004,  consisted primarily of a pre-tax gain from the
sale of our Canadian and U.S. Rocky Mountain oil and gas assets of $203.5.  On a
net of tax basis, income from discontinued operations for the three months ended
September 30, 2004, was $112.2, based on an effective tax rate of 47.7%.
<TABLE>
<CAPTION>
                                                                                  Three Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>               <C>
Net income (loss)..........................................................  $     (216.7) $      141.1  $     (357.8)     (253.6)%
</TABLE>

     For the three months ended September 30, 2005, we reported  revenue of $3.3
billion, representing an increase of 36% over the same period in the prior year.
Including the  discontinued  operations  discussed below, we recorded a net loss
per share of $0.45, or a net loss of $216.7, compared to net income per share of
$0.32, or net income of $141.1, for the same quarter in the prior year.

     For the three months ended  September  30,  2005,  our average  capacity in
operation for consolidated  projects in continuing  operations increased by 7.8%
to 26,126  megawatts.  Generation  volume  was up 7.9% from the prior year as we
generated approximately 28.7 million megawatt-hours, which equated to a baseload
capacity  factor of 54.0%,  and  realized an average  spark spread of $20.74 per
megawatt-hour.   For  the  same  period  in  2004,  we  generated  26.6  million
megawatt-hours,  which  equated  to a  baseload  capacity  factor of 55.4%,  and
realized an average spark spread of $21.15 per megawatt-hour.

     Gross  profit  increased  by $12.7 to  $239.1  in the  three  months  ended
September 30, 2005, compared to the same period in the prior year as total spark
spread margin  increased by $32.7  period-to-period.  We estimate that our spark
spread  margin  was  reduced  in the  quarter  as a  result  of being in a short
fixed-price  gas  position  following  the sale of our oil and gas  assets.  Our
overall short  fixed-price gas position makes us susceptible to diminished spark
spreads  when  natural  gas  prices  rise and will  continue  to do so until our




                                     - 63 -
<PAGE>

position is rebalanced.  Total spark spread margin did not increase in line with
the increases in plant operating  expense,  depreciation,  other cost of revenue
items and interest expense.

     During the three months ended  September 30, 2005,  financial  results were
positively  impacted by $15.5 of income  recorded from  repurchase of debt,  but
this was lower by $151.6 than the gain recorded  from  repurchase of debt in the
comparable  period  in 2004.  Costs to cancel  equipment  orders  and  long-term
service  agreements  totaled $1.3 in 2005,  compared to $11.8 in the prior year,
and income from unconsolidated  investments was also favorable,  by $16.6 versus
the prior year,  primarily  because we recorded  $11.6 of loss in the comparable
period of 2004 associated with an unfavorable jury award at AELLC.  However,  in
the third quarter of 2005, we recorded $6.7 higher project  development  expense
compared to the prior year due mostly to higher  preservation costs at suspended
projects,  and interest expense increased by $95.6 between periods primarily due
to lower  capitalization  of interest  expense,  as fewer  plants were in active
construction, and due to an increase in the average interest rate.

     Other  expense of $50.3 for the three months ended  September  30, 2005 was
unfavorable  by $27.9,  compared to other  expense of $22.4 for the three months
ended  September  30,  2004 due to an  increase  of $31.5  in  non-cash  foreign
currency transaction losses.

     In the three  months  ended  September  30, 2005 we recorded a pre-tax gain
from  discontinued  operations  of $196.3.  However,  our  effective tax rate on
discontinued  operations  was 86.9% due  primarily to a large tax return gain on
the sale of Saltend and, as a consequence,  our after-tax gain from discontinued
operations was only $25.7. Income from discontinued operations included gains on
the sale of our  remaining oil and gas assets and Saltend , both of which closed
in July 2005, and an impairment  charge  associated with  Ontelaunee,  which was
classified  as held for sale at September  30, 2005 and closed in October  2005.
Discontinued operations also includes the operating results until the respective
sales dates for those entities and the Morris power plant, for which we recorded
an  impairment  charge in the  second  quarter of 2005 and which was sold in the
third  quarter of 2005.  For the three  months  ended  September  30,  2004,  we
recorded a net after-tax gain of $112.2 million in discontinued  operations from
the sales of our Canadian and U. S. Rocky Mountain oil and gas assets.

Nine Months Ended  September 30, 2005,  Compared to Nine Months Ended  September
30, 2004

     (In  millions  unless   indicated   otherwise,   except  for  unit  pricing
information,  percentages  and MW volumes).  In the  comparative  tables  below,
increases in  revenue/income or decreases in expense  (favorable  variances) are
shown  without  brackets.  Decreases in  revenue/income  or increases in expense
(unfavorable variances) are shown with brackets.

Revenue
<TABLE>
<CAPTION>
                                                                                   Nine Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                 <C>
Total revenue..............................................................  $    7,526.2  $    6,466.3  $    1,059.9        16.4%
</TABLE>

     The change in total revenue is explained by category below.
<TABLE>
<CAPTION>
                                                                                   Nine Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                <C>
Electricity and steam revenue..............................................  $    4,625.1  $    3,851.9  $      773.2        20.1%
Transmission sales revenue.................................................           8.8          14.2          (5.4)      (38.0)%
Sales of purchased power for hedging and optimization......................       1,193.5       1,301.6        (108.1)       (8.3)%
                                                                             ------------  ------------  ------------
   Total electric generation and marketing revenue.........................  $    5,827.4  $    5,167.7  $      659.7        12.8%
                                                                             ============  ============  ============
</TABLE>

     Electricity and steam revenue  increased as we completed  construction  and
brought into operation four new baseload power plants and one expansion  project
completed  subsequent  to September  30,  2004,  and realized an increase in our
average   electric   price  before  the  effects  of  hedging,   balancing   and
optimization, from $ 59.85/ MWh for the nine months ended September 30, 2004, to
$ 67.78/ MWh for the same period in 2005.  Average megawatts in operation of our
consolidated  plants increased by 13.2% to 25,079 MW while generation  increased
by 6.0%,  resulting  in a drop in our baseload  capacity  factor to 45.9% in the



                                     - 64 -
<PAGE>

nine months  ended  September  30,  2005,  from 50.1% in the nine  months  ended
September  30, 2004.  This was  primarily  due to the  increased  occurrence  of
unattractive   off-peak  market  spark  spreads  in  certain  areas   reflecting
oversupply  conditions  which are  expected to  gradually  improve over the next
several years,  but which caused us to cycle-off  certain of our merchant plants
without contracts in off-peak hours.

     We purchase transmission capacity so that power can move from our plants to
our customers.  Transmission capacity can be purchased on a long term basis and,
in many of the  markets  in which  the  company  operates,  can be resold if the
Company does not need it and some other party can use it. If the generation from
our  plants is less  than we  anticipated  when we  purchased  the  transmission
capacity,  we  can  realize  revenue  by  selling  the  unused  portion  of  the
transmission capacity.

     Sales of purchased power for hedging and optimization decreased in the nine
months ended  September  30, 2005,  due  primarily to lower  volumes  which were
partially offset by higher prices, as compared to the same period in 2004.
<TABLE>
<CAPTION>
                                                                                   Nine Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                <C>
Oil and gas sales..........................................................  $        --    $        4.7  $       (4.7)     (100.0)%
Sales of purchased gas for hedging and optimization........................       1,574.1       1,258.4         315.7        25.1%
                                                                             ------------  ------------  ------------
   Total oil and gas production and marketing revenue......................  $    1,574.1  $    1,263.1  $      311.0        24.6%
                                                                             ============  ============  ============
</TABLE>

     We reclassified  our remaining oil and gas  operations,  which were sold in
July 2005, to  discontinued  operations  in the nine months ended  September 30,
2005.  Activity in prior years  relates to minor assets sold in prior years that
did not meet the criteria for reclassification to discontinued operations at the
time of  sale.  See  Note 8 of the  Notes to  Consolidated  Condensed  Financial
Statements for more information.

     Sales of purchased gas for hedging and  optimization  increased during 2005
due primarily to significantly higher natural gas prices and volumes compared to
the same period in 2004.
<TABLE>
<CAPTION>
                                                                                   Nine Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                <C>
Mark-to-market activities, net.............................................  $       40.2  $      (15.3) $       55.5       362.7%
</TABLE>

     Mark-to-market  activities,  which are shown on a net  basis,  result  from
general market price movements against our open commodity derivative  positions,
These  commodity  positions  represent a small portion of our overall  commodity
contract position.

     The net  gain  from  mark-to-market  activities  in the nine  months  ended
September  30, 2005,  as compared to the same period in 2004 is due primarily to
gains on our Deer Park transaction which are recorded on a mark-to-market basis,
and gains  attributable to gas contracts that lost hedge accounting  eligibility
for the quarter.  In order to qualify for hedge  accounting  under SFAS No. 133,
price movements in the hedge contract and the hedged  transaction must move in a
manner  whereby  changes in value of the hedge  contract and hedged  transaction
sufficiently  offset. As a result of significant  volatility in the gas markets,
certain of our gas  contracts  did not meet these  requirements  and we recorded
approximately  $18.3 million in  mark-to-market  gains that would have otherwise
been recorded through other comprehensive income.
<TABLE>
<CAPTION>
                                                                                   Nine Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                 <C>
Other revenue..............................................................  $       84.6  $       50.8  $       33.8        66.5%
</TABLE>

     Other revenue  increased due primarily to higher revenues at PSM associated
with sales of gas  turbine  components  and at TTS for gas  turbine  maintenance
services and spare turbine parts and component sales.



                                     - 65 -
<PAGE>

Cost of Revenue
<TABLE>
<CAPTION>
                                                                                   Nine Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                <C>
Cost of revenue............................................................  $    7,124.9  $    6,157.8  $     (967.1)      (15.7)%
</TABLE>

     The increase in total cost of revenue is explained by category below.
<TABLE>
<CAPTION>
                                                                                   Nine Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                <C>
Plant operating expense....................................................  $      555.4  $      522.2  $      (33.2)       (6.4)%
Transmission purchase expense..............................................          63.8          53.8         (10.0)      (18.6)%
Royalty expense............................................................          28.3          21.1          (7.2)      (34.1)%
Purchased power expense for hedging and optimization.......................         960.1       1,165.7         205.6        17.6%
                                                                             ------------  ------------  ------------
   Total electric generation and marketing expense.........................  $    1,607.6  $    1,762.8  $      155.2          8.8%
                                                                             ============  ============  ===========
</TABLE>

     Plant operating expense increased primarily due to four additional baseload
power facilities and one expansion  project that achieved  commercial  operation
subsequent  to  September  30,  2004  and  the  timing  of  regular  maintenance
activities,  partially offset by a decrease in major maintenance spending, which
was also affected by timing differences versus prior year.

     In many cases,  we incur  transmission  costs that result from  serving the
accounts of our  customers.  This is especially  true in the case of many of our
retail contracts. When we incur transmission expenses on behalf of our customers
we recognize these amounts as a component of transmission  purchase expense. For
the nine months ended  September 30, 2005 as compared to the same period in 2004
transmission  purchase  expenses  have  declined as we have seen a reduction  in
transmission purchases relating to our retail customers.

     Royalty expense increased primarily due to an increase in electric revenues
at The Geysers  geothermal plants and due to an increase in contingent  purchase
price  payments  to the  previous  owners of the Texas City and Clear Lake power
plants,  which are based on a percentage of gross revenues at the plants. At The
Geysers,  royalties are paid mostly as a percentage  of  geothermal  electricity
revenues.

     Purchased power expense for hedging and  optimization  decreased during the
nine months ended September 30, 2005, as compared to the same period in 2004 due
primarily to lower  volumes which were  partially  offset by higher  prices,  as
compared to the same period in 2004.
<TABLE>
<CAPTION>
                                                                                   Nine Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                <C>
Oil and gas operating expense..............................................  $        4.3  $        5.8  $        1.5        25.9%
Purchased gas expense for hedging and optimization.........................       1,623.7       1,243.8        (379.9)      (30.5)%
                                                                             ------------  ------------  ------------
   Total oil and gas operating and marketing expense.......................  $    1,628.0  $    1,249.6  $     (378.4)      (30.3)%
                                                                             ============  ============  ============
</TABLE>

     We reclassified  our remaining oil and gas  operations,  which were sold in
July 2005, to  discontinued  operations  in the nine months ended  September 30,
2005.  Remaining  activity in  continuing  operations  relates  primarily to gas
pipeline  activities  which  were not  sold and  activity  in prior  years  also
includes  the results of minor  assets sold in prior years that did not meet the
criteria for  reclassification  to discontinued  operations at the time of sale.
See Note 8 of the Notes to Consolidated  Condensed Financial Statements for more
information.

     Purchased  gas expense for hedging and  optimization  increased  during the
nine months ended  September 30, 2005, due to  significantly  higher natural gas
prices and higher volumes as compared to the same period in 2004.





                                     - 66 -
<PAGE>

<TABLE>
<CAPTION>
                                                                                   Nine Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                <C>
Fuel expense...............................................................  $    3,336.2  $    2,671.9  $     (664.3)      (24.9)%
</TABLE>

     Fuel expense  increased during the nine months ended September 30, 2005, as
compared to the same period in 2004 due  primarily to higher  natural gas prices
and an  increase  of 6.0% in  generation  due  largely to the  addition  of four
additional   baseload  power  facilities  and  one  expansion   project  to  our
consolidated  operating portfolio  subsequent to September 30, 2004. Our average
fuel expense before the effects of hedging, balancing and optimization increased
by 23%  from  $6.01/MMBtu  for the  nine  months  ended  September  30,  2004 to
$7.39/MMBtu for the same period in 2005.
<TABLE>
<CAPTION>
                                                                                   Nine Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                <C>
Depreciation, depletion and amortization expense...........................  $      371.3  $      324.9  $      (46.4)      (14.3)%
</TABLE>

     Depreciation, depletion and amortization expense increased primarily due to
the five additional  power facilities in consolidated  operations  subsequent to
September 30, 2004.
<TABLE>
<CAPTION>
                                                                                   Nine Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                  <C>
Operating lease expense....................................................  $       79.1  $       80.6  $        1.5         1.9%
</TABLE>

     Operating  lease  expense   decreased  from  the  prior  year  due  to  the
restructuring  of the King City lease in May 2004.  After the  restructuring  we
began to account  for the King City lease as a capital  lease.  As a result,  we
stopped incurring  operating lease expense at that facility and instead began to
incur depreciation and interest expense.  Partially offsetting this decrease was
an increase in operating lease expense due to upward  revisions in our estimated
dismantlement costs at our Watsonville  facility at the end of the lease term in
2010.
<TABLE>
<CAPTION>
                                                                                   Nine Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                <C>
Other cost of revenue......................................................  $      102.5  $       68.2  $      (34.3)      (50.3)%
</TABLE>

     Other cost of revenue  increased during the nine months ended September 30,
2005, as compared to the same period in 2004, due primarily to higher volumes of
parts sales at PSM and TTS and high volumes of services  work and spare  turbine
parts and component sales at TTS.

(Income)/Expenses
<TABLE>
<CAPTION>
                                                                                   Nine Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                <C>
(Income) loss from unconsolidated investments..............................  $      (14.6) $       12.2  $       26.8       219.7%
</TABLE>

     The increase in income was  primarily due to an increase in income from the
Acadia PP  investment  (mostly due to lower major  maintenance  costs),  and the
non-recurrence of losses recorded in 2004 from our investment in the AELLC power
plant. We ceased to recognize our share of the operating  results of AELLC as we



                                     - 67 -
<PAGE>

began to account for our  investment  in AELLC  using the cost method  following
loss of effective control when AELLC filed for bankruptcy protection in November
2004. In September 2004, we recognized our share of AELLC's adverse jury verdict
related to a dispute with International Paper of approximately $11.6.
<TABLE>
<CAPTION>
                                                                                   Nine Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                 <C>
Equipment cancellation and impairment cost.................................  $        0.7  $       10.2  $        9.5        93.1%
</TABLE>

     During the nine months ended September 30, 2005, equipment cancellation and
asset impairment charge decreased by $9.5 as compared to the same period in 2004
primarily as a result of three  non-recurring  charges we incurred  during 2004.
During the nine months ended  September 30, 2004, we incurred $2.3 in connection
with  the  termination  of a  purchase  contract  for HRSG  components,  $4.3 in
connection with the impairment  charge for one HRSG and a loss on the sale of 12
tube bundles in the amount of $3.5.
<TABLE>
<CAPTION>
                                                                                   Nine Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>               <C>
Long-term service agreement cancellation charge............................  $       34.4  $        4.0  $      (30.4)     (760.0)%
</TABLE>

     During the nine months ended  September  30, 2005,  we recorded  charges of
$33.8  related  to  the  cancellation  of  nine  LTSAs  with  GE  as  part  of a
restructuring of our service relationship. Additionally, we revised our previous
estimate  and  recorded  an  additional  $0.6 in charges  related to  previously
cancelled LTSAs with Siemens Westinghouse.
<TABLE>
<CAPTION>
                                                                                   Nine Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>               <C>
Project development expense................................................  $       71.6  $       15.1  $      (56.5)     (374.2)%
</TABLE>

     Project development expense increased by $56.5 during the nine months ended
September 30, 2005 compared to the same period in 2004 primarily due to a charge
of $44.8 to write off three projects in suspended  development and $12.3 in site
preservation costs related to four projects whose  development/construction  has
been suspended.
<TABLE>
<CAPTION>
                                                                                   Nine Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                <C>
Research and development expense...........................................  $       15.5  $       12.9  $       (2.6)      (20.2)%
</TABLE>

     Research and  development  expense  increased  during the nine months ended
September  30,  2005,  as compared to the same period in 2004  primarily  due to
increased  personnel  expense,  and consulting  fees related to new research and
development programs and testing at PSM.
<TABLE>
<CAPTION>
                                                                                   Nine Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                <C>
Sales, general and administrative expense..................................  $      176.3  $      156.0  $      (20.3)      (13.0)%
</TABLE>

     Sales, general and administrative  expense increased during the nine months
ended  September  30, 2005,  primarily  due to an increase in legal fees and the
reclassification  of $7.2 to  discontinued  operations  in the nine months ended




                                     - 68 -
<PAGE>

September  30, 2004,  related to the sale of the Canadian oil and gas  reserves.
Also contributing to the increase,  although to a lesser extent,  was additional
amortization related to tenant improvements and personnel costs.
<TABLE>
<CAPTION>
                                                                                   Nine Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                <C>
Interest expense...........................................................  $    1,027.4  $      791.2  $     (236.2)      (29.9)%
</TABLE>

Interest  expense  increased  primarily as a result of higher  average  interest
rates and lower  capitalization of interest  expense.  Our average interest rate
increased  from 8.4% for the nine months ended  September  30, 2004, to 9.7% for
the nine months ended September 30, 2005,  primarily due to the impact of rising
U.S.  interest  rates  and  their  effect  on our  existing  variable  rate debt
portfolio and higher average  interest  rates  incurred on new debt  instruments
that were entered into to replace  and/or  refinance  existing debt  instruments
during  2005.  Interest  capitalized  decreased  from $296.9 for the nine months
ended  September  30, 2004,  to $169.1 for the nine months ended  September  30,
2005, as new plants entered commercial operations (at which point capitalization
of interest expense ceases) and because of suspended  capitalization of interest
on three partially completed construction projects. We expect that the amount of
interest  capitalized  will continue to decrease in future periods as our plants
in construction are completed.  During the nine months ended September 30, 2005,
(i) interest expense related to our Senior Notes,  contingent convertible notes,
and term loans increased by $26.1;  (ii) interest  expense related to our CalGen
subsidiary   increased   $36.2;   (iii)   interest   expense   related   to  our
construction/project financing increased by $48.2; (iv) interest expense related
to our CCFC I subsidiary  increased by $9.4; and (v) interest expense related to
preferred interests increased by $46.1 primarily due to the October 2004 closing
of the  $360  offering  of  redeemable  preferred  securities  by  our  indirect
subsidiary,  Calpine  Jersey I, and the $260  offering on January 31,  2005,  of
redeemable preferred  securities by our indirect  subsidiary,  Calpine Jersey II
(the Calpine Jersey I and Calpine  Jersey II securities  were  repurchased  with
proceeds from the sale of Saltend in July 2005). The $155 offering of redeemable
preferred securities by our indirect subsidiary,  Metcalf, and the $150 offering
of redeemable preferred  securities by our indirect subsidiary,  CCFC LLC. These
increases in interest  expense are partially  offset by the decrease in interest
expense of $33.3 related to the  convertible  debentures  payable to the Calpine
Capital Trusts, which have been redeemed.
<TABLE>
<CAPTION>
                                                                                   Nine Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                 <C>
Interest (income)..........................................................  $      (57.4) $      (38.0) $       19.4        51.1%
</TABLE>

     Interest  (income)  increased  during the nine months ended  September  30,
2005, due primarily to higher  interest earned on margin deposits and collateral
posted to secure letters of credit and due to higher interest rates.
<TABLE>
<CAPTION>
                                                                                   Nine Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                <C>
Minority interest expense..................................................  $       31.8  $       23.1  $       (8.7)      (37.7)%
</TABLE>

     Minority  interest expense increased during the nine months ended September
30, 2005, as compared to the same period in 2004 primarily due to an increase in
income at CPLP,  which is 70% owned by CPIF.  The  variance is largely due to an
increase  in  availability  at the  Island  Cogen  plant in 2005 as a result  of
non-recurrence of major maintenance work performed during 2004.
<TABLE>
<CAPTION>
                                                                                   Nine Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                 <C>
(Income) from repurchase of debt...........................................  $     (166.5) $     (170.5) $       (4.0)       (2.3)%
</TABLE>



                                     - 69 -
<PAGE>

     The  decrease  in income  from  repurchase  of debt is due to  considerably
higher volumes  (approximately  $356.2) of Senior Notes  repurchased  during the
nine months ended  September 30, 2004,  versus  263.5in the same period in 2005.
The  decrease  was  partially  offset  by  higher   discounts   associated  with
repurchases  in the nine months ended  September  30, 2005  compared to the same
period in 2004.  See Note 7 of the  Notes to  Consolidated  Condensed  Financial
Statements for further information.
<TABLE>
<CAPTION>
                                                                                   Nine Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>               <C>
Other expense (income), net................................................  $       71.4  $     (168.9) $     (240.3)     (142.3)%
</TABLE>

     Other  expense  increased  $240.3 for the nine months ended  September  30,
2005,  compared  to a  gain  in  the  same  period  in  2004,  primarily  due to
non-recurring  gains in the nine  months  ended  September  30,  2004 of  $171.5
related to the  restructuring  and sale of power purchase  agreements for two of
our New Jersey plants, net of transaction costs and the write-off of unamortized
deferred  financing costs. Also contributing to the unfavorable  variance was an
impairment  charge of $18.5 in 2005  related to our  investment  in Grays Ferry,
$11.4 of additional  legal reserves  provided for in 2005 compared to 2004, $8.4
of higher  letter of credit fees in 2005  compared to 2004 and the  write-off of
$5.9 of unamortized  deferred financing costs in connection with the refinancing
of our Metcalf facility's project debt in 2005. Finally,  during the nine months
ended September 30, 2005,  non-cash  foreign  currency  transaction  losses were
higher  than  the  same  period  in 2004 by  $10.7.  See the  "foreign  currency
transaction gain (loss)"  discussion within "Financial Market Risks" for further
information.
<TABLE>
<CAPTION>
                                                                                   Nine Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>                <C>
Benefit for income taxes...................................................  $     (167.9) $     (144.3) $       23.6         16.4%
</TABLE>

     During the nine months ended September 30, 2005, our tax benefit  increased
as compared  to the nine months  ended  September  30, 2004 as our pre-tax  loss
increased in 2005 by approximately  $450.5.  The effective tax rate decreased to
21.3%  in 2005  compared  to 42.6% in the same  period  in 2004.  The  favorable
variance of $23.6 was relatively  moderate  despite the significant  increase in
our pre-tax  loss  largely due to a reserve  recorded  on certain  deferred  tax
assets  associated with CCFC which had the effect of reducing the tax benefit on
tour pre-tax loss by approximately  $143.4 million.  The tax rates on continuing
operations for the nine months ended  September 30, 2004,  have been restated to
reflect the  reclassification to discontinued  operations of certain tax expense
related  to the  sale of oil and  gas  reserves,  Saltend,  and the  Morris  and
Ontelaunee  power  plants.  See Note 8 of the  Notes to  Consolidated  Condensed
Financial Statements for more information.
<TABLE>
<CAPTION>
                                                                                   Nine Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>               <C>
Discontinued operations, net of tax........................................  $      (62.4) $      235.7  $     (298.1)     (126.5)%
</TABLE>

     During the nine months ended  September 30, 2005,  discontinued  operations
activity primarily consisted of the pre-tax gain on the sale of Saltend of $23.7
and the pre-tax gain on the sale of  substantially  all of our remaining oil and
gas assets of $340.2;  both dispositions  closed in July 2005.  Offsetting these
gains are two pre-tax  impairment  charges of $106.2 and $136.8,  related to the
sale of Morris and the pending sale of Ontelaunee, respectively;  Ontelaunee met
the discontinued  operations  criterion as of September 30, 2005, under SFAS No.
144 and was written down to the estimated sales price,  less transaction  costs.
On a pre-tax basis, we recorded income from discontinued operations for the nine
months ended  September  30, 2005 of $75.2.  However,  our effective tax rate on
discontinued operations for the three months ended September 30, 2005 was 183.0%
due  primarily  to a large tax  return  gain on the sale of  Saltend  and,  as a
consequence,  we recognized an after-tax  loss from  discontinued  operations of
$62.4.  Discontinued  operations  for the nine months ended  September  30, 2004
consisted  primarily  of a pre-tax  gain from the sale of our  Canadian and U.S.
Rocky Mountain oil and gas assets of $203.5, and a pre-tax gain from the sale of



                                     - 70 -
<PAGE>

the Lost Pines I Power  project of $35.3 as well as  operating  income from Lost
Pines I, Saltend and our Canadian  and U.S.  oil and gas  operations.  Operating
income from Saltend and the oil and gas assets were considerably  higher for the
nine  months  ended  September  30,  2004  compared  to the same  period in 2005
primarily due to the inclusion of the Canadian and U.S.  Rocky  Mountain  income
within 2004  results and  significant  foreign  currency  transaction  losses at
Saltend  in 2005  related  to a foreign  currency  exposure  which did not exist
during the nine months ended  September 30, 2004. On a net of tax basis,  income
from  discontinued  operations for the nine months ended  September 30, 2004 was
$235.7, based on an effective tax rate of 28.1%.
<TABLE>
<CAPTION>
                                                                                   Nine Months Ended
                                                                                     September 30,
                                                                             ---------------------------
                                                                                  2005          2004        $ Change      % Change
                                                                             ------------- ------------- ------------- -------------
<S>                                                                          <C>           <C>           <C>             <C>
Net income (loss)..........................................................  $     (683.9) $       41.2  $     (725.1)   (1,760.0)%
</TABLE>

     For the nine months ended  September 30, 2005, we reported  revenue of $7.5
billion,  representing  an  increase  of 16.4% over the same period in the prior
year.  Including the discontinued  operations discussed below, we recorded a net
loss per share of $1.49,  or a net loss of  $683.9,  compared  to net income per
share of $0.10, or net income of $41.2, for the same period in the prior year.

     For the nine months  ended  September  30,  2005,  our average  capacity in
operation for consolidated  projects in continuing operations increased by 13.2%
to 25,079  megawatts.  Generation  volume  was up 6.0% from the prior year as we
generated approximately 68.2 million megawatt-hours, which equated to a baseload
capacity  factor of 45.9%,  and  realized an average  spark spread of $22.16 per
megawatt-hour.   For  the  same  period  in  2004,  we  generated  64.4  million
megawatt-hours,  which  equated  to a  baseload  capacity  factor of 50.1%,  and
realized an average spark spread of $20.45 per megawatt-hour.

     Gross  profit  increased by $92.8,  or 30.1%,  to $401.3 in the nine months
ended  September  30,  2005,  compared to the same period in the prior year,  as
total spark spread increased by $196.1  period-to-period.  However, spark spread
did not increase in line with the  increases  in plant  operating  expense,  net
transmission purchase expense, depreciation, and interest expense.

     During the nine months ended  September  30, 2005,  financial  results were
positively  impacted  by $166.5  of  income  recorded  from  repurchase  of debt
(compared to $170.5 in the same period of 2004) and negatively impacted by $34.4
in long-term service agreement  cancellation  charges. In addition,  we recorded
$44.8 in project  development  expense due to the write-off of three projects in
suspended  development and $12.3 in project  development expense on preservation
costs for suspended projects.  Interest expense increased $236.1 between periods
primarily   due  to  an  increase  in  the  average   interest  rate  and  lower
capitalization of interest expense as fewer plants were in active construction.

     Other  expense  was $71.4 for the nine months  ended  September  30,  2005,
compared to other income of $168.9 for the nine months ended September 30, 2004.
The net expense for the nine months ended  September 30, 2005, was due mainly to
an impairment charge of $18.5 related to the sale of our interest in Grays Ferry
in July 2005, $18.3 of non-cash foreign currency  transactions losses related to
inter-company  transactions  (versus $7.6 in the prior year), $16.6 in letter of
credit fees  (versus $8.4 in the prior year) and higher  legal  reserves.  Other
income for the nine months ended September 30, 2004, included approximately $171
in pre-tax gains from the  restructuring  and sale of power purchase  agreements
for two of the company's New Jersey  plants,  net of  transaction  costs and the
write-off of unamortized deferred financing costs.

     In the nine months ended September 30, 2005 we recorded a pre-tax gain from
discontinued  operations of $75.2. However, our year-to-date  effective tax rate
on discontinued  operations was 183% due primarily to a large tax return gain on
the sale of Saltend and, as a  consequence,  we incurred an after-tax  loss from
discontinued operations of $62.4.  Discontinued operations included gains on the
sale of our  remaining  oil and gas assets and Saltend , both of which closed in
July  2005,  and an  impairment  charge  associated  with  the  pending  sale of
Ontelaunee , which was  classified  as held for sale at  September  30, 2005 and
closed in October  2005.  Discontinued  operations  also  includes the operating
results until the respective sales dates for those entities and the Morris power
plant,  for which we recorded an impairment  charge in accordance  with SFAS No.
144 in the second  quarter of 2005,  and which was sold in the third  quarter of
2005.  For the nine months ended  September  30, 2004, we recorded a net gain in
discontinued operations of $235.7 from the sales of our Canadian and U. S. Rocky
Mountain oil and gas assets and the Lost Pines 1 Power Project.








                                     - 71 -
<PAGE>

Liquidity and Capital Resources

     Our  business is capital  intensive.  Our ability to  capitalize  on growth
opportunities  and to service  the debt we incurred  in order to  construct  and
operate  our  current  fleet of  power  plants  is  dependent  on the  continued
availability of capital. The availability of such capital in today's environment
remains  uncertain.  To  date,  we  have  obtained  cash  from  our  operations;
borrowings  under  credit  facilities;  issuances  of  debt,  equity,  preferred
securities and  convertible  and  contingent  convertible  notes;  proceeds from
sale/leaseback transactions; sale or partial sale of certain assets; prepayments
received for power sales;  contract  monetizations;  and project financings.  We
have utilized this cash to fund  operations,  service,  repay or refinance  debt
obligations,   fund   acquisitions,   develop  and  construct  power  generation
facilities,   finance  capital   expenditures,   support   hedging,   balancing,
optimization and trading activities, and meet other cash and liquidity needs.

     Consistent with our strategic  initiative  announced in May 2005, we expect
to rely to a greater  extent  than in the past on asset sales to reduce debt and
related interest expense and to improve our liquidity position.

Transactions completed in the three months ended September 30, 2005:

     o    Issued $150.0 million of Class A Redeemable Preferred Shares due 2006,
          through our indirect subsidiary, CCFC LLC, which is an indirect parent
          of CCFC I, which owns a portfolio of six operating  natural  gas-fired
          power plants (not  including  Ontelaunee,  which met the held for sale
          criteria as of  September  30, 2005) with the  generation  capacity of
          more than 3,600  megawatts.  The Redeemable  Preferred  Shares bear an
          initial  dividend  rate of  LIBOR  plus  950  basis  points  and  were
          redeemable  in  whole  or in part at any  time by CCFC LLC at par plus
          accrued dividends. The Redeemable Preferred Shares were repurchased in
          full on October 14, 2005.

     o    Completed the sale of substantially all of our remaining  domestic oil
          and gas  exploration  and  production  properties and assets for $1.05
          billion,  less  adjustments,  transaction fees and expenses,  and less
          approximately  $75 million to reflect the value of certain oil and gas
          properties  for which we were unable to obtain  consents to assignment
          prior  to  closing.   Certain  of  the  consents  have  been  received
          subsequent  to  September  30,  2005,  and we  expect to  receive  the
          remaining  consents by December 31, 2005. As further discussed in Note
          12 of the Notes to Consolidated  Condensed Financial  Statements,  the
          Company  initiated a lawsuit  seeking access to blocked  proceeds from
          the sale.

     o    Completed  the  sale of  Saltend,  a  1,200-MW  power  plant  in Hull,
          England,  generating  total gross proceeds of $862.9 million.  Of this
          amount,  approximately  $647.1  million  was used to redeem the $360.0
          million  Two-Year  Redeemable  Preferred  Shares issued by our Calpine
          Jersey I  subsidiary  on October  26,  2004,  and the  $260.0  million
          Redeemable Preferred Shares issued by our Calpine Jersey II subsidiary
          on January 31, 2005,  including interest and termination fees of $16.3
          million and $10.8 million,  respectively. As described further in Note
          12 of  the  Notes  to  Consolidated  Condensed  Financial  Statements,
          certain bondholders filed a lawsuit concerning the use of the proceeds
          remaining  from the sale of Saltend.  As discussed in Note 12, certain
          bondholders  initiated a lawsuit  concerning  the use of the  proceeds
          remaining from the sale of Saltend.

     o    Completed  the sale of our Inland  Empire  Energy  Center  development
          project to GE, for  approximately  $30.9 million.  The project will be
          financed,  owned and  operated  by GE and will be used to launch  GE's
          most advanced gas turbine technology, the "H System (TM)." The Company
          will manage plant construction,  market the plant's output, and manage
          its fuel  requirements.  The  Company  has an option to  purchase  the
          facility in years  seven  through  fifteen  following  the  commercial
          operation date and GE can require the Company to purchase the facility
          for a limited  period of time in the  fifteenth  year,  all subject to
          satisfaction of various terms and conditions. If the Company purchases
          the  facility  under  the call or put,  GE will  continue  to  provide
          critical plant maintenance services throughout the remaining estimated
          useful life of the facility. Because of continuing involvement related
          to the  purchase  option and put,  the  Company  deferred  the gain of
          approximately  $10  million  until  the call or put  option  is either
          exercised or expires.

     o    Completed the sale of our 50% interest in the 175-MW Grays Ferry power
          plant for gross proceeds of $37.4  million.  We recorded an impairment
          charge of $18.5  million  related to our interest in the quarter ended
          June 30, 2005.

     o    Completed the sale of our 156-MW Morris power plant for  approximately
          $84.5 million.  In the three months ended June 30, 2005, we recorded a
          $106.2 million  impairment  charge related to our commitment to a plan



                                     - 72 -
<PAGE>

          of divesture of this facility, which was subsequently  reclassified to
          discontinued  operations in the three months ended September 30, 2005,
          upon completion of the sale.

     o    Repurchased  approximately  $138.9 million of our First Priority Notes
          pursuant to a tender  offer.  Following  the  completion of the tender
          offer, we now have  approximately  $641.5 million aggregate  principal
          amount of First Priority Notes outstanding.

     o    Announced a 15-year  Master  Products and Services  Agreement with GE,
          which is expected to lower operating costs in the future.  As a result
          of nine GE LTSA cancellations, we recorded $33.3 million in charges in
          the quarter ended June 30, 2005.

     o    Signed an  agreement  with  Siemens-Westinghouse  to  restructure  the
          long-term  relationship,  which we expect will  provide us  additional
          flexibility to self-perform maintenance work in the future.

     CalBear Transaction. On September 7, 2005, we and CES entered into a Master
Transaction  Agreement with Bear Stearns pursuant to which we agreed to create a
new energy  marketing and trading  venture with Bear Stearns.  At the closing of
the transactions contemplated by the Master Transaction Agreement, our indirect,
wholly owned subsidiary CMSC, and Bear Stearns' wholly owned subsidiary CalBear,
will  also  become  parties.  Pursuant  to the terms of the  Master  Transaction
Agreement,  upon  closing,  we and our  affiliates,  on the one  hand,  and Bear
Stearns and its  affiliates,  on the other hand,  will each refer certain trades
and third party service  transactions to CalBear.  This referral obligation does
not include any transaction  that could be serviced by, used by, hedge cash flow
from or  otherwise  optimize  the  results or  flexibility  of the assets of the
referring entity.  Bear Stearns has agreed to provide CalBear with all funds and
collateral  necessary  for  CalBear to perform  its  obligations  under  certain
agreements and to provide certain other financial support to CalBear.

     The closing is subject to certain  conditions,  including the execution and
delivery of certain  agreements,  including an Agency and Services  Agreement by
and  among  CMSC and  CalBear,  pursuant  to which  CMSC  will act as  CalBear's
exclusive  agent for gas and power trading;  a Trading  Master  Agreement by and
among CES,  CMSC and CalBear,  pursuant to which  CalBear  will  execute  credit
enhancement trades on behalf of CES; and an ISDA Master Agreement, Schedule, and
applicable  annexes between CES and CalBear to effectuate the credit enhancement
trades.  Pursuant to the Agency and Services  Agreement,  CSMC will earn service
fees (a portion  of which will be held in reserve  during the term of the Agency
and Services Agreement) equal to 50% of CalBear's profits, which fees (including
the reserve) are subject to a requirement  to return based on losses at CalBear,
up to 50% of such losses. We received FERC approval on October 31, 2005.

     The Master Transaction Agreement and the agreements entered into thereunder
will  terminate on November 30, 2006 unless both we and Bear Stearns  affirm the
continuation of the Master Transaction Agreement upon 90 days' advance notice to
the other,  and will  terminate at the end of each calendar  quarter  thereafter
unless  extended by both  parties.  In  addition,  both we and Bear  Stearns may
terminate the Master  Transaction  Agreement  voluntarily  upon 90 days' advance
written notice and for specified causes.  In addition,  none of the parties will
enter into a venture that substantially replicates the transactions contemplated
by the Master  Transaction  Agreement  during its term and for a period of up to
two years after its termination, depending upon the reason for the termination.

Transactions  completed  subsequent  to  September  30, 2005 (See Note 15 of the
Notes to Consolidated Condensed Financial Statements for more information):

     o    Completed  the sale of our 561-MW  Ontelaunee  power  plant for $225.0
          million,  less  transaction  costs and working capital  adjustments of
          approximately $13.0 million. The Company recorded an impairment charge
          of  $136.8   million  as  of  September  30,  2005,  is  reflected  in
          discontinued  operations.  The sale of  Ontelaunee  closed  October 6,
          2005.  See  Notes  5 and 8 of  the  Notes  to  Consolidated  Condensed
          Financial  Statements  for more  information.  CCFC I made  offers  to
          purchase its outstanding debt with the proceeds of the Ontelaunee sale
          in accordance  with the  instruments  governing  such debt. The offers
          have  expired,  and none of the  holders of such debt  elected to have
          their debt repurchased.

     o    Received  funding  for CCFC LLC's  $300.0  million  offering of 6-year
          Redeemable Preferred Shares 2011.

     o    Repurchased  the CCFC LLC $150.0 million Class A Redeemable  Preferred
          Shares due 2006.

     While we have  recognized a pre-tax  gain overall on asset sales  completed
during the three and nine months ended  September 30, 2005,  we have  recognized
significant  impairment  charges or losses with respect to certain  asset sales,
including the sale of the Morris facility, as well as the sale of the Ontelaunee
facility in October 2005. We are  considering  the sale of additional  assets in




                                     - 73 -
<PAGE>

connection with our strategic  initiative program,  and it is possible that some
or all of the  additional  asset  sales  contemplated  could  lead  to  material
impairment charges or losses upon sale.

     As a result of  transactions  subsequent to March 31, 2005, we have lowered
our total debt at September  30, 2005,  by  approximately  $0.9 billion to $17.2
billion.  Excluding the effect of new construction  financing of $178.7 million,
the Company has reduced  debt by  approximately  $1.1  billion in this six month
period.

Debt  repurchases  and  redemptions  during the three months ended September 30,
2005:

     During the three months ended  September  30, 2005, we  repurchased  Senior
Notes in open market  transactions  totaling $263.5 million in principal amount.
For cash of $233.9  million plus accrued  interest,  we  repurchased  the Senior
Notes as follows (in thousands):
<TABLE>
<CAPTION>
Senior Notes                                                                                           Principal       Cash Payment
------------                                                                                      ----------------- ---------------
<C> <C>    <C>                                                                                             <C>               <C>
8 1/4% due 2005.................................................................................           4,000.0           3,985.0
10 1/2 % due 2006...............................................................................          10,005.0           9,671.0
7 5/8% due 2006.................................................................................           8,051.0           7,648.4
8 3/4% due 2007.................................................................................           2,000.0           1,570.0
7 7/8% due 2008.................................................................................  $       53,500.0  $       39,598.8
8 1/2% due 2008.................................................................................          41,000.0           3,900.0
7 3/4% due 2009.................................................................................           6,000.0          28,632.5
9 5/8% due 2014.................................................................................         138,895.0         138,895.0
                                                                                                  ----------------  ----------------
   Total repurchases............................................................................  $      263,451.0  $      233,900.7
                                                                                                  ================  ================
</TABLE>

     For the three months  ended  September  30, 2005,  we recorded an aggregate
pre-tax gain of $23.6  million on the above  repurchases  after the write-off of
unamortized deferred financing costs, legal fees, and unamortized discounts.  In
addition, we redeemed and extinguished HIGH TIDES III for a pre-tax loss of $8.0
million after the write-off of unamortized  deferred financing costs, legal fees
and unamortized discounts.

     The sale of assets  to  reduce  debt and  lower  annual  interest  costs is
expected to materially lower our revenues,  spark spread and gross profit (loss)
in the near term and possibly longer. The final mix of assets actually sold will
determine the degree of impact on operating  results.  While  lowering debt, the
accomplishment  of the  strategic  initiative  program,  in and of itself,  will
likely not lead to  improvement  in certain  measures of interest and  principal
coverage without  significant  improvement in market  conditions.  The amount of
offsetting future interest savings will be a function of the principal amount of
debt retired,  and the interest  rate born by such debt,  and the amount that we
will spend to reduce debt will depend on the market price of such debt and other
factors.  The final net  future  earnings  impact  of the  initiatives  is still
uncertain. Our ability to use the proceeds from asset sales is generally subject
to  restrictions  in our indentures  (see Note 7 to the  Consolidated  Condensed
Financial  Statements).  Further, as discussed above and in Note 12 of the Notes
to Consolidated  Condensed  Financial  Statements,  we have experienced  certain
legal  challenges to our intended use of proceeds from certain asset sales,  and
such challenges could affect the timing or ultimate use of such proceeds.

     Capital  Availability  -- While we have been able to access the capital and
bank credit  markets since 2002, it has been on  significantly  different  terms
than before 2002. In particular,  our senior working capital facilities and term
loan financings  entered into, and the majority of our debt  securities  offered
and sold by us have been secured by certain of our assets and subsidiary  equity
interests.  We have also  provided  security to support  our  prepaid  commodity
transactions  and,  as our credit  ratings  have been  downgraded,  we have been
required  to  post  cash  collateral  to  support  our  hedging,  balancing  and
optimization activities.  In the aggregate, the average interest rate on our new
debt instruments,  especially on recent issuances of subsidiary  preferred stock
and or debt incurred to refinance  existing debt, has been higher.  The terms of
capital available to us now and in the future may not be attractive to us or our
access to capital  markets may otherwise  become  restricted.  The timing of the
availability  of capital  is  uncertain  and is  dependent,  in part,  on market
conditions  that are  difficult  to predict and are outside of our  control.  In
addition,  we are currently involved in various  litigations with the holders of
certain series of our  outstanding  secured and unsecured  bonds as described in
Note 12 of the Notes to Consolidated Condensed Financial Statements. The outcome
of these litigations is uncertain, and if, as a result of these litigations, the
Company's  access to the proceeds of asset sales continues to be restricted,  or
the Company is required to restore  proceeds of asset sales that have previously
been  utilized by the Company,  it could have a material  adverse  effect on the
Company and its liquidity.




                                     - 74 -
<PAGE>

     Satisfying the obligations under our outstanding indebtedness,  and funding
anticipated capital  expenditures and working capital  requirements for the next
twelve months and potentially thereafter, presents us with several challenges as
our  cash  requirements  are  expected  to  exceed  the sum of our  cash on hand
permitted  to be used to satisfy  such  requirements  and cash from  operations.
Accordingly,  we have in place a strategic  initiative,  discussed above,  which
includes several components including possible sales or monetizations of certain
of our assets.  Whether we will have sufficient  liquidity will depend, in part,
on the  success  of that  program.  No  assurance  can be given  that it will be
successful.  If it is not  successful,  additional  asset  sales,  refinancings,
monetizations   and  other  actions  beyond  those  included  in  the  strategic
initiative  would  likely  need  to  be  made  or  taken,  depending  on  market
conditions.  Our  ability  to reduce  debt will also  depend on our  ability  to
repurchase debt securities through open market and other  transactions,  and the
principal  amount  of debt we are able to  repurchase  will be  contingent  upon
market  prices and other  factors,  including  the ultimate  outcome of disputes
related to our intended use of the proceeds of certain  asset sales (see Note 12
of  the  Notes  to  Consolidated   Condensed   Financial   Statements  for  more
information).  Even if our strategic initiative program is successful, there can
be no  assurance  that  we will be able  to  continue  work on our  projects  in
development and suspended  construction that have not been successfully  project
financed, and we could possibly incur substantial impairment losses as a result.
Even if the strategic  initiative  is  successful,  until there are  significant
sustained  improvements  in  spark  spreads,  we  expect  that we will  not have
sufficient  cash  flow  from  operations  to repay  all of our  indebtedness  at
maturity or to fund our other  liquidity  needs.  We expect that we will need to
extend or refinance all or a portion of our  indebtedness on or before maturity.
While we currently believe that we will be successful in repaying,  extending or
refinancing all of our indebtedness on or before maturity,  we cannot assure you
that  we  will be able to do so on  attractive  terms,  or at all.  For  further
discussion  of this see the risk  factors in our 2004 Form 10-K and our  Current
Report on Form 8-K filed with the SEC on July 1, 2005.

     Cash  Flow  Activities  -- The  following  table  summarizes  our cash flow
activities for the periods indicated:
<TABLE>
<CAPTION>
                                                                                                           Nine Months Ended
                                                                                                             September 30,
                                                                                                  ----------------------------------
                                                                                                       2005                2004
                                                                                                  --------------      --------------
                                                                                                              (In thousands)
<S>                                                                                               <C>                 <C>
Beginning cash and cash equivalents............................................................   $      718,023      $     954,827
Net cash provided by (used in):
  Operating activities.........................................................................         (407,973)           229,870
  Investing activities.........................................................................          822,689           (381,934)
  Financing activities.........................................................................         (308,971)           633,703
  Effect of exchange rates changes on cash and cash equivalents................................              741             14,377
  Change in discontinued operations cash classified as current assets held for sale............           18,627              7,694
                                                                                                  --------------      --------------
  Net increase in cash and cash equivalents....................................................          125,113            503,710
                                                                                                  --------------      --------------
Ending cash and cash equivalents...............................................................   $      843,136      $    1,458,537
                                                                                                  ==============      ==============
</TABLE>

     Operating activities for the nine months ended September 30, 2005, used net
cash of $408.0  million,  as compared to providing  $229.9  million for the same
period in 2004. In the first nine months of 2005 there was a $205.2  million use
of funds from net changes in operating  assets and  liabilities  comprised of an
increase in accounts  receivable of $416.5 million and an increase in net margin
deposits posted to support CES contracting  activity of $24.1 million.  This was
offset by an increase in  accounts  payable of $212.1  million and a decrease in
inventory of $20.0  million.  The  significant  increase in accounts  receivable
period over period was primarily due to the significant increase in power prices
during the three-month  period ended September 30, 2005, and to a lesser extent,
an increase in megawatt hours sold (due to additional  generation capacity) from
September 30, 2004 to September 30, 2005.

     In the first nine months of 2004,  operating cash flows  benefited from the
receipt of $100.6 million from the termination of power purchase  agreements for
two of our New Jersey power plants and $16.4 million from the restructuring of a
long-term  gas supply  contract.  We had an $11.3  million use of funds from net
changes in  operating  assets and  liabilities,  including an increase of $104.8
million  in  accounts  receivable,  partially  offset by an  increase  of $218.9
million in accounts  payable and a $14.1 million decrease in net margin deposits
posted to support CES contracting activity.

     Investing activities for the nine months ended September 30, 2005, provided
net cash of $822.7  million,  as  compared to using  $381.9  million in the same
period of 2004. Capital expenditures,  including  capitalized interest,  for the
completion of our power  facilities  decreased from $1,184.4  million in 2004 to



                                     - 75 -
<PAGE>

$675.7  million  in  2005 as  there  were  fewer  projects  under  construction.
Investing  activities in 2005  reflected the receipt of $897.6  million from the
sale of our oil and  natural  gas assets,  $843.1  million  from the sale of our
Saltend  power  plant in the UK,  $84.5  million  from  the  sale of our  Morris
facility,  $30.4 million from the sale of our Inland Empire development  project
and $36.9  million  from the sale of our  investment  in the Grays  Ferry  power
plant. Additionally,  investing activities in 2005 reflect the receipt of $132.5
million from the  disposition of our  investment in High Tides III,  offset by a
$559.9 million  increase in restricted  cash,  including $401.7 million from the
proceeds  of the  sale of our oil and gas  assets,  which  is the  subject  of a
lawsuit. See Note 12 in the Notes to Consolidated Condensed Financial Statements
for more information regarding this matter. Investing activities in 2004 reflect
the  receipt of $148.6  million  from the sale of our 50%  interest  in the Lost
Pines I Power  Plant,  $626.6  million from the sale of our Canadian oil and gas
reserves,  $219.1  million from the sale of our U.S.  Rocky Mountain oil and gas
reserves, together with the proceeds from the sale of a subsidiary holding power
purchase  agreements  for two of our New  Jersey  power  plants,  offset  by the
purchase of the Brazos  Valley power plant,  the  remaining  50% interest in the
Aries power plant,  and the  remaining 20% interest in Calpine  Cogen.  Also, we
used $111.6 million to purchase a portion of High Tides III and invested  $124.2
million in restricted cash during the nine month period of 2004

     Financing  activities  for the nine months ended  September 30, 2005,  used
$309.0  million,  as compared to providing  $633.7 million in 2004. We continued
our  refinancing  program  in the first nine  months of 2005 by raising  $260.0,
$155.0 and $150.0  million  (which was  repurchased  on October  14,  2005) from
preferred  securities  offerings  by Calpine  Jersey II,  Metcalf  and CCFC LLC,
respectively,  $650.0 million from the 2015 Convertible  Notes offering,  $621.0
million  from  various  project  financings  and $290.6  million  from a prepaid
commodity  derivative contract at our Deer Park facility.  We continued our debt
reduction  program by using  $353.3  million to repay notes  payable and project
financing debt, $628.5 million to repay preferred security offerings  (including
the Calpine  Jersey II mentioned  above) in addition to using $821.3  million to
repay or  repurchase  Senior  Notes and $517.5  million to repay High Tides III.
Additionally, we incurred $89.3 million in financing and transaction costs.

     Working  Capital -- At September 30, 2005, we had working capital of $520.8
million which increased approximately $242.7 million from December 31, 2004. The
increase was primarily due to increases of $494.6 million,  $513.4 million,  and
$379.5 million in accounts  receivable,  restricted cash, and current derivative
assets, respectively,  offset by increases of $212.1 million, $249.4 million and
$618.1 million in accounts  payable,  Senior Notes,  current portion and current
derivative liabilities,  respectively,  from December 31, 2004, to September 30,
2005. The increase in accounts  receivable  period over the period was primarily
due to the significant  increase in power prices during the  three-month  period
ended September 30, 2005, and to a lesser extent,  an increase in megawatt hours
sold  (due  to  additional  generating  capacity).   Restricted  cash  increased
primarily  due to the addition of $607.5 in remaining net proceeds from the sale
of  Saltend  and our  remaining  oil and gas assets in July  2005.  Our  current
derivative assets and liabilities increased  significantly primarily as a result
of  significantly  higher  electricity  and natural gas prices at the end of the
third  quarter  in 2005.  Cash  flow used in  operating  activities  during  the
nine-month  period ended  September 30, 2005, was $408.0 million and is expected
to continue to be negative at least for the near term and  possibly  longer.  On
September  30,  2005,  our cash  and cash  equivalents  on hand  totaled  $843.1
million.  The current portion of restricted cash totaled $1,106.7  million.  See
Note 2 for more  information  on our cash and cash  equivalents  and  restricted
cash.

     Counterparties   and  Customers  --  Our  customer  and  supplier  base  is
concentrated  within the energy  industry.  Additionally,  we have  exposure  to
trends within the energy industry, including declines in the creditworthiness of
our marketing counterparties.

     Currently,  multiple  companies  within  the  energy  industry  have  below
investment grade credit ratings and certain have sought bankruptcy protection or
reorganization.  However, we do not currently have any significant  exposures to
counterparties that are not paying on a current basis.

     Letter of Credit Facilities -- At September 30, 2005 and December 31, 2004,
we had approximately $592.1 million and $596.1 million, respectively, in letters
of credit  outstanding  under  various  credit  facilities  to support  our risk
management  and other  operational  and  construction  activities.  Of the total
letters of credit outstanding,  $194.4 million and $233.3 million, respectively,
were issued under the cash collateralized letter of credit facility at September
30, 2005 and December 31, 2004, respectively.

     Commodity  Margin  Deposits and Other Credit Support -- As of September 30,
2005 and December 31, 2004, to support  commodity  transactions we had deposited
net  amounts of $273.0  million  and $248.9  million,  respectively,  in cash as
margin  deposits with third  parties,  and we made gas and power  prepayments of
$78.9  million,  and $78.0  million,  respectively,  and had  letters  of credit
outstanding of $181.1 million and $115.9 million,  respectively.  Since December
31, 2004,  such amounts have  increased as commodity  prices have risen.  We use



                                     - 76 -
<PAGE>

margin  deposits,  prepayments  and  letters  of credit as  credit  support  for
commodity  procurement  and risk management  activities.  Future cash collateral
requirements  may increase or decrease based on the extent of our involvement in
standard  contracts  and  movements  in  commodity  prices and also based on our
credit ratings and general perception of creditworthiness in the market.

     Unrestricted  Subsidiaries -- The information in this paragraph is required
to be provided under the terms of the Second Priority Secured Debt  Instruments.
We have designated  certain of our subsidiaries as  "unrestricted  subsidiaries"
under  the  Second  Priority  Secured  Debt   Instruments.   A  subsidiary  with
"unrestricted"  status  thereunder  generally is not required to comply with the
covenants contained therein that are applicable to "restricted subsidiaries." We
have  designated  Calpine  Gilroy 1, Inc.,  Calpine  Gilroy 2, Inc.  and Calpine
Gilroy Cogen,  L.P. as  "unrestricted  subsidiaries"  for purposes of the Second
Priority  Secured Debt  Instruments.  The  following  table sets forth  selected
balance sheet information of Calpine Corporation and restricted subsidiaries and
of such  unrestricted  subsidiaries  at September 30, 2005, and selected  income
statement  information  for  the  nine  months  ended  September  30,  2005  (in
thousands):
<TABLE>
<CAPTION>
                                                                   Calpine
                                                                 Corporation
                                                               and Restricted    Unrestricted
                                                                Subsidiaries     Subsidiaries      Eliminations          Total
                                                              ---------------  ---------------   ---------------   ----------------
<S>                                                           <C>              <C>               <C>               <C>
Assets......................................................  $    26,888,675  $       429,183   $      (229,621)  $    27,088,237
                                                              ===============  ===============   ===============   ===============
Liabilities.................................................  $    22,708,923  $       246,149   $            --   $    22,955,072
                                                              ===============  ===============   ================  ===============
Total revenue...............................................  $     7,522,915  $         9,781   $        (6,468)  $     7,526,228
Total cost of revenue.......................................       (7,117,986)         (16,305)            9,388        (7,124,903)
Interest income.............................................           49,947           12,706            (5,236)           57,417
Interest expense............................................       (1,017,659)          (9,723)               --        (1,027,382)
Other.......................................................         (116,371)           1,132                --          (115,239)
                                                              ---------------  ---------------   ----------------  ---------------
  Net income................................................  $      (679,154) $        (2,409)  $        (2,316)  $      (683,879)
                                                              ===============  ===============   ===============   ===============
</TABLE>

     Bankruptcy-Remote   Subsidiaries  --  Pursuant  to  applicable  transaction
agreements,  we have established  certain of our entities  separate from Calpine
and its other subsidiaries.  At September 30, 2005 these entities included: CCFC
LLC,  Metcalf LLC, Rocky Mountain Energy Center,  LLC,  Riverside Energy Center,
LLC, Calpine Riverside Holdings,  LLC, Calpine Energy Management,  L.P., CES GP,
LLC, PCF, PCF III, CNEM,  Calpine  Northbrook  Energy Marketing  Holdings,  LLC,
Gilroy Energy Center,  LLC, Calpine Gilroy Cogen,  L.P., Calpine Gilroy I, Inc.,
Calpine King City Cogen, LLC, Calpine Securities Company, L.P. (a parent company
of Calpine King City Cogen, LLC), and Calpine King City, LLC (an indirect parent
company of Calpine Securities Company,  L.P.),  Calpine Deer Park Partner,  LLC,
Calpine DP, LLC and Deer Park.

     Indenture  and  Debt  and  Lease  Covenant  Compliance  --  Certain  of our
indentures place conditions on our ability to issue indebtedness if our interest
coverage  ratio (as defined in those  indentures) is below 2:1.  Currently,  our
interest  coverage  ratio (as so  defined)  is below 2:1 and,  consequently,  we
generally  would not be allowed to issue new debt,  except for (i) certain types
of new indebtedness that refinances or replaces existing indebtedness,  and (ii)
non-recourse  debt and preferred equity interests issued by our subsidiaries for
purposes of financing  certain types of capital  expenditures,  including  plant
development,  construction and acquisition expenses. In addition, if and so long
as our  interest  coverage  ratio  is  below  2:1,  our  ability  to  invest  in
unrestricted  subsidiaries and non-subsidiary  affiliates and make certain other
types  of  restricted  payments  will  be  limited.  Moreover,  certain  of  our
indentures will prohibit any further investments in non-subsidiary affiliates if
and for so long as our  interest  coverage  ratio (as defined  therein) is below
1.75:1 and, as of September  30, 2005,  such interest  coverage  ratio was below
1.75:1.  We  currently  do not expect  this  limitation  on our  ability to make
investments  in  non-subsidiary  affiliates  to have a  material  impact  on our
business.

     Certain of the Company's  indebtedness  issued in the last half of 2004 was
incurred  in  reliance  on  provisions  in  certain of its  existing  indentures
pursuant to which the Company is able to incur  indebtedness  if,  after  giving
effect  to the  incurrence  and the  repayment  of other  indebtedness  with the
proceeds there from, the Company's  interest coverage ratio (as defined in those
indentures) is greater than 2:1. In order to satisfy the interest coverage ratio
requirement in connection with such issuances, the proceeds thereof was required
to be used to repurchase or redeem other  existing  indebtedness.  As previously
reported in the Company's  2004 10-K and its Quarterly  Reports on Form 10-Q for
the first two quarters of 2005, the Company  completed a substantial  portion of
such  repurchases  during the fourth quarter of 2004 and the first six months of
2005. The Company  completed the required  repurchases,  spending  approximately



                                     - 77 -
<PAGE>

$248.4  million in the third  quarter of 2005 to  repurchase  debt,  and has now
fully satisfied this requirement.  The amount we were required to spend exceeded
our estimate of $184.0 million because the required principal amount of debt was
repurchased at prices higher than originally anticipated.

     When the Company or one of its  subsidiaries  sells a significant  asset or
issues preferred equity, the Company's indentures generally require that the net
proceeds of the  transaction  be used to make capital  expenditures,  to acquire
permitted  assets or capital stock, or to repurchase or repay  indebtedness,  in
each case within 365 days of the closing date of the transaction.  To the extent
that $50 million or more of such net  proceeds  are not so used,  the Company is
required  under the terms of its secured  debt  instruments  to make an offer to
purchase its  outstanding  senior secured  indebtedness  up to the amount of the
unused  net  proceeds.  This  general  requirement  contains  certain  customary
exceptions,  and, in the case of certain assets  defined as "designated  assets"
under  some  of the  Company's  indentures,  including  the gas  portion  of the
Company's oil and gas assets sold in July 2005, there are additional  provisions
discussed further below that apply to the use of the proceeds of a sale of those
assets. In light of these requirements, and after taking into account the amount
of  capital  expenditures  currently  budgeted  for the  remainder  of 2005  and
forecasted for 2006, the Company anticipates that, in the fourth quarter of 2005
and the first three quarters of 2006, it will need to use  approximately  $195.5
million and $668.5 million,  respectively,  of the net proceeds from four series
of preferred  equity issued by  subsidiaries of the Company and three asset sale
transactions,  all completed prior to September 30, 2005, to repurchase or repay
indebtedness or acquire assets or capital stock. The Company has,  subsequent to
September 30, 2005,  fulfilled the portion of this  obligation as required to be
completed in the fourth quarter of 2005. Accordingly,  assuming that the Company
would  fulfill  the  remaining  obligations  by  repurchasing  indebtedness,  an
aggregate  amount of  approximately  $714.0  million  of Senior  notes and terms
loans, net of current portion, and $150.0 million of Preferred interest,  net of
current portion,  related to this use of remaining net proceeds  requirement has
been  classified  as Senior Notes,  current  portion,  and  Preferred  interest,
current portion,  respectively,  on the Company's Consolidated Condensed Balance
Sheet as of September 30, 2005.  The actual amount of the net proceeds that will
be  required to be used to  repurchase  or repay debt will  depend,  among other
things,  upon the actual amount of the net proceeds that is used to make capital
expenditures or acquire other assets or capital stock, which may be more or less
than the amount  currently  budgeted  and/or  forecasted.  This amount  includes
$207.5 million of the net proceeds of the sale of Saltend.  As described further
in Note 12 of the Notes to Consolidated Condensed Financial Statements,  certain
bondholders filed a lawsuit  concerning the use of the proceeds from the sale of
Saltend.  In  connection  with that  lawsuit,  the  Company is  prohibited  from
repatriating  this amount due to an order of the Court in that matter  requiring
such  proceeds  to be  held  at  or in  the  control  of  CCRC.  To  the  extent
repatriation of such net proceeds is ultimately  permitted,  the repatriated net
proceeds  will be applied  pursuant  to the use of  proceeds  provisions  of the
Company's  indentures described herein as if the sale of Saltend had occurred on
the date of repatriation.

     In addition,  the net proceeds from an issuance of preferred  equity and an
asset sale completed  after September 30, 2005 will similarly be subject to such
use of  proceeds  provisions  of  the  Company's  indentures,  and  the  Company
anticipates  that,  on the basis  described  above  (after  considering  capital
expenditures), an additional $452.1 million will need to be used to make capital
expenditures,  to  acquire  other  assets or  capital  stock,  or to  repurchase
indebtedness,  as  applicable,  within  365  days  of  the  consummation  of the
applicable transaction.

     As noted above, our remaining oil and gas assets were sold on July 7, 2005,
with the gas  component  of such sale  constituting  "designated  assets"  under
certain  of our  indentures.  These  indentures  require  us to make an offer to
purchase our First  Priority Notes with the net proceeds of a sale of designated
assets not otherwise  applied in accordance  with the other permitted uses under
such  indentures  and, to the extent any proceeds  (above $50.0  million  remain
thereafter,  to make an offer to purchase  its second  priority  senior  secured
debt. Accordingly, we made an offer to purchase the First Priority Notes in June
2005.  On July 12,  2005,  we  purchased,  with  proceeds of the sale of the gas
assets, all of the approximately $138.9 million in principal amount of the First
Priority  Notes  tendered  in  connection  with the  offer to  purchase.  Having
completed the tender offer,  we have used  approximately  $308.2  million of the
$708.5  million of the remaining  net proceeds  arising from the sale of our gas
assets to acquire natural gas and/or  geothermal  energy assets  permitted to be
acquired under such indentures. However, there can be no assurance that we would
be  successful  in  identifying  or  acquiring  any  additional  such  assets on
acceptable  terms or at all. If we do not, within 180 days of receipt of the net
proceeds from the sale of our gas assets,  use all of the remaining net proceeds
to acquire such such assets,  and/or to repurchase or repay (through open market
or privately-negotiated  transactions, tender offers or otherwise) any or all of
the approximately  $641.5 million  aggregate  principal amount of First Priority
Notes  remaining  outstanding  after  consummation  of  the  offer  to  purchase
described above (either of which actions we may, but are not required, to take),
then we will, to the extent that the remaining net proceeds from the sale exceed
$50 million,  be required  under the terms of our Second  Priority  Secured Debt



                                     - 78 -
<PAGE>

instruments to make an offer to purchase our outstanding  second priority senior
secured indebtedness,  of which $3.7 billion is outstanding, up to the amount of
the  remaining  net  proceeds.  However,  as  described  further  in Note 12, on
September  26,  2005,  the  Company  filed a lawsuit  seeking  acces to  blocked
proceeds  remaing from this sale of designated  assets.  If the Company does not
ultimately prevail in this lawsuit,  particularly if the Company is compelled to
return  previously  withdrawn  amounts to the gas sale proceeds  account as more
fully  described  in Note 12 of the Notes to  Consolidated  Condensed  Financial
Statements,  it could  have a material  adverse  effect on the  Company  and its
liquidity.

     In  connection   with  several  of  our   subsidiaries'   lease   financing
transactions (Agnews,  Geysers,  Pasadena, Broad River, RockGen and South Point)
the insurance  policies we have in place do not comply in every respect with the
insurance  requirements set forth in the financing documents.  We have requested
from the relevant  financing parties,  and are expecting to receive,  waivers of
this  noncompliance.  While  failure to have the required  insurance in place is
listed in the financing documents as an event of default,  the financing parties
may not  unreasonably  withhold  their approval of our waiver request so long as
the required  insurance  coverage is not  reasonably  available or  commercially
feasible and we deliver a report from our  insurance  consultant to that effect.
We have  delivered  the required  insurance  consultant  reports to the relevant
financing  parties and therefore  anticipate that the necessary  waivers will be
executed shortly.

     In connection with the  sale/leaseback  transaction of Agnews,  we have not
fully  complied with  covenants  pertaining to the  operations  and  maintenance
agreement, which noncompliance is technically an event of default. We are in the
process of addressing this by seeking the lessor's  approval to renew and extend
the operations and maintenance agreement for the Agnews facility.

     In  connection  with the  sale/leaseback  transaction  of Calpine  Monterey
Cogeneration,  Inc.,  we have not fully  complied with  covenants  pertaining to
amendments to gas and power purchase  agreements and the requirements to provide
a detailed  accounting  report,  which  noncompliance is technically an event of
default.  We are in the  process of  addressing  this by  seeking a consent  and
waiver.

     Almost all of our operations  are conducted  through our  subsidiaries  and
other affiliates. As a result, we depend almost entirely upon their cash flow to
service  our  indebtedness,  including  our  ability to pay the  interest on and
principal of our Senior Notes. However, as also described in our 2004 Form 10-K,
first quarter 10-Q,  second  quarter 10-Q,  and Current Report on Form 8-K filed
with the SEC on July 1, 2005,  and Current Report on Form 8-K filed with the SEC
on October 17, 2005, cash flow from operations is currently insufficient to meet
in full our cash,  liquidity  and  refinancing  obligations  for the year, so we
presently  also  depend in part upon the  success  of our  strategic  initiative
program in order to fully  service our debt. In addition,  financing  agreements
covering a substantial portion of the indebtedness of our subsidiaries and other
affiliates  restrict  their  ability to pay  dividends,  make  distributions  or
otherwise  transfer  funds  to us  prior to the  payment  of their  obligations,
including  their  outstanding  debt,  operating  expenses,  lease  payments  and
reserves.

     Effective Tax Rate -- For the three months ended  September  30, 2005,  the
effective  rate from  continuing  operations  increased to (7.8)% as compared to
(237.6)%  for the three  months ended  September  30, 2004.  For the nine months
ended  September 30, 2005, and 2004, the effective tax rate was 21.3% and 42.6%,
respectively.  The tax  rates on  continuing  operations  for the three and nine
months ended  September  30, 2005,  were  adversely  affected due to a valuation
allowance  recorded against certain NOL deferred tax assets associated with CCFC
LLC in the amount of approximately $143.4 million. The variance in the effective
tax rate for the three  months  ended  September  30, 2005  compared to the same
period in 2004 was significantly  impacted by the nominal absolute dollar amount
of our  pre-tax  income  (loss)  in each  period.  For the  three  months  ended
September  30, 2004,  our pre-tax  income from  continuing  operations  was $8.6
million.  Therefore,  due to the near break-even  absolute value of this amount,
the tax benefit for the period translated into a high tax rate percentage,  even
though the  benefit was only $20.3  million.  Conversely,  for the three  months
ended September 30, 2005, our pre-tax loss from continuing operations was $224.9
million and the tax  provision for the period was $17.5  million.  Excluding the
effects  of the  valuation  allowance  associated  with CCFC LLC,  we would have
recognized a tax benefit of $125.9 million for the three months ended  September
30, 2005  resulting  in an effective  tax rate of 56.0%.  While this tax benefit
(excluding  the  effects of CCFC LLC) was  $105.6  million  higher  than the tax
benefit  recognized for the three months ended September 30, 2004, the effective
tax rate was significantly  higher for the three months ended September 30, 2004
due to the nominal absolute value of pre-tax income from continuing  operations.
Also, the tax rates on continuing operations for the three and nine months ended
September 30, 2004,  have been restated in accordance  with FIN 18,  "Accounting
for Income Taxes in Interim Periods - an  Interpretation of APB Opinion No. 28,"
as  amended,  to reflect the effects of  classifying  the sale of the  Company's
Canadian and U.S. Rocky Mountain oil and gas assets, and the Saltend, Morris and
Ontelaunee  power  plants.  See Note 8 of the  Notes to  Consolidated  Condensed



                                     - 79 -
<PAGE>

Financial  Statements for more  information  on  discontinued  operations.  This
effective tax rate on continuing  operations  is based on the  consideration  of
estimated  year-end  earnings in estimating  the quarterly  effective  rate, the
effect of permanent  non-taxable items and establishment of valuation allowances
on certain deferred tax assets.

     Off-Balance  Sheet  Commitments -- In accordance  with SFAS No. 13 and SFAS
No. 98,  "Accounting for Leases" our facility  operating  leases,  which include
certain sale/leaseback transactions, are not reflected on our balance sheet. All
lessors in these  contracts  are third  parties  that are  unrelated  to us. The
sale/leaseback transactions utilize SPEs formed by the equity investors with the
sole purpose of owning a power generation facility. Some of our operating leases
contain  customary  restrictions  on  dividends,  additional  debt  and  further
encumbrances   similar  to  those   typically  found  in  project  finance  debt
instruments. We have no ownership or other interest in any of these SPEs.

     Effective Tax Rate -- For the three months ended  September  30, 2005,  the
effective  rate from  continuing  operations  increased to (7.8)% as compared to
(237.6)%  for the three  months ended  September  30, 2004.  For the nine months
ended  September 30, 2005, and 2004, the effective tax rate was 21.3% and 42.6%,
respectively.  The tax  rates on  continuing  operations  for the three and nine
months ended  September  30, 2005,  were  adversely  affected due to a valuation
allowance  recorded against certain NOL deferred tax assets associated with CCFC
LLC in the amount of approximately $143.4 million. The variance in the effective
tax rate for the three  months  ended  September  30, 2005  compared to the same
period in 2004 was significantly  impacted by the nominal absolute dollar amount
of our  pre-tax  income  (loss)  in each  period.  For the  three  months  ended
September  30, 2004,  our pre-tax  income from  continuing  operations  was $8.6
million.  Therefore,  due to the near break-even  absolute value of this amount,
the tax benefit for the period translated into a high tax rate percentage,  even
though the  benefit was only $20.3  million.  Conversely,  for the three  months
ended  September 30, 2005,  pre-tax loss from  continuing  operations was $224.9
million and the tax provision for the period was only $17.5  million.  Excluding
the effects of the valuation  allowance  associated with CCFC LLC, we would have
recognized a tax benefit of $125.9 million for the three months ended  September
30, 2005  resulting  in an effective  tax rate of 56.0%.  While this tax benefit
(excluding  the  effects of CCFC LLC) was  $105.6  million  higher  than the tax
benefit  recognized for the three months ended September 30, 2004, the effective
tax rate was significantly  higher for the three months ended September 30, 2004
due to the nominal absolute value of pre-tax income from continuing  operations.
Also, the tax rates on continuing operations for the three and nine months ended
September 30, 2004,  have been restated in accordance  with FIN 18,  "Accounting
for Income Taxes in Interim Periods - an  Interpretation of APB Opinion No. 28,"
as  amended,  to reflect the effects of  classifying  the sale of the  Company's
Canadian and U.S. Rocky Mountain oil and gas assets, and the Saltend, Morris and
Ontelaunee  power plants as  discontinued  operations due to our commitment to a
plan  of  divesture  in  the  second  quarter  of  2005.  See  Note  8 for  more
information.  This  effective tax rate on continuing  operations is based on the
consideration  of  estimated  year-end  earnings  in  estimating  the  quarterly
effective rate, the effect of permanent  non-taxable  items and establishment of
valuation allowances on certain deferred tax assets.

     We own a 32.3% interest in AELLC. AELLC owns the 136-MW Androscoggin Energy
Center  located in Maine.  On November  3, 2004,  a jury  verdict  was  rendered
against AELLC in a breach of contract  dispute with IP. See Note 12 of the Notes
to Consolidated  Condensed Financial  Statements for more information about this
legal proceeding. We recorded our $11.6 million share of the award amount in the
third  quarter of 2004. On November 26, 2004,  AELLC filed a voluntary  petition
for relief  under  Chapter 11 of the U.S.  Bankruptcy  Code.  As a result of the
bankruptcy,  we lost  significant  influence and control of the project and have
adopted the cost method of  accounting  for our  investment  in AELLC.  Also, in
December  2004,  we  determined  that our  investment  in AELLC was impaired and
recorded a $5.0 million impairment  reserve. On April 12, 2005, AELLC sold three
fixed-price gas contracts to Merrill Lynch Commodities  Canada,  ULC, and used a
portion of the  proceeds  to pay down its  remaining  construction  debt.  As of
September  30, 2005,  the  facility had  third-party  debt  outstanding  of $3.1
million. See Note 12 of the Notes to Consolidated Condensed Financial Statements
for an update on this investment.

     Credit  Considerations  -- On May 9, 2005,  Standard & Poor's  lowered  its
corporate credit rating on Calpine Corporation to B- from B. The outlook remains
negative. In addition, the ratings on Calpine's debt and the ratings on the debt
of its subsidiaries were also lowered by one notch, with a few exceptions.

     On May 12, 2005, Moody's Investor Service lowered its senior implied issuer
rating on Calpine  Corporation to B3 from B2. The outlook remains  negative.  In
addition,  the  ratings  on  Calpine's  debt and the  ratings on the debt of its
subsidiaries were also lowered by two notches, with a few exceptions.

     On November 4, 2005,  following the  announcement of our third quarter 2005
results of operation  release on November 3, 2005, Fitch Ratings  downgraded its
ratings on our senior  unsecured notes to CCC- from CCC+.  Calpine Canada Energy
Finance  ULC bonds  were also  downgraded  to CCC- from CCC+ (all with  negative
outlook).  Our second  priority notes were downgraded to B from BB-, while first
priority  notes were  reduced to B- from B+. This  downgrade  is not expected to
materially impact our operations.

     Credit  rating  downgrades  have had a negative  impact on our liquidity by
reducing  attractive  financing  opportunities  and  increasing  the  amount  of
collateral  required  by  trading  counterparties.   Any  future  credit  rating
downgrades could have similar effects on our liquidity.

     Capital  Spending  -- See  Note 5 of the  Notes to  Consolidated  Condensed
Financial  Statements  for a  discussion  of our  development  and  construction
projects at September 30, 2005


                                     - 80 -
<PAGE>

Performance Metrics

     In understanding our business,  we believe that certain non-GAAP  operating
performance metrics are particularly important. These are described below:

     o    Total  deliveries  of power.  We both  generate  power that we sell to
          third  parties  and  purchase  power for sale to third  parties in HBO
          transactions.  The former sales are recorded as electricity  and steam
          revenue and the latter sales are recorded as sales of purchased  power
          for  hedging  and  optimization.  The  volumes in MWh for each are key
          indicators of our respective levels of generation and HBO activity and
          the sum of the two, our total deliveries of power, is relevant because
          there are occasions  where we can either generate or purchase power to
          fulfill  contractual  sales  commitments.   Prospectively,   beginning
          October 1, 2003, in accordance  with EITF 03-11,  "Reporting  Realized
          Gains and Losses on  Derivative  Instruments  That Are Subject to SFAS
          No. 133 and Not `Held for Trading  Purposes'  As Defined in EITF Issue
          No. 02-3: `Issues Involved in Accounting for Derivative Contracts Held
          for Trading Purposes and Contracts Involved in Energy Trading and Risk
          Management  Activities,'  certain sales of purchased power for hedging
          and  optimization are shown net of purchased power expense for hedging
          and  optimization  in  our   consolidated   statement  of  operations.
          Accordingly,  we have also  netted HBO volumes on the same basis as of
          October 1, 2003, in the table below.

     o    Average availability and average baseload capacity factor or operating
          rate.  Availability  represents  the percent of total hours during the
          period that our plants were available to run after taking into account
          the downtime  associated with both scheduled and unscheduled  outages.
          The baseload  capacity  factor,  sometimes  called  operating rate, is
          calculated by dividing (a) total megawatt hours generated by our power
          plants  (excluding  peakers)  by the  product of  multiplying  (b) the
          weighted  average  megawatts in operation during the period by (c) the
          total hours in the period.  The  capacity  factor is thus a measure of
          total actual generation as a percent of total potential generation. If
          we elect not to generate  during periods when  electricity  pricing is
          too low or gas  prices too high to operate  profitably,  the  baseload
          capacity  factor will reflect that decision as well as both  scheduled
          and unscheduled outages due to maintenance and repair requirements.

     o    Average heat rate for gas-fired fleet of power plants expressed in Btu
          of fuel consumed per KWh generated. We calculate the average heat rate
          for our  gas-fired  power plants  (excluding  peakers) by dividing (a)
          fuel consumed in Btu's by (b) KWh  generated.  The resultant heat rate
          is a measure  of fuel  efficiency,  so the lower  the heat  rate,  the
          better.  We also calculate a  "steam-adjusted"  heat rate, in which we
          adjust  the fuel  consumption  in Btu's  down by the  equivalent  heat
          content in steam or other  thermal  energy  exported to a third party,
          such as to steam hosts for our cogeneration facilities. Our goal is to
          have the lowest average heat rate in the industry.

     o    Average all-in  realized  electric price  expressed in dollars per MWh
          generated.   Our  risk  management  and  optimization  activities  are
          integral to our power  generation  business  and  directly  impact our
          total realized revenues from generation. Accordingly, we calculate the
          all-in  realized  electric  price per MWh  generated  by dividing  (a)
          adjusted  electricity  and  steam  revenue,  which  includes  capacity
          revenues,  energy revenues,  thermal revenues,  the spread on sales of
          purchased power for hedging,  balancing, and optimization activity and
          generating revenue recorded in mark-to-market activities,  net, by (b)
          total generated MWh in the period.

     o    Average cost of natural gas expressed in dollars per millions of Btu's
          of fuel  consumed.  Our risk  management and  optimization  activities
          related to fuel  procurement  directly  impact our total fuel expense.
          The fuel costs for our  gas-fired  power  plants are a function of the
          price we pay for fuel  purchased  and the results of the fuel hedging,
          balancing,  and  optimization  activities  by  CES.  Accordingly,   we
          calculate  the  cost of  natural  gas per  millions  of  Btu's of fuel
          consumed in our power  plants by dividing  (a)  adjusted  fuel expense
          which  includes the cost of fuel  consumed by our plants  (adding back
          cost of  inter-company  gas pipeline  charges,  which is eliminated in
          consolidation),  the  spread on sales of  purchased  gas for  hedging,
          balancing,  and  optimization  activity  and fuel  expense  related to
          generation recorded in mark-to-market  activities, net by (b) the heat
          content  in  millions  of Btu's of the fuel we  consumed  in our power
          plants for the period.

     o    Average spark spread expressed in dollars per MWh generated.  Our risk
          management  activities  focus on  managing  the spark  spread  for our
          portfolio  of power  plants,  the spread  between  the sales price for
          electricity  generated  and the cost of fuel.  We calculate  the spark
          spread per MWh generated by subtracting (a) adjusted fuel expense from
          (b)  adjusted E&S revenue and  dividing  the  difference  by (c) total
          generated MWh in the period.


                                     - 81 -
<PAGE>

     o    Average plant  operating  expense per normalized MWh. To assess trends
          in electric power POX per MWh, we normalize the results from period to
          period by assuming a constant 70% total  company-wide  capacity factor
          (including both base load and peaker capacity) in deriving  normalized
          MWh. By normalizing the cost per MWh with a constant  capacity factor,
          we can better analyze trends and the results of our program to realize
          economies of scale,  cost reductions and  efficiencies at our electric
          generating  plants.  For  comparison  purposes we also include POX per
          actual MWh.

     The table below  presents,  the  operating  performance  metrics  discussed
above.
<TABLE>
<CAPTION>
                                                                    Three Months Ended September 30, Nine Months Ended September 30,
                                                                    -------------------------------- -------------------------------
                                                                          2005            2004            2005           2004
                                                                      -------------   -------------   -------------  --------------
                                                                                              (In thousands)
<S>                                                                   <C>             <C>             <C>            <C>
Operating Performance Metrics:
  Total deliveries of power:
    MWh generated..................................................          28,709          26,604          68,240         64,357
    HBO and trading MWh sold.......................................          11,643          13,395          36,072         39,157
                                                                      -------------   -------------   -------------  -------------
    MWh delivered..................................................          40,352          39,999         104,312        103,514
                                                                      =============   =============   =============  =============
  Average availability.............................................              97%             98%             92%            93%
  Average baseload capacity factor:
    Average total consolidated gross MW in operation...............          26,126          24,230          25,079         22,146
    Less: Average MW of pure peakers...............................           2,965           2,951           2,965          2,951
                                                                      -------------   -------------   -------------  -------------
    Average baseload MW in operation...............................          23,161          21,279          22,114         19,195
    Hours in the period............................................           2,208           2,208           6,552          6,576
    Potential baseload generation..................................          51,139          46,984         144,891        126,226
    Actual total generation........................................          28,709          26,604          68,240         64,357
    Less: Actual pure peakers' generation..........................           1,069             557           1,668          1,130
                                                                      -------------   -------------   -------------  -------------
    Actual baseload generation.....................................          27,640          26,047          66,572         63,227
    Average baseload capacity factor...............................            54.0%           55.4%           45.9%          50.1%
  Average heat rate for gas-fired power plants (excluding peakers)
   (Btu's/KWh):
    Not steam adjusted.............................................           8,050           8,276           8,346          8,292
    Steam adjusted.................................................           7,171           7,178           7,202          7,208
  Average all-in realized electric price:
    Electricity and steam revenue..................................   $   2,096,323   $   1,544,329   $   4,625,078  $   3,851,914
    Spread on sales of purchased power for hedging and optimization          69,503          79,355         233,427        135,912
                                                                      -------------   -------------   -------------  -------------
    Electricity and steam revenue before mark-to-market
     activities, net (in thousands)................................   $   2,165,826   $   1,623,684   $   4,858,505  $   3,987,826
    Electricity and steam revenue related to power generating
     in mark-to-market activities, net.............................          82,583               --         157,096              --
                                                                      -------------   --------------   -------------  --------------
    Adjusted electricity and steam revenue (in thousands)..........   $   2,248,409   $   1,623,684   $   5,015,601  $   3,987,826
    MWh generated (in thousands)...................................          28,709          26,604          68,240         64,357
    Average all-in realized electric price per MWh.................   $       78.32   $       61.03   $       73.50  $       61.96
  Average cost of natural gas:
    Fuel expense (in thousands)....................................   $   1,567,504   $   1,052,309   $   3,336,248  $   2,671,860
    Gas pipeline charge elimination (1)............................           1,803           3,118           6,738         14,509
    Spread on sales of purchased gas for hedging and optimization..          27,501           5,640          49,625        (14,660)
    Fuel expense related to power generation in
     mark-to-market activities, net................................          56,301               --         110,790              --
                                                                      -------------   --------------   -------------  --------------
    Adjusted fuel expense..........................................   $   1,653,109   $   1,061,067   $   3,503,401  $   2,671,709
    MMBtu of fuel consumed by generating plants (in thousands).....         189,321         178,868         451,480        444,460
    Average cost of natural gas per MMBtu..........................   $        8.73   $        5.93   $        7.76  $        6.01
    MWh generated (in thousands)...................................          28,709          26,604          68,240         64,357
    Average cost of adjusted fuel expense per MWh..................   $       57.58   $       39.88   $       51.34  $       41.51
  Average spark spread:
    Adjusted electricity and steam revenue (in thousands)..........   $   2,248,409   $   1,623,684   $   5,015,601  $   3,987,826
    Less: Adjusted fuel expense (in thousands).....................       1,653,109       1,061,067       3,503,401      2,671,709
                                                                      -------------   -------------   -------------  -------------
    Spark spread (in thousands)....................................   $     595,300   $     562,617   $   1,512,200  $   1,316,117
    MWh generated (in thousands)...................................          28,709          26,604          68,240         64,357
    Average spark spread per MWh...................................   $       20.74   $       21.15   $       22.16  $       20.45

                               (table continues)










                                     - 82 -
<PAGE>

                                                                    Three Months Ended September 30, Nine Months Ended September 30,
                                                                    -------------------------------- -------------------------------
                                                                          2005            2004            2005           2004
                                                                      -------------   -------------   -------------  --------------
                                                                                              (In thousands)
 Average POX per normalized MWh
   (for comparison purposes we also include POX per actual MWh):
    Average total consolidated gross MW in operations..............          26,126          24,230          25,079         22,146
    Hours in the period............................................           2,208           2,208           6,552          6,576
    Total potential MWh............................................          57,686          53,500         164,318        145,632
    Normalized MWh (at 70% capacity factor)........................          40,380          37,450         115,022        101,942
    Plant operating expense (POX)..................................   $     180,336   $     159,957   $     555,433  $     522,237
    POX per normalized MWh.........................................   $        4.47   $        4.27   $        4.83  $        5.12
    Actual MWh generated (in thousands)............................          28,709          26,604          68,240         64,357
                                                                      -------------   -------------   -------------  -------------
    POX per actual MWh.............................................   $        6.28   $        6.01   $        8.14  $        8.11
                                                                      -------------   -------------   -------------  -------------
------------
<FN>
     (1)  In prior year periods, "gas pipeline charges" also included some small
          amounts  for fuel  charges  related to gas  assets  since sold but not
          reclassified to discontinued operations.
</FN>
</TABLE>

     The  table  below  provides  additional  detail  of  total   mark-to-market
activity.  For the three and nine  months  ended  September  30,  2005 and 2004,
mark-to-market activities, net consisted of (dollars in thousands):
<TABLE>
<CAPTION>
                                                                    Three Months Ended September 30, Nine Months Ended September 30,
                                                                    -------------------------------- -------------------------------
                                                                          2005            2004            2005           2004
                                                                      -------------   -------------   -------------  --------------
<S>                                                                   <C>             <C>             <C>            <C>
Realized:
  Power activity
    "Trading Activity" as defined in EITF No. 02-03................   $     120,455   $       9,412   $     202,939  $      39,258
    Other mark-to-market activity (1)..............................            (946)           (434)         (9,607)        (6,378)
                                                                      -------------   -------------   -------------  -------------
     Total realized power activity.................................   $     119,509   $       8,978   $     193,332  $      32,880
                                                                      =============   =============   =============  =============
  Gas activity
    "Trading Activity" as defined in EITF No. 02-03................   $     (53,280)  $       9,679   $     (96,030) $       9,548
    Other mark-to-market activity (1)..............................            (286)             --            (286)            --
                                                                      -------------   -------------   -------------  -------------
     Total realized gas activity...................................   $     (53,566)  $       9,679   $     (96,316) $       9,548
                                                                      =============   =============   =============  =============
Total realized activity:
    "Trading Activity" as defined in EITF No. 02-03................   $      67,175   $      19,091   $     106,909  $      48,806
    Other mark-to-market activity (1)..............................         (1,232)           (434)         (9,893)        (6,378)
                                                                      -------------   -------------   -------------  -------------
     Total realized activity.......................................   $      65,943   $      18,657   $      97,016  $      42,428
                                                                      =============   =============   =============  =============
Unrealized:
  Power activity
    "Trading Activity" as defined in EITF No. 02-03................   $    (129,578)  $     (17,057)  $    (127,094) $     (40,926)
    Ineffectiveness related to cash flow hedges....................          (1,643)          1,142          (1,947)         1,268
    Other mark-to-market activity (1)..............................           1,935            (240)          3,681        (13,015)
                                                                      -------------   -------------   -------------  -------------
     Total unrealized power activity...............................   $    (129,286)  $     (16,155)  $    (125,360) $     (52,673)
                                                                      =============   =============   =============  =============
  Gas activity
    "Trading Activity" as defined in EITF No. 02-03................   $      94,546   $      (8,508)  $      58,124  $     (11,610)
    Ineffectiveness related to cash flow hedges....................           9,651             777          10,417          6,540
    Other mark-to-market activity (1)..............................              --              --              --             --
                                                                      -------------   -------------   -------------  -------------
     Total unrealized gas activity.................................   $     104,197   $      (7,731)  $      68,541  $      (5,070)
                                                                      =============   =============   =============  =============
Total unrealized activity:
  "Trading Activity" as defined in EITF No. 02-03..................   $     (35,032)  $     (25,565)  $     (68,970) $     (52,536)
  Ineffectiveness related to cash flow hedges......................           8,008           1,919           8,470          7,808
  Other mark-to-market activity (1)................................           1,935            (240)          3,681        (13,015)
                                                                      -------------   -------------   -------------  -------------
     Total unrealized activity.....................................   $.    (25,089)  $     (23,886)  $     (56,819) $     (57,743)
                                                                      =============   =============   =============  =============
Total mark-to-market activity:
  "Trading Activity" as defined in EITF No. 02-03..................   $      32,143   $      (6,474)  $      37,939  $      (3,730)
  Ineffectiveness related to cash flow hedges......................           8,008           1,919           8,470          7,808
  Other mark-to-market activity (1)................................             703            (674)         (6,212)       (19,393)
                                                                      -------------   -------------   -------------  -------------
     Total mark-to-market activity.................................   $      40,854   $      (5,229)  $      40,197  $     (15,315)
                                                                      =============   =============   =============  =============
------------

                               (table continues)

                                     - 83 -
<PAGE>

<FN>
(1) Activity related to our assets but does not qualify for hedge accounting.
</FN>
</TABLE>

Overview

     Summary of Key Activities Through September 30, 2005

     Finance -- New Issuances and Amendments:
<TABLE>
<CAPTION>
         Date                 Amount                                                 Description
----------------------  ----------------  ------------------------------------------------------------------------------------------
<S>                     <C>               <C>
8/12/05...............  $150.0 million    CCFC LLC  completes a $150.0  million  private  placement of Class A Redeemable  Preferred
                                             Shares; the preferred shares are repurchased in full on October 14, 2005
</TABLE>

     Finance -- Repurchases and Extinguishments:
<TABLE>
<CAPTION>
         Date                 Amount                                                 Description
----------------------  ----------------  ------------------------------------------------------------------------------------------
<S>                     <C>               <C>
7/12/05...............  $138.9 million    Purchase $138.9 million  aggregate  principal of outstanding First Priority Notes pursuant
                                             to a tender offer commenced June 9, 2005
7/13/05...............  $517.5 million    Repay the convertible  debentures  payable to Calpine Capital Trust III, the issuer of the
                                             HIGH TIDES III preferred securities,  the proceeds of which are applied by the Trust to
                                             redeem the HIGH TIDES III preferred securities in full
7/1/05-9/30/05........  $263.5 million    Repurchase  Senior Notes in open market  transaction  totaling $263.5 million in principal
                                             for cash of $233.9 million plus accrued interest
</TABLE>

     Asset Sales:
<TABLE>
<CAPTION>
         Date                                                            Description
----------------------  ------------------------------------------------------------------------------------------------------------
<S>                     <C>
7/7/05................  Complete  the  sale  of  substantially  all remaining  oil and gas exploration and production properties and
                           assets for $1.05 billion, less adjustments, transaction fees, and expenses
7/8/05................  Complete  the sale of 50% interest in the 175-MW Grays Ferry power plant for gross proceeds of $37.4 million
7/28/05...............  Complete the sale of Saltend, a 1,200-MW power plant in Hull, England, for $862.9 million
7/29/05...............  Complete  the  sale of Inland Empire Energy Center development project to GE for approximately $30.9 million
8/2/05................  Complete the sale of the 156-MW Morris power plant for $84.5 million
8/16/05...............  Agree to sell  561-MW  Ontelaunee;  the sale is  consummated  on  October  6, 2005,  for $225  million  less
                           adjustments, transaction fees and expenses
</TABLE>

     Power Plant Development and Construction:
<TABLE>
<CAPTION>
         Date                        Project                            Description
----------------------  ---------------------------------          --------------------
<S>                     <C>                                        <C>
7/1/05................  Bethpage Energy Center 3                   Commercial Operation
7/5/05................  Pastoria Energy Center (Phase II)          Commercial Operation
</TABLE>

     Other:
<TABLE>
<CAPTION>
         Date                                                            Description
----------------------  ------------------------------------------------------------------------------------------------------------
<S>                     <C>
7/5/05................  Sign an  agreement with Siemens-Westinghouse to restructure the long-term relationship, which is expected to
                          provide additional flexibility to self-perform maintenance work in the future
7/7/05................  Announce a 15-year Master Products and Services Agreement with GE to supplement operations with a variety of
                          services and to lower operating costs
7/11/05...............  Major  merchant  power  generator  selects PSM to install LEC-III (R) and eliminate 90% of the power plant's
                          nitrogen oxide emissions
8/26/05...............  CES  announces  new  service  agreements with Project Orange Associates LLC and the Greater Toronto Airports
                          Authority to provide them with marketing, scheduling, and other energy managements services
8/29/05...............  CES  announces  five  year  long-term  power  supply agreement for 170-MW of electricity with Tampa Electric
                          Company
9/7/05................  Agreed  to form an energy  marketing and  trading venture with Bear Stearns Companies,  Inc.( Bear Stearns).
                          The new energy venture is expected to develop a third-party  customer business focused on physical natural
                          gas  and  power  trading  and  related  structured   transactions.  Regulatory  approval  was  received on
                          Oct. 31, 2005, and it is anticipated that operations will begin in the fourth quarter of 2005.
</TABLE>






                                     - 84 -
<PAGE>

California Power Market

     The  volatility  in the  California  power  market  from  mid-2000  through
mid-2001 has produced significant  unanticipated  results. The unresolved issues
arising  in that  market,  where 41 of our 95 power  plants are  located,  could
adversely  affect  our  performance.  See Note 14 of the  Notes to  Consolidated
Condensed Financial Statements for a further discussion.

Financial Market Risks

     As we are primarily  focused on generation of electricity  using  gas-fired
turbines, our natural physical commodity position is "short" fuel (i.e., natural
gas consumer) and "long" power (i.e.,  electricity  seller).  To manage  forward
exposure  to  price  fluctuation  in  these  and  (to  a  lesser  extent)  other
commodities, we enter into derivative commodity instruments.

     The change in fair value of outstanding  commodity  derivative  instruments
from January 1, 2005 through  September  30, 2005,  is  summarized  in the table
below (in thousands):
<TABLE>
<CAPTION>
<S>                                            <C>                                                                  <C>
Fair value of contracts outstanding at January 1, 2005..........................................................    $       37,863
Cash losses recognized or otherwise settled during the period (1)...............................................             1,310
Non-cash gains recognized or otherwise settled during the period (2)............................................            38,125
Changes in fair value attributable to new contracts (3).........................................................          (331,155)
Changes in fair value attributable to price movements (4).......................................................          (245,081)
                                                                                                                    --------------
  Fair value of contracts outstanding at September 30, 2005.....................................................    $     (498,938)
                                                                                                                    ==============
Realized cash flow from fair value hedges (5)...................................................................    $      181,097
                                                                                                                    ==============
------------
<FN>
(1)  Realized  losses  from cash flow  hedges and  mark-to-market  activity  are
     reflected in the tables below (in millions):

Realized value of cash flow hedges (a)..........................................................................    $       (292.1)
Net of:
  Terminated and monetized derivatives..........................................................................             (23.2)
  Equity method hedges..........................................................................................               2.0
  Hedges reclassified to discontinued operations................................................................            (199.4)
                                                                                                                    --------------
  Cash losses realized from cash flow hedges....................................................................    $        (71.5)
                                                                                                                    --------------
Realized value of mark-to-market activity (b)...................................................................    $         97.0
Net of:
  Non-cash realized mark-to-market activity.....................................................................              26.8
                                                                                                                    --------------
  Cash gains realized on mark-to-market activity................................................................              70.2
                                                                                                                    --------------
  Cash losses recognized or otherwise settled during the period.................................................    $         (1.3)
                                                                                                                    ==============

     (a)  Realized  value as  disclosed  in Note 9 of the Notes to  Consolidated
          Condensed Financial Statements

     (b)  Realized value as reported in Management's  discussion and analysis of
          operating performance metrics

(2)  This represents the non-cash amortization of deferred items embedded in our
     derivative assets and liabilities.

(3)  The change  attributable  to new  contracts  includes  the  $292.4  million
     derivative  liability  associated  with  a  transaction  by our  Deer  Park
     facility  as  discussed  in Note 9 of the Notes to  Consolidated  Condensed
     Financial Statements.

(4)  Net  commodity  derivative  assets  reported  in  Note  9 of the  Notes  to
     Consolidated Condensed Financial Statements.

(5)  Not  included  as part of the  roll-forward  of net  derivative  assets and
     liabilities because changes in the hedge instrument and hedged item move in
     equal and  offsetting  directions  to the extent the fair value  hedges are
     perfectly effective.
</FN>
</TABLE>










                                     - 85 -
<PAGE>

     The fair value of outstanding derivative commodity instruments at September
30, 2005, based on price source and the period during which the instruments will
mature, are summarized in the table below (in thousands):
<TABLE>
<CAPTION>
              Fair Value Source                              2005         2006-2007       2008-2009       After 2009        Total
----------------------------------------------------      ----------      ----------      ----------      ----------      ----------
<S>                                                       <C>             <C>             <C>             <C>             <C>
Prices actively quoted .............................      $ 142,702       $  63,809       $      --       $      --       $ 206,511
Prices provided by other external sources ..........       (211,699)       (382,774)          3,414         (33,729)       (624,788)
Prices based on models and other
  valuation methods ................................             --             189         (56,563)        (24,287)        (80,661)
                                                          ---------       ---------       ---------       ---------       ---------
  Total fair value .................................      $ (68,997)      $(318,776)      $ (53,149)      $ (58,016)      $(498,938)
                                                          =========       =========       =========       =========       =========
</TABLE>

     Our risk  managers  maintain  fair value  price  information  derived  from
various  sources  in  our  risk  management  systems.   The  propriety  of  that
information  is validated  by our Risk Control  group.  Prices  actively  quoted
include  validation with prices sourced from  commodities  exchanges  (e.g., New
York Mercantile  Exchange).  Prices  provided by other external  sources include
quotes from commodity brokers and electronic trading platforms.  Prices based on
models and other valuation methods are validated using quantitative methods.

     The  counterparty   credit  quality  associated  with  the  fair  value  of
outstanding  derivative  commodity  instruments  at September 30, 2005,  and the
period  during which the  instruments  will mature are  summarized  in the table
below (in thousands):
<TABLE>
<CAPTION>
              Credit Quality                                 2005         2006-2007       2008-2009       After 2009        Total
----------------------------------------------------      ----------      ----------      ----------      ----------      ----------
<S>                                                       <C>             <C>             <C>             <C>             <C>
(Based on Standard & Poor's Ratings
  as of September 30, 2005)
Investment grade....................................      $ (79,177)      $(316,713)      $ (53,065)      $ (58,016)      $(506,971)
Non-investment grade................................         11,699           1,704             (20)             --          13,383
No external ratings.................................         (1,519)         (3,767)            (64)             --          (5,350)
                                                          ---------       ---------       ---------       ---------       ---------
  Total fair value..................................      $ (68,997)      $(318,776)      $ (53,149)      $ (58,016)      $(498,938)
                                                          =========       =========       =========       =========       =========
</TABLE>

     The fair value of outstanding derivative commodity instruments and the fair
value that would be expected after a ten percent  adverse price change are shown
in the table below (in thousands):

                                                                 Fair Value
                                                                  After 10%
                                                                   Adverse
                                              Fair Value        Price Change
                                             ------------      --------------
At September 30, 2005:
  Electricity.............................   $ (1,060,248)     $ (1,373,769)
  Natural gas.............................        561,310           387,411
                                             ------------      ------------
    Total.................................   $   (498,938)     $   (986,358)
                                             ===========       ============

     Derivative  commodity  instruments included in the table are those included
in Note 9 of the Notes to Consolidated Condensed Financial Statements.  The fair
value of  derivative  commodity  instruments  included  in the table is based on
present value adjusted  quoted market prices of comparable  contracts.  The fair
value of electricity  derivative commodity instruments after a 10% adverse price
change  includes the effect of  increased  power  prices  versus our  derivative
forward commitments.  Conversely,  the fair value of the natural gas derivatives
after a 10% adverse price change reflects a general decline in gas prices versus
our derivative forward commitments.  Derivative commodity instruments offset the
price risk  exposure of our physical  assets.  None of the  offsetting  physical
positions are included in the table above.

     Price changes were calculated by assuming an  across-the-board  10% adverse
price change regardless of term or historical  relationship between the contract
price of an instrument and the underlying  commodity  price.  In the event of an
actual 10% change in prices,  the fair value of our derivative  portfolio  would
typically  change by more than 10% for earlier  forward months and less than 10%
for later forward months because of the higher volatilities in the near term and
the effects of discounting expected future cash flows.

     The primary  factors  affecting  the fair value of our  derivatives  at any
point in time are (1) the volume of open derivative  positions  (MMBtu and MWh),
and (2) changing  commodity  market  prices,  principally  for  electricity  and
natural gas. The total volume of open gas derivative  positions increased by 44%



                                     - 86 -
<PAGE>

from  December 31, 2004,  to  September  30, 2005,  and the total volume of open
power derivative positions increased by 135% for the same period. In that prices
for  electricity  and natural gas are among the most  volatile of all  commodity
prices,  there may be material changes in the fair value of our derivatives over
time,  driven  both by  price  volatility  and the  changes  in  volume  of open
derivative  transactions.   Under  SFAS  No.  133,  "Accounting  for  Derivative
Instruments  and Hedging  Activities,"  the change since the last balance  sheet
date in the total value of the  derivatives  (both  assets and  liabilities)  is
reflected  either in OCI, net of tax, or in the  statement of  operations  as an
item (gain or loss) of current earnings. As of September 30, 2005, a significant
component of the balance in accumulated  OCI represented the unrealized net loss
associated with commodity cash flow hedging transactions.  As noted above, there
is a substantial amount of volatility  inherent in accounting for the fair value
of these  derivatives,  and our results  during the three and nine months  ended
September  30, 2005,  have  reflected  this.  See Notes 9 and 10 of the Notes to
Consolidated  Condensed  Financial  Statements  for  additional  information  on
derivative activity.

     Interest  Rate  Swaps  -- From  time to time,  we use  interest  rate  swap
agreements  to mitigate our exposure to interest  rate  fluctuations  associated
with  certain of our debt  instruments  and to adjust the mix between  fixed and
floating  rate debt in our capital  structure to desired  levels.  We do not use
interest rate swap agreements for speculative or trading purposes. The following
tables  summarize  the fair market  values of our  existing  interest  rate swap
agreements as of September 30, 2005 (dollars in thousands):

     Variable to Fixed Swaps
<TABLE>
<CAPTION>
                                                                             Weighted
                                                                              Average          Weighted Average
                                                            Notional       Interest Rate         Interest Rate         Fair Market
Maturity Date                                            Principal Amount       (Pay)              (Receive)               Value
-----------------------------------------------------   ----------------- ---------------  -----------------------  ---------------
<C>                                                     <C>                     <C>        <C>                      <C>
2009..................................................  $       50,000          4.8%       3-month US $LIBOR        $         (488)
2011..................................................          57,291          4.5%       3-month US $LIBOR                   (11)
2011..................................................         287,447          4.5%       3-month US $LIBOR                   (44)
2011..................................................         201,003          4.4%       3-month US $LIBOR                   725
2011..................................................          40,062          4.4%       3-month US $LIBOR                   145
2011..................................................          12,347          6.9%       3-month US $LIBOR                (2,554)
2011..................................................          50,300          4.9%       3-month US $LIBOR                  (647)
2011..................................................          24,695          4.8%       3-month US $LIBOR                  (495)
2011..................................................          12,347          4.8%       3-month US $LIBOR                  (248)
2011..................................................          15,986          4.9%       3-month US $LIBOR                  (323)
2011..................................................          15,986          4.9%       3-month US $LIBOR                  (323)
2011..................................................          12,347          4.8%       3-month US $LIBOR                  (248)
2011..................................................          15,986          4.9%       3-month US $LIBOR                  (323)
2011..................................................          12,347          4.8%       3-month US $LIBOR                  (248)
2012..................................................         100,926          6.5%       3-month US $LIBOR                (7,742)
2016..................................................          20,355          7.3%       3-month US $LIBOR                (2,907)
2016..................................................          13,570          7.3%       3-month US $LIBOR                (1,936)
2016..................................................          40,710          7.3%       3-month US $LIBOR                (5,809)
2016..................................................          27,140          7.3%       3-month US $LIBOR                (3,872)
2016..................................................          33,925          7.3%       3-month US $LIBOR                (4,841)
                                                        --------------                                              --------------
   Total..............................................  $    1,044,770          5.1%                                $      (32,189)
                                                        ==============                                              ==============
</TABLE>

     Fixed to Variable Swaps
<TABLE>
<CAPTION>
                                                                             Weighted Average      Weighted Average
                                                            Notional          Interest Rate         Interest Rate     Fair Market
Maturity Date                                           Principal Amount          (Pay)               (Receive)           Value
-----------------------------------------------------   ---------------- ------------------------  ----------------  --------------
<C>                                                     <C>              <C>                             <C>         <C>
2011..................................................  $      100,000   6-month US $LIBOR               8.5%        $       (6,520)
2011..................................................         100,000   6-month US $LIBOR               8.5%                (7,442)
2011..................................................         100,000   6-month US $LIBOR               8.5%                (5,090)
2011..................................................         200,000   6-month US $LIBOR               8.5%               (10,465)
                                                        --------------                                               --------------
   Total..............................................  $      500,000                                   8.5%        $      (29,517)
                                                        ==============                                               ==============
</TABLE>











                                     - 87 -
<PAGE>

     The fair value of  outstanding  interest rate swaps and the fair value that
would be expected after a 1% adverse interest rate change are shown in the table
below (in thousands):

                                                          Fair Value After a
                                                                 1.0%
                                                          (100 Basis Point)
                                                              Adverse
Net Fair Value as of September 30, 2005                  Interest Rate Change
---------------------------------------                 ---------------------
$(61,706)............................................         $  (82,200)

     Currency Exposure -- We own subsidiary entities in several countries. These
entities  generally have functional  currencies other than the U.S.  dollar.  In
most cases, the functional currency is consistent with the local currency of the
host country where the particular  entity is located.  In certain cases,  we and
our foreign subsidiary entities hold monetary assets and/or liabilities that are
not  denominated  in the  functional  currencies  referred  to  above.  In  such
instances,   we  apply  the  provisions  of  SFAS  No.  52,  "Foreign   Currency
Translation,"  ("SFAS No. 52") to account for the monthly  re-measurement  gains
and losses of these assets and  liabilities  into the functional  currencies for
each entity.  In some cases we can reduce our potential  exposures to net income
by designating liabilities denominated in non-functional currencies as hedges of
our net  investment  in a foreign  subsidiary  or by  entering  into  derivative
instruments  and  designating  them in hedging  relationships  against a foreign
exchange  exposure.  Based on our unhedged  exposures at September 30, 2005, the
impact to our pre-tax earnings that would be expected after a 10% adverse change
in exchange rates is shown in the table below (in thousands):

                                                   Impact to Pre-Tax Net Income
                                                    After 10% Adverse Exchange
Currency Exposure                                         Rate Change
-----------------                                  ----------------------------
GBP-Euro......................................           $    (14,758)
$Cdn-$US......................................               (131,367)
$Cdn-GBP......................................                (13,885)
Other.........................................                 (1,869)

     In  prior  periods,   we  reported   significant   unhedged  positions  and
corresponding  foreign currency transaction gains and losses due to our exposure
to changes in the GBP-$US exchange rate. As a result of the sale of Saltend (see
Note 8 of the Notes to  Consolidated  Condensed  Financial  Statements  for more
information),  effectively  all of our  GBP-$US  accounting  exposure  has  been
eliminated. We expect that currency movements will continue to create volatility
within our  pre-tax  earnings  in future  periods,  but such  volatility  is not
expected to result from movements in the GBP-$US exchange rate.

     Significant changes in exchange rates will also impact our CTA balance when
translating  the  financial  statements  of our  foreign  operations  from their
respective functional  currencies into our reporting currency,  the U.S. dollar.
An example of the impact that  significant  exchange rate  movements can have on
our Balance Sheet position  occurred in 2004.  During 2004, our CTA increased by
approximately  $62 million  primarily  due to a  strengthening  of the  Canadian
dollar and GBP against the U.S. dollar by approximately 7% each.

Foreign Currency Transaction Gain (Loss)

     Three  Months  Ended  September  30,  2005,  Compared to Three Months Ended
September 30, 2004:

     The major  components  of our  foreign  currency  transaction  losses  from
continuing  operations  of $43.9  million and $12.4 million for the three months
ended  September  30, 2005 and 2004,  respectively,  are as follows  (amounts in
millions):

                                                                2005      2004
                                                              --------  --------
Loss from $Cdn-$US fluctuations............................   $ (54.6)  $  (8.6)
Loss from GBP-Euro fluctuations............................      (2.0)     (4.1)
Gain (Loss) from $Cdn-GBP fluctuations.....................      12.8        --
Gain (Loss) from other currency fluctuations...............      (0.1)      0.3
                                                              -------   -------
   Total...................................................   $ (43.9)  $ (12.4)
                                                              =======   =======

     The $Cdn-$US loss for the three months ended  September  30, 2005,  was due
primarily to a  significant  weakening of the U.S.  dollar  against the Canadian
dollar  during  the  third   quarter  of  2005.  In  September   2004,  we  sold
substantially  all of our oil and gas  assets  in  Canada,  which  significantly
reduced the degree to which we could designate our $Cdn-denominated  liabilities
as hedges against our investment in Canadian dollar denominated subsidiaries. As
a result,  we are now considerably  more exposed to fluctuations in the $Cdn-$US
exchange rate as we hold several significant  $Cdn-denominated  liabilities that
can no longer be hedged under SFAS No. 52. When the U.S.  dollar weakened during



                                     - 88 -
<PAGE>

the third quarter of 2005,  significant  re-measurement losses were triggered on
these  loans.  These  losses  were  partially  offset  by  re-measurement  gains
recognized on the  translation of the interest  receivable  associated  with our
large  intercompany loan that has been deemed a permanent  investment under SFAS
No.  52.  While  re-measurement  gains and losses  associated  with the loan are
recorded within CTA, the  re-measurement of the underlying  interest  receivable
every  period  continues  to be recorded as a component of net income due to the
fact that the interest is physically settled semi-annually.

     The  $Cdn-$US  loss for the three  months ended  September  30,  2004,  was
moderate despite the fact that the U.S. dollar weakened considerably against the
Canadian  dollar during the third quarter of 2004.  The primary  reason for this
was because the majority of our existing  $Cdn-$US  exposures  were  effectively
designated  as hedges of our net  investment  in  Canadian  dollar  subsidiaries
through early September 2004. As a result,  re-measurement losses that otherwise
would have been  recognized  within our  Consolidated  Condensed  Statements  of
Operations were recorded within CTA in accordance with SFAS No. 52. In September
2004, we completed the sale of our Canadian oil and gas assets and subsequent to
this transaction, the Canadian dollar strengthened considerably against the U.S.
dollar for the rest of the month.  The loss of the majority of our natural hedge
position combined with the strengthened  Canadian dollar created the majority of
the $Cdn-$US loss of $8.6 million for the three months ended September 30, 2004.
The loss recognized was partially offset by  re-measurement  gains recognized on
the   translation  of  the  interest   receivable   associated  with  our  large
intercompany loan that has been deemed a permanent  investment under SFAS No. 52
as described above.

     During the three months ended  September  30, 2005 and 2004,  respectively,
the  Euro  strengthened  against  the  GBP,  triggering   re-measurement  losses
associated with our Euro-denominated 8 3/8% Senior Notes Due 2008.

     The primary  driver  behind our gain of $12.8  million from other  $Cdn-GBP
fluctuations  for the three months ended September 30, 2005, was due to the sale
of  Saltend  in July  2005,  combined  with a  subsequent  strengthening  of the
Canadian dollar against the GBP. One of our $Cdn-denominated  subsidiaries holds
a  significant  GBP-denominated  liability  position  which relates to financing
borrowed for the original  purchase of Saltend in 2001.  Prior to the sale, this
liability  position was designated as a hedge of the subsidiary's net investment
in Saltend and as a result, all re-measurement  gains and losses associated with
the  liability  were  recorded  within  CTA in  accordance  with  SFAS  No.  52.
Subsequent to the sale, all such re-measurement gains and losses are required to
be recorded within net income as we no longer own a  GBP-denominated  investment
to hedge  against.  The  strengthening  of the Canadian  dollar  against the GBP
during the third  quarter of 2005 created  significant  re-measurement  gains on
this newly exposed liability position.  For the three months ended September 30,
2004, our $Cdn-GBP  liability  position was effectively  hedged and as a result,
all re-measurement gains and losses were recorded as a component of CTA.

     Nine Months  Ended  September  30,  2005,  Compared  to Nine  Months  Ended
September 30, 2004:

     The major  components of our foreign currency  transaction  losses of $18.3
million and $7.6 million,  respectively, for the nine months ended September 30,
2005 and 2004, respectively, are as follows (amounts in millions):

                                                                2005      2004
                                                              --------  --------
Loss from $Cdn-$US fluctuations............................   $ (35.6)  $ (14.0)
Gain from GBP-Euro fluctuations............................       7.6       6.5
Gain (Loss) from $Cdn-GBP fluctuations.....................      11.9        --
Loss from other currency fluctuations......................      (2.2)     (0.1)
                                                              -------   -------
Total......................................................   $ (18.3)  $  (7.6)
                                                              =======   =======

     The $Cdn-$US  loss for the nine months ended  September  30, 2005,  was due
primarily to a  significant  weakening of the U.S.  dollar  against the Canadian
dollar, most significantly  within the third quarter of 2005. In September 2004,
we  sold  substantially  all  of  our  oil  and  gas  assets  in  Canada,  which
significantly   reduced   the   degree   to  which  we   could   designate   our
$Cdn-denominated liabilities as hedges against our investment in Canadian dollar
denominated  subsidiaries.  As a result, we are now considerably more exposed to
fluctuations  in the  $Cdn-$US  exchange  rate  as we hold  several  significant
$Cdn-denominated  liabilities  that can no longer be hedged  under  SFAS No. 52.
When the U.S. dollar weakened,  significant re-measurement losses were triggered
on these  loans.  These losses were  partially  offset by  re-measurement  gains
recognized on the  translation of the interest  receivable  associated  with our
large  intercompany loan that has been deemed a permanent  investment under SFAS
No.  52.  While  re-measurement  gains and losses  associated  with the loan are
recorded within CTA, the  re-measurement of the underlying  interest  receivable
every  period  continues  to be recorded as a component of net income due to the
fact that the interest is physically settled semi-annually.





                                     - 89 -
<PAGE>

     The $Cdn-$US  loss for the nine months ended  September 30, 2004 was due to
two primary  reasons.  First,  in September  2004,  we completed the sale of our
Canadian oil and gas assets and  subsequent  to this  transaction,  the Canadian
dollar  strengthened  considerably  against the U.S.  dollar for the rest of the
month.  The sale  eliminated  the  majority  of our  natural  hedge  position as
described  above,  resulting in a large open  exposure that was  susceptible  to
volatility in the $Cdn-$US exchange rate.  Second, we recognized  re-measurement
losses on the translation of the interest  receivable  associated with our large
intercompany  loan that has been deemed a permanent  investment during the first
two quarters of 2004, as the Canadian  dollar  weakened  against the U.S. dollar
during  this  period.  As  noted  above,  physical  settlement  of the  interest
receivable  occurs  semi-annually,  in May and November.  As a result,  the most
significant  re-measurement  gains and losses  associated  with this  receivable
generally  occur  within  1-2  months of the  payment  date,  as the  receivable
approaches its full value for the 6-month period.  From January to May 2004, the
U.S.  dollar  strengthened  considerably  against the Canadian  dollar while the
interest   receivable   balance   grew   significantly,   resulting   in   large
re-measurement  losses.  These  losses were  partially  offset  during the third
quarter of 2004 as the Canadian dollar strengthened against the U.S. dollar, but
the average interest receivable balance outstanding during the third quarter was
not as large as the balance  outstanding in March and April,  resulting in a net
loss for the nine months ended September 30, 2004.

     During the nine months ended September 30, 2005 and 2004, respectively, the
Euro weakened against the GBP, triggering  re-measurement  gains associated with
our Euro-denominated 8 3/8% Senior Notes Due 2008.

     The primary  driver  behind our gain of $11.9  million from other  $Cdn-GBP
fluctuations  for the nine months ended  September 30, 2005, was due to the sale
of  Saltend  in July  2005,  combined  with a  subsequent  strengthening  of the
Canadian dollar against the GBP. One of our $Cdn-denominated  subsidiaries holds
a  significant  GBP-denominated  liability  position  which relates to financing
borrowed for the original  purchase of Saltend in 2001.  Prior to the sale, this
liability  position was designated as a hedge of the subsidiary's net investment
in Saltend and as a result, all re-measurement  gains and losses associated with
the  liability  were  recorded  within  CTA in  accordance  with  SFAS  No.  52.
Subsequent to the sale, all such re-measurement gains and losses are required to
be recorded within net income as we no longer own a  GBP-denominated  investment
to hedge  against.  The  strengthening  of the Canadian  dollar  against the GBP
during the third  quarter of 2005 created  significant  re-measurement  gains on
this newly exposed liability  position.  For the nine months ended September 30,
2004, our $Cdn-GBP  liability  position was effectively  hedged and as a result,
all re-measurement gains and losses were recorded as a component of CTA.

     The primary  driver  behind our loss of $2.2  million  from other  currency
fluctuations  for the nine months  ended  September  30, 2005 was a  significant
strengthening  of the U.S.  dollar  against the Euro,  and its impact on certain
U.S. dollar-denominated  intercompany trade payables owed by our TTS subsidiary.
By contrast,  movement in the $US-Euro exchange rate was relatively flat for the
nine months  ended  September  30 2004 and as a result,  minimal  re-measurement
losses were created.

     Available-for-Sale  Debt  Securities  -- On July 13, 2005, we completed the
redemption of all of the outstanding HIGH TIDES III preferred  securities and of
the underlying convertible debentures. Accordingly, the HIGH TIDES III preferred
securities repurchased by us are no longer outstanding. See Notes 4 and 7 of the
Notes to Consolidated Condensed Financial Statements for further information.

     Debt Financing -- Because of the significant  capital  requirements  within
our industry,  debt  financing is often needed to fund our growth.  Certain debt
instruments may affect us adversely because of changes in market conditions.  We
have used two  primary  forms of debt  which are  subject  to market  risk:  (1)
Variable  rate  construction/project   financing  and  (2)  other  variable-rate
instruments.  Significant  LIBOR  increases  could have a negative impact on our
future interest expense.

     Our variable-rate  construction/project  financing is primarily through the
CalGen  floating  rate  notes,  institutional  term loans and  revolving  credit
facility.  Borrowings  under our $200 million CalGen  revolving credit agreement
are used  primarily  for  letters of credit in support of gas  purchases,  power
contracts and transmission,  and was available for the construction costs of the
Pastoria  Energy  Center  expansion  project,  which was completed in July 2005.
Other  variable-rate  instruments  consist primarily of our revolving credit and
term loan facilities,  which are used for general corporate  purposes.  Both our
variable-rate construction/project financing and other variable-rate instruments
are indexed to base rates, generally LIBOR, as shown below.

     On  August  12,  2005,  we  issued  $150.0  million  of Class A  Redeemable
Preferred  Shares due  February  13,  2006,  through our wholly  owned  indirect
subsidiary,  CCFC LLC,  which is an  indirect  parent of CCFC I. The  Redeemable
Preferred  Shares bear an initial  dividend  rate of LIBOR plus 950 basis points
and may be  redeemed  in whole or in part at any time by the  issuer at par plus
accrued dividends.  The Redeemable  Preferred Shares were repurchased in full on
October 14, 2005.



                                     - 90 -
<PAGE>

     The following  table  summarizes by maturity  date our  variable-rate  debt
exposed to interest rate risk as of September  30, 2005.  All fair market values
are shown net of applicable premium or discount, if any (dollars in thousands):
<TABLE>
<CAPTION>
                                                                            2005           2006           2007           2008
                                                                         ----------     ----------     ----------     ----------
<S>                                                                      <C>            <C>            <C>            <C>
3-month US $LIBOR weighted average interest rate basis (4)
  MEP Pleasant Hill Term Loan, Tranche A ...........................     $    2,528     $    7,482     $    8,132     $    9,271
  Riverside Energy Center project financing ........................             --          3,685          3,685          3,685
  Rocky Mountain Energy Center project financing ...................             --          2,649          2,649          2,649
                                                                         ----------     ----------     ----------     ----------
    Total of 3-month US $LIBOR rate debt ...........................          2,528         13,816         14,466         15,605
1-month EURLIBOR weighted average interest rate basis (4)
  Thomassen revolving line of credit ...............................          2,417             --             --             --
                                                                         ----------     ----------     ----------     ----------
    Total of 1-month EURLIBOR rate debt ............................          2,417             --             --             --
1-month US $LIBOR weighted average interest rate basis (4)
First Priority Secured Floating Rate Notes Due 2009
   (CalGen) ........................................................             --             --          1,175          2,350
                                                                         ----------     ----------     ----------     ----------
    Total of 1-month US $LIBOR weighted average
     interest rate debt ............................................             --             --          1,175          2,350
1-month US $LIBOR interest rate basis (4)
  Freeport Energy Center project financing .........................             --             --          1,969          1,810
  Mankato Energy Center project financing ..........................             --             --          1,727          1,781
                                                                         ----------     ----------     ----------     ----------
    Total 1-month US $LIBOR interest rate ..........................             --             --          3,696          3,591
6-month US $LIBOR weighted average interest rate basis (4)
  Third Priority Secured Floating Rate Notes Due 2011
   (CalGen) ........................................................             --             --             --             --
                                                                         ----------     ----------     ----------     ----------
    Total of 6-month US $LIBOR rate debt ...........................             --             --             --             --
(1)(4)
  Class A Redeemable Preferred Shares (CCFC) .......................             --        150,000             --             --
  Metcalf Energy Center, LLC preferred interest ....................             --             --             --             --
  First Priority Secured Institutional Term Loan Due 2009
   (CCFC I) ........................................................             --          3,208          3,208          3,208
  Second Priority Senior Secured Floating Rate Notes
   Due 2011 (CCFC I) ...............................................             --             --             --             --
                                                                         ----------     ----------     ----------     ----------
    Total of variable rate debt as defined at (1) below ............             --        153,208          3,208          3,208
(2)(4)
  Second Priority Senior Secured Term Loan B Notes
   Due 2007 ........................................................          1,875          7,500        725,625             --
                                                                         ----------     ----------     ----------     ----------
    Total of variable rate debt as defined at (2) below ............          1,875          7,500        725,625             --
(3)(4)
  Second Priority Senior Secured Floating Rate Notes
   Due 2007 ........................................................          1,250          5,000        483,750             --
  Blue Spruce Energy Center project financing ......................            938          3,750          3,750          3,750
                                                                         ----------     ----------     ----------     ----------
    Total of variable rate debt as defined at (3) below ............          2,188          8,750        487,500          3,750
(5)(4)
  First Priority Secured Term Loans Due 2009 (CalGen) ..............             --             --          3,000          6,000
  Second Priority Secured Floating Rate Notes Due 2010
   (CalGen) ........................................................             --             --             --          3,200
  Second Priority Secured Term Loans Due 2010 (CalGen) .............             --             --             --            500
  Metcalf Energy Center, LLC project financing .....................             --             --             --             --
                                                                         ----------     ----------     ----------     ----------
    Total of variable rate debt as defined at (5) below ............             --             --          3,000          9,700
                                                                         ----------     ----------     ----------     ----------
(6)(4)
  Island Cogen .....................................................          9,860             --             --             --
  Contra Costa .....................................................             --            171            179            187
                                                                         ----------     ----------     ----------     ----------
    Total of variable rate debt as defined at (6) below ............          9,860            171            179            187
                                                                         ----------     ----------     ----------     ----------
      Grand total variable-rate debt instruments (8) ...............     $   18,868     $  183,445     $1,238,849     $   38,391
                                                                         ==========     ==========     ==========     ==========
</TABLE>















                                     - 91 -
<PAGE>

<TABLE>
<CAPTION>
                                                                                     2009        Thereafter   September 30, 2005 (7)
                                                                                 -----------     ----------   ----------------------
<S>                                                                              <C>             <C>             <C>
3-month US $LIBOR weighted average interest rate basis (4)
  MEP Pleasant Hill Term Loan, Tranche A ....................................    $     9,433     $   85,479      $   122,325
  Riverside Energy Center project financing .................................          3,685        340,553          355,293
  Rocky Mountain Energy Center project financing ............................          2,649        235,276          245,872
                                                                                 -----------     ----------      -----------
    Total of 3-month US $LIBOR rate debt ....................................         15,767        661,308          723,490
1-month EURLIBOR weighted average interest rate basis (4)
  Thomassen revolving line of credit ........................................             --             --            2,417
                                                                                 -----------     ----------      -----------
    Total of 1-month EURLIBOR rate debt .....................................             --             --            2,417
1-month US $LIBOR weighted average interest rate basis (4)
  First Priority Secured Floating Rate Notes Due 2009 (CalGen) ..............        231,475             --          235,000
                                                                                 -----------     ----------      -----------
    Total of 1-month US $LIBOR weighted average interest rate debt ..........        231,475             --          235,000
1-month US $LIBOR interest rate basis (4)
  Freeport Energy Center project financing ..................................          1,600        122,058          127,437
  Mankato Energy Center project financing ...................................          1,530        112,500          117,538
                                                                                 -----------     ----------      -----------
    Total 1-month US $LIBOR interest rate ...................................          3,130        234,558          244,975
6-month US $LIBOR weighted average interest rate basis (4)
  Third Priority Secured Floating Rate Notes Due 2011 (CalGen) ..............             --        680,000          680,000
                                                                                 -----------     ----------      -----------
    Total of 6-month US $LIBOR rate debt ....................................             --        680,000          680,000
(1)(4)
  Class A Redeemable Preferred Shares (CCFC) ................................             --             --          150,000
  Metcalf Energy Center, LLC preferred interest .............................             --        155,000          155,000
  First Priority Secured Institutional Term Loan Due 2009
   (CCFC I) .................................................................        365,189             --          374,813
  Second Priority Senior Secured Floating Rate Notes Due 2011
   (CCFC I) .................................................................             --        409,296          409,296
                                                                                 -----------     ----------      -----------
    Total of variable rate debt as defined at (1) below .....................        365,189        564,296        1,089,109
(2)(4)
  Second Priority Senior Secured Term Loan B Notes Due 2007 .................             --             --          565,950
                                                                                 -----------     ----------      -----------
    Total of variable rate debt as defined at (2) below .....................             --             --          565,950
(3)(4)
  Second Priority Senior Secured Floating Rate Notes Due 2007 ...............             --             --          377,300
  Blue Spruce Energy Center project financing ...............................          3,750         81,395           97,333
                                                                                 -----------     ----------      -----------
    Total of variable rate debt as defined at (3) below .....................          3,750         81,395          474,633
(5)(4)
  First Priority Secured Term Loans Due 2009 (CalGen) .......................        591,000             --          600,000
  Second Priority Secured Floating Rate Notes Due 2010 (CalGen) .............          6,400        623,239          632,839
  Second Priority Secured Term Loans Due 2010 (CalGen) ......................          1,000         97,381           98,881
  Metcalf Energy Center, LLC project financing ..............................             --        100,000          100,000
                                                                                 -----------     ----------      -----------
    Total of variable rate debt as defined at (5) below .....................        598,400        820,620        1,431,720
                                                                                 -----------     ----------      -----------
(6)(4)
Island Cogen ................................................................             --             --            9,860
Contra Costa ................................................................            196          1,381            2,114
                                                                                 -----------     ----------      -----------
    Total of variable rate debt as defined at (6) below .....................            196          1,381           11,974
                                                                                 -----------     ----------      -----------
     Grand total variable-rate debt instruments (8) .........................    $ 1,217,907     $3,043,558      $ 5,459,268
                                                                                 ===========     ==========      ===========
------------
<FN>
(1)  British  Bankers  Association  LIBOR Rate for  deposit in US dollars  for a
     period of six months.

(2)  U.S. prime rate in combination with the Federal Funds Effective Rate.

(3)  British  Bankers  Association  LIBOR Rate for  deposit in US dollars  for a
     period of three months.

(4)  Actual interest rates include a spread over the basis amount.

(5)  Choice of 1-month US $LIBOR,  2-month US $LIBOR, 3-month US $LIBOR, 6-month
     US $LIBOR, 12-month US $LIBOR or a base rate.

(6)  Bankers Acceptance Rate.

(7)  Fair value equals carrying value, with the exception of the Second-Priority
     Senior  Secured Term B Loans Due 2007 and  Second-Priority  Senior  Secured
     Floating Rate Notes Due 2007,  which are shown at quoted  trading values as
     of September 30, 2005.

                               (table continues)


                                     - 92 -
<PAGE>

(8)  The aggregate  principal amount subject to variable  interest rate risk was
     $5,741.0 million as of September 30, 2005.
</FN>
</TABLE>

New Accounting Pronouncements (See Note 2 of the Notes to Consolidated Condensed
Financial Statements for a discussion of new accounting pronouncements)

     Summary of Dilution  Potential of Our Contingent  Convertible  Notes:  2023
Convertible  Notes,  2015 Convertible  Notes and 2014  Convertible  Notes -- The
table below assumes  normal  conversion  for the 2014  Convertible  Notes,  2015
Convertible  Notes and 2023  Convertible  Notes in which the principal amount is
paid in cash,  and the  excess up to the  conversion  value is paid in shares of
Calpine  common stock.  The table shows only the  potential  impact of our three
contingent  convertible  notes  issuances  and does not  include  the  potential
dilutive  effect of the now fully redeemed HIGH TIDES III preferred  securities,
the remaining 2006 Convertible Notes or employee stock options. Additionally, we
are still assessing the potential impact of the SFAS No. 128-R exposure draft on
our three series of contingent convertible securities. See Notes 2 and 11 of the
Notes to Consolidated Condensed Financial Statements for more information.
<TABLE>
<CAPTION>
                                                                                       2014              2015              2023
                                                                                    Convertible       Convertible       Convertible
                                                                                       Notes             Notes             Notes
                                                                                  -------------     -------------     --------------
<S>                                                                               <C>               <C>               <C>
Aggregate outstanding principal amount at maturity............................    $  641,685,000    $  650,000,000    $  633,775,000
Conversion price per share....................................................    $         3.85    $         4.00    $         6.50
Conversion rate...............................................................          259.7402          250.0000          153.8462
Trigger price (20% over conversion price).....................................    $         4.62    $         4.80    $         7.80
</TABLE>

Additional Shares
<TABLE>
<CAPTION>
                                                 2014             2015              2023
                                              Convertible      Convertible       Convertible          Share        Share    Dilution
Future Calpine Common Stock Price              Notes (2)          Notes             Notes           Subtotal     Increase    in EPS
---------------------------------------    ---------------  ----------------  ----------------  ---------------- ---------- --------
<S>                                            <C>              <C>                                 <C>            <C>         <C>
$5.00..................................        38,334,429       32,500,000                --        70,834,429     14.8%       12.9%
$7.50..................................        81,113,429       75,833,333        13,000,542       169,947,304     35.6%       26.2%
$10.00.................................       102,502,929       97,500,000        34,126,375       234,129,304     49.0%       32.9%
$20.00.................................       134,587,179      130,000,000        65,815,125       330,402,304     69.2%       40.9%
$40.00.................................       150,629,304      146,250,000        81,659,500       378,538,804     79.2%       44.2%
$100.00................................       160,254,579      156,000,000        91,166,125       407,420,704     85.3%       46.0%

Common shares outstanding at
  September 30, 2005 (1)...............       478,964,218
------------
<FN>
(1)  Excludes the 89 million  shares  issued under the Share  Lending  Agreement
     (see Note 11 of the Notes to Consolidated  Condensed Financial  Statements)
     and excludes our contingently issuable restricted stock.

(2)  In the case of the 2014 Convertible Notes, more shares could be issued when
     the  accreted  value is less than  $1,000  than in the table  above  since,
     generally,  the accreted value  (initially  $839 per bond) is paid in cash,
     and the  balance of the  conversion  value is paid in shares.  The  maximum
     potential incremental shares assuming conversion when the accreted value is
     $839 per bond are shown in the table below:

                                                              Incremental
        Future Calpine Common Stock Price                        Shares
        ---------------------------------                     -----------
        $5.00.................................................20,662,257
        $7.50.................................................13,774,838
        $10.00................................................10,331,129
        $20.00.................................................5,165,564
        $40.00.................................................2,582,782
        $100.00................................................1,033,113
</FN>
</TABLE>
Item 3. Quantitative and Qualitative Disclosures About Market Risk.

     See "Financial Market Risks" in Item 2.










                                     - 93 -
<PAGE>

Item 4.  Controls and Procedures.

Disclosure Controls and Procedures

     We maintain  disclosure controls and procedures that are designed to ensure
that  information  we are required to disclose in reports that we file or submit
under the Securities Exchange Act of 1934 is recorded, processed, summarized and
reported within the time periods specified in SEC rules and forms, and that such
information is accumulated and  communicated  to our  management,  including our
Chief Executive Officer and Chief Financial  Officer,  as appropriate,  to allow
timely decisions regarding required disclosure.

     As of December 31, 2004,  management identified a material weakness related
to our tax accounting  processes,  procedures and controls that was discussed in
Item 9A of the  Company's  2004 Form 10-K.  During the first  three  quarters of
2005, we have taken steps necessary to improve our internal controls relating to
the  preparation  and review of interim and annual income tax  provisions and to
remediate this material  weakness.  While significant  progress has been made in
the  remediation  of these  controls,  the controls  have not yet operated for a
sufficient  period of time to allow us to complete the  required  testing and to
conclude that they are designed and operating effectively.

     Our senior  management,  including  our Chief  Executive  Officer and Chief
Financial  Officer,  evaluated the effectiveness of our disclosure  controls and
procedures as of the end of the period covered by this quarterly  report.  Based
on the status of the remediation of the material  weakness,  our Chief Executive
Officer and our Chief Financial Officer  concluded that our disclosure  controls
and procedures are not effective. We continue to perform additional analysis and
post-closing  procedures to ensure our  consolidated  financial  statements  are
prepared in  accordance  with GAAP.  Accordingly,  management  believes that the
financial  statements  included in this report  fairly  present in all  material
respects our financial  condition,  results of operations and cash flows for the
periods presented.  The certificates required by this item are filed as Exhibits
31.1, 31.2 and 32.1 to this Form 10-Q.

Status of Remediation of the Material Weakness

     During the first three quarters of 2005, we have taken the steps  necessary
to improve  our  internal  controls  relating to the  preparation  and review of
interim and annual income tax  provisions,  including the accounting for current
income taxes  payable and deferred  income tax assets and  liabilities.  We have
hired  additional  resources and have engaged third party tax experts to improve
the effectiveness of the controls over management's review of the details of the
income tax  calculations.  We have also  improved the process of  preparing  and
reviewing  the   workpapers   supporting  our  tax  related   calculations   and
conclusions.

     We will continue to do the following:

     o    Complete the  implementation  of the CorpTax computer  application and
          enhance  other  financial  applications  to  automate  more of the tax
          analysis and  provision  processes and continue to improve the clarity
          of supporting documentation and reports, and

     o    Add additional  resources in the tax department as well as provide tax
          accounting training for key personnel.

     We continue to monitor the effectiveness of the tax controls and procedures
and will make any additional changes that management deems appropriate.

Changes in Internal Control Over Financial Reporting

     We  continuously  seek to improve the efficiency and  effectiveness  of our
internal  controls.  This results in  refinements  to processes  throughout  the
Company.  During the first  three  quarters of 2005,  there were no  significant
changes in our internal control over financial reporting, other than the changes
related to the tax  accounting  processes,  procedures  and  controls  discussed
above, that materially affected,  or are reasonably likely to materially affect,
our internal control over financial reporting.


















                                     - 94 -
<PAGE>
                          PART II -- OTHER INFORMATION

Item 1. Legal Proceedings.

     See Note 12 of the Notes to Consolidated Condensed Financial Statements for
a description of our legal proceedings.

Item 6. Exhibits.

     (a) Exhibits

     The following exhibits are filed herewith unless otherwise indicated:

                                  EXHIBIT INDEX
                                  -------------

Exhibit
Number                               Description
-------  -----------------------------------------------------------------------

3.1.1    Amended and Restated  Certificate of Incorporation  of the Company,  as
         amended through June 2, 2004.(a)

3.1.2    Amendment to Amended and Restated  Certificate of  Incorporation of the
         Company, dated June 20, 2005.(b)

3.2      Amended and Restated By-laws of the Company.(c)

4.1      Amended  and  Restated  Limited  Liability  Company  Agreement  of CCFC
         Preferred  Holdings,  LLC  containing  terms of its Class A  Redeemable
         Preferred Shares due February 13, 2006.(d)

4.2      Second  Amended  and  Restated  Limited   Liability  Company  Operating
         Agreement  of CCFC  Preferred  Holdings,  LLC,  dated as of October 14,
         2005,  containing terms of its 6-Year  Redeemable  Preferred Shares Due
         2011.(d)

10.1     Purchase and Sale  Agreement  dated July 7, 2005,  by and among Calpine
         Gas Holdings  LLC,  Calpine  Fuels  Corporation,  Calpine  Corporation,
         Rosetta  Resources  Inc.,  and the other Subject  Companies  identified
         therein.(e)

10.2     Master  Transaction  Agreement,  dated September 7, 2005, among Calpine
         Corporation,  Calpine Energy Services, L.P., The Bear Stearns Companies
         Inc.,  and such other  parties as may become party thereto from time to
         time.  Approximately  two  pages of this Exhibit 10.2 have been omitted
         pursuant to a request for confidential treatment.  The omitted language
         has been filed separately with the SEC.(*)

10.3     Amendment to 1996 Stock Incentive Plan, as amended.(f)

31.1     Certification  of the Chairman,  President and Chief Executive  Officer
         Pursuant  to Rule  13a-14(a)  or Rule  15d-14(a)  under the  Securities
         Exchange  Act of  1934,  as  Adopted  Pursuant  to  Section  302 of the
         Sarbanes-Oxley Act of 2002.(*)

31.2     Certification  of the  Executive  Vice  President  and Chief  Financial
         Officer  Pursuant  to  Rule  13a-14(a)  or  Rule  15d-14(a)  under  the
         Securities  Exchange Act of 1934, as Adopted Pursuant to Section 302 of
         the Sarbanes-Oxley Act of 2002.(*)

32.1     Certification  of Chief Executive  Officer and Chief Financial  Officer
         Pursuant to 18 U.S.C.  Section 1350, as Adopted Pursuant to Section 906
         of the Sarbanes-Oxley Act of 2002.(*)

----------
(*) Filed herewith.

(a)  Incorporated by reference to Calpine Corporation's Quarterly Report on Form
     10-Q for the quarter  ended June 30, 2004,  filed with the SEC on August 9,
     2004.

(b)  Incorporated by reference to Calpine Corporation's Quarterly Report on Form
     10-Q for the quarter ended June 30, 2005, filed
     with the SEC on August 9, 2005.

(c)  Incorporated  by reference to Calpine  Corporation's  Annual Report on Form
     10-K for the year ended December 31, 2001,  filed with the SEC on March 29,
     2002.

(d)  This  document  has been  omitted in  reliance  on Item  601(b)(4)(iii)  of
     Regulation  S-K.  Calpine  Corporation  agrees  to  furnish  a copy of such
     document to the SEC upon request.

                                  (continued)



                                     - 95 -
<PAGE>

(e)  Incorporated by reference to Calpine  Corporation's  Current Report on Form
     8-K filed with the SEC on July 13, 2005.

(f)  Description of such amendment is  incorporated by reference to Item 1.01 of
     Calpine  Corporation's  Current  Report on Form 8-K  filed  with the SEC on
     September 20, 2005.  Such  amendment  constitutes a management  contract or
     compensatory plan or arrangement.
















































































                                     - 96 -
<PAGE>

                                   SIGNATURES

     Pursuant to the  requirements  of the Securities  Exchange Act of 1934, the
registrant  has duly  caused  this  report  to be  signed  on its  behalf by the
undersigned thereunto duly authorized.

                               CALPINE CORPORATION

                               By:                /s/ ROBERT D. KELLY
                                  ----------------------------------------------
                                                    Robert D. Kelly
                                              Executive Vice President and
                                                 Chief Financial Officer
                                              (Principal Financial Officer)

Date: November 9, 2005

                               By:             /s/ CHARLES B. CLARK, JR.
                                  ----------------------------------------------
                                                   Charles B. Clark, Jr.
                                                 Senior Vice President and
                                                    Corporate Controller
                                               (Principal Accounting Officer)

Date: November 9, 2005






























































                                     - 97 -
<PAGE>

     The following exhibits are filed herewith unless otherwise indicated:

                                  EXHIBIT INDEX
                                  -------------

Exhibit
Number                               Description
-------  -----------------------------------------------------------------------

3.1.1    Amended and Restated  Certificate of Incorporation  of the Company,  as
         amended through June 2, 2004.(a)

3.1.2    Amendment to Amended and Restated  Certificate of  Incorporation of the
         Company, dated June 20, 2005.(b)

3.2      Amended and Restated By-laws of the Company.(c)

4.1      Amended  and  Restated  Limited  Liability  Company  Agreement  of CCFC
         Preferred  Holdings,  LLC  containing  terms of its Class A  Redeemable
         Preferred Shares due February 13, 2006.(d)

4.2      Second  Amended  and  Restated  Limited   Liability  Company  Operating
         Agreement  of CCFC  Preferred  Holdings,  LLC,  dated as of October 14,
         2005,  containing terms of its 6-Year  Redeemable  Preferred Shares Due
         2011.(d)

10.1     Purchase and Sale  Agreement  dated July 7, 2005,  by and among Calpine
         Gas Holdings  LLC,  Calpine  Fuels  Corporation,  Calpine  Corporation,
         Rosetta  Resources  Inc.,  and the other Subject  Companies  identified
         therein.(e)

10.2     Master  Transaction  Agreement,  dated September 7, 2005, among Calpine
         Corporation,  Calpine Energy Services, L.P., The Bear Stearns Companies
         Inc.,  and such other  parties as may become party thereto from time to
         time.  Approximately [ten] pages of this Exhibit 10.2 have been omitted
         pursuant to a request for confidential treatment.  The omitted language
         has been filed separately with the SEC.(*)

10.3     Amendment to 1996 Stock Incentive Plan, as amended.(f)

31.1     Certification  of the Chairman,  President and Chief Executive  Officer
         Pursuant  to Rule  13a-14(a)  or Rule  15d-14(a)  under the  Securities
         Exchange  Act of  1934,  as  Adopted  Pursuant  to  Section  302 of the
         Sarbanes-Oxley Act of 2002.(*)

31.2     Certification  of the  Executive  Vice  President  and Chief  Financial
         Officer  Pursuant  to  Rule  13a-14(a)  or  Rule  15d-14(a)  under  the
         Securities  Exchange Act of 1934, as Adopted Pursuant to Section 302 of
         the Sarbanes-Oxley Act of 2002.(*)

32.1     Certification  of Chief Executive  Officer and Chief Financial  Officer
         Pursuant to 18 U.S.C.  Section 1350, as Adopted Pursuant to Section 906
         of the Sarbanes-Oxley Act of 2002.(*)

----------
(*) Filed herewith.

(a)  Incorporated by reference to Calpine Corporation's Quarterly Report on Form
     10-Q for the quarter  ended June 30, 2004,  filed with the SEC on August 9,
     2004.

(b)  Incorporated by reference to Calpine Corporation's Quarterly Report on Form
     10-Q for the quarter ended June 30, 2005, filed
     with the SEC on August 9, 2005.

(c)  Incorporated  by reference to Calpine  Corporation's  Annual Report on Form
     10-K for the year ended December 31, 2001,  filed with the SEC on March 29,
     2002.

(d)  This  document  has been  omitted in  reliance  on Item  601(b)(4)(iii)  of
     Regulation  S-K.  Calpine  Corporation  agrees  to  furnish  a copy of such
     document to the SEC upon request.

(e)  Incorporated by reference to Calpine  Corporation's  Current Report on Form
     8-K filed with the SEC on July 13, 2005.

(f)  Description of such amendment is  incorporated by reference to Item 1.01 of
     Calpine  Corporation's  Current  Report on Form 8-K  filed  with the SEC on
     September 20, 2005.  Such  amendment  constitutes a management  contract or
     compensatory plan or arrangement.
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10
<SEQUENCE>2
<FILENAME>ex10-2.txt
<TEXT>
                                                                    EXHIBIT 10.2








================================================================================
                          MASTER TRANSACTION AGREEMENT


                                  by and among

                              Calpine Corporation,
                             a Delaware corporation
                                  as "Calpine"

                    Calpine Merchant Services Company, Inc.,
                             a Delaware corporation
                                    as "CMSC"

                                       and

                         Calpine Energy Services, L.P.,
                         a Delaware limited partnership
                                    as "CES"

                                       and

                        The Bear Stearns Companies Inc.,
                             a Delaware corporation
                                as "Bear Stearns"

                                       and

                               CalBear Energy LP,
                         a Delaware limited partnership
                                  as "CalBear"

                            Dated: September 7, 2005
================================================================================




<PAGE>
<TABLE>
<CAPTION>
                                TABLE OF CONTENTS


<S>                                                                                                       <C>
ARTICLE I. DEFINITIONS......................................................................................2
-------------------------------------------------------------------------------------------------------------

   1.1      Defined Terms...................................................................................2
   1.2      Construction...................................................................................15

ARTICLE II. FORMATION TRANSACTIONS; EFFECTIVE DATE.........................................................16
-------------------------------------------------------------------------------------------------------------

   2.1      Pre-Formation Transactions.....................................................................16
   2.2      Formation Transactions.........................................................................16
   2.3      Effective Date.................................................................................17

ARTICLE III. RELATIONSHIP OF THE PARTIES...................................................................17
-------------------------------------------------------------------------------------------------------------

   3.1      CalBear Business...............................................................................17
   3.2      Exclusivity....................................................................................17
   3.3      Certain Restrictions on Sales by Calpine of Equity Securities and Assets of CMSC...............18
   3.4      Certain Restrictions on Sales by Bear Stearns of Equity Securities and Assets of CalBear.......21
   3.5      No Joint Venture or Partnership Created........................................................24
   3.6      Conflicts of Interest; Non-Discrimination......................................................25
   3.7      Non-Solicitation of Bear Stearns Employees.....................................................25
   3.8      Non-Solicitation of Calpine Employees..........................................................26
   3.9      Confidential Information.......................................................................27
   3.10     Netting........................................................................................29
   3.11     Acknowledgements...............................................................................29
   3.12     CMSC Board Representation......................................................................30
   3.13     Performance of Financial Obligations of CalBear................................................30
   3.14     [*]............................................................................................30
   3.15     Fiscal Year of CalBear.........................................................................30
   3.16     Interest on Overdue Amounts....................................................................31

ARTICLE IV. CALPINE GUARANTEE..............................................................................31
-------------------------------------------------------------------------------------------------------------

   4.1      Calpine Guarantee..............................................................................31
   4.2      Calpine May Consolidate, etc., on Certain Terms................................................32
   4.3      Release........................................................................................32

ARTICLE V. BEAR STEARNS GUARANTEE..........................................................................33
-------------------------------------------------------------------------------------------------------------

   5.1      Bear Stearns Guarantee.........................................................................33
   5.2      Bear Stearns May Consolidate, etc., on Certain Terms...........................................34
   5.3      Release........................................................................................34

ARTICLE VI. REGULATORY MATTERS.............................................................................35
-------------------------------------------------------------------------------------------------------------

   6.1      Regulatory Matters With Respect to Calpine.....................................................35
   6.2      Regulatory Matters With Respect to Bear Stearns................................................35
   6.3      Regulatory Matters With Respect to CalBear and CMSC............................................35

ARTICLE VII. NOTICES, RECORDS, MEETINGS, AUDITS AND AVAILABILITY...........................................36
-------------------------------------------------------------------------------------------------------------

   7.1      Notices........................................................................................36



<PAGE>

   7.2      Books and Records..............................................................................38
   7.3      Meetings.......................................................................................38
   7.4      Audits.........................................................................................39
   7.5      Availability of Parties........................................................................40

ARTICLE VIII. REPRESENTATIONS AND WARRANTIES OF THE PARTIES................................................40
-------------------------------------------------------------------------------------------------------------

   8.1      Organization...................................................................................40
   8.2      Authorization..................................................................................40
   8.3      No Similar Business............................................................................40
   8.4      Accuracy of Information Furnished..............................................................41

ARTICLE IX. REPRESENTATIONS AND WARRANTIES OF CALPINE......................................................41
-------------------------------------------------------------------------------------------------------------

   9.1      Calpine and Calpine Transaction Parties........................................................41
   9.2      No Conflict or Violation.......................................................................41
   9.3      Sufficiency of Assets..........................................................................41
   9.4      Permits........................................................................................42
   9.5      Litigation.....................................................................................42
   9.6      Compliance with Law............................................................................42
   9.7      Insurance......................................................................................42
   9.8      Adequate Capital...............................................................................43
   9.9      SEC Filings; Financial Statements..............................................................43
   9.10     Regulation.....................................................................................43
   9.11     Due Consideration..............................................................................44
   9.12     Operations of CMSC.............................................................................44
   9.13     Material Contracts of CMSC.....................................................................44

ARTICLE X. REPRESENTATIONS AND WARRANTIES OF BEAR STEARNS..................................................44
-------------------------------------------------------------------------------------------------------------

   10.1     Bear Stearns and CalBear.......................................................................44
   10.2     No Conflict or Violation.......................................................................44
   10.3     Sufficiency of Assets..........................................................................45
   10.4     Permits........................................................................................45
   10.5     Litigation.....................................................................................45
   10.6     Compliance with Law............................................................................45
   10.7     Insurance......................................................................................45
   10.8     Adequate Capital...............................................................................46
   10.9     SEC Filings; Financial Statements..............................................................46
   10.10    Regulation.....................................................................................46
   10.11    Operations of CalBear..........................................................................47

ARTICLE XI. PRE-EFFECTIVE DATE COVENANTS OF THE PARTIES....................................................47
-------------------------------------------------------------------------------------------------------------

   11.1     Notification of Certain Matters................................................................47
   11.2     Consents and Commercially Reasonable Efforts...................................................47
   11.3     Other Transaction Documents....................................................................48

ARTICLE XII. CONDITIONS TO CALPINE'S OBLIGATIONS...........................................................48
-------------------------------------------------------------------------------------------------------------

   12.1     Representations, Warranties and Covenants......................................................48
   12.2     No Proceedings or Litigation...................................................................48
   12.3     Bankruptcy.....................................................................................49
   12.4     Effective Date Deliveries......................................................................49


                                       ii
<PAGE>

   12.5     Transaction Documents..........................................................................49
   12.6     Pre-Formation Transactions.....................................................................49
   12.7     Corporate Proceedings..........................................................................49
   12.8     Regulatory Approvals...........................................................................49
   12.9     Opinion of Counsel to Bear Stearns.............................................................49

ARTICLE XIII. CONDITIONS TO BEAR STEARNS' OBLIGATIONS......................................................50
-------------------------------------------------------------------------------------------------------------

   13.1     Representations, Warranties and Covenants......................................................50
   13.2     No Proceedings or Litigation...................................................................50
   13.3     Bankruptcy.....................................................................................50
   13.4     Effective Date Deliveries......................................................................50
   13.5     Transaction Documents..........................................................................51
   13.6     Pre-Formation Transactions.....................................................................51
   13.7     Corporate Proceedings..........................................................................51
   13.8     Regulatory Approvals...........................................................................51
   13.9     Opinion of Counsel to Calpine..................................................................51

ARTICLE XIV. CERTAIN ACTIONS AFTER THE EFFECTIVE DATE......................................................51
-------------------------------------------------------------------------------------------------------------

   14.1     Survival of Representations, etc...............................................................51
   14.2     No Conflict or Violation.......................................................................52
   14.3     Sufficiency of Assets..........................................................................52
   14.4     Permits........................................................................................52
   14.5     Insurance......................................................................................52
   14.6     Adequate Capital...............................................................................53
   14.7     Further Assurances.............................................................................53
   14.8     Litigation Support.............................................................................53
   14.9     Organizational Documents of CMSC and CalBear...................................................53

ARTICLE XV. INDEMNIFICATION................................................................................53
-------------------------------------------------------------------------------------------------------------

   15.1     General Indemnification........................................................................53
   15.2     Right of Offset................................................................................60
   15.3     Payment........................................................................................60
   15.4     Right to Indemnification Not Affected by Knowledge or Presumption..............................60

ARTICLE XVI. TERM; EVENTS OF DEFAULT AND TERMINATION.......................................................60
-------------------------------------------------------------------------------------------------------------

   16.1     Term...........................................................................................60
   16.2     Renewal........................................................................................60
   16.3     Certain Matters with Respect to Renewal........................................................62
   16.4     Calpine Events of Default......................................................................62
   16.5     Bear Stearns Events of Default.................................................................63
   16.6     Termination; Liquidation Date; Transfer of Final Third Party Master Agreements.................63

ARTICLE XVII. LIMITATION OF LIABILITY......................................................................69
-------------------------------------------------------------------------------------------------------------

   17.1     Limitation of Remedies.........................................................................69
   17.2     Limitation of Monetary Damages.................................................................70
   17.3     Limitation of Non-Monetary Damages.............................................................70
   17.4     Limitation of Consequential Damages, Etc.......................................................70


                                      iii
<PAGE>

   17.5     Liability for Acts or Omissions of Other Persons...............................................71
   17.6     Survival of Limitations........................................................................71

ARTICLE XVIII. MISCELLANEOUS...............................................................................71
-------------------------------------------------------------------------------------------------------------

   18.1     Assignment.....................................................................................71
   18.2     Notices........................................................................................71
   18.3     Choice of Law; Service of Process; Venue; Jury Trial Waiver....................................76
   18.4     Dispute Resolution; Arbitration................................................................77
   18.5     Continued Performance..........................................................................79
   18.6     Regulatory Event...............................................................................79
   18.7     Forward Contracts..............................................................................79
   18.8     Effectiveness; Entire Agreement; Amendments and Waivers........................................79
   18.9     Multiple Counterparts..........................................................................80
   18.10    Invalidity.....................................................................................80
   18.11    Titles; Currency; Schedules....................................................................80
   18.12    Payments.......................................................................................80
   18.13    Publicity......................................................................................80
   18.14    Fees and Expenses..............................................................................81
   18.15    Specific Performance; Remedies Cumulative......................................................81
   18.16    Representation of Counsel; Mutual Negotiation..................................................81
   18.17    Knowledge......................................................................................81
   18.18    No Third Party Beneficiaries...................................................................81
   18.19    Time of Essence................................................................................82
   18.20    Force Majeure..................................................................................82
</TABLE>


                                       iv
<PAGE>


EXHIBITS

Exhibit A..................................Form of Agency and Services Agreement
Exhibit B.......................................Form of Trading Master Agreement
Exhibit C.......................................Organizational Documents of CMSC
Exhibit D....................................Organizational Documents of CalBear
Exhibit E.............................Form of Signature Page of CMSC and CalBear
Exhibit F.................................................Form of Renewal Notice

SCHEDULES

Schedule 1.1(a)......................................Calpine Existing Indentures
Schedule 1.1(b)...................................Calpine Restricted Transferees
Schedule 1.1(c)..............................Bear Stearns Restricted Transferees
Schedule 1.1(d).........................................Significant Subsidiaries
Schedule 3.7(a)........................................Employees of Bear Stearns
Schedule 3.8(a).............................................Employees of Calpine
Schedule 9.1.............................Calpine and Calpine Transaction Parties
Schedule 9.2..........................Calpine Conflicts, Violations and Consents
Schedule 10.1...........................................Bear Stearns and CalBear
Schedule 10.2....................Bear Stearns Conflicts, Violations and Consents
Schedule 12.9................................Opinions of Counsel to Bear Stearns
Schedule 13.9.....................................Opinions of Counsel to Calpine
Schedule 18.17.........................................................Knowledge


                                       v

<PAGE>
                          MASTER TRANSACTION AGREEMENT


          THIS MASTER  TRANSACTION  AGREEMENT  (this  "Agreement"),  dated as of
September  7,  2005,  is made  by and  among  Calpine  Corporation,  a  Delaware
corporation  ("Calpine"),  Calpine  Energy  Services,  L.P., a Delaware  limited
partnership ("CES") and The Bear Stearns Companies Inc., a Delaware  corporation
("Bear  Stearns")  and,  on and after the  Effective  Date (as  defined  herein)
Calpine Merchant Services  Company,  Inc., a Delaware  corporation  ("CMSC") and
CalBear Energy LP, a Delaware limited partnership ("CalBear").  Each of Calpine,
CES and Bear Stearns and, on and after the Effective Date, CMSC and CalBear, are
sometimes  hereinafter  individually  referred  to as a  "Party",  and  together
referred to as the "Parties".

                                    RECITALS

          WHEREAS,  the Calpine  Transaction  Parties  (as  defined  herein) and
CalBear desire to enter into a mutually beneficial arrangement to facilitate the
Calpine  Transaction  Parties,  on the one hand, and CalBear, on the other hand,
trading in physical and financial gas and electric  power with Third Parties (as
defined herein), and engaging in certain energy management  services,  including
power and gas transportation and transmission services (the "Transaction");

          WHEREAS, Calpine and its Affiliates (as defined herein) will generally
obtain  more  favorable  terms  for their  purchases  and sales of gas and power
through the Transaction than the terms that are otherwise currently available to
Calpine and its Affiliates for such purchases and sales;

          WHEREAS,  CalBear  desires  CMSC to provide the  Services  (as defined
herein)  to  CalBear,  including  acting as agent for  CalBear  with  respect to
certain  Trades,  all in  accordance  with the terms of the Agency and  Services
Agreement (as defined herein);

          WHEREAS,  CMSC is willing to provide  the  Services  to CalBear on the
terms set forth in the Agency and Services Agreement and in this Agreement;

          WHEREAS,   Calpine  and  Bear  Stearns  desire  to  guarantee  certain
obligations  of CMSC and CES, on the one hand,  and CalBear,  on the other hand,
respectively;

          WHEREAS, the Parties view the Transaction as one transaction, and none
of the Parties  would enter into any of the  Transaction  Documents  (as defined
herein) without entering into all of the Transaction Documents; and

          WHEREAS,  the Parties  desire to enter into this Agreement in order to
more fully set forth certain rights and obligations  with respect to the CalBear
Business (as defined herein) and the Transaction and certain related matters.


                                        1
<PAGE>


                                    AGREEMENT

          NOW,  THEREFORE,  in consideration  of the foregoing  premises and the
mutual covenants and promises  contained herein, and for other good and valuable
consideration,  the receipt and adequacy of which are hereby  acknowledged,  the
Parties hereto agree as follows:

                                   ARTICLE I.
                                  DEFINITIONS

   1.1    Defined  Terms.  As  used  herein,  the  terms  below  shall  have the
following meanings:

          "AAA" shall have the meaning given to such term in Section 18.4(b).

          "Action"  shall  mean,  with  respect to any Person,  any  outstanding
action, order, writ, injunction, judgment, determination or decree or any claim,
suit,  litigation,  proceeding,  appeal,  arbitration,  mediation,  tax audit or
governmental  investigation of any kind involving such Person or its business or
Assets.

          "Affiliate"  shall mean,  with  respect to any Person  (the  "referent
person"), any Person that, directly or indirectly, controls the referent person,
any Person that the referent Person  controls,  or any Person that,  directly or
indirectly,  is under common control with the referent  person.  For purposes of
the  preceding  sentence,  the term  "control"  shall mean the power,  direct or
indirect,  to direct or cause the direction of the  management and policies of a
Person through voting securities, by contract or otherwise. Any Subsidiary shall
be deemed to be an  "Affiliate".  Neither  Calpine nor any  Calpine  Transaction
Party is, or shall be deemed to be, an  "Affiliate"  of Bear Stearns or CalBear.
Neither Bear Stearns nor CalBear is, or shall be deemed to be, an "Affiliate" of
Calpine or any Calpine Transaction Party.

          "Agency and Services  Agreement"  shall mean that  certain  Agency and
Services  Agreement,  substantially in the form attached hereto as Exhibit A, to
be dated on or about  the  Effective  Date,  by and  between  CMSC and  CalBear,
pursuant to which,  among other matters,  CalBear  appoints CMSC as its agent to
transact CalBear Business on behalf of CalBear.

          "Applicable  Agency Law" shall mean any  federal,  state or local laws
(including   common  law  and  criminal  law),  codes,   statutes,   directives,
ordinances, by-laws, regulations, rules, judgments, consent orders, settlements,
and agreements  with  Governmental  Authorities,  proclamations  or delegated or
subordinated   legislation   of  any   Governmental   Authority   governing  the
relationships  and  related  duties  of  agents  or  attorneys-in-fact  to their
principals,  such as any of the  foregoing  providing  for duties of good faith,
fair dealing, loyalty or due care of agents or attorneys-in-fact to principals.

          "Applicable  Law"  shall  mean  any  federal,   state  or  local  laws
(including   common  law  and  criminal  law),  codes,   statutes,   directives,
ordinances,  by-laws, regulations, rules, judgments, consent orders, settlements
and agreements  with  Governmental  Authorities,  proclamations  or delegated or
subordinated  legislation of any  Governmental  Authority that are applicable to
this Agreement, the other Transaction Documents,  the transactions  contemplated


                                       2

hereby or thereby,  Calpine,  the Calpine  Transaction  Parties,  Bear  Stearns,
CalBear,  the Services or the CalBear Trades, in each case other than Applicable
Agency Law.

          "Arbitration  Panel"  shall  have the  meaning  given to such  term in
Section 18.4(c).

          "Assets" shall mean, with respect to any Person,  all of such Person's
right,  title and  interest in and to all  properties,  assets and rights of any
kind, now owned or hereafter acquired,  whether tangible or intangible,  real or
personal, wherever located.

          "Bankruptcy"  or  "Bankruptcy  Event" shall mean,  with respect to any
Person,  if that Person shall institute a voluntary case seeking  liquidation or
reorganization under the Bankruptcy Law, or shall consent to an involuntary case
thereunder  against  it; or such  Person  shall  file a  petition  or consent or
otherwise institute any similar proceeding under any other applicable Federal or
state law, or shall consent thereto;  or such Person shall apply for, or consent
or acquiesce to, the  appointment of a receiver,  administrator,  administrative
receiver, liquidator, sequestrator, trustee or other officer with similar powers
for itself or any  substantial  part of its Assets;  or such Person shall make a
general assignment for the benefit of its creditors;  or such Person shall admit
in writing its inability to pay its debts generally as they become due; or if an
involuntary case shall be commenced  seeking  liquidation or  reorganization  of
such  Person  under  the  Bankruptcy  Law or any  similar  proceedings  shall be
commenced  against  such  Person  under  any  other  Applicable  Law and (a) the
petition  commencing the  involuntary  case or similar  proceeding is not timely
controverted,  (b) the  petition  commencing  the  involuntary  case or  similar
proceeding  is not  dismissed  within  thirty  (30) days of its  filing,  (c) an
interim  trustee  is  appointed  to take  possession  of all or a portion of the
property,  and/or to operate all or any part of the  business of such Person and
such  appointment  is not vacated  within  thirty (30) days, or (d) an order for
relief  shall  have been  issued or entered  therein;  or a decree or order of a
court having  jurisdiction  in the premises for the  appointment  of a receiver,
administrator,  administrative receiver,  liquidator,  sequestrator,  trustee or
other  officer  having  similar  powers over such Person or all or a part of its
property  shall have been entered;  or any other similar relief shall be granted
against such Person under any applicable Bankruptcy Law.

          "Bankruptcy Law" shall mean Title 11, U.S. Code or any similar federal
or  state  law for the  relief  of  debtors,  as  amended,  and  all  rules  and
regulations promulgated thereunder.

          "Bankruptcy  Remote"  shall mean,  with respect to a Person that is an
Affiliate of Calpine,  that such Person has implemented  governance  procedures,
organizational structure or other arrangements designed to make such Person less
likely to become the  subject of a  Bankruptcy  Event or to become  consolidated
into a Bankruptcy of Calpine or its Affiliates; provided that if such Person has
at least two (2) directors or persons in similar governance functions designated
by Bear Stearns that have the right to veto any  voluntary  and veto any consent
to any involuntary  bankruptcy  filing,  and all of such Persons'  Contracts and
arrangements  with  Affiliates  are  substantially  similar to the Contracts and
arrangements  existing  on the  date  of  this  Agreement  or  substantially  as
advantageous to such Person as the Contracts and arrangements  which such Person
would obtain in a  comparable  arm's  length  transaction,  such Person shall be
deemed to be Bankruptcy Remote.


                                       3
<PAGE>

          "Bear  Stearns  Assets"  shall  mean the Assets of Bear  Stearns,  its
Subsidiaries and their Affiliates (other than CalBear).

          "Bear  Stearns  Claim"  shall have the  meaning  given to such term in
Section 15.1(a)(i).

          "Bear Stearns  Event of Default"  shall have the meaning given to such
term in Section 16.5.

          "Bear Stearns  Guarantee" shall have the meaning given to such term in
Section 5.1(a).

          "Bear  Stearns  Party"  shall have the  meaning  given to such term in
Section 15.1(a)(i).

          "Bear  Stearns SEC Filings"  shall have the meaning given to such term
in Section 10.9(a).

          "Bonus Amount" shall have the meaning given to such term in the Agency
and Services Agreement.

          "Books and Records" shall mean, with respect to any Person, all books,
records,  lists,  ledgers,  financial data, files,  reports,  product and design
manuals, plans, drawings,  technical manuals and operating records of every kind
pertaining  to  such  Person,  any of its  Subsidiaries  or  the  Assets  or the
customers,  suppliers,  distributors  or  personnel of such Person or any of its
Subsidiaries, in whatever form, including all (a) corporate books and records of
such Person or any of its Subsidiaries,  (b) disk or tape files, printouts, runs
or  other  computer-based  information  and  such  Person's,  or its  applicable
Subsidiary's,  interest in all  computer  programs  required to access,  and the
equipment containing, all such computer-based information, (c) product, business
and marketing plans, (d)  environmental  control  records,  (e) sales,  customer
maintenance,  distributor,  supplier and production  records including sales and
promotional literature, and (f) personnel records and information.

          "Business  Day" shall  mean any day on which  Federal  Reserve  member
banks in New York City are open for business.

          "CalBear  Business"  shall  have the  meaning  given  to such  term in
Section 3.1(a).

          "CalBear  Default Option" shall have the meaning given to such term in
Section 16.6(d)(iii).

          "CalBear  Governance  Operations" shall have the meaning given to such
term in the Agency and Services Agreement.

     "CalBear  Information"  shall  mean the  terms  of,  or  other  information
relating to, this Agreement,  any other Transaction  Document,  the transactions


                                       4
<PAGE>

entered into  hereunder or thereunder  or  contemplated  hereby or thereby,  the
Services, the CalBear Trades, the CalBear Business or any related information.

          "CalBear  Name" shall have the  meaning  given to such term in Section
16.6(c)(i).

          "CalBear Referral  Business" shall have the meaning given to such term
in Section 3.1(a).

          "CalBear Termination Option" shall have the meaning given to such term
in Section 16.6(d)(ii).

          "CalBear  Trades"  shall  have the  meaning  given to such term in the
Agency and Services Agreement.

          "Calpine  Assets" shall mean the Assets of Calpine,  its  Subsidiaries
and their Affiliates.

          "Calpine  Claim" shall have the meaning  given to such term in Section
15.1(b)(i).

          "Calpine  Event of Default"  shall have the meaning given to such term
in Section 16.4.

          "Calpine  Existing  Indentures"  shall mean the  indentures  listed on
Schedule 1.1(a).

          "Calpine  Guarantee"  shall  have the  meaning  given to such  term in
Section 4.1(a).

          "Calpine  Party" shall have the meaning  given to such term in Section
15.1(b)(i).

          "Calpine  SEC  Filings"  shall have the meaning  given to such term in
Section 9.9(a).

          "Calpine Transaction Parties" shall mean each of CMSC and CES.

          "Capital Stock" shall mean (a) in the case of a corporation, corporate
stock,  (b)  in  the  case  of  a  partnership  or  limited  liability  company,
partnership or membership  interests or units (whether general or limited),  and
(c) any other  interest or  participation  that confers on a Person the right to
receive a share of the profits and losses of, or  distribution of assets of, the
issuing entity.

          "CEA" shall mean the Commodity Exchange Act, as amended, and all rules
and regulations promulgated thereunder.

          "CET ISDA Agreement"  shall have the meaning given to such term in the
Trading Master Agreement.

          "CFTC" shall mean the Commodity  Futures  Trading  Commission  and its
successors.


                                       5
<PAGE>

          "Chairman"  shall  have  the  meaning  given to such  term in  Section
18.4(c).

          "Claim"   shall   mean  a  claim,   counterclaim,   Action,   inquiry,
investigation, demand, charge, complaint, information or subpoena.

          "Claim  Notice"  shall have the meaning  given to such term in Section
15.1(c)(i).

          "Confidential   Information"   shall  mean,  as  to  any  Person,  all
proprietary and confidential financial, marketing, operational,  organizational,
know-how, personnel,  customer, vendor, technical and other data relating to the
business of such Person,  in any form,  whether oral or written,  including  all
correspondence,  memoranda, notes, summaries, analyses, compilations, forecasts,
studies, models, extracts of and documents and records reflecting, based upon or
derived from Confidential Information, regardless of who prepares it, as well as
all  copies  and other  reproductions  thereof,  whether in writing or stored or
maintained in or by electronic, magnetic or other means, media or devices.

          "Contract"  shall mean,  with  respect to any Person,  any  agreement,
contract,  lease,  sublease,  note, loan,  evidence of indebtedness,  indenture,
guarantee, letter of credit, franchise agreement,  undertaking,  covenant not to
compete,  employment agreement,  license,  sublicense,  instrument,  obligation,
commitment,   purchase  and/or  sales  order,   quotation  and  other  executory
commitment to which such Person is a party or that relates to the  businesses of
such Person or its Assets, whether oral or written, express or implied, and that
pursuant to its terms has not expired, terminated or been fully performed by the
parties thereto.

          "Credit  Enhancement  Trade" shall have the meaning given to such term
in the Trading Master Agreement.

          "Cumulative Net Trading  Profits" shall have the meaning given to such
term in the Agency and Services Agreement.

          "Damages"  shall  have  the  meaning  given  to such  term in  Section
15.1(a)(i).

          "Default  Purchase Right" shall have the meaning given to such term in
Section 16.6(d)(iii).

          "Default  Sale  Right"  shall have the  meaning  given to such term in
Section 16.6(d)(iii).

          "Default Termination Notice" shall have the meaning given to such term
in Section 16.6(d)(iii).

          "Defaulting Parties" means Calpine and each Calpine Transaction Party,
in respect of Calpine  Events of  Default,  and Bear  Stearns  and  CalBear,  in
respect of Bear Stearns Events of Default.

          "Defaulting  Termination  Parties"  shall mean (i) if the  Liquidation
Date occurs  pursuant to Section  16.6(b)(iv) or (v), the applicable  Defaulting


                                       6
<PAGE>

Parties,  (ii) if the Liquidation Date occurs pursuant to Section 16.6(b)(vi) or
16.6(b)(vii),  the Parties other than the Party that terminated any of the other
Transaction  Documents in accordance  with its terms,  and its  Affiliates,  and
(iii) if the  Liquidation  Date occurs pursuant to Section  16.6(b)(viii),  Bear
Stearns and CalBear.

          "Designated  CMSC Board  Member"  shall have the meaning given to such
term in Section 3.12.

          "Effective  Date" shall have the meaning given to such term in Section
2.3.

          "Election Notice" shall have the meaning given to such term in Section
3.3(c).

          "Elective  Non-Terminating  Parties" shall mean the Parties other than
the Elective Terminating Parties.

          "Elective  Terminating  Parties"  shall mean the Party  delivering the
Termination Notice pursuant to Section  16.6(b)(iii) or Section  16.6(b)(ix) and
its Affiliates that are Parties.

          "Encumbrance" shall mean any claim, lien,  judgment,  pledge,  escrow,
option, liability,  charge, easement,  restrictive covenant,  security interest,
deed of trust,  right of first refusal,  mortgage,  right-of-way,  encroachment,
building  or use  restriction,  encumbrance  or other  right  of third  parties,
whether  voluntarily  incurred or arising by operation of law, and shall include
any agreement to give any of the foregoing in the future,  and any contingent or
conditional  sales agreement or other title retention  agreement or lease in the
nature  thereof or the filing of, or agreement to give any financing  statement,
under the laws of any jurisdiction.

          "Equity  Securities"  shall mean (i) shares of Capital  Stock or other
equity securities,  (ii) subscriptions,  calls, warrants, options or commitments
of any kind or character  relating  to, or  entitling  any Person to purchase or
otherwise  acquire,  any Capital  Stock or other  equity  securities,  and (iii)
securities convertible into or exercisable or exchangeable for shares of Capital
Stock or other equity securities.

          "Exchange Act" shall mean the U.S. Securities Exchange Act of 1934, as
amended, and all rules and regulations promulgated thereunder.

          "Facilities"  shall mean,  collectively,  Power generating  facilities
that are located in the United States of America, Canada or Mexico.

          "FERC"  means  the  Federal  Energy  Regulatory   Commission  and  its
successors.

          "Final Third Party Master  Agreements" shall have the meaning given to
such term in Section 16.6(d)(i).

          "Fiscal  Quarter"  shall  have the  meaning  given to such term in the
Agency and Services Agreement.


                                       7
<PAGE>

          "Fiscal  Year" shall mean a fiscal  year of  CalBear,  which as of the
date of this Agreement commences on December 1 of each calendar year and ends on
November 30 of the following  calendar  year,  subject to revision in accordance
with Section 3.15; provided that (x) the first Fiscal Year shall commence on the
date of this  Agreement and end the earlier of (1) November 30, 2005 and (2) the
Termination  Date,  and (y) the last  Fiscal  Year shall end on the  Termination
Date.

          "Force Majeure" shall mean an event or circumstance which prevents one
Party from performing its obligations  under the  Transaction  Documents,  which
event  or  circumstance  was  not  anticipated  as of the  date  the  applicable
obligation was agreed to, which is not within the reasonable  control of, or the
result of the negligence of, the Party claiming the Force Majeure, and which, by
the  exercise  of  commercially  reasonable  efforts,  such  Party is  unable to
overcome or avoid or cause to be  avoided,  including  acts of God,  acts of the
public  enemy  including   terrorism,   unexpected  delay  by  any  Governmental
Authority,  and any change in  Applicable  Law.  Force Majeure shall exclude any
event or  circumstance  if its sole  effect  on a Party is  economic,  including
economic effects that prevent Payment.

          "Formation  Transactions" shall have the meaning given to such term in
Section 2.2.

          "Forward"  shall have the  meaning  given to such term in the  Trading
Master Agreement.

          "FPA" shall mean the Federal Power Act, as amended,  and all rules and
regulations promulgated thereunder.

          "GAAP"  shall mean  accounting  principles  generally  accepted in the
United  States of America.  The term,  "GAAP," when used herein,  shall mean the
accounting  principles  generally accepted by the Securities Exchange Commission
as reflected in  Regulation  S-X  promulgated  under the Exchange  Act. The term
"GAAP,"  when used herein with respect to CalBear or the CalBear  Trades,  shall
mean GAAP as applied consistently by Bear Stearns from time to time.

          "Gas" shall mean  physical or financial  natural gas unless  otherwise
agreed upon between the Parties.

          "Gas  Trade"  shall mean any  purchase or sale or hedge of Gas, or the
transportation, transmission or storage of Gas, all on a world-wide basis.

          "Governmental  Authority"  shall  mean any  federal,  state,  local or
municipal government, governmental department, commission, board, bureau, agency
or  instrumentality,   any  RTO/ISO  control  area  or  SRO,  or  any  judicial,
regulatory,  administrative or  quasi-governmental  court,  panel or other body,
having or asserting jurisdiction as to the matter in question.

          "Hard  Covenants" shall mean Section 4.2(b) of the Agency and Services
Agreement  (to the extent of the  prohibition  therein  with respect to entering


                                       8
<PAGE>

into Trades directly with Calpine or any of its Affiliates),  Sections  4.17(a),
(b), (c) and (e) of the Agency and Services Agreement,  and Section 3.13 of this
Agreement.

          "Initial  Notice" shall have the meaning given to such term in Section
3.3(a).

          "Initial  Period" shall have the meaning given to such term in Section
3.3(b).

          "Initial Term" shall mean the period  commencing on the Effective Date
and ending on November 30, 2006.

          "ISO" shall mean any FERC-authorized independent system operator.

          "Latest  Renewal  Period" shall have the meaning given to such term in
Section 16.2(a)(ii).

          "Liabilities"  shall  mean any  liability,  indebtedness,  obligation,
co-obligation,  commitment,  expense, claim, deficiency, guaranty or endorsement
of or by any Person of any nature (whether direct or indirect, known or unknown,
absolute  or  contingent,  liquidated  or  unliquidated,  due or to become  due,
accrued or unaccrued, matured or unmatured).

          "Liquidation"  shall have the meaning given to such term in the Agency
and Services Agreement.

          "Liquidation  Date"  shall  mean the date on which  Liquidation  shall
begin.

          "Material  Adverse  Effect" or "Material  Adverse  Change" shall mean,
with  respect to any Person,  any change,  circumstance,  event or effect  that,
individually or in the aggregate with such other changes, circumstances,  events
or effects, is or is reasonably likely to constitute,  a material adverse change
in, or have a material adverse effect on (a) the business,  operations,  assets,
liabilities, foreseeable prospects, financial condition or results of operations
of such  Person  and its  Subsidiaries,  taken as a whole,  or (b) the  right or
ability  of such  Person  to  consummate  the  transactions,  taken  as a whole,
contemplated hereby and by the other Transaction Documents.

          "Misconduct"   shall  mean,  with  respect  to  any  Person:  (a)  any
nonfulfillment,  nonperformance,  nonobservance or other breach or violation of,
or default  under,  any  provision of any  Transaction  Document by such Person,
through any act or omission,  if (i) such act or omission was taken or not taken
with the intent to take or not take the same by the individual  acting on behalf
of such Person, (ii) such individual knew that such act or omission  constituted
a breach or  violation  of the  Transaction  Documents  or the  policies of such
Person or such individual had previously taken, or omitted to take, such act and
had been warned that such act or omission  constituted  a breach or violation of
the Transaction  Documents or the policies of such Person, and (iii) at the time
of such act or omission,  an officer (or with respect to CMSC,  prior to January
1, 2006, an officer  seconded to CMSC under the applicable  transition  services
agreement with an Affiliate of Calpine) of such Person knew or should have known
that such act or omission was being taken or omitted to be taken,  (b) any fraud
by such Person with respect to the Transaction  Documents or the matters covered
thereby,  and (c) any  nonfulfillment,  nonperformance,  nonobservance  or other


                                       9
<PAGE>

breach or  violation  of, or  default  under any  provision  of any  Transaction
Document  by such  Person  through  any act or  omission if such act or omission
constituted gross negligence in the scheduling of physical Trades.

          "Month" shall mean a calendar month.

          "MW" shall mean megawatt, or one million (1,000,000) watts of Power.

          "MWh" shall mean  megawatt-hour,  or one million watts  (1,000,000) of
Power for one (1) hour.

          "Non-Compete  Defaulting  Termination  Parties"  shall mean (i) if the
Liquidation  Date occurs pursuant to Section  16.6(b)(iv) or (v), the applicable
Defaulting  Parties,  (ii) if the  Liquidation  Date occurs  pursuant to Section
16.6(b)(vi)  (except for an occurrence of the Liquidation  Date as a result of a
termination of the Agency and Services Agreement pursuant to Section 7.1(a)(iii)
thereof) or 16.6(b)(vii)  (except for an occurrence of the Liquidation Date as a
result of a termination of the Agency and Services Agreement pursuant to Section
7.1(a)(iv) thereof), the Parties other than the Party that terminated any of the
other  Transaction  Documents in accordance with its terms,  and its Affiliates,
and (iii) if the Liquidation Date occurs pursuant to Section 16.6(b)(viii), Bear
Stearns and CalBear.

          "Non-Compete Period" [*]

          "Non-Defaulting Termination Parties" shall mean the Parties other than
the Defaulting Termination Parties.

          "Non-Renewal  Purchase  Notice"  shall have the meaning  given to such
term in Section 16.6(d)(i).

          "Non-Renewal Purchase Right" shall have the meaning given to such term
in Section 16.6(d)(i).

          "Non-Renewing  Parties"  shall have the meaning  given to such term in
Section 16.2(d).

          "Offer" shall have the meaning given to such term in Section 3.3(b).

          "Offer  Notice"  shall have the meaning  given to such term in Section
3.3(b).

          "Offer  Period"  shall have the meaning  given to such term in Section
3.3(b).

          "Ordinary Losses" shall mean (a) any Claims or Damages with respect to
the actual or prospective  operations or economic results of CalBear,  including
losses (i) on CalBear Trades where delivery of Gas or Power or  determination of
price has occurred,  (ii) on Forward CalBear  Trades,  and (iii) with respect to
lost  CalBear  Trades,  profits or  opportunities,  and (b) any other  Claims or
Damages, excluding in each case under clauses (a) and (b), Third Party Losses.


                                       10
<PAGE>

          "Organizational  Documents" shall mean the articles of  incorporation,
by-laws,   articles  of  organization,   limited  liability  company  agreement,
partnership  agreement,  formation  agreement,  joint venture agreement or other
similar  organizational  documents of any Person other than any  individual,  as
applicable with respect to such Person.

          "Party  Arbitrator"  shall  have the  meaning  given  to such  term in
Section 18.4(c).

          "Payment" shall mean any payment, repayment, return, refund, transfer,
deposit,  funding, posting or other type of payment or provision of an amount or
collateral  (including provision of letters of credit),  whether as a payment or
provision  for  services or property,  capital  contribution,  loan,  guarantee,
advance, cure of default,  collateral,  margin, credit support or any other form
of security or any other amount.

          "Permits"  shall  mean,  with  respect to any  Person,  all  licenses,
permits,  franchises,  approvals,  authorizations,   certifications,   consents,
orders,  settlements,  exemptions  or  similar  items of, or  filings,  reports,
notifications  or similar  items  submitted  to or granted by, any  Governmental
Authority,  whether  foreign,  federal,  state  or  local  or  otherwise,  under
Applicable Law,  necessary for the past,  present or anticipated  conduct of, or
relating to the  operation of the  businesses  of or the ownership of the Assets
of, such Person.

          "Person" shall mean any individual,  corporation,  partnership,  joint
venture,  association,  joint stock company, trust, unincorporated organization,
limited liability company or Governmental Authority or other entity.

          "Power" shall mean physical or financial electric capacity as measured
in MWs,  physical or financial  electric  energy as measured in MWh,  and/or any
other  electricity  related products or services  available for sale,  including
reserves and other  ancillary  services needed to support the  transmission  and
distribution  of Power from a point of generation to a delivery  point,  as such
services are defined in applicable FERC-filed tariffs.

          "Power  Trade" shall mean any  purchase or sale or hedge of Power,  or
the transportation or transmission of Power, all on a world-wide basis.

          "Pre-Formation Transactions" shall have the meaning given to such term
in Section 2.1.

          "PUHCA" shall mean the Public Utility  Holding Company Act of 1935, as
amended, and all rules and regulations promulgated thereunder.

          "Regulatory  Approval"  shall mean all Permits that are  necessary for
the entering into and performance of CalBear Trades,  this Agreement,  the other
Transaction Documents, or the transactions contemplated hereby or thereby.

          "Regulatory  Event"  shall  have the  meaning  given  to such  term in
Section 18.6.

          "Remedial  Parties"  shall  have the  meaning  given  to such  term in
Section 17.1.


                                       11
<PAGE>

          "Renewal  Notice" shall have the meaning given to such term in Section
16.2(a)(i).

          "Renewal  Period" shall have the meaning given to such term in Section
16.1.

          "Renewing  Parties"  shall  have the  meaning  given  to such  term in
Section 16.2(d).

          "Reports"  shall have the meaning given to such term in the Agency and
Services Agreement.

          "Representative"  shall mean, with respect to any Person, any officer,
director, principal, attorney, employee, agent, consultant,  accountant or other
representative of such Person.

          "Restricted  Transferees"  shall mean,  with  respect to Calpine,  the
Calpine Transaction Parties and their Affiliates, the Persons listed in Schedule
1.1(b),  and with respect to Bear  Stearns,  CalBear and their  Affiliates,  the
Persons listed in Schedule 1.1(c).

          "Returns" shall mean, with respect to any Person, any and all returns,
reports,  declarations,  documents and  information  statements  with respect to
Taxes required to be filed by or on behalf of such Person with any  governmental
authority or Tax  authority or agency,  whether  domestic or foreign,  including
consolidated, combined and unitary returns and all amendments thereto or thereof
and any documents with respect to or accompanying  requests for the extension of
time in which to file any such  returns,  reports,  declarations,  documents and
information statements.

          "Risk  Policy" shall have the meaning given to such term in the Agency
and Services Agreement.

          "RTO"   shall   mean   any   FERC-authorized   regional   transmission
organization.

          "Securities  Act"  shall  mean the  U.S.  Securities  Act of 1933,  as
amended, and all rules and regulations promulgated thereunder.

          "Service  Fee" shall have the meaning given to such term in the Agency
and Services Agreement.

          "Service Fee Return"  shall have the meaning given to such term in the
Agency and Services Agreement.

          "Service Fee Return  Refund" shall have the meaning given to such term
in the Agency and Services Agreement.

          "Services" shall have the meaning given to such term in the Agency and
Services Agreement.

          "Significant  Subsidiary"  shall mean (a) in the case of Calpine,  the
Subsidiaries of Calpine listed on Schedule  1.1(d),  their  successors,  if such
successors are Affiliates of Calpine, and assigns of all or substantially all of


                                       12
<PAGE>

their assets,  if such assigns are  Affiliates of Calpine and (b) in the case of
Bear Stearns,  the Subsidiaries of Bear Stearns listed on Schedule 1.1(d), their
successors,  if such  successors are Affiliates of Bear Stearns,  and assigns of
all or substantially all of their assets, if such assigns are Affiliates of Bear
Stearns.

          "Soft  Covenants"  shall mean Sections 3.1 and 3.14 of this  Agreement
and  Sections  4.1(b),  (c) and (e),  and  4.4(a)  of the  Agency  and  Services
Agreement.

          "Specified  Risk Limits"  shall have the meaning given to such term in
the Agency and Services Agreement.

          "SRO"  shall  mean  any   applicable   self-regulatory   organization,
including CFTC-designated contract markets.

          "Subsidiary"  shall mean, with respect to any Person,  any corporation
or other  business  entity,  whether  or not  incorporated,  of which at least a
majority of the securities or interests having, by their terms,  ordinary voting
power to elect members of the board of  directors,  managing  members,  or other
persons  performing  similar  functions  with respect to such  entity,  is held,
directly or indirectly, by such Person.

          "Tax(es)" shall mean all taxes,  estimated taxes,  withholding  taxes,
assessments,  levies,  imposts, and other like charges,  including any interest,
fines, penalties, additions to tax or additional amounts that have or may become
payable in respect  thereof,  imposed by any  foreign,  federal,  state or local
government or taxing  authority,  whether computed on a separate,  consolidated,
unitary,  combined or any other  basis,  which  taxes  shall  include all income
taxes,  service,  license and net worth taxes,  payroll and employee withholding
taxes, unemployment insurance, retirement, social security, sales and use taxes,
value-added  taxes,  excise  taxes,   franchise  taxes,  gross  receipts  taxes,
occupation taxes, real and personal  property taxes,  stamp taxes,  transfer and
recording taxes, workers' compensation and other obligations of the same or of a
similar nature.

          "Termination  Amount"  shall  have the  meaning  given to such term in
Section 16.6(d)(ii).

          "Termination  Date"  shall  have the  meaning  given  to such  term in
Section 16.1.

          "Termination Fee" shall have the meaning given to such term in Section
16.6(d)(ii).

          "Termination  Notice" shall mean an irrevocable  notice delivered by a
Party, on behalf of itself and its Affiliates that are Parties and in any manner
set forth in Section 18.2, to any of the Parties that are not Affiliates of such
Party,  stating  the  intent  of  such  Party  to  cause a  Liquidation  Date in
accordance with Section  16.6(b)(iii)  or Section  16.6(b)(ix) and setting forth
(a) a  Termination  Amount,  (b)(i) in the case of such notice by Calpine or any
Calpine  Transaction  Party, (A) Calpine's or such Calpine  Transaction  Party's
binding  offer,  irrevocable  by its terms for two (2) Business  Days  following
receipt of the  Termination  Notice by Bear  Stearns or  CalBear,  to either (x)
purchase the Final Third Party Master  Agreements,  in  accordance  with Section


                                       13
<PAGE>

16.6(d)(v)  (including  the  last  sentence  thereof),   from  CalBear  for  the
Termination  Amount or (y) receive from Bear Stearns or CalBear the  Termination
Fee,  and (B) that Bear  Stearns  or CalBear  shall  elect  within  such two (2)
Business  Day period to either sell the Final Third Party Master  Agreements  or
pay the Termination Fee in accordance with the immediately preceding clause (A),
or (ii) in the case of such notice by Bear Stearns or CalBear, (A) Bear Stearns'
or CalBear's  binding offer,  irrevocable by its terms for two (2) Business Days
following  receipt  of  the  Termination   Notice  by  Calpine  or  any  Calpine
Transaction  Party, to either (x) sell the Final Third Party Master  Agreements,
in accordance with Section  16.6(d)(v)  (including the last sentence thereof) to
Calpine or any Calpine  Transaction Party for the Termination  Amount or (y) pay
to Calpine or any Calpine  Transaction  Party the  Termination  Fee and (B) that
Calpine  or any  Calpine  Transaction  Party  shall  elect  within  such two (2)
Business Day period to either  purchase the Final Third Party Master  Agreements
or pay the Termination Fee in accordance with the immediately  preceding  clause
(A).

          "Termination Purchase Right" shall have the meaning given to such term
in Section 16.6(d)(ii).

          "Termination  Sale Right" shall have the meaning given to such term in
Section 16.6(d)(ii).

          "Third Party" shall mean, with respect to any Person, any other Person
that is not an Affiliate of such Person,  including any Governmental  Authority.
For purposes of this  Agreement  and the other  Transaction  Documents,  none of
Calpine or any Calpine  Transaction  Party shall be deemed to be a "Third Party"
with  respect to Bear  Stearns or CalBear and neither  Bear  Stearns nor CalBear
shall be deemed to be a "Third  Party"  with  respect to Calpine or any  Calpine
Transaction Party.

          "Third  Party  Claim"  shall  have the  meaning  given to such term in
Section 15.1(c)(i).

          "Third Party Losses"  shall mean any Claims or Damages  arising out of
or  resulting  from (i) a Third  Party  Claim,  including  any  such  Claim by a
Governmental Authority or (ii) actions taken to investigate, prevent or mitigate
a potential  Third  Party  Claim,  to the extent  such  actions (A) are taken by
Calpine or any Calpine  Transaction Party or (B) are reasonable actions taken by
CalBear or any of its Affiliates to investigate,  prevent or mitigate  potential
Third Party Claims  arising out of or resulting  from a violation of  Applicable
Law by Calpine or any Calpine Transaction Party for which  indemnification would
be available under Section  15.1(a)(i)(A),  (B), or (E), if after notice of such
violation by CalBear or any of its  Affiliates,  neither Calpine nor any Calpine
Transaction Party takes timely,  reasonable  actions to investigate,  prevent or
mitigate such potential Third Party Claims.

          "Third Party Master  Agreement"  shall have the meaning  given to such
term in the Agency and Services Agreement.

          "Third  Party  Service  Transaction"  shall  mean any  arrangement  to
provide a set of  services  to a Third  Party  related to Power or Gas  contract
management or physical or financial  optimization  activities of a counterparty,


                                       14
<PAGE>

to the  extent  that  such  services  are  related  to Power  generation  or Gas
production,   purchases,   sales,   transmission,    transportation,   dispatch,
scheduling,  nomination,  injection,  withdrawal, storage, ancillary services or
related physical or financial services and products.

          "Threshold"  shall  have the  meaning  given to such  term in  Section
15.1(a)(iv)(B).

          "Trades" shall mean any and all Gas Trades and Power Trades.

          "Trading  Master  Agreement"  shall mean that certain  Trading  Master
Agreement,  substantially  in the form attached hereto as Exhibit B, to be dated
on or about the Effective Date, by and between CES, CMSC and CalBear, governing,
among other matters, Credit Enhancement Trades.

          "Trading  Volume"  shall mean a volume of Power equal to the aggregate
volume of Power  (measured in MWhs) traded in any calendar  year by (a) Calpine,
in the CES discretionary program, and (b) CalBear.

          "Transaction Documents" shall mean (a) this Agreement,  (b) the Agency
and Services Agreement,  (c) the Trading Master Agreement,  and (d) the CET ISDA
Agreement.

          "Transaction  Parties" shall mean the Calpine  Transaction Parties and
CalBear, collectively.

          "Transfer"  shall  have  the  meaning  given to such  term in  Section
3.3(a).

   1.2    Construction.

          (a) Unless the context of this Agreement otherwise requires, (i) words
of any gender include each other gender, (ii) words using the singular or plural
number also include the plural or singular number, respectively, (iii) the terms
"hereof,"  "herein,"  "hereby"  and  derivative  or similar  words refer to this
entire  Agreement,  (iv) the terms  "modified"  and "amended" and  derivative or
similar words shall mean amended,  supplemented,  waived or otherwise  modified,
(v) the terms "Article" or "Section"  refer to the specified  Article or Section
of this Agreement,  (vi) the word  "including"  shall mean  "including,  without
limitation,"  whether  or not so  specified,  and (vii)  the word "or"  shall be
disjunctive but not exclusive.

          (b)  References to agreements and other  documents  shall be deemed to
include all subsequent modifications thereto.

          (c) References to statutes shall include all  regulations  promulgated
thereunder  and  references  to statutes or  regulations  shall be  construed as
including all statutory and  regulatory  provisions  consolidating,  amending or
replacing the statute or regulation.

          (d) The  language  used in this  Agreement  shall be  deemed to be the
language  chosen by the Parties to express their mutual  intent,  and no rule of
strict construction shall be applied against any Party.


                                       15
<PAGE>

          (e) The  annexes,  schedules  and  exhibits  to this  Agreement  are a
material part hereof and shall be treated as if fully incorporated into the body
of this Agreement.

          (f) Whenever this  Agreement  refers to a number of days,  such number
shall refer to calendar days unless Business Days are specified.

          (g) Whenever  this  Agreement  refers to a right,  obligation,  act or
omission of CalBear, the same shall mean a right, obligation, act or omission of
CalBear itself, and not of CalBear through CMSC as agent or attorney-in-fact for
or on behalf of or in the name of CalBear,  unless the  applicable  provision of
this Agreement expressly states otherwise.

                                  ARTICLE II.
                    FORMATION TRANSACTIONS; EFFECTIVE DATE

    2.1   Pre-Formation Transactions.  As soon as reasonably practicable
          following the date hereof:

          (a) CES Marketing VII, LLC shall be converted from a limited liability
company to a  corporation  under the laws of the State of Delaware  and its name
shall be changed to Calpine Merchant Services  Company,  Inc., and Calpine shall
enter into,  or cause to be entered  into,  amended and restated  Organizational
Documents of CMSC, substantially in the form attached hereto as Exhibit C;

          (b) Arroyo Energy LP's name shall be changed to CalBear  Energy LP and
Bear  Stearns  or  its   Affiliates   shall  enter  into  amended  and  restated
Organizational  Documents of CalBear,  substantially in the form attached hereto
as Exhibit D;

          (c)   Calpine  and  the  Calpine   Transaction   Parties   shall  take
commercially  reasonable actions to obtain any Regulatory Approvals necessary or
advisable in order for CMSC to perform the Services; and

          (d) CalBear shall take commercially  reasonable  actions to obtain any
Regulatory  Approvals necessary or advisable in order for CalBear to execute any
CalBear Trades.

          The  transactions  described  in this Section 2.1 shall be referred to
herein as the "Pre-Formation Transactions."

   2.2    Formation  Transactions.  Upon the terms and subject to the conditions
          set  forth in this Agreement, on or prior to the Effective Date:

          (a) Calpine  shall cause CMSC and Bear Stearns  shall cause CalBear to
become a Party to this  Agreement by executing an additional  signature  page to
this Agreement,  substantially in the form of Exhibit E hereto,  and,  following
such  execution  each of CMSC and CalBear shall be a party to, shall be bound by
the  obligations  of, and shall receive the benefits of this Agreement and shall
be "CMSC" and "CalBear",  respectively,  and a "Party",  in each case as defined
herein, for all purposes hereunder; and


                                       16
<PAGE>

          (b) CalBear and the applicable Calpine Transaction Parties shall enter
into the Agency and Services Agreement, the Trading Master Agreement and the CET
ISDA Agreement.

                  The transactions described in this Section 2.2 shall be
referred to herein as the "Formation Transactions."

    2.3   Effective  Date.  Unless  this  Agreement  shall have been  terminated
pursuant  to  Section  16.6(a)  hereof,  the  consummation  of the  transactions
contemplated  herein to be consummated on the Effective Date shall take place at
10:00 a.m.  New York time at the  offices of Latham & Watkins  LLP, at 885 Third
Avenue,  New York,  NY 10022,  on the third (3rd)  Business  Day  following  the
satisfaction or waiver of all of the conditions  precedent to the obligations of
the Parties set forth in Article  XII and  Article  XIII (other than  conditions
which are not capable of being  satisfied  until the  Effective  Date),  or such
other date as the Parties hereto agree (the "Effective Date").

                                  ARTICLE III.
                          RELATIONSHIP OF THE PARTIES

          Each of the Parties covenant and agree with each other as follows:

    3.1   CalBear Business[*]

          (b)  Notwithstanding  any other provision of this Agreement,  the sole
and  exclusive  remedy for any breach of this Section 3.1 shall be, in the event
of a breach by Calpine or the Calpine  Transaction  Parties, on the one hand, or
Bear Stearns,  on the other hand, the termination of this Agreement  pursuant to
Section 16.6(b)(iii) hereof.

    3.2   Exclusivity.

          (a)  Except  as  may  otherwise  be  specifically   provided  in  this
Agreement,  including  Sections  3.2(b),  (c) and (d), or the other  Transaction
Documents,  from  the  date  hereof  through  the  earlier  of (i)  the  date of
termination  of this  Agreement,  if this  Agreement is terminated  prior to the
Effective  Date,  or (ii) in all other  cases,  the last day of the  Non-Compete
Period,  neither Calpine or any of the Calpine  Transaction  Parties, on the one
hand,  nor Bear  Stearns  or  CalBear,  on the other  hand,  will,  directly  or
indirectly,  through one or more of their  respective  Affiliates  or otherwise,
engage in any business  arrangement with a Third Party,  whether structured as a
strategic  alliance,  joint  venture,  partnership,   co-ownership,  contractual
relationship,  agency relationship,  or otherwise, which, when taken as a whole,
substantially  replicates  the substance of the business  arrangement  under the
Transaction  Documents,  taken as a whole, and in connection  therewith provides
for the  sharing  of the  profits  (whether  through  the  ownership  of  Equity
Securities,  contractually, or otherwise) of such business with the Third Party,
in each case, in any state, possession, territory or other political subdivision
of the United States, Canada or Mexico.

          (b) The  foregoing  Section  3.2(a) shall not prohibit any business of
Calpine  or any  Calpine  Transaction  Party with a Third  Party if the  primary
business  of such  Third  Party  and its  Affiliates,  taken as a whole,  is the


                                       17
<PAGE>

ownership,  operation or management of one or more Facilities or gas or electric
loads or the purchase, sale, trading or transmission of Power or Gas.

          (c)  Nothing  in this  Agreement  shall  prohibit  (x)  Calpine or the
Calpine Transaction Parties or any of their Affiliates, on the one hand, or Bear
Stearns or CalBear or any of their  Affiliates,  on the other hand,  from having
passive  investments  of less  than five (5)  percent  in the  aggregate  of the
outstanding  Equity  Securities  of any entity  listed for trading on a national
stock  exchange (as defined in the  Exchange  Act) or any  recognized  automatic
quotation system, (y) Calpine,  the Calpine  Transaction Parties or any of their
Affiliates,  on the one  hand,  or  Bear  Stearns  or  CalBear  or any of  their
Affiliates,  on the other  hand,  from  entering  into any  financing  or credit
enhancement  transaction,  including any  transaction  similar to a transactions
contemplated by the Trading Master Agreement (provided that the other aspects of
such  transaction  do not  result in the  engagement  in a  business  that would
otherwise  violate this Section  3.2),  or (z) Bear  Stearns,  CalBear or any of
their  Affiliates from acting as an underwriter,  initial  purchaser,  lender or
otherwise with respect to any debt,  equity or other financing of any Person, or
purchasing,  owning, holding,  trading or selling any security or other interest
in any Person  (provided  that such activity or the related  transactions,  when
taken as a whole,  does not result in the  engagement  in a business  that would
otherwise violate this Section 3.2).

          (d) Nothing in this Agreement  shall  prohibit  Calpine or the Calpine
Transaction Parties or any of their Affiliates, on the one hand, or Bear Stearns
or any of its Affiliates (other than CalBear),  on the other hand, from engaging
in any  transaction  that  has  been  proposed  to  CalBear  by  Calpine  or its
Affiliates,  on the one hand,  or Bear Stearns or its  Affiliates,  on the other
hand, in accordance with the terms of the Transaction Documents,  if CalBear has
elected not to pursue such  transaction  and such  transaction  has ceased to be
CalBear Referral Business in accordance with Section 3.1(a) above.

   3.3    Certain  Restrictions  on  Sales  by  Calpine of Equity Securities and
Assets of CMSC.

          (a) Calpine and each of the Calpine  Transaction Parties hereby agrees
that it shall not, and shall cause its Affiliates not to, directly or indirectly
(through the sale of Equity  Securities  in an Affiliate  or  otherwise),  sell,
assign, transfer, convey, pledge, mortgage, hypothecate or otherwise encumber or
dispose of (in each case,  a  "Transfer")  any Equity  Securities  of, or all or
substantially all of the Assets of, CMSC, except in compliance with this Section
3.3.  If  Calpine,  any of the  Calpine  Transaction  Parties,  or any of  their
Affiliates  wishes to  Transfer  any such Assets or Equity  Securities,  Calpine
shall first  deliver to Bear Stearns a letter (the "Initial  Notice")  signed by
Calpine (and any such Calpine  Transaction  Party or Affiliate,  if  applicable)
setting forth the Equity Securities and/or Assets proposed to be Transferred and
the material terms of the proposed Transfer other than the price.

          (b) Upon receipt of an Initial Notice, Bear Stearns and its Affiliates
shall  have  forty  five (45) days (the  "Initial  Period")  to submit a binding
letter (the "Offer Notice")  signed by Bear Stearns (and any such Affiliate,  if
applicable)  setting  forth (A) a proposed  purchase  price with  respect to the
Equity Securities and/or Assets proposed to be Transferred and (B) Bear Stearns'
(or such Affiliate's) offer (irrevocable by its terms for five (5) Business Days


                                       18
<PAGE>

(such five (5) day period, the "Offer Period")) to purchase from Calpine or such
Calpine  Transaction  Party or any of their  Affiliates  the  Equity  Securities
and/or  Assets  described  in the Initial  Notice,  on the terms and  conditions
described  in the  Initial  Notice and for the  purchase  price set forth in the
Offer Notice (an "Offer").  If an Offer Notice is delivered  prior to the end of
the Initial Period, the Initial Period shall end on the date of delivery of such
Offer Notice and the Offer Period shall  commence on such date.  If neither Bear
Stearns nor any of its Affiliates delivers an Offer Notice to Calpine within the
Initial Period, Calpine or its Affiliate may, during the period beginning on the
forty-sixth  (46th) day  following  the  receipt of the  Initial  Notice by Bear
Stearns  and ending on the  ninetieth  (90th) day  following  the receipt of the
Initial Notice by Bear Stearns, Transfer to a Third Party all (but not less than
all) of the Equity Securities and/or Assets covered by the Initial Notice, for a
purchase price negotiated between Calpine or such Affiliate and such Third Party
and on other  terms and  conditions  at least as  favorable  to Calpine as those
contained in the Initial Notice;  provided that if a Third Party  transferee has
accepted  such offer,  Calpine  shall have  completed  such  Transfer  within an
additional  one hundred  eighty  (180) days from the end of such ninety (90) day
period; and provided,  further,  that, with respect to any such Transfer that is
not completed within the time periods set forth in this Section 3.3(b),  Calpine
shall not complete any such Transfer without again complying with each provision
of this Section 3.3, as applicable.

          (c) Upon receipt of an Offer Notice,  Calpine and its Affiliates shall
have the option to sell the Equity  Securities  and/or  Assets  described in the
Initial Notice to Bear Stearns (or its Affiliate, as applicable) at the purchase
price and upon the terms and  conditions  specified in the Offer.  If Calpine or
any of its Affiliates  desires to exercise the option set forth in the preceding
sentence,  it shall deliver a notice (an  "Election  Notice") to Bear Stearns at
any time during the Offer  Period,  which  Election  Notice  shall  specify that
Calpine or any of its  Affiliates  has elected to exercise  its option to accept
the Offer and sell the Equity  Securities and/or Assets described in the Initial
Notice to Bear Stearns (or its Affiliate,  as applicable) on the terms set forth
in the Offer.  If Calpine or any of its Affiliates  delivers an Election  Notice
during the Offer Period,  then Bear Stearns (or its  Affiliates,  as applicable)
shall be obligated to purchase and Calpine (or such  Affiliate,  as  applicable)
shall be obligated to sell, the Equity Securities and/or Assets described in the
Initial  Notice at the  purchase  price and on the  other  terms and  conditions
indicated in the Offer.  The closing of such  purchase and sale shall occur on a
closing  date  selected  by Bear  Stearns  or  such  Affiliate,  as  applicable;
provided,  however,  that such closing date shall be not less than ten (10) days
nor more than ninety (90) days following the date of the Election Notice, unless
more time is required to obtain any applicable regulatory or other approvals. If
neither  Calpine nor any of its Affiliates  delivers an Election  Notice to Bear
Stearns (or its  Affiliate,  as applicable)  within the Offer Period,  the Offer
shall  automatically  expire at the end of the Offer  Period  and  neither  Bear
Stearns nor any of its  Affiliates  shall have any  obligation  to purchase  the
Equity Securities and/or Assets described in the Initial Notice.

          (d) If Bear Stearns or one of its Affiliates  delivers an Offer Notice
to  Calpine  within the  Initial  Period,  but  neither  Calpine  nor any of its
Affiliates  delivers an Election Notice to Bear Stearns during the Offer Period,
Calpine or its Affiliate may, during the period beginning on the sixth (6th) day
following  the receipt of the Offer Notice by Calpine and ending on the fiftieth
(50th) day following  the receipt of the Offer Notice by Calpine,  Transfer to a
Third Party all (but not less than all) of the Equity  Securities  and/or Assets
covered by the Initial Notice, (x) for the purchase price and on the other terms


                                       19
<PAGE>

and  conditions  contained in the Offer Notice or (y) for a purchase  price more
favorable  financially  to Calpine,  and on other terms at least as favorable to
Calpine, as those contained in the Offer Notice;  provided that if a Third Party
transferee  has accepted such offer,  Calpine shall have completed such Transfer
within an  additional  one hundred  eighty (180) days from the end of such fifty
(50) day period; and provided,  further, that, with respect to any such Transfer
that is not completed  within the time periods set forth in this Section 3.3(d),
Calpine  shall not complete  such Transfer  without  again  complying  with each
provision of this Section 3.3, as applicable.

          (e) In  addition  to  the  foregoing  restrictions,  Calpine  (or  the
applicable  Calpine  Transaction  Party or  Affiliate)  shall not  complete  any
Transfer  pursuant to Section  3.3(b) or Section  3.3(d)  without  receiving the
prior consent of Bear Stearns to the transferee of such  Transfer,  such consent
with  respect to any  proposed  Third Party  transferee  not to be  unreasonably
withheld or delayed  after  Calpine's  (or the  applicable  Calpine  Transaction
Party's or  Affiliate's)  request for such  consent  (and in no event shall such
consent take more than the longer of ten (10) Business Days following receipt of
such request by Bear Stearns or the time remaining  until the end of the Initial
Period or the Offer Period, as applicable);  provided that Bear Stearns may give
or withhold such consent in its sole and absolute discretion with respect to any
proposed Transfers to a Restricted Transferee.  Calpine may make the request for
such  consent at any time  following  delivery of an Initial  Notice,  including
contemporaneously with the applicable Initial Notice; provided that Calpine must
provide the  identity of any  proposed  Third Party  transferee  (as well as the
identity of the ultimate  operating and holding company parent,  if any, of each
proposed  Third  Party  transferee,  if the  identity of such  Person(s)  is not
readily  apparent) in each request for consent,  and otherwise  comply with this
Section 3.3.  Any consent  given to a Transfer  pursuant to this Section  3.3(e)
shall expire (i) if no proposed  Third Party  transferee  mentioned in a request
for  consent and  approved  by Bear  Stearns  has  accepted  Calpine's  offer to
Transfer the Equity  Securities  and/or Assets  covered by the Initial Notice in
accordance  with Section  3.3(b) or Section 3.3(d) by the end of the ninety (90)
day period set forth in Section 3.3(b) or the fifty (50) day period set forth in
Section 3.3(d),  respectively,  at the end of such period, or (ii) if a proposed
Third Party  transferee  approved by Bear  Stearns has accepted  such offer,  if
Calpine's  Transfer to such Third Party transferee has not been completed within
an additional  one hundred eighty (180) days from the end of the ninety (90) day
period  set forth in  Section  3.3(b) or the fifty  (50) day period set forth in
Section 3.3(d), as applicable.

          (f)  Calpine  further  agrees  that in  connection  with any  Transfer
subject to this Section 3.3  consented to by Bear  Stearns,  Calpine  shall,  if
requested  by Bear  Stearns,  deliver to Bear  Stearns  an  opinion of  external
counsel  in form and  substance  reasonably  satisfactory  to Bear  Stearns  and
counsel for Bear Stearns, to the effect that the Transfer is not in violation of
this Agreement,  and, with respect to a Transfer of any Equity Security,  is not
in violation of the  Securities  Act or the  securities  laws of any State.  Any
purported Transfer in violation of the provisions of this Section 3.3, including
any Transfer to a Third Party made without Bear Stearns' prior consent, shall be
null and void and shall have no force or effect.

          (g) Notwithstanding  anything herein to the contrary, this Section 3.3
shall not apply to (i) a Transfer to Calpine or any of its Affiliates,  provided
that if such Transfer is a Transfer of (A) Assets from CMSC, such Transfer is to


                                       20
<PAGE>

an Affiliate of Calpine that is Bankruptcy  Remote,  or (B) Equity Securities of
CMSC, following such Transfer CMSC is Bankruptcy Remote, (ii) a Transfer to Bear
Stearns  or any of its  Affiliates,  or (iii) a  Transfer  to any Person or such
Person's  Subsidiaries if such Person or its Subsidiaries  merge with Calpine or
purchase all or substantially all of the Equity Securities or Assets of Calpine.

          (h) In  addition  to the  restrictions  set  forth  elsewhere  in this
Agreement,  in the event of a proposed  Transfer  to a Third Party by Calpine or
any of its  Affiliates  of Equity  Securities  and/or Assets of CMSC pursuant to
this Section 3.3,  Bear Stearns'  consent to such  Transfer  shall not be deemed
unreasonably  withheld  if such Third  Party  does not agree to become  bound in
writing at the  closing of such  Transfer  by the terms and  conditions  of this
Agreement and the other Transaction Documents and agree to assume the rights and
obligations of Calpine and all of the Calpine  Transaction Parties hereunder and
thereunder  pursuant  to  one  or  more  instruments  of  assumption  reasonably
satisfactory  in form and substance to Bear Stearns.  Notwithstanding  the other
provisions of this Section 3.3,  unless  expressly  waived by Bear Stearns,  any
otherwise  permitted  Transfer  shall be null and void ab initio if Bear Stearns
does not receive written  instruments  with respect to such Transfer  (including
copies of any instruments of assumption and the Third Party transferee's consent
to  be  bound  by  this  Agreement  and  the  other  Transaction  Documents,  as
applicable) that are in a form reasonably  satisfactory in form and substance to
Bear Stearns. Upon the execution of such instruments of assumption by such Third
Party,  such  Third  Party  shall  be  deemed  to be  Calpine  and  the  Calpine
Transaction Parties for all purposes of this Agreement.

   3.4    Certain Restrictions on Sales by Bear Stearns of Equity Securities and
Assets of CalBear.

          (a) Bear Stearns  hereby agrees that it shall not, and shall cause its
Affiliates not to, directly or indirectly (through the sale of Equity Securities
in an Affiliate or  otherwise),  Transfer  any Equity  Securities  of, or all or
substantially  all of the Assets of,  CalBear,  except in  compliance  with this
Section  3.4. If Bear  Stearns or any of its  Affiliates  wishes to Transfer any
such Assets or Equity Securities, Bear Stearns shall first deliver to Calpine an
Initial  Notice signed by Bear Stearns (and any such  Affiliate,  if applicable)
setting forth the Equity Securities and/or Assets proposed to be Transferred and
the material terms of the proposed Transfer other than the price.

          (b) Upon  receipt of an Initial  Notice,  Calpine  and its  Affiliates
shall have the Initial  Period to submit an Offer Notice  signed by Calpine (and
any such Affiliate,  if applicable)  setting forth (A) a proposed purchase price
with respect to the Equity  Securities  and/or Assets proposed to be Transferred
and (B) Calpine's (or such Affiliate's)  offer (irrevocable by its terms for the
Offer Period) to purchase from Bear Stearns or any of its  Affiliates the Equity
Securities  and/or  Assets  described  in the Initial  Notice,  on the terms and
conditions  described in the Initial Notice and for the purchase price set forth
in the Offer  Notice.  If an Offer Notice is  delivered  prior to the end of the
Initial  Period,  the Initial  Period  shall end on the date of delivery of such
Offer  Notice and the Offer  Period  shall  commence  on such  date.  If neither
Calpine  nor any of its  Affiliates  delivers  an Offer  Notice to Bear  Stearns
within the Initial Period,  Bear Stearns or its Affiliate may, during the period
beginning on the  forty-sixth  (46th) day  following  the receipt of the Initial
Notice by Calpine and ending on the  ninetieth  (90th) day following the receipt


                                       21
<PAGE>

of the Initial  Notice by  Calpine,  Transfer to a Third Party all (but not less
than all) of the Equity  Securities and/or Assets covered by the Initial Notice,
for a purchase price negotiated  between Bear Stearns or such Affiliate and such
Third  Party and on other terms and  conditions  at least as  favorable  to Bear
Stearns as those contained in the Initial Notice; provided that if a Third Party
transferee  has accepted  such offer,  Bear Stearns  shall have  completed  such
Transfer within an additional one hundred eighty (180) days from the end of such
ninety (90) day period;  and provided,  further,  that, with respect to any such
Transfer that is not completed within the time periods set forth in this Section
3.4(b),  Bear  Stearns  shall  not  complete  any such  Transfer  without  again
complying with each provision of this Section 3.4, as applicable.

          (c) Upon receipt of an Offer Notice,  Bear Stearns and its  Affiliates
shall have the option to sell the Equity  Securities  and/or Assets described in
the Initial Notice to Calpine (or its Affiliate,  as applicable) at the purchase
price and upon the terms and conditions  specified in the Offer. If Bear Stearns
or any of its  Affiliates  desires  to  exercise  the  option  set  forth in the
preceding  sentence,  it shall deliver an Election Notice to Calpine at any time
during the Offer Period,  which Election  Notice shall specify that Bear Stearns
or any of its  Affiliates has elected to exercise its option to accept the Offer
and sell the Equity  Securities and/or Assets described in the Initial Notice to
Calpine (or its  Affiliate,  as applicable) on the terms set forth in the Offer.
If Bear Stearns or any of its Affiliates  delivers an Election Notice during the
Offer Period, then Calpine (or its Affiliates, as applicable) shall be obligated
to  purchase  and Bear  Stearns  (or such  Affiliate,  as  applicable)  shall be
obligated to sell, the Equity  Securities and/or Assets described in the Initial
Notice at the purchase price and on the other terms and conditions  indicated in
the Offer.  The closing of such  purchase and sale shall occur on a closing date
selected by Calpine or such Affiliate,  as applicable;  provided,  however, that
such closing date shall be not less than ten (10) days nor more than ninety (90)
days following the date of the Election Notice,  unless more time is required to
obtain any applicable regulatory or other approvals. If neither Bear Stearns nor
any of its Affiliates  delivers an Election Notice to Calpine (or its Affiliate,
as applicable) within the Offer Period, the Offer shall automatically  expire at
the end of the Offer Period and neither Calpine nor any of its Affiliates  shall
have any obligation to purchase the Equity Securities and/or Assets described in
the Initial Notice.

          (d) If Calpine or one of its  Affiliates  delivers an Offer  Notice to
Bear Stearns within the Initial Period,  but neither Bear Stearns nor any of its
delivers an Election Notice to Calpine during the Offer Period,  Bear Stearns or
its Affiliate may, during the period  beginning on the sixth (6th) day following
the  receipt of the Offer  Notice by Bear  Stearns  and  ending on the  fiftieth
(50th) day following  the receipt of the Offer Notice by Bear Stearns,  Transfer
to a Third  Party all (but not less than all) of the  Equity  Securities  and/or
Assets  covered by the Initial  Notice,  (x) for the  purchase  price and on the
other terms and  conditions  contained in the Offer Notice or (y) for a purchase
price more favorable financially to Bear Stearns, and on other terms at least as
favorable to Bear Stearns, as those contained in the Offer Notice; provided that
if a Third Party  transferee  has accepted  such offer,  Bear Stearns shall have
completed such Transfer  within an additional one hundred eighty (180) days from
the end of such fifty (50) day period; and provided, further, that, with respect
to any such Transfer that is not completed  within the time periods set forth in
this Section 3.4(d), Bear Stearns shall not complete such Transfer without again
complying with each provision of this Section 3.4, as applicable.


                                       22
<PAGE>

          (e) In addition to the  foregoing  restrictions,  Bear Stearns (or the
applicable Affiliate) shall not complete any Transfer pursuant to Section 3.4(b)
or  Section  3.4(d)  without  receiving  the prior  consent  of  Calpine  to the
transferee  of such  Transfer,  such consent with respect to any proposed  Third
Party transferee not to be unreasonably  withheld or delayed after Bear Stearns'
(or the applicable  Affiliate's) request for such consent (and in no event shall
such  consent  take more than the  longer of ten (10)  Business  Days  following
receipt of such  request by Calpine or the time  remaining  until the end of the
Initial Period or the Offer Period,  as  applicable);  provided that Calpine may
give or withhold such consent in its sole and absolute  discretion  with respect
to any proposed Transfers to a Restricted Transferee.  Bear Stearns may make the
request for such consent at any time  following  delivery of an Initial  Notice,
including  contemporaneously  with the applicable Initial Notice;  provided that
Bear Stearns must  provide the identity of any proposed  Third Party  transferee
(as well as the identity of the ultimate  operating and holding  company parent,
if any,  of each  proposed  Third  Party  transferee,  if the  identity  of such
Person(s) is not readily  apparent) in each request for consent,  and  otherwise
comply with this Section 3.4. Any consent  given to a Transfer  pursuant to this
Section 3.4(e) shall expire (i) if no proposed Third Party transferee  mentioned
in a request for consent and  approved  by Calpine has  accepted  Bear  Stearns'
offer to Transfer the Equity  Securities  and/or  Assets  covered by the Initial
Notice in  accordance  with Section  3.4(b) or Section  3.4(d) by the end of the
ninety (90) day period set forth in Section  3.4(b) or the fifty (50) day period
set forth in Section 3.4(d), respectively, at the end of such period, or (ii) if
a proposed Third Party  transferee  approved by Calpine has accepted such offer,
if Bear Stearns'  Transfer to such Third Party transferee has not been completed
within an  additional  one hundred  eighty (180) days from the end of the ninety
(90) day  period  set forth in  Section  3.4(b) or the fifty (50) day period set
forth in Section 3.4(d), as applicable.

          (f) Bear Stearns  further agrees that in connection  with any Transfer
subject to this Section 3.4  consented to by Calpine,  Bear  Stearns  shall,  if
requested by Calpine,  deliver to Calpine an opinion of external counsel in form
and substance reasonably satisfactory to Calpine and counsel for Calpine, to the
effect that the Transfer is not in violation  of this  Agreement,  and is not in
violation  of the  Securities  Act or the  securities  laws  of any  State.  Any
purported Transfer in violation of the provisions of this Section 3.4, including
any Transfer to a Third Party made without  Calpine's  prior  consent,  shall be
null and void and shall have no force or effect.

          (g) Notwithstanding  anything herein to the contrary, this Section 3.4
shall not apply to (i) a Transfer to Bear Stearns or any of its Affiliates, (ii)
a Transfer  to Calpine or any of its  Affiliates,  including  any such  Transfer
pursuant to Section 16.6(d),  or (iii) a Transfer to any Person or such Person's
Subsidiaries  if such  Person or its  Subsidiaries  merge  with Bear  Stearns or
purchase all or  substantially  all of the Equity  Securities  or Assets of Bear
Stearns.

          (h) In  addition  to the  restrictions  set  forth  elsewhere  in this
Agreement,  in the event of a proposed Transfer to a Third Party by Bear Stearns
or any of its Affiliates of Equity  Securities and/or Assets of CalBear pursuant
to this  Section 3.4,  Calpine's  consent to such  Transfer  shall not be deemed
unreasonably  withheld  if such Third  Party  does not agree to become  bound in
writing at the  closing of such  Transfer  by the terms and  conditions  of this
Agreement and the other Transaction Documents and agree to assume the rights and
obligations of Bear Stearns and CalBear hereunder and thereunder pursuant to one


                                       23
<PAGE>

or more instruments of assumption reasonably  satisfactory in form and substance
to Calpine.  Notwithstanding  the other  provisions of this Section 3.4,  unless
expressly waived by Calpine,  any otherwise permitted Transfer shall be null and
void ab initio if Calpine does not receive written  instruments  with respect to
such Transfer  (including  copies of any instruments of assumption and the Third
Party  transferee's  consent  to be  bound  by  this  Agreement  and  the  other
Transaction Documents, as applicable) that are in a form reasonably satisfactory
in form and  substance to Calpine.  Upon the  execution of such  instruments  of
assumption  by such Third  Party,  such Third  Party  shall be deemed to be Bear
Stearns and CalBear for all purposes of this Agreement.

          (i) In  addition  to the  restrictions  set  forth  elsewhere  in this
Agreement,  in the event of a proposed Transfer to a Third Party by Bear Stearns
or any of its Affiliates of Equity  Securities and/or Assets of CalBear pursuant
to this  Section 3.4,  Calpine's  consent to such  Transfer  shall not be deemed
unreasonably  withheld  if such Third  Party  does not have,  at the time of the
transfer, a credit rating by (i) Standard & Poors Ratings Group of at least BBB+
and (ii) Moody's Investor Services of at least Baa1.

   3.5    No Joint Venture or Partnership Created.

          (a) Calpine and the Calpine Transaction  Parties, on the one hand, and
Bear  Stearns and  CalBear,  on the other  hand,  are  independent  contractors.
Neither  Calpine or any Calpine  Transaction  Party,  on the one hand,  nor Bear
Stearns or  CalBear,  on the other  hand,  is an agent  (except as  specifically
provided in the Agency and  Services  Agreement),  representative  or partner of
Bear  Stearns  or  CalBear,   or  Calpine  or  any  Calpine  Transaction  Party,
respectively,  and each of Calpine and the Calpine  Transaction Parties and Bear
Stearns  and CalBear  agrees that the  Transaction,  this  Agreement,  the other
Transaction  Documents and the transactions  contemplated hereby and thereby are
not  intended to create,  and shall not be  interpreted,  construed or deemed to
create  in  any   respect   an   association,   joint   venture,   co-ownership,
co-authorship,  or partnership,  whether general, limited or otherwise,  between
Calpine or any Calpine  Transaction  Party, on the one hand, and Bear Stearns or
CalBear,  on  the  other  hand,  or to  impose  any  partnership  obligation  or
partnership  liability between Calpine or any Calpine  Transaction Party, on the
one hand, and Bear Stearns or CalBear, on the other hand. None of Calpine or any
Calpine  Transaction Party, on the one hand, nor Bear Stearns or CalBear, on the
other hand,  shall have any right,  power or  authority to  negotiate,  execute,
authenticate  or deliver any  Contract for or on behalf of or in the name of, or
to incur any  Liability  for, or to  otherwise  bind,  Bear  Stearns or Calpine,
respectively,  or  bind  CalBear  or  any of the  Calpine  Transaction  Parties,
respectively,  except as  specifically  set  forth in the  Agency  and  Services
Agreement or the Trading Master Agreement,  in each case with respect to CalBear
and CMSC. Calpine and the Calpine Transaction Parties, on the one hand, and Bear
Stearns and CalBear,  on the other hand,  agree that they are not, and shall not
be, and shall not hold Bear  Stearns  or  CalBear,  or  Calpine  or the  Calpine
Transaction Parties, respectively, out to be, co-employers.

          (b) The Parties will determine a public description of the Transaction
mutually  satisfactory  to Calpine and Bear  Stearns.  Calpine and Bear  Stearns
shall not, and shall cause their  Affiliates not to, make any press release that
is materially  inconsistent with such public  description.  Reference is made to
Section 18.13 for other agreements with respect to press releases.


                                       24
<PAGE>

   3.6    Conflicts of Interest; Non-Discrimination.

          (a)  Conflicts of Interest.  Calpine,  CMSC,  Bear Stearns and CalBear
acknowledge  that CMSC is providing the Services to CalBear and that Calpine (a)
indirectly  owns a one hundred  percent  (100%) equity  interest in CMSC and (b)
either  directly  or  indirectly   through  one  or  more  of  its  wholly-owned
Subsidiaries,  including  CES or  CMSC,  is  conducting  for its own  account  a
business similar to the CalBear Referral Business.  Accordingly,  Calpine, CMSC,
Bear Stearns and CalBear  acknowledge  and agree that  conflicts  may arise from
time to time between the interests of CalBear,  on the one hand,  and CMSC,  CES
and Calpine's other Affiliates,  on the other hand. In addition,  Calpine, CMSC,
Bear Stearns and CalBear  acknowledge  and agree that CMSC may provide  services
similar to the  Services  with  respect to  transactions  entered  into by Third
Parties or for or on behalf of Third  Parties by CMSC.  The Parties  acknowledge
that Section 4.2 of the Agency and Services Agreement contains certain covenants
of CMSC  representing  the sole and  exclusive  agreement  of the  Parties  with
respect to such conflicts of interest.

          (b) Non-Discrimination.  Calpine agrees that it shall, and shall cause
its Affiliates to, cause CMSC to comply with its obligations pursuant to Section
4.2 of the Agency and Services Agreement.  Calpine agrees that it shall not, and
shall cause its  Affiliates not to, take any action or enter into any agreement,
transaction or arrangement with the purpose of avoiding CMSC's obligations under
Section  4.2 of the  Agency  and  Services  Agreement,  including  by  providing
services  substantially  similar to the Services  through  Calpine or any of its
Affiliates  other  than  CES  or  CMSC  with  the  purpose  of  avoiding  CMSC's
obligations under Section 4.2 of the Agency and Services Agreement.

   3.7    Non-Solicitation of Bear Stearns Employees.

          (a) Prior to the termination of this Agreement and for a period of one
(1) year following the date of termination  of this  Agreement,  each of Calpine
and the Calpine  Transaction Parties shall not, and shall cause their Affiliates
not to, directly or indirectly, for itself or on behalf of any other Person, (i)
hire any employee of Bear Stearns or CalBear who is involved in the transactions
contemplated hereby or by the other Transaction  Documents or the CalBear Trades
and who is listed on Schedule  3.7(a)  (provided that Schedule  3.7(a) shall not
initially  include more than [*]  employees) (A) while such employee is employed
by Bear Stearns or CalBear, or (B) in the event of a voluntary  resignation from
Bear Stearns or CalBear of an employee  listed on Schedule 3.7(a) at the time of
such resignation,  for a period of (60) days following such resignation, or (ii)
solicit,  induce or attempt to solicit or induce any employee of Bear Stearns or
CalBear  listed on  Schedule  3.7(a) to leave  his or her  employment  with Bear
Stearns or CalBear,  as applicable;  provided that a general  solicitation or an
employment agency  solicitation that is not directed to specifically  target any
such employee shall not be deemed to violate this Section  3.7(a)(ii) so long as
Calpine,  the Calpine  Transaction  Parties and their Affiliates do not hire any
such employee as a result of such solicitation or inducement.

          (b) Once each calendar year,  commencing with calendar year 2006, Bear
Stearns  may modify  Schedule  3.7(a) to (i)  increase  the number of  employees
listed on Schedule 3.7(a) up to the number of employees that Calpine includes on
Schedule 3.8(a),  and/or (ii) remove  employees from Schedule  3.7(a);  provided


                                       25
<PAGE>

that if Bear Stearns modifies Schedule 3.7(a) to remove any employee  therefrom,
Section  3.7(a)  shall no  longer  apply  with  respect  to such  employee;  and
provided,  further,  that such  modifications  to Schedule  3.7(a)  shall not be
effective  until Bear Stearns  provides a copy of such modified  Schedule 3.7(a)
(highlighting any  modifications  thereto) to Calpine in accordance with Section
18.2. In addition, after (i) the dismissal or termination of any employee listed
on Schedule  3.7(a) or (ii) sixty (60) days have  elapsed  following a voluntary
resignation  of an employee  listed on Schedule  3.7(a),  Schedule  3.7(a) shall
automatically be modified to remove the name of such employee,  and Bear Stearns
shall  promptly  provide a copy of such modified  Schedule  3.7(a) to Calpine in
accordance with Section 18.2.

          (c) Notwithstanding the provisions of Section 3.7(a), none of Calpine,
the  Calpine  Transaction  Parties or their  Affiliates  shall be deemed to have
violated  Section  3.7(a) until Bear Stearns  provides  notice to Calpine of the
hiring  and/or  solicitation  of any  employee  of Bear  Stearns  or  CalBear in
violation of Section 3.7(a) (which notice contains the name,  title and position
of the employee hired in violation of Section  3.7(a) or details  concerning the
solicitation violating Section 3.7(a)) and Bear Stearns has provided Calpine the
opportunity  to cure such  violation in  accordance  with this  Section  3.7(c).
During the  period  commencing  on the date of  receipt  of any such  notice and
ending on the thirtieth  (30th) day thereafter  (subject to an extension for any
retention period or other period required by Applicable  Law),  Calpine shall be
entitled to cure any  violation  of Section  3.7(a) by  dismissing  the employee
named in the notice (on terms  determined  by  Calpine  in its  discretion,  but
subject  to the  length  of the cure  period  described  above) or  ceasing  the
activity causing the solicitation described in the notice, as applicable.

   3.8    Non-Solicitation of Calpine Employees.

          (a) Prior to the termination of this Agreement and for a period of one
(1) year  following  the date of  termination  of this  Agreement,  each of Bear
Stearns and CalBear shall not, and shall cause their Affiliates not to, directly
or  indirectly,  for  itself  or on behalf  of any  other  Person,  (i) hire any
employee  of Calpine or any  Calpine  Transaction  Party who is  involved in the
transactions  contemplated  hereby or by the other Transaction  Documents or the
CalBear  Trades or the Services and who is listed on Schedule  3.8(a)  (provided
that Schedule  3.8(a) shall not initially  include more than [*]  employees) (A)
while such employee is employed by Calpine or any Calpine  Transaction Party, or
(B)  in the  event  of a  voluntary  resignation  from  Calpine  or any  Calpine
Transaction  Party of an employee  listed on Schedule 3.8(a) at the time of such
resignation,  for a period  of (60) days  following  such  resignation,  or (ii)
solicit,  induce or attempt to solicit or induce any  employee of Calpine or any
Calpine  Transaction  Party  listed  on  Schedule  3.8(a)  to  leave  his or her
employment  with  Calpine  or any  Calpine  Transaction  Party,  as  applicable;
provided that a general  solicitation or an employment agency  solicitation that
is not directed to specifically  target any such employee shall not be deemed to
violate  this Section  3.8(a)(ii)  so long as Bear Stearns and CalBear and their
Affiliates  do not hire any such  employee as a result of such  solicitation  or
inducement.

          (b) Once each  calendar  year,  commencing  with  calendar  year 2006,
Calpine may modify Schedule 3.8(a) to (i) proportionally  increase the number of
employees  listed on  Schedule  3.8(a) to  reflect  increases  in the  number of


                                       26
<PAGE>

employees of CMSC,  and/or (ii) remove employees from Schedule 3.8(a);  provided
that if  Calpine  modifies  Schedule  3.8(a) to remove any  employee  therefrom,
Section  3.8(a)  shall no  longer  apply  with  respect  to such  employee;  and
provided,  further,  that such  modifications  to Schedule  3.8(a)  shall not be
effective  until  Calpine  provides  a copy of  such  modified  Schedule  3.8(a)
(highlighting  any  modifications  thereto) to Bear Stearns in  accordance  with
Section  18.2.  In  addition,  after (i) the  dismissal  or  termination  of any
employee  listed on  Schedule  3.8(a)  or (ii)  sixty  (60)  days  have  elapsed
following a voluntary  resignation  of an  employee  listed on Schedule  3.8(a),
Schedule  3.8(a)  shall  automatically  be  modified  to remove the name of such
employee,  and Calpine shall promptly  provide a copy of such modified  Schedule
3.8(a) to Bear Stearns in accordance with Section 18.2.

          (c)  Notwithstanding  the provisions of Section  3.8(a),  none of Bear
Stearns,  CalBear or their  Affiliates  shall be deemed to have violated Section
3.8(a)  until  Calpine  provides  notice to Bear  Stearns of the  hiring  and/or
solicitation  of any  employee  of Calpine or any Calpine  Transaction  Party in
violation of Section 3.8(a) (which notice contains the name,  title and position
of the employee hired in violation of Section  3.8(a) or details  concerning the
solicitation violating Section 3.8(a)) and Calpine has provided Bear Stearns the
opportunity  to cure such  violation in  accordance  with this  Section  3.8(c).
During the  period  commencing  on the date of  receipt  of any such  notice and
ending on the thirtieth  (30th) day thereafter  (subject to an extension for any
retention period or other period required by Applicable Law), Bear Stearns shall
be entitled to cure any violation of Section  3.8(a) by dismissing  the employee
named in the notice (on terms determined by Bear Stearns in its discretion,  but
subject  to the  length  of the cure  period  described  above) or  ceasing  the
activity causing the solicitation described in the notice, as applicable.

   3.9    Confidential Information.

          (a) Prior to the termination of this Agreement and for a period of one
(1) year following the  termination of this  Agreement,  the Parties shall,  and
shall cause their respective  Affiliates and Representatives to, (i) maintain in
strict  confidence any and all Confidential  Information  concerning the Parties
and the CalBear Business (including the CalBear Information) and not disclose to
any Third Party any such  Confidential  Information and (ii) restrict the use of
Confidential  Information to prevent  anticompetitive use of such information in
violation of antitrust laws, including with respect to Confidential  Information
regarding  trading  positions,   pricing  models,  projected  trades  and  other
commercial information related to the Power and Gas trading markets developed by
CMSC, with respect to compliance by Bear Stearns and CalBear,  or CalBear,  with
respect to compliance by Calpine and the Calpine Transaction  Parties;  provided
that the  foregoing  obligations  shall  not  apply to  Calpine  or the  Calpine
Transaction  Parties in  connection  with a disclosure by Calpine or the Calpine
Transaction  Parties of the aggregate  net portfolio  positions of CES, but, for
the  avoidance  of doubt,  shall  apply with  respect to any  individual  Credit
Enhancement Trade or any disclosure that, directly or indirectly,  would allow a
Third Party to identify or otherwise  directly determine the terms of any Credit
Enhancement  Trade.  It is  understood  that  the  Parties  shall  not  have any
liability hereunder with respect to information that (i) is, or through no fault
of the Parties or any of their respective Affiliates or Representatives becomes,
generally  available to the public,  (ii) is received  from a Third Party and is


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<PAGE>

not subject to any  confidentiality  obligation  between the receiving  Party or
Parties  and such  Third  Party,  (iii) is  independently  developed  by a Party
without  the use of the  Confidential  Information,  (iv) the  Parties  or their
respective  Affiliates or Representatives  are legally required to disclose,  or
that is the subject of any disclosure request made by any Governmental Authority
or by any Third  Party  pursuant  to  Applicable  Law,  or (v) is  necessary  in
connection with the defense or prosecution of any Action.

          (b)  In  the  event  that  a  Party  or  any  of  its   Affiliates  or
Representatives   is  required  or  requested   to  disclose  any   Confidential
Information  pursuant to Section  3.9(a)(iv)  or (v),  such Party shall,  unless
prohibited or otherwise  required by Applicable Law, if an Affiliate of Calpine,
promptly  notify Bear  Stearns,  or if an  Affiliate of Bear  Stearns,  promptly
notify Calpine,  so that the Parties may cooperate in seeking a protective order
and/or other motion,  at the expense of the Party seeking such protective  order
and/or other  motion,  to prevent or limit the  production or disclosure of such
Confidential  Information.  If such  protective  order is not  obtained  or such
motion has been denied,  then the Person  required or requested to disclose such
Confidential  Information  may disclose  only that portion of such  Confidential
Information  which,  based on the advice of such Person's outside legal counsel,
is required by  Applicable  Law or requested by a  Governmental  Authority to be
disclosed  (provided  that the Person  required or  requested  to disclose  such
information shall use all reasonable efforts to preserve the  confidentiality of
the remainder of such Confidential  Information).  Such Person shall continue to
be bound by its  obligations  pursuant to this Section 3.9 for any  Confidential
Information that is not required or requested to be disclosed,  or that has been
afforded protective treatment, pursuant to such order or motion.

          (c)   Notwithstanding   the   provisions  of  Section   3.9(a)  above,
disclosures of  Confidential  Information may be made (i) in the ordinary course
of CalBear's  business,  but only to the extent reasonably  necessary to conduct
such  business,  (ii) to each  Party's  advisors,  auditors,  legal  counsel and
insurers  and lenders who  reasonably  need to have access to such  Confidential
Information  in  connection  with  the  performance  of  their  work,  (iii)  to
Representatives of Calpine and its Affiliates who reasonably need to have access
to such  Confidential  Information in connection  with the  performance of their
work, (iv) to  Representatives of Bear Stearns and its Affiliates who reasonably
need to have access to such  Confidential  Information  in  connection  with the
performance of their work, (v) to bona fide potential Third Party  purchasers of
an  interest  in any  Party or its  Subsidiaries,  but in each  case only to the
extent  required in  connection  with such  transaction;  provided that any such
Third Party  receiving  any  Confidential  Information  agrees to  maintain  the
confidentiality  of such  Confidential  Information in accordance with the terms
hereof, and (vi) by any Party or any of their respective  Affiliates at any time
in  connection  with  any  reporting  requirements  of  such  Person  under  any
Applicable Law, any bona fide debt or equity financing of such Person,  any bona
fide  merger  or  sale  of  such  Person,  or  any  bona  fide  sale  of  all or
substantially  all of such Person's Assets,  but in each case only to the extent
reasonably necessary in connection with such transaction,  and such Confidential
Information  may  be  included  in  any  financial   statements,   schedules  or
information,  any diligence  materials or any prospectus,  offering  memorandum,
information  statement or proxy  statement  provided to any Person in connection
therewith  (provided that any such disclosure pursuant to this clause (vi) shall
not include the terms of any individual  CalBear Trade or any  disclosure  that,


                                       28
<PAGE>

directly or  indirectly,  would  allow a Third  Party to  identify or  otherwise
directly  determine the terms of any  individual  CalBear  Trade,  without prior
notice to each Party that is not an  Affiliate  of the  disclosing  Party unless
prohibited by Applicable Law).

    3.10  Netting. Except as expressly set forth in Section 4.4(e) of the Agency
and Services  Agreement,  in the event that, at any time, Calpine or any Calpine
Transaction  Party,  on the one hand,  or Bear Stearns or CalBear,  on the other
hand, is required,  pursuant to this Agreement, the other Transaction Documents,
the  transactions  contemplated  hereby or thereby,  the Services or the CalBear
Trades,  to make any  Payment to Bear  Stearns or CalBear,  on the one hand,  or
Calpine or any Calpine Transaction Party, on the other hand, respectively,  then
in each case the amounts of such Payments between or among Calpine,  the Calpine
Transaction Parties, Bear Stearns and CalBear, as applicable,  may be aggregated
and  Calpine  and the  Calpine  Transaction  Parties,  on the one hand,  or Bear
Stearns and CalBear,  on the other hand,  as  applicable,  may  discharge  their
obligations to make such Payments through  netting,  in which case the Party (or
Calpine and the Calpine Transaction Parties or Bear Stearns and CalBear, in each
case as a group),  if any, owing the greater aggregate amount to any other Party
(or Calpine and the Calpine  Transaction Parties or Bear Stearns and CalBear, in
each case as a group),  may pay to the Party (or such group of Parties) to which
the applicable  Payment or Payments are owed the difference  between the amounts
owed.  For the  avoidance  of doubt,  this  Section  3.10 is  intended to permit
netting of all amounts due among the Parties  hereto or the parties to any other
Transaction  Documents to the fullest  extent  possible.  Each Party reserves to
itself all  rights,  setoffs,  counterclaims  and other  remedies  and  defenses
consistent  with  Article  XVII (to the extent not  expressly  herein  waived or
denied)  which each such Party is or may be entitled  to arising  from or out of
this Agreement and the other  Transaction  Documents.  All  outstanding  CalBear
Trades,  Services and obligations to make Payment in connection  therewith under
this  Agreement and the other  Transaction  Documents may be offset against each
other,  set off or recouped  therefrom.  Except as provided in this Agreement or
the other Transaction  Documents,  upon the termination of this Agreement or any
other  Transaction  Document,  the Parties shall continue to net all amounts due
among them arising under this Agreement or the other Transaction Documents.

    3.11  Acknowledgements.  Each Party acknowledges that, in view of the nature
of the Transaction and the CalBear Business,  and the consideration given by the
Parties  therefore,  the restrictions  contained in Sections 3.2, 3.3, 3.4, 3.5,
3.6, 3.7,  3.8,  3.9,  3.12,  and 3.15 are  reasonably  necessary to protect the
legitimate  business  interests  of the Parties and that any  violation  of such
restrictions will result in irreparable  injury to the Parties,  the Transaction
and the CalBear Business for which damages will not be an adequate remedy.  Each
Party therefore  acknowledges that, if any such restrictions are violated by it,
each other  Party that is not an  Affiliate  of such Party  shall be entitled to
preliminary and injunctive  relief or other equitable  remedies.  Each Party has
independently consulted with its counsel and after such consultation agrees that
the  covenants  set forth in Sections  3.2,  3.3,  3.4, 3.5, 3.6, 3.7, 3.8, 3.9,
3.12, and 3.15 are reasonable and appropriate.  If the final judgment of a court
or  arbitration  body  of  competent  jurisdiction  declares  that  any  term or
provision of Sections 3.2, 3.3, 3.4, 3.5, 3.6, 3.7, 3.8, 3.9,  3.12, and 3.15 is
invalid or  unenforceable,  the Parties agree that the court or arbitration body
making the determination of invalidity or unenforceability  shall have the power
to reduce  the  scope,  duration,  or area of the term or  provision,  to delete
specific words or phrases,  or to replace any invalid or  unenforceable  term or


                                       29
<PAGE>

provision with a term or provision that is valid and  enforceable and that comes
closest to  expressing  the  intention of the invalid or  unenforceable  term or
provision,  and this  Agreement  shall be  enforceable  as so modified after the
expiration  of the time  within  which  the  judgment  or  determination  may be
appealed.

    3.12  CMSC Board  Representation.  CalBear shall be entitled to designate up
to two (2) members of the board of directors of CMSC (each,  a "Designated  CMSC
Board  Member");  provided that each such  Designated CMSC Board Member shall be
either (a) a professional  independent  director  compensated by Bear Stearns or
its Affiliates (other than CalBear) and reasonably acceptable to Calpine, or (b)
an employee of Bear Stearns or its Affiliates with a title of Managing  Director
or equivalent  or a more senior title.  CalBear shall be entitled to designate a
replacement for any Designated  CMSC Board Member at any time,  whether upon the
death, removal or resignation of such Designated CMSC Board Member or otherwise.
If CalBear  designates any Designated CMSC Board Member at any time, Calpine and
each of the  Calpine  Transaction  Parties  agrees,  and  agrees  to  cause  its
Affiliates  to (a) vote for,  elect or appoint each such  Designated  CMSC Board
Member  designated  by  CalBear  to the  board  of  directors  of CMSC  promptly
following  such  designation,  (b) vote for,  elect or appoint  any  replacement
Designated CMSC Board Member  designated by CalBear to the board of directors of
CMSC promptly following such designation,  and (c) unless otherwise requested by
Bear Stearns, maintain the Designated CMSC Board Members (as replaced by CalBear
from time to time) as directors of CMSC at all times prior to the termination of
this Agreement.  CMSC's Organizational Documents shall provide that any decision
of the board of  directors of CMSC shall  require the consent of the  Designated
CMSC Board Members,  if any, to (i) initiate a voluntary  Bankruptcy Event, (ii)
consent to an involuntary  Bankruptcy Event, or (iii) modify the  Organizational
Documents  of CMSC to  eliminate  or  otherwise  alter the voting  rights of the
Designated  CMSC Board Members or CalBear's  right to designate,  or Calpine and
its Affiliates  duty to appoint,  such  Designated  CMSC Board  Members.  CMSC's
Organizational  Documents  shall also  provide  that the  Designated  CMSC Board
Members  shall not be entitled to vote with  respect to any matter  presented to
the board of  directors of CMSC other than the matters  listed in the  preceding
sentence.

   3.13   Performance of Financial Obligations of CalBear.

          Bear  Stearns  shall  provide  to  CalBear  all funds  and  collateral
necessary  for CalBear to perform its  obligations  under the Third Party Master
Agreements,  and the CalBear Trades,  and to pay the amounts required to be paid
by CalBear  pursuant to Section 4.17 of the Agency and Services  Agreement,  and
shall itself or shall cause  CalBear to perform  CalBear's  Payment  obligations
under the Third Party Master  Agreements and the CalBear Trades,  and to pay the
amounts  required to be paid by CalBear  pursuant to Section  4.17 of the Agency
and Services Agreement, in each case in accordance with such Section.

    3.14  [*]3.15  Fiscal Year of CalBear.  CalBear  shall not change its Fiscal
Year without the prior consent of Calpine,  such consent not to be  unreasonably
withheld;  provided  that  Calpine's  consent shall not be required in the event
that such  change is made to  conform  CalBear's  fiscal  year to Bear  Stearns'
fiscal  year in  connection  with a change of Bear  Stearns'  fiscal  year;  and
provided,  further,  that in  connection  with any change in the Fiscal  Year of


                                       30
<PAGE>

CalBear,  the  provisions  of the  Transaction  Documents  shall be  adjusted as
applicable to conform to such adjusted fiscal year and shall also be adjusted to
the extent  necessary to give effect to the original intent of the provisions of
the Transaction  Documents,  as if such change in the Fiscal Year of CalBear had
not  occurred,  including  appropriate  proration  or  other  adjustment  of any
Payments paid pursuant to the Transaction Documents.

    3.16  Interest on Overdue Amounts.  In the event that, at any time,  Calpine
or any Calpine  Transaction  Party, on the one hand, or Bear Stearns or CalBear,
on the  other  hand,  fails to make any  Payment  when  due to Bear  Stearns  or
CalBear,  on the one hand, or Calpine or any Calpine  Transaction  Party, on the
other hand, then the outstanding  principal amount of such overdue Payment shall
bear  interest  at the  lesser of (a) a rate  equal to LIBOR  [*](or  shall bear
additional  interest  at a rate  equal  to the  existing  interest  rate on such
overdue Payment [*], if such overdue  Payment  already bears interest;  provided
that any overdue Payment  already  bearing default or additional  interest shall
not bear further interest pursuant to this Section 3.16) or (b) the highest rate
permitted by law,  until such overdue  Payment plus all  accumulated  but unpaid
interest (and additional  interest,  if applicable) thereon is paid in full, and
the Party  making such  overdue  Payment  shall pay all  accumulated  but unpaid
interest (and additional interest,  if applicable) on the amount of such overdue
Payment at the time the principal of such overdue Payment is paid.

                                  ARTICLE IV.
                               CALPINE GUARANTEE

          Calpine  covenants  and agrees with Bear Stearns and CalBear that from
and after the Effective Date:

   4.1    Calpine Guarantee.

          (a) Subject to the terms of this Article IV, in  consideration of each
of Bear Stearns and CalBear  entering into the  Transaction  Documents,  Calpine
hereby unconditionally and irrevocably guarantees, as primary obligor and not as
surety (the "Calpine Guarantee"), to each of Bear Stearns and CalBear, and their
respective successors and assigns:

               (i) the prompt  payment in full when due of all  amounts  owed by
and due from any Calpine  Transaction  Party to Bear Stearns or CalBear pursuant
to the terms of the Transaction Documents, including all amounts owed by and due
from any  Calpine  Transaction  Party to Bear  Stearns  or CalBear  pursuant  to
Section 15.1(a) and pursuant to Section 6.3 of the Trading Master Agreement; and

               (ii) that in case of any  extension  of time of payment of any of
such  obligations,  such  obligations  will be promptly paid in full when due in
accordance with the terms of the extension.

Failing payment when due of any amount so guaranteed for any reason  whatsoever,
Calpine will  promptly pay the same on the date such payment is due. The Parties
agree that this is a guarantee of payment and not a guarantee of  collection  or
performance.


                                       31
<PAGE>

          (b) Calpine  hereby  agrees that its  obligations  under this  Calpine
Guarantee are  absolute,  irrevocable  and  unconditional,  irrespective  of the
validity,   regularity  or   enforceability  of  this  Agreement  or  the  other
Transaction Documents, the absence of any Action to enforce the same, any waiver
or consent by Bear Stearns or CalBear,  any course of dealings among the Parties
with respect to any provisions  hereof or thereof,  the recovery of any judgment
against any  Calpine  Transaction  Party,  any Action to enforce the same or any
other  circumstance  which  might  otherwise  constitute  a legal  or  equitable
discharge of defense of Calpine.  Calpine hereby waives diligence,  presentment,
demand of payment,  filing of claims with a court in the event of any Bankruptcy
of Calpine or any Calpine  Transaction  Party, any right to require a proceeding
first against any Calpine  Transaction  Party,  protest,  notice and all demands
whatsoever  and  covenants  that this Calpine  Guarantee  will not be discharged
except by complete performance and payment of the obligations  contained in this
Agreement and the other Transaction Documents.

          (c) If  Bear  Stearns  or  CalBear  is  required  by any  Governmental
Authority or otherwise to return to Calpine or any Calpine  Transaction Party or
any custodian,  trustee, liquidator or other similar official acting in relation
to Calpine or any  Calpine  Transaction  Party,  any amount paid by them to Bear
Stearns  or  CalBear,   this  Calpine  Guarantee,   to  the  extent  theretofore
discharged,  will be  reinstated  in full force and effect with  respect to such
amount.

          (d)  Calpine  agrees  that it will  not be  entitled  to any  right of
subrogation in relation to Bear Stearns or CalBear in respect of any obligations
guaranteed  hereby until payment in full of all obligations  guaranteed  hereby.
Calpine  further  agrees that,  as between  Calpine,  on the one hand,  and Bear
Stearns or CalBear,  on the other  hand,  (i) the  maturity  of any  obligations
guaranteed  hereby  that  may  be  accelerated  pursuant  to  the  terms  of the
Transaction  Documents,  may be so accelerated  for the purposes of this Calpine
Guarantee,  notwithstanding any stay, injunction or other prohibition preventing
such  acceleration in respect of the obligations  guaranteed  hereby and (ii) in
the event of any declaration of acceleration of such  obligations as provided in
the Transaction  Documents,  such  obligations  (whether or not due and payable)
will forthwith become due and payable by Calpine for the purpose of this Calpine
Guarantee.  Calpine will have the right to seek contribution from any non-paying
Calpine  Transaction Party so long as the exercise of such right does not impair
the rights of Bear Stearns or CalBear under this Calpine Guarantee.

    4.2   Calpine May Consolidate, etc., on Certain Terms.  Calpine may not sell
or  otherwise  dispose  of  all  or  substantially  all of  its  Assets  to,  or
consolidate  with or merge with or into (whether or not Calpine is the surviving
Person) another Person unless the Person acquiring the property in any such sale
or  disposition or the Person formed by or surviving any such  consolidation  or
merger  unconditionally  assumes  all the  obligations  of  Calpine  under  this
Agreement, the Calpine Guarantee and the other Transaction Documents.  Except as
set forth in this Section 4.2, nothing  contained in this Agreement will prevent
any  consolidation  or merger of  Calpine  or any sale or  conveyance  of all or
substantially all of the property of Calpine.

   4.3    Release.


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<PAGE>

          Upon termination of this Agreement in accordance with Section 16.6 and
full  and  final  discharge  of all  obligations  of  Calpine  and  the  Calpine
Transaction Parties under the Transaction Documents,  Calpine shall be fully and
unconditionally  released and  relieved  from any  obligation  under the Calpine
Guarantee;  provided that if, following such discharge,  Bear Stearns or CalBear
is required by any  Governmental  Authority or otherwise to return to Calpine or
any Calpine  Transaction  Party or any custodian,  trustee,  liquidator or other
similar official acting in relation to Calpine or any Calpine Transaction Party,
any amount paid by them to Bear Stearns or CalBear,  the Calpine  Guarantee,  to
the extent  theretofore  released,  relieved or  otherwise  discharged,  will be
reinstated in full force and effect.

                                   ARTICLE V.
                            BEAR STEARNS GUARANTEE

          Bear Stearns covenants and agrees with Calpine and each of the Calpine
Transaction Parties that from and after the Effective Date:

   5.1    Bear Stearns Guarantee.

          (a)  Subject  to the  terms of this  Article  V, in  consideration  of
Calpine  and the  Calpine  Transaction  Parties  entering  into the  Transaction
Documents,  Bear Stearns hereby unconditionally and irrevocably  guarantees,  as
primary  obligor and not as surety (the "Bear  Stearns  Guarantee"),  to each of
Calpine and the Calpine Transaction Parties, and their respective successors and
assigns:

               (i) the prompt  payment in full when due of all  amounts  owed by
and due from CalBear to Calpine or any Calpine Transaction Party pursuant to the
terms of the Transaction  Documents,  including all amounts owed by and due from
CalBear to Calpine or any Calpine Transaction Party pursuant to Section 15.1(b);
and

               (ii) that in case of any  extension  of time of payment of any of
such  obligations,  such  obligations  will be promptly paid in full when due in
accordance with the terms of the extension.

Failing payment when due of any amount so guaranteed for any reason  whatsoever,
Bear  Stearns  will  promptly  pay the same on the date such payment is due. The
Parties  agree  that this is a  guarantee  of  payment  and not a  guarantee  of
collection or performance.

          (b) Bear Stearns  hereby agrees that its  obligations  under this Bear
Stearns Guarantee are absolute,  irrevocable and unconditional,  irrespective of
the  validity,  regularity  or  enforceability  of this  Agreement  or the other
Transaction Documents, the absence of any Action to enforce the same, any waiver
or consent by Calpine or any Calpine  Transaction  Party, any course of dealings
among the Parties with respect to any provisions hereof or thereof, the recovery
of any  judgment  against  CalBear,  any Action to enforce the same or any other
circumstance which might otherwise  constitute a legal or equitable discharge of
defense of Bear  Stearns.  Bear Stearns  hereby waives  diligence,  presentment,
demand of payment,  filing of claims with a court in the event of any Bankruptcy
of Bear  Stearns or CalBear,  any right to require a  proceeding  first  against
CalBear, protest, notice and all demands whatsoever and covenants that this Bear


                                       33
<PAGE>

Stearns  Guarantee  will not be discharged  except by complete  performance  and
payment of the obligations contained in this Agreement and the other Transaction
Documents.

          (c) If Calpine or any  Calpine  Transaction  Party is  required by any
Governmental  Authority or otherwise to return to Bear Stearns or CalBear or any
custodian,  trustee,  liquidator or other similar official acting in relation to
Bear  Stearns  or  CalBear,  any amount  paid by them to Calpine or any  Calpine
Transaction  Party,  this Bear  Stearns  Guarantee,  to the  extent  theretofore
discharged,  will be  reinstated  in full force and effect with  respect to such
amount.

          (d) Bear  Stearns  agrees that it will not be entitled to any right of
subrogation in relation to Calpine or the Calpine Transaction Parties in respect
of any  obligations  guaranteed  hereby until payment in full of all obligations
guaranteed hereby. Bear Stearns further agrees that, as between Bear Stearns, on
the one hand, and Calpine or the Calpine Transaction Parties, on the other hand,
(i) the maturity of any  obligations  guaranteed  hereby that may be accelerated
pursuant to the terms of the  Transaction  Documents,  may be so accelerated for
the  purposes  of  this  Bear  Stearns  Guarantee,   notwithstanding  any  stay,
injunction or other  prohibition  preventing such acceleration in respect of the
obligations  guaranteed  hereby  and  (ii) in the  event of any  declaration  of
acceleration of such obligations as provided in the Transaction Documents,  such
obligations  (whether  or not due and  payable)  will  forthwith  become due and
payable by Bear  Stearns for the purpose of this Bear  Stearns  Guarantee.  Bear
Stearns  will have the right to seek  contribution  from  CalBear so long as the
exercise  of such right  does not  impair  the rights of Calpine or the  Calpine
Transaction Parties under this Bear Stearns Guarantee.

    5.2   Bear Stearns May Consolidate, etc., on Certain Terms. Bear Stearns may
not sell or otherwise  dispose of all or substantially  all of its Assets to, or
consolidate  with or merge  with or into  (whether  or not Bear  Stearns  is the
surviving Person) another Person unless the Person acquiring the property in any
such  sale  or  disposition  or the  Person  formed  by or  surviving  any  such
consolidation  or merger  unconditionally  assumes all the  obligations  of Bear
Stearns  under  this  Agreement,  the  Bear  Stearns  Guarantee  and  the  other
Transaction  Documents.  Except  as set  forth  in  this  Section  5.2,  nothing
contained in this  Agreement  will prevent any  consolidation  or merger of Bear
Stearns or any sale or conveyance of all or substantially all of the property of
Bear Stearns.

   5.3    Release.

          Upon termination of this Agreement in accordance with Section 16.6 and
full and final  discharge of all  obligations  of Bear Stearns and CalBear under
the  Transaction  Documents,  Bear  Stearns  shall be fully and  unconditionally
released  and relieved  from any  obligation  under the Bear Stearns  Guarantee;
provided that if, following such discharge,  Calpine or any Calpine  Transaction
Party is required by any  Governmental  Authority or otherwise to return to Bear
Stearns  or CalBear  or any  custodian,  trustee,  liquidator  or other  similar
official acting in relation to Bear Stearns or CalBear,  any amount paid by them
to Calpine or any Calpine Transaction Party, the Bear Stearns Guarantee,  to the
extent  theretofore  released,   relieved  or  otherwise  discharged,   will  be
reinstated in full force and effect.


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<PAGE>

                                  ARTICLE VI.
                              REGULATORY MATTERS

   6.1    Regulatory Matters With Respect to Calpine.

          (a)  Calpine  and  each  of the  Calpine  Transaction  Parties  hereby
covenant  and agree from and after the  Effective  Date that they shall take all
necessary or appropriate  actions to maintain exemption from material regulatory
restrictions under PUHCA (other than Section 9(a)(2) of PUHCA).

          (b) CES and  CMSC  hereby  covenant  and  agree  from  and  after  the
Effective  Date  that they  shall  take or cause to be taken  all  necessary  or
appropriate   actions  to  maintain  for  CES  and  CMSC,   respectively,   FERC
authorization  to sell Power at  wholesale  at  market-based  rates and,  to the
extent  necessary,  any other FERC approval required under the FPA to sell Power
at wholesale, in each case to the extent necessary to permit ongoing performance
by CES and CMSC under the Transaction Documents.

          (c) Calpine and the Calpine  Transaction  Parties hereby  covenant and
agree from and after the  Effective  Date to (i) obtain all material  Regulatory
Approvals,  and (ii)  comply  with all  material  applicable  federal  and state
energy, and federal commodity,  regulatory laws, including all material notices,
filings,  reports,  consents,  authorizations  or exemptions  from  registration
required or  permitted  under the FPA,  PUHCA,  CEA and state  utility  laws and
regulations,  in each case to the extent necessary to permit ongoing performance
by Calpine and the Calpine Transaction Parties under the Transaction Documents.

   6.2    Regulatory Matters With Respect to Bear Stearns.

          (a) Bear Stearns and CalBear hereby  covenant and agree from and after
the Effective Date that they shall take all necessary or appropriate  actions to
maintain exemption from material regulatory restrictions under PUHCA (other than
Section 9(a)(2) of PUHCA).

          (b) CalBear  hereby  covenants and agrees from and after the Effective
Date  that it  shall  take or cause to be taken  all  necessary  or  appropriate
actions to maintain for CalBear FERC authorization to sell Power at wholesale at
market-based  rates  and,  to the  extent  necessary,  any other  FERC  approval
required  under the FPA to sell Power at  wholesale,  in each case to the extent
necessary  to permit  ongoing  performance  by  CalBear  under  the  Transaction
Documents.

          (c)  Subject  to  compliance  with  Section  4.1(n) of the  Agency and
Services Agreement by CMSC, Bear Stearns and CalBear covenant and agree from and
after the Effective Date to (i) obtain all material  Regulatory  Approvals,  and
(ii) comply with all material  applicable  federal and state  energy  regulatory
laws,   including  all  material   notices,   filings,   reports,   consents  or
authorizations or exemptions from  registration  required or permitted under the
FPA,  PUHCA and state utility laws and  regulations,  in each case to the extent
necessary to permit  ongoing  performance  by Bear Stearns and CalBear under the
Transaction Documents.

    6.3   Regulatory  Matters With  Respect to CalBear and CMSC.  From and after
the  date  of  this  Agreement,  each  Party  covenants and agrees that it shall


                                       35
<PAGE>

cooperate  with the other  Parties to take or cause to be taken all necessary or
appropriate  actions to prepare and file all  documents  necessary  for (i) CES,
(ii) CMSC's predecessor CES Marketing VII, LLC, and (iii) CalBear's  predecessor
Arroyo Energy LP, to obtain FERC  approval  under Section 203 of the FPA for (A)
an internal  corporate  restructuring of the upstream ownership of Arroyo Energy
LP, (B) the  performance  of the Services by CMSC,  (C) the  provision of energy
related services by CMSC to CES, and any notice filings or other  approvals,  as
needed under Section 203 of the FPA in respect of the Transaction.  With respect
to these filings,  the Parties shall cooperate and use  commercially  reasonable
efforts to share and develop  information  necessary for such filings and drafts
of such filings and shall give each other  reasonable  opportunity to comment on
and to revise such draft filings before such filings are submitted to FERC.

                                  ARTICLE VII.
               NOTICES, RECORDS, MEETINGS, AUDITS AND AVAILABILITY

          Each of the Parties covenants and agrees with each other that from and
after the Effective Date, subject to the confidentiality  obligations  contained
in Section 3.9:

   7.1    Notices.


          (a)   Notice   from   Calpine.   Anything   herein  to  the   contrary
notwithstanding,  Calpine and the Calpine  Transaction  Parties shall  promptly,
upon obtaining knowledge thereof, submit notice to Bear Stearns and CalBear of:

               (i) any Actions  pending or, to the  knowledge  of Calpine or the
Calpine  Transaction  Parties,  threatened  in writing  or filed by any  Person,
concerning the CalBear Business,  the CalBear Trades, this Agreement,  the other
Transaction Documents or the transactions contemplated hereby or thereby;

               (ii) any refusal or, to the  knowledge  of Calpine or the Calpine
Transaction Parties, refusal threatened in writing to grant, renew or extend, or
any Action pending or threatened in writing that would reasonably be expected to
affect, the granting,  renewal or extension of any material Regulatory Approval,
including   CES',   CMSC's   or   CalBear's   FERC-granted   market-based   rate
authorization;

               (iii)  any  material  dispute  with  any  Governmental  Authority
relating to the CalBear Trades, the Transaction Documents,  the CalBear Business
or  Calpine's  and  the  Calpine  Trading  Parties'  ability  to  perform  their
obligations under the Transaction Documents;

               (iv) any  Bankruptcy  Event with  respect to Calpine,  any of the
Calpine Transaction Parties or any Significant Subsidiary of Calpine;

               (v) any Material Adverse Change with respect to Calpine or any of
the Calpine Transaction Parties;

               (vi) all material  penalties  or notices of  violation  issued or
threatened by any Governmental Authority or other Person relating to the CalBear
Trades or the Services;


                                       36
<PAGE>

               (vii) the violation by Calpine or any Calpine  Transaction  Party
in any material  respect of any  Applicable  Law relating to the  Services,  the
CalBear Trades, the Transaction Documents or the CalBear Business;

               (viii) the failure by Calpine or any Calpine Transaction Party to
perform any covenant or agreement of Calpine or such Calpine  Transaction Party,
respectively,  set forth in this  Agreement or any other  Transaction  Document,
which  failure  constitutes  a material  breach of this  Agreement or such other
Transaction  Document;  provided  that any breach of this clause (viii) shall be
deemed to be cured upon cure of the underlying failure to perform; or

               (ix) any other  event or  circumstance  that would be  reasonably
likely to  materially  adversely  affect  Calpine's  or any Calpine  Transaction
Party's ability to engage in Trades,  perform Services or otherwise  perform its
obligations under the Transaction Documents.

          (b)  Notice  from  Bear  Stearns.  Anything  herein  to  the  contrary
notwithstanding,  Bear  Stearns  and  CalBear  shall  promptly,  upon  obtaining
knowledge thereof,  submit notice to Calpine and the Calpine Transaction Parties
of:

               (i) any Actions  pending or, to the  knowledge of Bear Stearns or
CalBear,  threatened in writing or filed by any Person,  concerning  the CalBear
Business, the CalBear Trades, this Agreement, the other Transaction Documents or
the transactions contemplated hereby or thereby;

               (ii) any refusal or, to the knowledge of Bear Stearns or CalBear,
refusal  threatened in writing to grant,  renew or extend, or any Action pending
or  threatened  in writing  that would  reasonably  be expected  to affect,  the
granting,  renewal or extension of any material Regulatory  Approval,  including
CalBear's FERC-granted market-based rate authorization;

               (iii)  any  material  dispute  with  any  Governmental  Authority
relating to the CalBear Trades, the Transaction Documents,  the CalBear Business
or Bear Stearns' and CalBear's  ability to perform their  obligations  under the
Transaction Documents;

               (iv) any Bankruptcy  Event with respect to Bear Stearns,  CalBear
or any Significant Subsidiary of Bear Stearns;

               (v) any Material  Adverse  Change with respect to Bear Stearns or
CalBear;

               (vi) all material  penalties  or notices of  violation  issued or
threatened by any Governmental Authority or other Person relating to the CalBear
Trades or the Services;

               (vii) the  violation  by Bear  Stearns or CalBear in any material
respect of any Applicable Law relating to the CalBear  Trades,  the  Transaction
Documents or the CalBear Business;


                                       37
<PAGE>

               (viii)  the  failure by Bear  Stearns  or CalBear to perform  any
covenant or  agreement of Bear  Stearns or CalBear,  respectively,  set forth in
this Agreement or any other Transaction  Document,  which failure  constitutes a
material breach of this Agreement or such other Transaction  Document;  provided
that any breach of this clause  (viii)  shall be deemed to be cured upon cure of
the underlying failure to perform;

               (ix) any downgrade of the credit rating  assigned to Bear Stearns
by (i)  Standard  & Poors  Ratings  Group  below BBB+ or (ii)  Moody's  Investor
Services below Baa1;

               (x) any change of Bear  Stearns'  fiscal  year from a November 30
year-end; or

               (xi) any other  event or  circumstance  that would be  reasonably
likely to  materially  adversely  affect Bear  Stearns' or CalBear's  ability to
engage in Trades or  otherwise  perform its  obligations  under the  Transaction
Documents.

   7.2    Books and Records.

          (a) Books and  Records of Calpine  Transaction  Parties.  The  Calpine
Transaction  Parties shall maintain in good order all Books and Records relating
to the CalBear Trades, any Services and the CalBear Business,  including general
ledgers,  risk systems and related data  storage,  and each Calpine  Transaction
Party shall retain  related  written  records for a minimum  period of seven (7)
years and related oral records  including  tapes in accordance with such Calpine
Transaction  Party's internal policy and, in each case, as otherwise required by
Applicable  Law and  Regulatory  Approvals.  Where Books and  Records  relate to
Actions or the  settlement  of claims  arising  out of the  performance  of this
Agreement,  the  other  Transaction  Documents,  or  any  related  documents  or
agreements,  the  Calpine  Transaction  Parties  shall  maintain  such Books and
Records until the later of (x) three (3) years after the final resolution of the
matter  giving  rise to the Action or  dispute  or (y) the end of the  retention
periods otherwise set forth in this Section 7.2(a).

          (b) Books and Records of CalBear. CalBear shall maintain in good order
all Books and Records  relating to (i) the CalBear Trades,  any Services and the
CalBear  Business to the extent  CalBear  (A)  produces  Books and Records  with
respect  thereto or (B)  receives  copies of any Books and Records  with respect
thereto  from CMSC and (ii) CalBear  Governance  Operations,  and CalBear  shall
retain  related  written  records  for a  minimum  period of seven (7) years and
related oral records  including  tapes in  accordance  with  CalBear's  internal
policy and, in each case, as otherwise required by Applicable Law and Regulatory
Approvals. Where Books and Records relate to Actions or the settlement of claims
arising  out of  the  performance  of  this  Agreement,  the  other  Transaction
Documents,  or any related documents or agreements,  CMSC, on behalf of CalBear,
and CalBear  shall  maintain such Books and Records until the later of (x) three
(3) years after the final  resolution of the matter giving rise to the Action or
dispute  or (y) the end of the  retention  periods  otherwise  set forth in this
Section 7.2(b).

    7.3   Meetings. Representatives of Calpine, the Calpine Transaction Parties,
Bear Stearns and/or CalBear shall meet in person or by conference  call or video
conference at such reasonable times as any of them may request (provided that in


                                       38
<PAGE>

no event shall  Representatives  of any Party or its Affiliates (other than CMSC
and CalBear) be required to attend more than two (2) such  meetings in any given
Month).  During such meetings,  the Representatives of any Party may provide any
information  concerning the CalBear  Business,  the Trades,  the Services or the
Transaction to the  Representatives of any other Party for discussion,  and each
Party shall  provide  any other  information  reasonably  related to the CalBear
Business,  the CalBear Trades or the Transaction that is reasonably requested in
advance by the  Representatives  of any other Party, to the extent the requested
information is required to be maintained for or provided to the requesting Party
under other  provisions of the Transaction  Documents and subject to Section 3.9
and confidentiality duties owed to Third Parties.

   7.4    Audits.  Each  of  the  Calpine  Transaction Parties and CalBear shall
          comply with the following audit provisions:


          (a)  Subject to Section  3.9,  Calpine  and each  Calpine  Transaction
Party, on the one hand, and Bear Stearns and CalBear,  on the other hand, or any
of their respective  Representatives,  has the right, in its sole discretion and
at its sole expense and upon at least five (5) Business Days advance  notice and
during  normal  working  hours,  to  examine  and copy the Books and  Records of
CalBear or any Calpine Transaction Party, respectively,  to the extent necessary
to  verify  compliance  with  the  provisions  of  this  Agreement,   the  other
Transaction Documents, any related documents and agreements and the transactions
contemplated hereby and thereby (other than verifying compliance with provisions
regarding  general  financial  condition or solvency of Calpine or CES), and the
accuracy of any Report or  information,  daily or Monthly  settlement,  Payment,
charge or  computation  made or  provided  pursuant  to the  provisions  of this
Agreement, the other Transaction Documents, any related documents and agreements
or the  transactions  contemplated  hereby  and  thereby,  the  Trades  and  the
Services.

          (b) If any audit  conducted  under  Section  7.4(a) above  reveals any
inaccuracy in any Report,  daily or Monthly settlement or Payment, the necessary
adjustments in such  settlement  and the Payments  thereof will be promptly made
and this  provision  shall  survive any  termination  of this  Agreement for the
purpose  of such  daily or  Monthly  settlement  and  Payment  objections.  Each
Transaction Party shall preserve all applicable  records held by it for the time
periods set forth in Section 7.2, as  applicable,  following the  termination of
this  Agreement,  or such longer  period as may be required by  Applicable  Law.
Information  obtained  by any Party's  Representatives  in  examining  any other
Party's  applicable Books and Records to verify such  settlements,  Payments and
billings and Gas and Power delivery data shall not be disclosed to Third Parties
except as provided in Section 3.9.  The audit  rights  contained in this Section
7.4 shall survive the termination of this Agreement.

          (c) Subject to Section  3.9,  Bear  Stearns or CalBear  shall have the
right,  in its sole discretion and at its sole expense and during normal working
hours,  to examine,  at any time and from time to time,  CES' and/or CMSC's risk
management  protocols and procedures in a location reasonably  determined by CES
or CMSC, as applicable,  to the extent  necessary to verify  compliance with the
provisions  of this  Agreement,  the other  Transaction  Documents,  any related
documents and agreements and the transactions  contemplated  hereby and thereby,
and the accuracy of any Reports, daily or Monthly settlement, Payment, charge or


                                       39
<PAGE>

computation  made  pursuant  to the  provisions  of this  Agreement,  the  other
Transaction Documents,  any related documents and agreements or the transactions
contemplated hereby and thereby, the CalBear Trades or the Services.

   7.5    Availability of Parties.

          Each  Calpine   Transaction   Party  and  CalBear  shall  make  itself
reasonably   available   to  CalBear  and  the  Calpine   Transaction   Parties,
respectively,  through  telephone,  voicemail,  e-mail and/or  facsimile  during
normal business hours,  and by telephone,  mobile  telephone and/or pager during
non-business  hours.  CMSC shall make itself  available  to CalBear  through its
24-hour Power trading desk.

                                 ARTICLE VIII.
                 REPRESENTATIONS AND WARRANTIES OF THE PARTIES

          As an  inducement  to enter into this  Agreement,  each  Party  hereby
represents  and warrants to each other Party,  as of the date hereof (other than
with respect to CMSC and CalBear) and as of the Effective Date the following:

    8.1   Organization.  Such Party is duly organized,  validly  existing and in
good  standing as a  corporation  or other entity under the laws of the state of
its organization and has full  organizational  power and authority to own, lease
and operate its Assets and to conduct its  business as it is now  conducted  and
presently proposed to be conducted.

    8.2   Authorization. Such Party has the requisite  organizational  power and
authority to, and has taken all organizational  action necessary to, execute and
deliver this  Agreement  and each other  Transaction  Document to which it is or
will be a party, to consummate the transactions  contemplated hereby and thereby
and to  perform  its  obligations  contained  herein and  therein,  and no other
organizational  proceedings on the part of such Party are necessary to authorize
this  Agreement,  each other  Transaction  Document  to which it is or will be a
party and the consummation of the transactions  contemplated hereby and thereby.
This Agreement has been duly executed and delivered by such Party and is a valid
and  binding  obligation  of such  Party,  enforceable  against  such  Party  in
accordance with its terms,  except as the enforceability  thereof may be limited
by (a) applicable bankruptcy, insolvency, moratorium,  reorganization or similar
laws in effect which affect the enforcement of creditors rights generally or (b)
general  principles of equity,  whether  considered in a proceeding at law or in
equity.  Each  Transaction  Document  (other than this  Agreement) to which such
Party is or will be a party has been or will be duly  executed and  delivered by
such Party, as applicable,  and is or will be a valid and binding  obligation of
such Party,  enforceable against such Party in accordance with its terms, except
as the  enforceability  thereof  may be  limited by (a)  applicable  bankruptcy,
insolvency,  moratorium,  reorganization  or similar laws in effect which affect
the  enforcement  of creditors  rights  generally or (b) general  principles  of
equity, whether considered in a proceeding at law or in equity.

    8.3   No Similar  Business.  Neither  such  Party nor any of its  respective
Affiliates  is  currently  engaged in any business  relationship  with any Third
Party pursuant to which such Party or its Affiliates, on the one hand, and such


                                       40
<PAGE>

Third Party, on the other hand,  engage in any business  which,  when taken as a
whole, would be in violation of Section 3.2.

    8.4   Accuracy of Information Furnished.  With respect to such Party and its
Affiliates,  the information contained in this Agreement,  any other Transaction
Document,  and  the  exhibits,  schedules,   certificates,   documents,  written
information  or lists  attached  hereto or thereto or  specifically  referred to
herein or therein  that has been  delivered by or on behalf of such Party or any
of its Affiliates  pursuant to this Agreement or any other Transaction  Document
or otherwise in connection with the transactions  contemplated hereby or thereby
does not, to the  knowledge  of such Party,  contain any untrue  statement  of a
material  fact, or omit to state any material fact that is necessary to make the
statements contained herein and therein, taken as a whole, not misleading.

                                  ARTICLE IX.
                   REPRESENTATIONS AND WARRANTIES OF CALPINE

          As an inducement to enter into this Agreement, each of Calpine and the
Calpine  Transaction  Parties hereby represents and warrants to Bear Stearns and
CalBear,  as of the date hereof  (other than with respect to CMSC) and as of the
Effective  Date,  and except as otherwise  disclosed in the Calpine SEC Filings,
the following:

    9.1   Calpine and Calpine Transaction Parties.  Schedule 9.1 lists the name,
type of entity and  jurisdiction  of  organization  of  Calpine  and each of the
Calpine Transaction  Parties.  Calpine owns, directly or indirectly,  all of the
outstanding Equity Securities of each of the Calpine Transaction Parties.

    9.2   No  Conflict  or  Violation.  None  of  the  execution,  delivery  and
performance  of  this  Agreement  or  any  other  Transaction   Documents,   the
consummation of the  transactions  contemplated  hereby and thereby,  compliance
with any of the provisions  hereof or thereof,  the  consummation of any CalBear
Trades or the  provision  of the  Services,  by  Calpine  or any of the  Calpine
Transaction  Parties  will result in (a) a violation  of or a conflict  with any
provision  of the  Organizational  Documents  of Calpine  or any of the  Calpine
Transaction  Parties,  (b) a violation  of, a conflict  with,  a breach of, or a
default under (with or without  notice or passage of time),  the  termination or
acceleration of the performance required by, or the creation of any right of any
party to accelerate, modify, terminate or cancel, any material term or provision
of any material Contract to which Calpine or such Calpine Transaction Party is a
party or by which any of its Assets are bound,  (c) a violation or breach in any
material  respect of any  Applicable  Law  applicable to Calpine or such Calpine
Transaction  Party  or (d)  Calpine  or such  Calpine  Transaction  Party  being
required to obtain any material consent, waiver,  agreement,  Permit or approval
or  material  authorization  of,  or  material  declaration,  filing,  notice or
registration  to or  with,  or  material  assignment  by,  any  Third  Party  or
Governmental Authority, except, in each case, as set forth on Schedule 9.2.

    9.3   Sufficiency of Assets.  The Calpine Transaction  Parties own, license,
lease  or  otherwise  have a right  to use or  have  contracted  for all  Assets
materially  necessary and  sufficient  for the  performance  of the Services and
their other obligations under the Transaction Documents, and their Assets in the


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<PAGE>

aggregate are  materially  in such  operating  condition and repair  (subject to
normal wear and tear) as is necessary and sufficient for the performance of such
Services and obligations.

   9.4    Permits. Except as set forth on Schedule 9.2, the Calpine  Transaction
Parties  have  all  material  Permits  necessary  for (i) the  conduct  of their
businesses  as  now  being   conducted  and  as  proposed  to  be  conducted  as
contemplated in this Agreement and the other Transaction  Documents and (ii) the
performance of the Services and their other  obligations  under the  Transaction
Documents,  and own or  possess  such  Permits  free and  clear of any  material
Encumbrances.  All such  Permits  are valid and in full  force and effect in all
material respects.

    9.5   Litigation.  There is no Action  pending or, to the  knowledge  of the
Calpine  Transaction  Parties,  threatened  in writing  against,  relating to or
affecting Calpine or the Calpine Transaction Parties or any of their properties,
rights or Assets (a) that, if pending,  involves the risk of criminal  liability
or, if threatened,  could reasonably be expected to involve the risk of criminal
liability,  (i) for any  Calpine  Transaction  Party or (ii) for Calpine and its
Affiliates;  provided,  in the case of clause  (ii),  such Action is material to
Calpine  and  its  Affiliates,  taken  as a  whole,  (b)  that  relates  to  the
transactions  contemplated  by  this  Agreement  or  by  the  other  Transaction
Documents,  or (c) with respect to which there is a reasonable  likelihood  of a
determination  which  would  prevent  or  delay  Calpine  or any of the  Calpine
Transaction Parties from consummating the transactions contemplated hereby or by
the other  Transaction  Documents  in any  material  respect or  performing  any
material obligations hereunder or thereunder,  in any court or other tribunal or
before any arbitrator, mediator, authority or Governmental Authority.

    9.6   Compliance with Law.  None  of  Calpine  or  the  Calpine  Transaction
Parties  has  violated  any  Applicable  Laws,  and  each  of  Calpine  and  the
Calpine Transaction Parties is in compliance  with all Applicable  Laws,  except
to the extent that any such violations or failures to comply, individually or in
the  aggregate, have not had a Material Adverse Effect on Calpine or any Calpine
Transaction  Party.  None of  Calpine or the  Calpine  Transaction  Parties  has
received  any written  notice to the effect  that,  and the Calpine  Transaction
Parties do not have any knowledge that, (a) any  investigation  or review by any
Governmental  Authority  related  to  this  Agreement,   the  other  Transaction
Documents, the transactions contemplated hereby or thereby, Calpine, the Calpine
Transaction Parties, the Services or the CalBear Trades is pending or threatened
in writing, or (b) any currently existing  circumstances are likely to result in
a failure of any of Calpine or the Calpine  Transaction  Parties to comply with,
or a  violation  by any of Calpine or the  Calpine  Transaction  Parties of, any
Applicable  Laws, in either case which such failure to comply or violation would
be  reasonably  expected  to have a  Material  Adverse  Effect on Calpine or any
Calpine Transaction Party.

    9.7   Insurance.  The Calpine Transaction  Parties have insurance  policies,
binders or other forms of  insurance  that  provide,  and during their term have
provided,  coverage to the extent and in the manner (a) adequate for the Calpine
Transaction  Parties and their Assets,  businesses  and operations and the risks
insured  against  in  connection  therewith  and (b) as may be or may have  been
required by material  Applicable Law and by any material  Contracts to which any


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<PAGE>

Calpine  Transaction  Party is or has been a party,  except,  in either case, as
would not have a Material Adverse Effect on any Calpine Transaction Party.

    9.8   Adequate Capital.  Neither Calpine nor any of the Calpine  Transaction
Parties  is  insolvent  or  will  be  insolvent   after  giving  effect  to  the
transactions contemplated by this Agreement and the other Transaction Documents,
as the  term  insolvent  is used in  applicable  state  and  federal  fraudulent
conveyance or transfer laws.

    9.9   SEC Filings; Financial Statements.

          (a) Calpine has filed all registration statements, prospectuses, forms
and reports  required to be filed by it under the Securities Act or the Exchange
Act, as the case may be, since January 1, 2003  (collectively,  the "Calpine SEC
Filings"). Each Calpine SEC Filing, as amended or supplemented,  complied in all
material  respects with the  requirements  of the Securities Act or the Exchange
Act, as the case may be, with respect to such  Calpine SEC Filing.  Each Calpine
SEC Filing, as amended or supplemented, if applicable, did not (as so amended or
supplemented) contain any untrue statement of a material fact or omit to state a
material  fact  required to be stated  therein or necessary in order to make the
statements made therein, in the light of the circumstances under which they were
made, not misleading.

          (b) Except as may be indicated  in the notes  thereto and, in the case
of unaudited  quarterly financial  statements,  except as permitted by Form 10-Q
under  the  Exchange  Act,  each  of  the  consolidated   financial   statements
(including,  in each case,  any notes  thereto)  contained  in the  Calpine  SEC
Filings was  prepared in  accordance  with GAAP  applied on a  consistent  basis
throughout the periods indicated,  and, at the time such consolidated  financial
statements  were  filed and at the time they were  amended or  supplemented,  if
applicable,  each fairly  presented  in all material  respects the  consolidated
financial  position of Calpine and its  subsidiaries as of the respective  dates
thereof and for the respective  periods indicated therein (subject,  in the case
of unaudited statements, to normal, recurring year-end adjustments which did not
have a Material Adverse Effect on Calpine).

   9.10   Regulation.

          (a)  Neither  Calpine nor any of the  Calpine  Transaction  Parties is
subject to regulation as an "electric  utility company," a "gas utility company"
a  "public-utility  company,"  or  a  "holding  company,"  under  PUHCA  or  any
regulation  promulgated  thereunder.  Neither  Calpine  nor  any of the  Calpine
Transaction Parties is subject to material  regulatory  restrictions under PUHCA
(other than Section 9(a)(2) of PUHCA).

          (b) CES and CMSC each have validly issued final orders authorizing CES
and CMSC,  respectively,  to engage in Power sales at wholesale at  market-based
rates.  CES and  CMSC  are in  compliance  with all  FERC  reporting  and  other
requirements  generally  imposed on entities  authorized  to engage in wholesale
sales of Power at market-based rates,  including requirements to file electronic
quarterly  transaction  reports,  triennial  market-power updates and changes in
status,  except  to the  extent  that  non-compliance  could not  reasonably  be
expected to cause a Material Adverse Effect with respect to CES or CMSC.


                                       43
<PAGE>

    9.11  Due  Consideration.   Calpine  and  the  Calpine  Transaction  Parties
acknowledge  that they will  generally  obtain more  favorable  terms for Trades
through the Transaction than the terms that are currently  available to them for
similar  transactions with Third Parties and Calpine and the Calpine Transaction
Parties  desire  Bear  Stearns  to  provide  financial  support  as  part of the
Transaction  in order to enhance the credit of certain Gas and Power trades made
by  CalBear  and CES and in order to  otherwise  support  certain  Gas and Power
trading activities of the Calpine Transaction  Parties.  Calpine and the Calpine
Transaction  Parties have received due and adequate  consideration  and fair and
equivalent value for their  agreements and obligations  under this Agreement and
the other Transaction Documents as determined in good faith, in each case within
the meaning of applicable state and federal fraudulent conveyance laws.

    9.12  Operations  of CMSC.  CMSC  has not taken any  action  that would have
violated Section 4.1(m) of the Agency and Services Agreement had it been subject
to such Section  4.1(m) on the Effective  Date.  Except in  connection  with the
transactions  contemplated  by the  Transaction  Documents  or the  provision of
energy  related  services  to CES,  CMSC does not have any  Contracts  with,  or
Liabilities to, Third Parties or its Affiliates.

    9.13  Material  Contracts  of CMSC.  At least  ten (10)  days  prior to the
Effective  Date,  CMSC has  provided to Bear  Stearns and CalBear  copies of all
material  Contracts to which CMSC is a party and copies of all Contracts  listed
on Schedules 4.1(m) to the Agency and Services Agreement.

                                   ARTICLE X.
                 REPRESENTATIONS AND WARRANTIES OF BEAR STEARNS

          As an  inducement to enter into this  Agreement,  each of Bear Stearns
and CalBear  hereby  represents  and warrants to Calpine and each of the Calpine
Transaction  Parties, as of the date hereof (other than with respect to CalBear)
and as of the  Effective  Date,  and except as  otherwise  disclosed in the Bear
Stearns SEC Filings, the following:

   10.1   Bear Stearns and CalBear. Schedule 10.1 lists the name, type of entity
and jurisdiction of organization of Bear Stearns and CalBear. Bear Stearns owns,
directly or indirectly, all of the outstanding Equity Securities of CalBear.

   10.2   No  Conflict  or  Violation.  None  of  the  execution,  delivery  and
performance  of  this  Agreement  or  any  other  Transaction   Documents,   the
consummation of the  transactions  contemplated  hereby and thereby,  compliance
with any of the provisions hereof or thereof, or the consummation of any CalBear
Trades,  by Bear  Stearns  or CalBear  will  result in (a) a  violation  of or a
conflict with any provision of the  Organizational  Documents of Bear Stearns or
CalBear,  (b) a violation  of, a conflict  with, a breach of, or a default under
(with or without notice or passage of time),  the termination or acceleration of
the  performance  required  by,  or the  creation  of any  right of any party to
accelerate,  modify,  terminate or cancel, any material term or provision of any
material Contract to which Bear Stearns or CalBear is a party or by which any of
its Assets are bound,  (c) a violation or breach in any material  respect of any
Applicable  Law  applicable  to  Bear  Stearns  or  CalBear  or (d)  subject  to
compliance  with Section  4.1(n) of the Agency and  Services  Agreement by CMSC,


                                       44
<PAGE>

Bear Stearns or CalBear being required to obtain any material  consent,  waiver,
agreement,  Permit  or  approval  or  material  authorization  of,  or  material
declaration,  filing,  notice or registration to or with, or material assignment
by, any Third Party or  Governmental  Authority,  except,  in each case,  as set
forth on Schedule 10.2.

   10.3   Sufficiency of Assets. CalBear owns, licenses, leases or otherwise has
a  right  to use or has  contracted  for all  Assets  materially  necessary  and
sufficient  for  the  performance  of  its  obligations  under  the  Transaction
Documents,  and its Assets in the  aggregate are  materially  in such  operating
condition  and repair  (subject  to normal  wear and tear) as is  necessary  and
sufficient for the performance of such obligations.

   10.4   Permits.  Except  as  set  forth on  Schedule  10.2,  CalBear  has all
material  Permits  necessary  for (i) the  conduct of its  business as now being
conducted and as proposed to be conducted as  contemplated in this Agreement and
the other  Transaction  Documents and (ii) the  performance  of its  obligations
under the  Transaction  Documents,  and owns or possesses  such Permits free and
clear of any material Encumbrances. All such Permits are valid and in full force
and effect in all material respects.

   10.5   Litigation.  There  is no  Action  pending  or,  to the  knowledge  of
CalBear, threatened in writing against, relating to or affecting Bear Stearns or
CalBear  or any of their  properties,  rights or Assets  (a) that,  if  pending,
involves the risk of criminal  liability or, if threatened,  could reasonably be
expected to involve the risk of criminal liability,  (i) for CalBear or (ii) for
Bear Stearns and its  Affiliates;  provided,  in the case of clause  (ii),  such
Action is material to Bear  Stearns and its  Affiliates,  taken as a whole,  (b)
that relates to the transactions  contemplated by this Agreement or by the other
Transaction  Documents,  or (c)  with  respect  to which  there is a  reasonable
likelihood  of a  determination  which  would  prevent or delay Bear  Stearns or
CalBear from consummating the transactions  contemplated  hereby or by the other
Transaction  Documents  in any  material  respect  or  performing  any  material
obligations  hereunder or  thereunder,  in any court or other tribunal or before
any arbitrator, mediator, authority or Governmental Authority.

   10.6   Compliance with Law. Neither Bear Stearns nor CalBear has violated any
Applicable  Laws, and each of Bear Stearns and CalBear is in compliance with all
Applicable  Laws,  except to the extent that any such  violations or failures to
comply, individually or in the aggregate, have not had a Material Adverse Effect
on Bear  Stearns or CalBear.  Neither  Bear Stearns nor CalBear has received any
written notice to the effect that,  and CalBear do not have any knowledge  that,
(a) any  investigation or review by any Governmental  Authority  related to this
Agreement, the other Transaction Documents, the transactions contemplated hereby
or thereby, CalBear, Bear Stearns, the Services or the CalBear Trades is pending
or threatened in writing, or (b) any currently existing circumstances are likely
to result in a failure of Bear Stearns or CalBear to comply with, or a violation
by Bear Stearns or CalBear of, any  Applicable  Laws,  in either case which such
failure to comply or violation  would be reasonably  expected to have a Material
Adverse Effect on Bear Stearns or CalBear.

   10.7   Insurance.  CalBear has insurance policies,  binders or other forms of
insurance  that provide,  and during their term have  provided,  coverage to the
extent and in the manner (a) adequate for CalBear and its Assets, businesses and
operations and the risks insured against in connection  therewith and (b) as may


                                       45
<PAGE>

be or may have been  required by  material  Applicable  Law and by any  material
Contracts to which  CalBear is or has been a party,  except,  in either case, as
would not have a Material Adverse Effect on CalBear.

   10.8   Adequate  Capital.  CalBear is not insolvent and will not be insolvent
after giving effect to the  transactions  contemplated by this Agreement and the
other Transaction  Documents,  as the term insolvent is used in applicable state
and federal fraudulent conveyance or transfer laws.

   10.9   SEC Filings; Financial Statements.

          (a) Bear Stearns has filed all registration statements,  prospectuses,
forms and  reports  required to be filed by it under the  Securities  Act or the
Exchange Act, as the case may be, since January 1, 2003 (collectively, the "Bear
Stearns SEC Filings"). Each Bear Stearns SEC Filing, as amended or supplemented,
complied in all material respects with the requirements of the Securities Act or
the  Exchange  Act,  as the case may be, with  respect to such Bear  Stearns SEC
Filing. Each Bear Stearns SEC Filing, as amended or supplemented, if applicable,
did not (as so amended  or  supplemented)  contain  any  untrue  statement  of a
material fact or omit to state a material fact required to be stated  therein or
necessary  in order to make the  statements  made  therein,  in the light of the
circumstances under which they were made, not misleading.

          (b) Except as may be indicated  in the notes  thereto and, in the case
of unaudited  quarterly financial  statements,  except as permitted by Form 10-Q
under  the  Exchange  Act,  each  of  the  consolidated   financial   statements
(including,  in each case, any notes thereto)  contained in the Bear Stearns SEC
Filings was  prepared in  accordance  with GAAP  applied on a  consistent  basis
throughout the periods indicated,  and, at the time such consolidated  financial
statements  were  filed and at the time they were  amended or  supplemented,  if
applicable,  each fairly  presented  in all material  respects the  consolidated
financial  position of Bear Stearns and its  subsidiaries  as of the  respective
dates thereof and for the respective periods indicated therein (subject,  in the
case of unaudited  statements,  to normal,  recurring year-end adjustments which
did not have a Material Adverse Effect on Bear Stearns).

   10.10  Regulation.

          (a) Neither  Bear Stearns nor CalBear is subject to  regulation  as an
"electric utility company," a "gas utility company" a "public-utility  company,"
or a "holding  company," under PUHCA or any regulation  promulgated  thereunder.
Neither Bear Stearns nor CalBear is subject to material regulatory  restrictions
under PUHCA (other than Section 9(a)(2) of PUHCA).

          (b) CalBear has validly  issued  final orders  authorizing  CalBear to
engage  in  Power  sales at  wholesale  at  market-based  rates.  CalBear  is in
compliance with all FERC reporting and other  requirements  generally imposed on
entities authorized to engage in wholesale sales of Power at market-based rates,
including   requirements  to  file  electronic  quarterly  transaction  reports,
triennial  market-power updates and changes in status, except to the extent that
non-compliance  could not  reasonably  be expected  to cause a Material  Adverse
Effect with respect to CalBear.


                                       46
<PAGE>

   10.11  Operations  of CalBear.  CalBear  has  not taken any action that would
have violated  Section  4.4(f) of the Agency and Services  Agreement had it been
subject to such Section 4.4(f) on the Effective Date.  Except in connection with
the  transactions  contemplated by the Transaction  Documents,  CalBear does not
have any Contracts with, or Liabilities to, Third Parties or its Affiliates.

                                  ARTICLE XI.
                   PRE-EFFECTIVE DATE COVENANTS OF THE PARTIES

          From the date hereof through the Effective Date:

   11.1   Notification of Certain Matters.  Calpine and the Calpine  Transaction
Parties, on the one hand, and Bear Stearns and CalBear, on the other hand, shall
promptly  following  knowledge  thereof  give  notice  to each  other of (a) the
occurrence, or failure to occur, of any event, which occurrence or failure could
reasonably be expected to cause any  representation or warranty of such Party or
any of its Affiliates  contained in this Agreement or in any exhibit,  schedule,
certificate,  document  or written  instrument  attached  hereto to be untrue or
inaccurate in any material respect, (b) any Material Adverse Change with respect
to such Party or its Assets or the businesses of such Party,  or any development
that  occurs  before the  Effective  Date  (including  the  commencement  of any
proceeding  relating  to the  Bankruptcy  of any such Party) that has a Material
Adverse  Effect with  respect to such Party or its Assets or  business,  (c) any
Bankruptcy of such Party or any of its Significant Subsidiaries, (d) the failure
by such Party to perform any  covenant or  agreement  of such Party set forth in
this Agreement or any other Transaction  Document,  which failure  constitutes a
material breach of this Agreement or such other Transaction  Document;  provided
that any breach of this  clause (d) shall be deemed to be cured upon the cure of
the  underlying  failure to perform,  (e) any material  notice or other  written
communication from any Person alleging that the consent of such Person is or may
be required in connection  with the  execution,  delivery or performance of this
Agreement, any Transaction Document or the transactions  contemplated herein and
therein,  and (f) any material  notice or other written  communication  from any
Governmental  Authority  in  connection  with this  Agreement,  any  Transaction
Document or the transactions contemplated herein and therein;  provided, in each
case, that such disclosure  shall not be deemed to cure, or to relieve any Party
of any  Liability  or  obligation  with  respect to, any breach of or failure to
satisfy any  representation,  warranty,  covenant or agreement or to satisfy any
condition hereunder.

   11.2   Consents and Commercially  Reasonable Efforts. Each of the Transaction
Parties covenants and agrees, upon the terms and conditions contained herein, to
(a) cooperate with the other Transaction Parties hereto and to pursue diligently
and in good faith and use all commercially  reasonable efforts to take, or cause
to be taken, all actions  necessary,  proper or advisable to consummate and make
effective  the  transactions  contemplated  hereby and by the other  Transaction
Documents and (b) execute any documents,  instruments or conveyances of any kind
that  may  be  reasonably  necessary  or  advisable  to  carry  out  any  of the
transactions contemplated hereby and by the other Transaction Documents. Without
limiting the generality of the foregoing,  each Transaction  Party shall use all
commercially  reasonable best efforts to obtain at the earliest practicable date
all consents,  approvals, Permits,  authorizations,  exemptions and waivers from
Governmental  Authorities  and other Persons  (including  all FERC approvals and


                                       47
<PAGE>

authorizations under Section 6.1(c), Section 6.2(c) and Section 6.3) required to
be obtained by it and necessary or advisable to authorize, approve or permit the
performance by such  Transaction  Party of its  obligations  hereunder and under
each other agreement and instrument  referred to herein or contemplated  hereby,
including all such consents, approvals,  authorizations,  exemptions and waivers
listed on Schedules 9.2 and 10.2.

   11.3   Other  Transaction  Documents.  On or prior to the Effective Date, the
Calpine  Transaction  Parties and  CalBear,  respectively,  shall enter into the
Transaction  Documents  (other than this  Agreement),  as applicable,  and shall
provide each other with original copies thereof.

                                  ARTICLE XII.
                       CONDITIONS TO CALPINE'S OBLIGATIONS

          The obligation of Calpine and each of the Calpine  Transaction Parties
to perform its  obligations  under this  Agreement that are to be performed from
and after the Effective  Date and to consummate  any  transactions  contemplated
under  this  Agreement  to be  consummated  on or after the  Effective  Date are
subject to the  satisfaction,  on or prior to the Effective Date, of each of the
following  conditions,  any of which may be waived by  Calpine  and the  Calpine
Transaction Parties:

   12.1   Representations,  Warranties and  Covenants.  All  representations and
warranties of Bear Stearns and CalBear contained in this Agreement and qualified
by the words "material,"  "Material  Adverse Effect,"  "Material Adverse Change"
and  similar  phrases  shall  be  true  and  correct  in all  respects,  and all
representations  and  warranties  of Bear Stearns and CalBear  contained in this
Agreement  that are not so  qualified  shall be true and correct in all material
respects, in each case, at and as of the date of this Agreement and at and as of
the Effective Date, except for those  representations  and warranties that speak
as of a particular  date,  which shall be true and correct as of such date,  and
Bear  Stearns and CalBear  shall have  performed  and  satisfied in all material
respects all agreements  and covenants  required to be performed by it hereunder
prior to or on the Effective Date.

   12.2   No Proceedings or Litigation.  No Action by any Governmental Authority
or any other Person shall have been  instituted or threatened in writing for the
purpose of enjoining or preventing,  or which questions the validity or legality
of, the transactions  contemplated hereby and by the other Transaction Documents
and which  could  reasonably  be  expected  to  damage  Calpine  or any  Calpine
Transaction Party materially if Calpine and each Calpine  Transaction Party were
to perform its obligations that are to be performed hereunder from and after the
Effective Date or were to consummate any transactions that are to be consummated
hereunder  or under  any of the  other  Transaction  Documents  on or after  the
Effective Date.  Since the date of this Agreement,  no Applicable Law shall have
been  enacted  that  makes  performance  of this  Agreement  or any of the other
Transaction  Documents  by Calpine  or any of the  Calpine  Transaction  Parties
illegal or otherwise  prohibited or that otherwise has a Material Adverse Effect
on Calpine or any of the Calpine Transaction Parties.


                                       48
<PAGE>

   12.3   Bankruptcy.  Since the date  of this  Agreement,  there shall not have
been  any  Bankruptcy  Event  with  respect  to  Bear  Stearns,  CalBear  or any
Significant Subsidiary of Bear Stearns.

   12.4   Effective Date Deliveries. Calpine and the Calpine Transaction Parties
shall have received from Bear Stearns and CalBear,  at or prior to the Effective
Date, the following:

          (a) a copy of each  of the  Transaction  Documents  (other  than  this
Agreement), duly executed by CalBear;

          (b) a  certificate  executed by an officer of Bear Stearns  certifying
that, as of the Effective  Date,  the  conditions  set forth in Section 12.1 and
Section 12.3 have been satisfied; and

          (c) a certificate  of an officer of CalBear,  certifying the existence
of CalBear and the authority of CalBear to enter into the Transaction  Documents
to which CalBear is a party, in form reasonably satisfactory to Calpine.

   12.5   Transaction  Documents.  Each of the Transaction Documents (other than
this  Agreement)  shall have been  executed and  delivered by each party thereto
other than the Calpine Transaction  Parties.  All of the conditions precedent to
the obligations of the parties to each of the Transaction  Documents (other than
this Agreement)  shall have been satisfied or waived by the party or parties for
whose benefit they were established.

   12.6   Pre-Formation Transactions.  The Pre-Formation Transactions shall have
          been completed.

   12.7   Corporate  Proceedings.  All corporate proceedings of Bear Stearns and
CalBear that are required in connection with the Pre-Formation Transactions, the
Formation Transactions or the transactions contemplated by this Agreement and by
the other  Transaction  Documents  shall be reasonably  satisfactory in form and
substance to Calpine and its counsel.

   12.8   Regulatory Approvals. FERC shall have issued a final order pursuant to
Section 203 of the FPA,  not  undergoing  rehearing or appeal,  authorizing  the
internal  reorganization  of the upstream  ownership  of CalBear's  predecessor,
Arroyo Energy LP, and providing the authorizations required for the provision of
the Services by CMSC to CalBear and the provision of energy related  services by
CMSC to CES.

   12.9   Opinion of Counsel to Bear  Stearns.  Calpine  shall have received (a)
opinions,  dated as of the  Effective  Date,  in form and  substance  reasonably
satisfactory  to  Calpine,  of Latham & Watkins  LLP,  internal  counsel to Bear
Stearns and/or other counsel to Bear Stearns  reasonably  acceptable to Calpine,
with  respect to the matters  set forth on  Schedule  12.9 and (b) copies of any
officer's  certificates or other certificates,  in form and substance reasonably
satisfactory to Calpine, referred to in such opinions.


                                       49
<PAGE>

                                 ARTICLE XIII.
                    CONDITIONS TO BEAR STEARNS' OBLIGATIONS

          The  obligation  of each of Bear  Stearns  and  CalBear to perform its
obligations  under this  Agreement  that are to be performed  from and after the
Effective  Date and to  consummate  any  transactions  contemplated  under  this
Agreement to be  consummated  on or after the Effective  Date are subject to the
satisfaction,  on or  prior  to the  Effective  Date,  of each of the  following
conditions, any of which may be waived by Bear Stearns and CalBear:

   13.1   Representations,  Warranties  and Covenants.  All  representations and
warranties of Calpine and of each Calpine  Transaction  Party  contained in this
Agreement  and qualified by the words  "material,"  "Material  Adverse  Effect,"
"Material  Adverse  Change" and similar phrases shall be true and correct in all
respects,  and all representations and warranties of Calpine and of each Calpine
Transaction Party contained in this Agreement that are not so qualified shall be
true and correct in all material  respects,  in each case, at and as of the date
of  this  Agreement  and at  and as of the  Effective  Date,  except  for  those
representations  and warranties that speak as of a particular  date, which shall
be true and correct as of such date,  and Calpine and each  Calpine  Transaction
Party shall have performed and satisfied in all material respects all agreements
and  covenants  required  to be  performed  by it  hereunder  prior to or on the
Effective Date.

   13.2   No Proceedings or Litigation.  No Action by any Governmental Authority
or any other Person shall have been  instituted or threatened in writing for the
purpose of enjoining or preventing,  or which questions the validity or legality
of, the transactions  contemplated hereby and by the other Transaction Documents
and which  could  reasonably  be  expected  to damage  Bear  Stearns  or CalBear
materially  if each of Bear Stearns and CalBear were to perform its  obligations
that are to be performed  hereunder from and after the Effective Date or were to
consummate any transactions that are to be consummated hereunder or under any of
the other  Transaction  Documents on or after the Effective Date. Since the date
of this  Agreement,  no  Applicable  Law shall  have  been  enacted  that  makes
performance of this Agreement or any of the other Transaction  Documents by Bear
Stearns or CalBear  illegal or  otherwise  prohibited  or that  otherwise  has a
Material Adverse Effect on Bear Stearns or CalBear.

   13.3   Bankruptcy.  Since  the date of this  Agreement,  there shall not have
been  any  Bankruptcy  Event  with  respect  to  Calpine,  any  of  the  Calpine
Transaction Parties or any Significant Subsidiary of Calpine.

   13.4   Effective  Date  Deliveries.  Bear  Stearns  and  CalBear  shall  have
received from Calpine and the Calpine  Transaction  Parties,  at or prior to the
Effective Date, the following:

          (a) a copy of each  of the  Transaction  Documents  (other  than  this
Agreement),  duly  executed by each  Calpine  Transaction  Party that is a party
thereto;

          (b) a certificate  executed by an officer of Calpine  certifying that,
as of the Effective  Date,  the conditions set forth in Section 13.1 and Section
13.3 have been satisfied; and

          (c) a  certificate  of an officer of each Calpine  Transaction  Party,
certifying the existence of such Calpine  Transaction Party, as applicable,  and
the authority of such Calpine  Transaction  Party, as applicable,  to enter into


                                       50
<PAGE>

the Transaction Documents to which such Calpine Transaction Party is a party, in
form reasonably satisfactory to Bear Stearns.

   13.5   Transaction  Documents.  Each of the Transaction Documents (other than
this  Agreement)  shall have been  executed and  delivered by each party thereto
other than CalBear.  All of the conditions  precedent to the  obligations of the
parties to each of the Transaction  Documents  (other than this Agreement) shall
have been  satisfied  or waived by the party or parties for whose  benefit  they
were established.

  13.6    Pre-Formation Transactions.  The Pre-Formation Transactions shall have
been completed.

   13.7   Corporate  Proceedings.  All corporate  proceedings of Calpine and the
Calpine   Transaction   Parties  that  are  required  in  connection   with  the
Pre-Formation  Transactions,  the  Formation  Transactions  or the  transactions
contemplated by this Agreement and by the other  Transaction  Documents shall be
reasonably satisfactory in form and substance to Bear Stearns and its counsel.

   13.8   Regulatory Approvals. FERC shall have issued a final order pursuant to
Section 203 of the FPA,  not  undergoing  rehearing or appeal,  authorizing  the
internal  reorganization of the upstream  ownership of CMSC's  predecessor,  CES
Marketing VII, LLC, and providing the authorizations  required for the provision
of the Services by CMSC to CalBear and the provision of energy related  services
by CMSC to CES.

   13.9   Opinion of Counsel to Calpine.  Bear Stearns  shall have  received (a)
opinions,  dated as of the  Effective  Date,  in form and  substance  reasonably
satisfactory to Bear Stearns,  of Bracewell & Giuliani LLP,  internal counsel to
Calpine and/or other counsel to Calpine  reasonably  acceptable to Bear Stearns,
with  respect to the matters  set forth on  Schedule  13.9 and (b) copies of any
officer's  certificates or other certificates,  in form and substance reasonably
satisfactory to Bear Stearns, referred to in such opinions.

                                  ARTICLE XIV.
                    CERTAIN ACTIONS AFTER THE EFFECTIVE DATE

          Each of the Parties, with respect to itself only, covenants and agrees
with each of the other Parties that from and after the Effective Date:

   14.1   Survival of  Representations,  etc. The representations and warranties
of each Party contained  herein shall survive for one (1) year after the date on
which  such  representations  and  warranties  are made,  unless  another  Party
notifies  such  Party  prior to such date of any  specific  claim or claims  for
alleged  breach  of any such  representation  or  warranty,  in which  case such
representation  or warranty  shall  survive with respect to such claim until the
later of (a) final  resolution  by  settlement,  Action or otherwise of any such
claim or (b) the end of such one (1) year period.  No investigation  made by any
Party  (whether prior to, on or after the date of this  Agreement)  shall in any
way limit the representations  and warranties of the Parties.  The covenants and
agreements of the Parties contained herein shall survive the termination of this


                                       51
<PAGE>

Agreement only to the extent expressly set forth herein,  including as set forth
in Section 16.6(c)(ii).

  14.2    No Conflict or Violation.

          (a) Each of CMSC and  CalBear  shall  operate  their  businesses  in a
manner  that  will not  result  in (i) a  violation  of or a  conflict  with any
provision of the  Organizational  Documents of such Transaction  Party or (ii) a
violation of or a breach or default under,  the  termination or  acceleration of
the  performance  required  by,  or the  creation  of any  right of any party to
accelerate,  modify,  terminate or cancel, any material term or provision of any
material  Contract related to the Transaction to which such Transaction Party is
a party or by which any of its material  Assets are bound,  or (iii) a violation
or breach in any  material  respect of any  Applicable  Law  applicable  to such
Transaction Party and, in the case of CMSC, applicable to CalBear.

          (b) CES shall  operate  its  businesses  with  respect to the  Trading
Master  Agreement  and this  Agreement in a manner that will not result in (i) a
violation of or a conflict with any provision of the Organizational Documents of
CES or (ii) a violation  of or a breach or default  under,  the  termination  or
acceleration of the performance required by, or the creation of any right of any
party to accelerate, modify, terminate or cancel, any material term or provision
of any  material  Contract  relating  to any  Credit  Enhancement  Trade  or the
Transaction  to which CES is a party or by which any of its material  Assets are
bound, or (iii) a violation or breach in any material  respect of any Applicable
Law applicable to CES.

   14.3   Sufficiency  of Assets.  Each of the Calpine  Transaction  Parties and
CalBear shall continue to own,  license,  lease or otherwise have a right to use
or have  contracted for all Assets  materially  necessary and sufficient for the
performance  of its  obligations  under  the  Transaction  Documents,  and  will
maintain its Assets in the aggregate  materially in such operating condition and
repair  (subject to normal wear and tear) as is necessary and sufficient for the
performance of such obligations.

   14.4   Permits.  Subject  to  Section  4.1(n)  of  the  Agency  and  Services
Agreement,  each of Calpine, the Calpine Transaction  Parties,  Bear Stearns and
CalBear  shall  maintain and keep in full force and effect all material  Permits
needed for the performance of its obligations  under the Transaction  Documents,
and each such Party shall continue to own or possess such Permits free and clear
of any material Encumbrances.

   14.5   Insurance.  Each of the Calpine  Transaction Parties and CalBear shall
maintain and keep in full force and effect insurance policies,  binders or other
forms of insurance  that provide  coverage in  connection  with its  obligations
under the  Transaction  Documents and the  Transaction  to the extent and in the
manner  adequate  for  such  Person  and its  material  Assets,  businesses  and
operations  and the risks  insured  against in connection  therewith,  except as
would not have a Material Adverse Effect.


                                       52
<PAGE>

   14.6   Adequate Capital.  Each of Calpine,  the Calpine Transaction  Parties,
Bear Stearns and CalBear shall operate and maintain its businesses  such that at
all  times it is not  insolvent,  as such term is used in  applicable  state and
federal fraudulent conveyance or transfer laws.

   14.7   Further  Assurances.  The Transaction  Parties shall use  commercially
reasonable efforts to take all actions and to do all things necessary, proper or
advisable to consummate and make effective the transactions contemplated by this
Agreement and by the other Transaction Documents.  Following the Effective Date,
each Transaction  Party agrees to execute such documents or instruments and take
such actions as may be reasonably  requested by the other  Transaction  Parties,
and  otherwise  cooperate  in a  reasonable  manner  with the other  Transaction
Parties and their respective Affiliates and their respective  Representatives in
connection  with any action that may be necessary,  proper or advisable to carry
out the provisions hereof or transactions  contemplated  hereby and by the other
Transaction Documents.

   14.8   Litigation  Support.  In  the  event  and for so long as any  Party is
actively  contesting or defending against any Action or Claim in connection with
(a) any transaction  contemplated  under this Agreement or the other Transaction
Documents or (b) any fact, situation, circumstance, status, condition, activity,
practice,  plan,  occurrence,   event,  incident,  action,  failure  to  act  or
transaction  involving the CalBear  Business,  the Trades or the Services,  each
other Party that is not an Affiliate of such Party, will use reasonable  efforts
to  cooperate  with such Party and its counsel in the  contest or defense,  make
available  its  Representatives,  and provide such  testimony  and access to its
Books and  Records  as shall be  reasonably  necessary  in  connection  with the
contest  or  defense,  all at the sole cost and  expense  of the  contesting  or
defending  Party  (unless  the  contesting  or  defending  Party is  entitled to
indemnification  hereunder).  The covenant  contained in this Section 14.8 shall
not apply if Calpine or any Calpine  Transaction  Party has an adverse Action or
Claim  against  Bear  Stearns or CalBear and shall not apply if Bear  Stearns or
CalBear  has  an  adverse  Action  or  Claim  against  Calpine  or  any  Calpine
Transaction Party, but shall apply equally with respect to any other Transaction
Documents  and shall not be in lieu of or  otherwise  limit the  indemnification
obligations of the Parties pursuant to Article XV hereof.

  14.9    Organizational Documents of CMSC and CalBear.

          (a) Calpine shall not, and shall cause its  Affiliates  not to, modify
the  Organizational  Documents of CMSC,  or any provision  thereof,  without the
prior consent of Bear Stearns, not to be unreasonably withheld.

          (b) Bear  Stearns  shall not, and shall cause its  Affiliates  not to,
modify the  Organizational  Documents  of  CalBear,  or any  provision  thereof,
without the prior consent of Calpine, not to be unreasonably withheld.

                                   ARTICLE XV.
                                 INDEMNIFICATION

  15.1    General Indemnification.

          (a) By CMSC and CES.


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<PAGE>

               (i) Subject to Section 14.1 and the limitations set forth in this
Article XV and  Article  XVII,  the  Calpine  Transaction  Parties,  jointly and
severally,  shall indemnify,  save and hold harmless Bear Stearns, CalBear, each
of  their  Affiliates,  and  each  of  their  respective  directors,   officers,
employees, successors, transferees and assignees (each, a "Bear Stearns Party"),
from and against any and all costs, losses, charges,  liabilities,  obligations,
damages,  Actions  (including  response  Actions,  removal  Actions and remedial
Actions),  judgments,  deficiencies,  demands,  fees,  settlements and expenses,
including  interest,  fines,  penalties,  costs of mitigation  and cover (to the
extent, but only to the extent, such costs are provided for in the definition of
Third Party  Losses),  attorneys'  fees and  expenses,  all amounts  paid in the
investigation,  defense  or  settlement  of any of the  foregoing  and  costs of
enforcing the applicable indemnity  (collectively,  "Damages") arising out of or
resulting from:

                    (A) any untruth,  inaccuracy or  incorrectness  of, or other
          breach of, any  representation  or  warranty of Calpine or any Calpine
          Transaction Party in or pursuant to this Agreement or any of the other
          Transaction Documents;

                    (B) any  nonfulfillment,  nonperformance,  nonobservance  or
          other  breach or  violation  of, or default  under,  any  covenant  or
          agreement  made by  Calpine  or any  Calpine  Transaction  Party in or
          pursuant to this Agreement or any of the other Transaction Documents;

                    (C)  any  Misconduct  of  Calpine  or  any  of  the  Calpine
          Transaction  Parties or any of their  Affiliates  or their  respective
          Representatives;

                    (D) any Liability of Calpine,  any Calpine Transaction Party
          or any of their  Affiliates  for any finder's  fee,  brokerage  fee or
          commission  or similar  Payment in  connection  with the  transactions
          contemplated hereby and by the other Transaction Documents; or

                    (E) any violation of Applicable Law by Calpine or any of the
          Calpine  Transaction  Parties  or any of  their  Affiliates  or  their
          respective  Representatives,  in each  case  to the  extent  that  the
          Damages to a Bear  Stearns  Party  arose out of or  resulted  from the
          transactions  contemplated  by the  Transaction  Documents or the fact
          that Bear Stearns or CalBear are parties to the Transaction Documents;
          provided  that this  clause (E) shall not apply to any  violations  of
          Applicable Law indemnified  under clauses (A), (B) or (C) above or any
          violations of Applicable Law not indemnified  pursuant to such clauses
          (A),  (B) or (C)  as a  result  of  materiality,  knowledge,  Material
          Adverse Effect and similar qualifiers in the applicable  provisions of
          this Agreement and the other Transaction Documents;

(each claim for  indemnity  by a Bear  Stearns  Party  pursuant to this  Section
15.1(a), a "Bear Stearns Claim").

               (ii) The  indemnity  provided for in this Section  15.1(a) is not
limited to Third Party Claims against any Bear Stearns Party,  but includes Bear
Stearns Claims incurred or sustained by any Bear Stearns Party in the absence of


                                       54
<PAGE>

Third Party  Claims.  With  respect to any Third Party  Claims  against any Bear
Stearns Party covered by the indemnity  provided in this Section  15.1(a),  such
indemnification shall include coverage of any consequential,  indirect, special,
punitive, exemplary or incidental damages included in such Third Party Claims.

               (iii) The  indemnity  provided for in this Section  15.1(a) shall
not  apply  to  Claims  or  Damages   arising  out  of  or  resulting  from  any
nonfulfillment, nonperformance, nonobservance or other breach or violation of or
default under, or any Misconduct related to, Soft Covenants,  for which the sole
and exclusive rights and remedies are described in Clause (a) of Section 17.3 of
this Agreement.

               (iv) The  indemnity  set forth in clauses  (A) and (B) of Section
15.1(a)(i) is subject to the following additional limitations:

                    (A) such  indemnity  shall not  apply to  Claims or  Damages
          constituting  Ordinary  Losses,  except to the  extent  such  Ordinary
          Losses are not consequential,  indirect, special, punitive,  exemplary
          or  incidental  Claims or Damages  and arise out of or result from (I)
          any nonfulfillment,  nonperformance,  nonobservance or other breach or
          violation  of or default  under Hard  Covenants,  (II)  Misconduct  of
          Calpine  or  any  Calpine  Transaction  Party  or  any  other  matters
          indemnified   in   clauses   (C)   through   (E)   above,   (III)  any
          nonfulfillment,  nonperformance,  nonobservance  or  other  breach  or
          violation  of or  default  under  any  provisions  of any  Transaction
          Document  arising out of or  resulting  from the gross  negligence  of
          Calpine or any Calpine Transaction Party (except to the extent covered
          in the definition of  "Misconduct" or limited by paragraph (v) below),
          to the extent  that such  Ordinary  Losses  covered  under this clause
          (III)  incurred in the same Fiscal Year in the  aggregate  exceed $[*]
          million  (provided  that the  occurrence of losses or gains on CalBear
          Trades  does not by itself  represent  the  presence  or  absence  of,
          respectively,  gross  negligence)  or (IV) the failure of Calpine or a
          Calpine  Transaction  Party to make any  Payment  to Bear  Stearns  or
          CalBear  specifically  provided  for  pursuant  to  the  terms  of the
          Transaction Documents; and

                    (B) such  indemnity  shall not  apply to  Claims or  Damages
          constituting  Third  Party  Losses,  unless and until  such  Claims or
          Damages covered under such indemnity  incurred in the same Fiscal Year
          in the aggregate exceed $[*] million (the "Threshold"),  in which case
          such indemnity shall apply to all such Claims or Damages covered under
          such indemnity  during such Fiscal Year whether or not the same exceed
          the  Threshold,  provided that this Section  15.1(a)(iv)(B)  shall not
          apply to Claims or Damages  arising out of or  resulting  from (I) any
          nonfulfillment,  nonperformance,  nonobservance  or  other  breach  or
          violation  of or default  under Hard  Covenants,  (II)  Misconduct  of
          Calpine  or  any  Calpine  Transaction  Party  or  any  other  matters
          indemnified  in clauses (C)  through  (E) above,  (III) the failure of
          Calpine  or a Calpine  Transaction  Party to make any  Payment to Bear


                                       55
<PAGE>

          Stearns or CalBear specifically  provided for pursuant to the terms of
          the Transaction Documents,  or (IV) indemnification  obligations under
          Section 4.4(e)(iv) of the Agency and Services Agreement.

               (v) No Bear Stearns Party shall have the right to indemnification
for any Ordinary Losses resulting from or arising out of the gross negligence of
Calpine or any  Calpine  Transaction  Party to the extent  that Bear  Stearns or
CalBear  actually  knew of such gross  negligence  and did not  promptly,  after
obtaining such knowledge,  inform Calpine or a Calpine  Transaction Party of (A)
its intent to preserve any claim for indemnification  under this Section 15.1(a)
with respect to such gross  negligence  and (B) the facts,  events or conditions
constituting such gross negligence, to the extent then known.

          (b) By CalBear.

               (i) Subject to Section 14.1 and the limitations set forth in this
Article XV and Article  XVII,  CalBear shall  indemnify,  save and hold harmless
Calpine,  each Calpine Transaction Party, each of their Affiliates,  and each of
their respective directors,  officers,  employees,  successors,  transferees and
assignees  (each,  a "Calpine  Party"),  from and  against  any and all  Damages
arising out of or resulting from:

                    (A) any untruth,  inaccuracy or  incorrectness  of, or other
          breach of, any  representation  or warranty of Bear Stearns or CalBear
          in or  pursuant  to this  Agreement  or any of the  other  Transaction
          Documents;

                    (B) any  nonfulfillment,  nonperformance,  nonobservance  or
          other  breach or  violation  of, or default  under,  any  covenant  or
          agreement  made by Bear  Stearns  or CalBear  in or  pursuant  to this
          Agreement or any of the other Transaction Documents;

                    (C) any  Misconduct  of Bear  Stearns  or  CalBear or any of
          their Affiliates or their respective Representatives;

                    (D) any Liability of Bear  Stearns,  CalBear or any of their
          Affiliates  for any  finder's  fee,  brokerage  fee or  commission  or
          similar  Payment  in  connection  with the  transactions  contemplated
          hereby and by the other Transaction Documents; or

                    (E) any violation of Applicable Law by CalBear or any of its
          Affiliates or their  respective  Representatives,  in each case to the
          extent  that the  Damages to a Calpine  Party arose out of or resulted
          from the transactions contemplated by the Transaction Documents or the
          fact that Calpine and the Calpine  Transaction  Parties are parties to
          the  Transaction  Documents;  provided  that this clause (E) shall not
          apply to any  violations of Applicable Law  indemnified  under clauses
          (A),  (B) or (C)  above  or  any  violations  of  Applicable  Law  not
          indemnified  pursuant to such  clauses  (A), (B) or (C) as a result of
          materiality, knowledge, Material Adverse Effect and similar qualifiers
          in  the  applicable   provisions  of  this  Agreement  and  the  other
          Transaction Documents;


                                       56
<PAGE>

(each claim for indemnity by a Calpine Party pursuant to this Section 15.1(b), a
"Calpine  Claim");  provided  that in no event  shall  CalBear be  obligated  to
indemnify  any Calpine Party for Damages to the extent such Damages arose out of
or  resulted  from  CMSC's  performance  of or  failure  to  perform  any of its
obligations  as agent or  attorney-in-fact  for  CalBear  under the  Agency  and
Services Agreement.

               (ii) The  indemnity  provided for in this Section  15.1(b) is not
limited to Third Party Claims  against any Calpine Party,  but includes  Calpine
Claims  incurred or sustained by any Calpine Party in the absence of Third Party
Claims. With respect to any Third Party Claims against any Calpine Party covered
by the indemnity provided in this Section 15.1(b),  such  indemnification  shall
include coverage of any consequential, indirect, special, punitive, exemplary or
incidental damages included in such Third Party Claims.

               (iii) The  indemnity  provided for in this Section  15.1(b) shall
not  apply  to  Claims  or  Damages   arising  out  of  or  resulting  from  any
nonfulfillment, nonperformance, nonobservance or other breach or violation of or
default under, or any Misconduct related to, Soft Covenants,  for which the sole
and exclusive rights and remedies are described in Clause (a) of Section 17.3 of
this Agreement.

               (iv) The  indemnity  set forth in clauses  (A) and (B) of Section
15.1(b)(i) is subject to the following additional limitations:

                    (A) such  indemnity  shall not  apply to  Claims or  Damages
          constituting  Ordinary  Losses,  except to the  extent  such  Ordinary
          Losses are not consequential,  indirect, special, punitive,  exemplary
          or  incidental  Claims or Damages  and arise out of or result from (I)
          any nonfulfillment,  nonperformance,  nonobservance or other breach or
          violation of or default under Hard Covenants,  (II) Misconduct of Bear
          Stearns or CalBear or any other  matters  indemnified  in clauses  (C)
          through   (E)  above,   (III)  any   nonfulfillment,   nonperformance,
          nonobservance  or other breach or  violation  of or default  under any
          provisions  of any  Transaction  Document  arising out of or resulting
          from the gross  negligence  of Bear Stearns or CalBear  (except to the
          extent  covered  in the  definition  of  "Misconduct"  or  limited  by
          paragraph (v) below),  to the extent that such Ordinary Losses covered
          under  this  clause  (III)  incurred  in the same  Fiscal  Year in the
          aggregate  exceed $[*]  million or (IV) the failure of Bear Stearns or
          CalBear  to  make  any   Payment  to  a  Calpine   Transaction   Party
          specifically  provided  for  pursuant to the terms of the  Transaction
          Documents; and

                    (B) such  indemnity  shall not  apply to  Claims or  Damages
          constituting  Third  Party  Losses,  unless and until  such  Claims or
          Damages covered under such indemnity  incurred in the same Fiscal Year
          in the aggregate  exceed the  Threshold,  in which case such indemnity
          shall apply to all such Claims or Damages covered under such indemnity
          during such Fiscal Year whether or not the same exceed the  Threshold,
          provided that this Section 15.1(b)(iv)(B) shall not apply to Claims or
          Damages  arising  out of or  resulting  from  (I) any  nonfulfillment,
          nonperformance,  nonobservance  or other  breach  or  violation  of or


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<PAGE>

          default  under Hard  Covenants,  (II)  Misconduct  of Bear  Stearns or
          CalBear or any other  matters  indemnified  in clauses (C) through (E)
          above or (III) the  failure  of Bear  Stearns  or  CalBear to make any
          Payment  to  Calpine  or  any  of  the  Calpine   Transaction  Parties
          specifically  provided  for  pursuant to the terms of the  Transaction
          Documents.

               (v) No Calpine Party shall have the right to indemnification  for
any Ordinary  Losses  resulting  from or arising out of the gross  negligence of
Bear  Stearns or CalBear to the extent that  Calpine or any Calpine  Transaction
Party  actually  knew of such  gross  negligence  and  did not  promptly,  after
obtaining  such  knowledge,  inform Bear Stearns or CalBear of (A) its intent to
preserve any claim for  indemnification  under this Section 15.1(b) with respect
to such gross  negligence and (B) the facts,  events or conditions  constituting
such gross negligence, to the extent then known.

          (c) Defense of Claims.

               (i)  If  a  Claim  is  to  be  made  by  a  Person   entitled  to
indemnification  hereunder  (without  regard  to  any  thresholds),  the  Person
claiming such  indemnification  shall give written notice (a "Claim  Notice") to
the indemnifying  Person (A) as soon as practicable after the Person entitled to
indemnification  becomes  aware of any fact,  condition  or event which may give
rise to Damages for which  indemnification may be sought under this Section 15.1
and (B) in the case of the  assertion  of a Claim  (whether  pursuant to a legal
Action or  otherwise) or the  commencement  of any Action by a Third Party other
than directors, officers, employees, successors, transferees or assignees of, or
other  Representatives  of,  Calpine,  any  Calpine  Transaction  Party or their
Affiliates  or Bear Stearns,  CalBear or their  Affiliates  (together,  a "Third
Party Claim"), promptly upon receipt of written notice of the Third Party Claim.
The failure of any indemnified  Person to give timely notice hereunder shall not
affect rights to indemnification  hereunder,  except and only to the extent that
the indemnifying Person demonstrates actual prejudice caused by such failure.

               (ii) In the  case of a Third  Party  Claim,  if the  indemnifying
Person  shall  acknowledge  in  writing  to  the  indemnified  Person  that  the
indemnifying Person shall be obligated to indemnify the indemnified Person under
the terms of its indemnity  hereunder in connection with such Third Party Claim,
then the  indemnifying  Person shall be entitled and, if it so elects,  shall be
obligated at its own cost,  risk and expense,  to participate in or take control
of the defense and  investigation  of such Third Party Claim,  and to pursue the
defense  thereof in good faith by appropriate  actions or  proceedings  promptly
taken or  instituted  and  diligently  pursued,  including  to employ and engage
attorneys of its own choice reasonably  acceptable to the indemnified  Person to
handle and defend the same,  compromise or settle such Third Party Claim subject
to Sections 15.1(c)(iii) and 15.1(c)(iv);  provided that the indemnifying Person
shall not be entitled to take control of the defense or investigation of a Third
Party Claim, if (x) the indemnifying  Person is also a party to such Third Party
Claim and the indemnified  Person  determined in good faith,  upon the advice of
outside  counsel,  that a conflict of interest  exists  between the  indemnified
Person and the  indemnifying  Person with respect to such Third Party Claim, (y)
the indemnifying  Person fails to demonstrate to the reasonable  satisfaction of
the indemnified  Person its financial  capacity to defend such Third Party Claim


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and provide  indemnification  with respect to such Third Party Claim or (z) such
Third Party Claim is a Claim by a Governmental Authority.

               (iii) In the  event  the  indemnifying  Person  elects  to assume
control of the defense and investigation of such Third Party Claim in accordance
with  Section  15.1(c)(ii),  the  indemnified  Person  may,  at its own cost and
expense,  participate  in the  investigation,  trial,  and defense of such Third
Party Claim; provided that, if (x) the named persons to an Action resulting from
such Third Party Claim include both the indemnifying  Person and the indemnified
Person and the  indemnified  Person has been  advised in writing by counsel that
there may be one or more legal  defenses  available to such  indemnified  Person
that are different  from or additional  to those  available to the  indemnifying
person or that a conflict of interest exists between the indemnified  Person and
the  indemnifying  Person with  respect to such Third Party  Claim,  or (y) such
Third Party Claim is a Claim by a Governmental Authority, the indemnified Person
shall be entitled,  at the  indemnifying  person's  cost,  risk and expense,  to
reasonable fees and  disbursements of separate  counsel of its own choosing.  In
the event the indemnifying  Person assumes the defense of the Third Party Claim,
the indemnifying Person shall keep the indemnified Person reasonably informed of
the progress of any such defense,  compromise or  settlement.  The  indemnifying
Person shall not have the power to  compromise or settle such Third Party Claim,
except with the written consent of the indemnified  Person,  such consent not to
be unreasonably withheld or delayed (it being understood that the failure of the
indemnified Person to give such consent shall not be considered  unreasonable in
respect  of  any  compromise  or  settlement   that  (A)  does  not  include  an
unconditional  release of such indemnified  Person from all liabilities  arising
out of, or that may arise out of,  such  Third  Party  Claim or (B)  includes  a
statement as to or an admission of fault, culpability or a failure to act, by or
on behalf of such indemnified Person).

               (iv) If the  indemnifying  Person fails to notify the indemnified
Person in writing of its  election  to assume  the  defense of such Third  Party
Claim in  accordance  with this Section  15.1(c)  within ten (10)  calendar days
after  receipt  of the  Claim  Notice,  or if  the  indemnifying  person  is not
permitted  to assume the defense of such Third Party  Claim in  accordance  with
this Section  15.1(c),  the  indemnified  Person  against which such Third Party
Claim has been asserted shall have the right to undertake,  at the  indemnifying
Person's cost, risk and expense, the defense,  compromise and settlement of such
Third Party Claim on behalf of and for the account of the  indemnifying  Person;
provided  that  the  indemnifying  Person  shall  not be  liable  for  costs  of
settlement of such Third Party Claim if such Third Party Claim is compromised or
settled  without the written consent of the  indemnifying  Person (which consent
shall not be unreasonably withheld or delayed).

          (d) Loss Calculation.

          The amount of Claims or Damages to which an indemnity  provided for in
this  Section  15.1  applies  shall be  determined  after  giving  effect to all
provisions  of the  Transaction  Documents  other  than  this  Section  15.1 the
operation of which  mitigates or compensates  for such Claims or Damages (to the
extent such terms are given full force and effect),  including  (as  applicable)
any  reductions  in the Service Fee,  Service Fee Return  Refund or Bonus Amount


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<PAGE>

payable under the Agency and Services Agreement on account or in respect of such
Claims and Damages.

   15.2   Right of Offset.  Each  Party may,  to the extent set forth in Section
3.10  hereof,  withhold and set off against any and all amounts due to any other
Party any and all amounts as to which the other Party is  obligated to indemnify
such Party pursuant to any provision of this Article XV.

   15.3   Payment.  With respect to Third Party Claims for which indemnification
is payable  hereunder,  the indemnifying  Person will pay the indemnified Person
promptly after the earlier of (a) the entry of judgment  against the indemnified
Person and the  expiration of any applicable  appeal period,  (b) the entry of a
non-appealable  judgment or final  appellate  decision  against the  indemnified
person, or (c) the execution of any settlement  agreement referred to in Section
15.1.  Notwithstanding  the foregoing,  expenses of the  indemnified  Person for
which the  indemnifying  Person is responsible  (including  reasonable  fees and
disbursements  of  counsel)  shall  be  reimbursed  on a  current  basis  by the
indemnifying Person.

   15.4   Right to  Indemnification  Not Affected by  Knowledge or  Presumption.

          (a) Except as otherwise  specifically  provided  herein,  the right to
indemnification  based upon breach of  representations,  warranties,  covenants,
agreements or obligations  will not be affected by any  investigation  conducted
with  respect to, or knowledge  acquired  (or capable of being  acquired) at any
time,  whether  before or after the execution and delivery of this  Agreement or
the Effective Date, whether as a result of disclosure by a Party hereto pursuant
to Section 11.1 or  otherwise,  with respect to the accuracy or inaccuracy of or
compliance  with any  such  representation,  warranty,  covenant,  agreement  or
obligation.

          (b) The  satisfaction of any condition based on the presumed  accuracy
of  any  representation  or  warranty,  or on  the  presumed  performance  of or
compliance with any covenant, agreement or obligation, will not affect the right
to   indemnification,   payment  of  Damages  or  other  remedy  based  on  such
representations, warranties, covenants, agreements and obligations.

                                  ARTICLE XVI.
                     TERM; EVENTS OF DEFAULT AND TERMINATION

   16.1   Term.  The term of this  Agreement  shall  commence on the date hereof
and,  subject to the other  provisions of this Agreement,  the Liquidation  Date
shall occur on (a) November 30, 2006,  and (b) on each  February 28 (or February
29, in the event of a leap year),  May 31,  August 31 and November 30 thereafter
(each  three (3) Month  period  ending on each such date,  a "Renewal  Period"),
unless,  in each case, this Agreement is renewed or otherwise stays in effect in
accordance with Section 16.2 below.  This Agreement shall terminate  immediately
upon completion of Liquidation (the "Termination Date").

  16.2    Renewal.

          (a) (i) If any Party  wishes to renew this  Agreement so that it shall
continue after the end of the Initial Term through the end of the Renewal Period
commencing on December 1, 2006, Calpine or any Calpine Transaction Party, on the


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one hand, or Bear Stearns or CalBear,  on the other hand, shall deliver a notice
setting forth the intention of such Party and its Affiliates that are Parties to
renew this  Agreement (the "Renewal  Notice")  through the Renewal Period ending
February 28, 2007,  which Renewal  Notice shall be delivered on or before August
31, 2006.

               (ii) If this  Agreement  has been  renewed  so that it  continues
after  the end of the  Initial  Term,  and if any  Party  wishes  to renew  this
Agreement so that it shall  continue  after the end of the latest Renewal Period
for which this  Agreement  has  previously  been renewed  (the  "Latest  Renewal
Period"),  then Calpine or any Calpine  Transaction  Party,  on the one hand, or
Bear  Stearns or CalBear,  on the other  hand,  shall  deliver a Renewal  Notice
setting forth the intention of such Party and its Affiliates that are Parties to
renew this Agreement through the end of the Renewal Period immediately following
the Latest  Renewal  Period,  which  notice  shall be given on or before the day
immediately preceding the first day of the Latest Renewal Period.

               (iii) A Renewal  Notice may set forth the intention of Calpine or
any Calpine  Transaction Party, on the one hand, or Bear Stearns or CalBear,  on
the other  hand,  to renew this  Agreement  for any  number of  Renewal  Periods
following the end of the Initial Term or the end of the Latest  Renewal  Period,
as applicable (and, in such case, such Renewal Notice shall serve as the Renewal
Notice for each such Renewal  Period,  unless such  Renewal  Notice is withdrawn
with respect to any Renewal Period (and all subsequent Renewal Periods contained
in such  Renewal  Notice,  if any) on or prior to the date such  Renewal  Notice
would otherwise be due for such Renewal  Period,  except as set forth in Section
16.3(a)  below),  as determined by the Party  delivering such notice in its sole
discretion.  A form of  Renewal  Notice is  attached  hereto as  Exhibit F. Each
Renewal Notice shall be delivered in any manner provided in Section 18.2.

          (b) If both Calpine or any Calpine Transaction Party, on the one hand,
and Bear Stearns or CalBear,  on the other hand,  deliver a Renewal  Notice with
respect to an Applicable  Renewal Period as specified in Section  16.2(a),  this
Agreement shall continue in full force and effect at least until the end of such
Applicable  Renewal Period,  unless otherwise  terminated  pursuant to the terms
hereof.

          (c) If none of Calpine, any Calpine Transaction Party, Bear Stearns or
CalBear  delivers a Renewal Notice with respect to an Applicable  Renewal Period
as specified in Section 16.2(a),  the Liquidation Date shall occur at the end of
the Initial Term or the end of the Renewal  Period  immediately  preceding  such
Applicable Renewal Period, as applicable, in accordance with Section 16.6(b)(i).

          (d) If either  Calpine or any Calpine  Transaction  Party,  on the one
hand, or Bear Stearns or CalBear,  on the other hand,  delivers a Renewal Notice
with respect to an  Applicable  Renewal  Period as specified in Section  16.2(a)
(such Party,  together with its Affiliates,  the "Renewing Parties") but neither
of Bear Stearns nor CalBear,  on the one hand, or none of Calpine or the Calpine
Transaction Parties, on the other hand, respectively,  delivers a Renewal Notice
with respect to such  Applicable  Renewal  Period (such  Parties,  together with
their Affiliates,  the "Non-Renewing Parties"), the Liquidation Date shall occur


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<PAGE>

at the end of the  Initial  Term or the end of the  Renewal  Period  immediately
preceding such  Applicable  Renewal  Period,  as applicable,  in accordance with
Section 16.6(b)(ii).

  16.3    Certain Matters with Respect to Renewal.

          (a) Notwithstanding  anything herein to the contrary,  if a Bankruptcy
Event has occurred with respect to any Party,  neither such Party nor any of its
Affiliates  that are Parties shall have a right to send any Renewal  Notice with
respect  to any  Applicable  Renewal  Period,  unless  such Party and all of its
Affiliates  that are  Parties  have (i)  "assumed",  within  the  meaning of the
Bankruptcy Law, this Agreement and the other Transaction Documents prior to such
time and (ii)  complied  with all of their  obligations  hereunder and under the
other Transaction Documents prior to such time.

          (b) Notwithstanding anything herein to the contrary, in no event shall
delivery of a Renewal Notice or a renewal of this  Agreement in accordance  with
Section  16.2 result in, or be deemed to, or cause,  the waiver of any rights of
the  Renewing  Parties  under this  Agreement,  the  Transaction  Documents,  or
otherwise.

  16.4    Calpine Events of Default.

          The  occurrence  of any  one or  more of the  following  events  shall
constitute a Calpine Event of Default  ("Calpine  Event of Default")  under this
Agreement and the other Transaction Documents:

          (a) the failure by any Calpine  Transaction  Party to make any Payment
required under this Agreement or any of the other  Transaction  Documents  which
failure  continues  unremedied  (i) if  notice  of such  failure  was  given  in
accordance with the applicable  notice  provisions by Bear Stearns or CalBear to
Calpine or any such Calpine  Transaction  Party prior to 4:30 p.m. New York City
time on a Business  Day, at the end of the Business Day  following  the day such
notice was given, or (ii) if notice of such default was given by Bear Stearns or
CalBear  after 4:30 p.m. New York City time on any  Business  Day, or on any day
that  is not a  Business  Day,  at the  end of the  second  (2nd)  Business  Day
following the day such notice was given;

          (b) the failure by Calpine or any Calpine Transaction Party to perform
any  covenant  or  agreement  of  Calpine  or such  Calpine  Transaction  Party,
respectively,  set forth in this  Agreement  or any other  Transaction  Document
(other than as  described  in Sections  16.4(a),  16.4(c)  and  16.4(d)),  which
failure   constitutes  a  material  breach  of  this  Agreement  or  such  other
Transaction Document or would have a Material Adverse Effect on the Transaction,
and which  failure  is not cured  within (i) any  applicable  cure  period  with
respect to such  failure set forth in this  Agreement  or any other  Transaction
Document,  if any, or, (ii) in the event that there is no such  applicable  cure
period with respect to such failure, ten (10) Business Days after notice thereof
is given to Calpine or such Calpine  Transaction  Party,  respectively,  by Bear
Stearns or CalBear in accordance with Section 18.2;

          (c) a Bankruptcy Event shall have occurred with respect to Calpine,  a
Calpine Transaction Party or a Significant Subsidiary of Calpine; or


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<PAGE>

          (d)  any   representation  or  warranty  of  Calpine  or  any  Calpine
Transaction  Party  hereunder  proves to have  been  incorrect  in any  material
respect as of the date such representation or warranty was made; provided that a
Calpine  Event of Default shall not arise under this Section  16.4(d)  following
the  expiration of the survival  period with respect to such  representation  or
warranty set forth in Section 14.1.

  16.5    Bear Stearns Events of Default.

          The  occurrence  of any  one or  more of the  following  events  shall
constitute a Bear Stearns  Event of Default  ("Bear  Stearns  Event of Default")
under this Agreement and the other Transaction Documents:

          (a) the  failure by CalBear to make any  Payment  required  under this
Agreement or any of the other  Transaction  Documents  which  failure  continues
unremedied  (i) if  notice of such  failure  was  given in  accordance  with the
applicable notice  provisions by Calpine or a Calpine  Transaction Party to Bear
Stearns or CalBear  prior to 4:30 p.m. New York City time on a Business  Day, at
the end of the Business Day following the day such notice was given,  or (ii) if
notice of such default was given by Calpine or a Calpine Transaction Party after
4:30 p.m.  New York City time on any  Business  Day, or on any day that is not a
Business Day, at the end of the second (2nd) Business Day following the day such
notice was given;

          (b) the failure by Bear  Stearns or CalBear to perform any covenant or
agreement of Bear Stearns or CalBear,  respectively, set forth in this Agreement
or any other Transaction  Document (other than as described in Sections 16.5(a),
16.5(c)  and  16.5(d)),  which  failure  constitutes  a material  breach of this
Agreement or such other  Transaction  Document or would have a Material  Adverse
Effect  on the  Transaction,  and which  failure  is not  cured  within  (i) any
applicable  cure period with respect to such failure set forth in this Agreement
or any other Transaction Document, if any, or (ii) in the event that there is no
such applicable cure period with respect to such failure, ten (10) Business Days
after  notice  thereof is given to Bear  Stearns or  CalBear,  respectively,  by
Calpine or a Calpine Transaction Party in accordance with Section 18.2;

          (c) a  Bankruptcy  Event  shall  have  occurred  with  respect to Bear
Stearns, CalBear or a Significant Subsidiary of Bear Stearns; or

          (d)  any  representation  or  warranty  of  Bear  Stearns  or  CalBear
hereunder  proves to have been incorrect in any material  respect as of the date
such  representation or warranty was made; provided that a Bear Stearns Event of
Default shall not arise under this Section  16.5(d)  following the expiration of
the survival period with respect to such representation or warranty set forth in
Section 14.1.

   16.6   Termination;  Liquidation  Date;  Transfer of Final Third Party Master
Agreements.

          (a)  Termination  Prior to the Effective  Date.  This Agreement may be
terminated,  and the transactions  contemplated  hereby abandoned,  prior to the
Effective Date as follows:


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<PAGE>

               (i) by mutual consent of the Parties at any time;

               (ii) by Bear Stearns or CalBear,  on the one hand,  or Calpine or
the  Calpine  Transaction  Parties,  on the  other  hand,  upon  notice,  if the
Effective  Date shall not have occurred on or before  December 31, 2005,  except
that  neither  Bear  Stearns or  CalBear,  on the one hand,  nor  Calpine or the
Calpine Transaction  Parties, on the other hand, may terminate this Agreement if
the  failure of the  Effective  Date to occur is due to the  failure of any such
Party  or its  Affiliates  to  perform  in all  material  respects  each  of its
obligations  required to be  performed  under this  Agreement at or prior to the
Effective Date;

               (iii) by Bear  Stearns or CalBear,  upon notice to Calpine or the
Calpine  Transaction  Parties,  if an event or events  shall occur which  render
compliance  with  one or  more of the  conditions  set  forth  in  Article  XIII
impossible and such  condition (or  conditions) is not waived by Bear Stearns or
CalBear;  provided  that  neither  Bear  Stearns nor CalBear is in breach in any
material  respect of its  representations,  warranties,  covenants or agreements
contained in this Agreement; or

               (iv) by Calpine or the Calpine Transaction  Parties,  upon notice
to Bear  Stearns or CalBear,  if an event or events  shall  occur  which  render
compliance  with  one or  more  of the  conditions  set  forth  in  Article  XII
impossible,  and such condition (or  conditions) is not waived by Calpine or the
Calpine  Transaction  Parties,  provided  that none of  Calpine  or the  Calpine
Transaction Parties is in breach in any material respect of its representations,
warranties, covenants or agreements contained in this Agreement.

          (b)  Liquidation  Date and  Termination  Following the Effective Date.
Following  the  occurrence  of the  Effective  Date,  and,  subject to the other
provisions of this Agreement, this Agreement and the other Transaction Documents
shall be automatically terminated,  without any further action by any Party, and
the transactions  contemplated  hereby and thereby  abandoned,  immediately upon
completion of Liquidation.  The Liquidation Date shall occur and the Liquidation
shall commence:

               (i) as  determined  by mutual  consent of the Parties at any time
(provided  that if none of the Parties  delivers a Renewal  Notice in accordance
with  Section  16.2(a) of this  Agreement,  the Parties  shall be deemed to have
mutually  consented to a Liquidation Date  immediately  following the end of the
Initial Term or the applicable Renewal Period, as applicable);

               (ii) in  accordance  with  Section  16.2(d)  of  this  Agreement,
automatically upon the end of the Initial Term or the applicable Renewal Period,
as applicable,  if only Bear Stearns or CalBear,  on the one hand, or Calpine or
any  Calpine  Transaction  Party,  on the other hand,  but not both,  delivers a
Renewal  Notice  with  respect to the end of the  Initial  Term or such  Renewal
Period, as applicable;

               (iii)  following  the end of the Initial  Term,  ninety (90) days
after the delivery of a  Termination  Notice by any Party (or, in the event of a
delivery  of a  Termination  Notice by  Calpine  following  a breach of  Section
3.14(b) by Bear Stearns,  on the one hand, or by Bear Stearns following a breach


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<PAGE>

of Section 3.14(a) by Calpine, on the other hand, fifty (50) days after delivery
of such  Termination  Notice);  provided  that a  Termination  Notice may not be
delivered by any Party if the  Liquidation  Date has occurred or will occur as a
result of non-renewal of this Agreement or an Event of Default,  or otherwise in
accordance  with this Section  16.6(b) (and,  for the  avoidance of doubt,  if a
Liquidation  Date occurs before the end of the ninety (90) day period  following
the delivery of a Termination  Notice in accordance  with this Section  16.6(b),
Liquidation shall commence and this Agreement shall terminate in accordance with
such  Liquidation  Date and the  applicable  Termination  Notice  shall be of no
further force and effect); provided,  further, that, in the event of a breach of
Section 3.1 or Section 3.14 by Calpine or a Calpine  Transaction  Party,  on the
one hand,  or Bear  Stearns  or  CalBear,  on the other  hand,  Bear  Stearns or
CalBear,  on the one hand, or Calpine or any Calpine  Transaction  Party, on the
other  hand,  may  deliver  a  Termination   Notice  pursuant  to  this  Section
16.6(b)(iii)  at any time following the Effective  Date; and provided,  further,
that if Calpine or any  Calpine  Transaction  Party,  on the one hand,  and Bear
Stearns and  CalBear,  on the other hand,  deliver  Termination  Notices to each
other nearly simultaneously (and in such a manner that it is reasonably unlikely
that  either  Termination  Notice  was  sent  following  receipt  of  the  other
Termination Notice), the Liquidation Date shall occur ninety (90) days after the
delivery of such  Termination  Notices  pursuant to Section  16.6(b)(i)  and the
Parties  shall be deemed to have  mutually  consented to the  occurrence of such
Liquidation Date;

               (iv) upon a  Calpine  Event of  Default,  if so  elected  by Bear
Stearns or CalBear;

               (v)  upon a Bear  Stearns  Event of  Default,  if so  elected  by
Calpine or a Calpine Transaction Party;

               (vi)  automatically,  following a termination of any  Transaction
Document (other than this Agreement) by Calpine or a Calpine  Transaction  Party
in accordance with the terms thereof,  unless  otherwise  agreed by Calpine or a
Calpine Transaction Party prior to such time;

               (vii)  automatically,  following a termination of any Transaction
Document  (other than this  Agreement)  by Bear Stearns or CalBear in accordance
with the terms thereof, unless otherwise agreed by Bear Stearns or CalBear prior
to such time;

               (viii)  following a downgrade  of the credit  rating  assigned to
Bear  Stearns by (i) Standard & Poors  Ratings  Group below BBB+ or (ii) Moody's
Investor  Services  below Baa1, if terminated in writing by Calpine or a Calpine
Transaction Party; or

               (ix) by Bear Stearns or CalBear, following the end of the Initial
Term,  ninety  (90) days after the  delivery  of a  Termination  Notice,  if the
Trading  Volume for a calendar  year during the term of this  Agreement  is less
than [*]MWh.

          (c)  Conduct Of  Business  Following  Liquidation  Date;  Termination;
Survival Following Termination.


                                       65
<PAGE>

               (i)  Conduct  of   Business   Following   Liquidation   Date  and
Termination. Immediately following the occurrence of a Liquidation Date, (1) the
Liquidation  shall commence and (2) pending  completion of the  Liquidation  and
subject to Section  7.1(b) of the Agency and  Services  Agreement,  the  Parties
shall continue to have the benefit of, and be bound by, their applicable  rights
and obligations under the Transaction Documents. Following the Termination Date,
(i) Bear Stearns and CalBear shall,  or shall cause their  Affiliates to, change
the name of CalBear to another name not including the phrase  "CalBear" and (ii)
the  Parties  shall not,  and shall  cause  their  Affiliates  not to,  transact
business  under the name  "CalBear  Energy  LP",  "CalBear",  or any other  name
containing the word "CalBear" (the "CalBear  Name").  Without  limitation of the
foregoing,  as soon as practicable following the Termination Date, but not later
than ninety (90) days after such date, the Parties shall,  and shall cause their
respective  Affiliates  to,  remove and change  signage,  change and  substitute
promotional or advertising  material in whatever medium,  change  stationery and
packaging  and take all such other steps as may be required  or  appropriate  to
cease use of the CalBear Name; provided,  however, that no Party shall be deemed
to have violated this Section  16.6(c)(i) by reason of (i) the appearance of the
CalBear  Name in or on any  equipment,  manuals,  work  sheets,  risk  policies,
operating  procedures,  other written materials or other Assets of such Party or
its Affiliates  that are used for internal  purposes only in connection with the
Transaction  or  CalBear's  business;  provided  that  the  such  Party  and its
Affiliates shall endeavor to remove such appearances of the CalBear Name as soon
as  reasonably  practicable  in  the  ordinary  course  of  business,  (ii)  the
appearance  of  the  CalBear  Name  in or on  any  Third  Party's  publications,
marketing materials,  brochures,  instruction sheets, equipment or products that
any Party or its Affiliates distributed in the ordinary course of business or in
connection with the  Transaction or CalBear's  business prior to the Termination
Date, and that generally are in the public domain,  or any other similar uses by
any such Third Party over which such Party has no  control,  or (iii) the use by
any Party or its  Affiliates  of the CalBear  Name for  purposes of conveying to
customers  or the  general  public  that the name of CalBear  has changed or the
change in ownership or  historical  origins or  historical  business of CalBear,
including the use by any Party or its  Affiliates of the CalBear Name in (A) any
legally required disclosure,  (B) response to any disclosure request made by any
Governmental  Authority,  (C) connection  with the defense or prosecution of any
Action,  (D)  connection  with any reporting  requirements  of such Party or its
Affiliates under any Applicable Law, and (E) any financial statements, schedules
or information.

               (ii)  Survival  of  Certain  Obligations  Following  Termination.
Following the Termination  Date, all rights and obligations of the Parties under
this Agreement shall  terminate,  except for (i) rights and obligations  accrued
prior to the Termination Date,  including rights and obligations with respect to
a breach or violation of or default under any provision of this  Agreement  that
occurred  prior to the  Termination  Date (unless the  survival  period for such
right or obligation has otherwise expired pursuant to Section 14.1), (ii) rights
and  obligations  under  Articles IV, Article V, Article XV and Article XVII and
Sections 3.2, 3.5, 3.7, 3.8, 3.9, 3.10, 3.11, 3.16, 7.2, 7.4(a),  7.4(b),  14.1,
14.8, this Section  16.6(c),  Section 16.6(d) and Sections 18.1 through 18.4 and
18.6 through 18.20,  (iii) rights and obligations under other provisions of this
Agreement  to  the  extent  the  same  expressly  survive  termination  of  this
Agreement,  and (iv) rights and obligations  under  provisions of this Agreement
necessary  for the operation of effective  provisions  of the other  Transaction
Documents that reference such provisions in this Agreement.


                                       66
<PAGE>

          (d)  Transfer  of  Final  Third  Party  Master  Agreements   Following
Termination Date.

               (i)  Transfer of Final Third Party  Master  Agreements  Following
Non-Renewal.  In  the  event  that  the  Liquidation  Date  occurs  pursuant  to
16.6(b)(ii)  and Calpine and the Calpine  Transaction  Parties are the  Renewing
Parties, subject to clause (iv) below, the Renewing Parties shall have the right
(but not the obligation), exercisable within two (2) Business Days following the
date that the  applicable  Renewal Notice was due from CalBear,  to acquire,  or
cause any of their  respective  Affiliates to acquire,  for a purchase  price of
[*], the Third Party Master  Agreements to which CalBear is a party at such time
(collectively,  the "Final Third Party Master  Agreements"),  in accordance with
Section 16.6(d)(v)  (including the last sentence thereof),  following completion
of Liquidation (the "Non-Renewal Purchase Right"). Calpine or any of the Calpine
Transaction Parties may exercise the Non-Renewal  Purchase Right by delivering a
notice (the  "Non-Renewal  Purchase  Notice") to Bear Stearns or CalBear  within
such two (2) Business Day period,  in any applicable  manner provided in Section
18.2,  setting forth Calpine's or such Calpine  Transaction  Party's election to
exercise its  Non-Renewal  Purchase  Right.  For the avoidance of doubt,  in the
event that the Liquidation Date occurs pursuant to Section 16.6(b)(ii) after the
Non-Renewing  Parties  fail to deliver a Renewal  Notice and if Bear Stearns and
CalBear are the  Renewing  Parties,  Bear  Stearns and CalBear  shall retain the
Final Third Party Master  Agreements  following  completion of  Liquidation  and
Calpine  and the  Calpine  Transaction  Parties  shall  not  have  any  right to
purchase,  or any other right with  respect  to, the Final  Third  Party  Master
Agreements.

               (ii)  Transfer of Final Third Party Master  Agreements  Following
Elective Termination.  In the event that the Liquidation Date occurs pursuant to
Section  16.6(b)(iii)  or  Section   16.6(b)(ix),   following  delivery  of  the
Termination  Notice by an  Elective  Terminating  Party,  subject to clause (iv)
below,  the  Elective  Non-Terminating  Parties  shall  have the  right  and the
obligation  (the  "CalBear  Termination  Option"),  exercisable  within  two (2)
Business Days  following  such delivery of a Termination  Notice,  to (A) if the
Elective  Non-Terminating  Parties  are  Calpine  and  the  Calpine  Transaction
Parties, either (1) elect to acquire the Final Third Party Master Agreements, in
accordance with Section 16.6(d)(v)  (including the last sentence  thereof),  for
the amount set forth in the  applicable  Termination  Notice  (the  "Termination
Amount")  or (2) elect to receive a  termination  fee in an amount  equal to the
Termination Amount from CalBear (the "Termination  Fee"), or (B) if the Elective
Non-Terminating  Parties are Bear  Stearns and  CalBear,  to either (1) sell the
Final Third Party Master  Agreements,  in  accordance  with  Section  16.6(d)(v)
(including the last sentence thereof),  to the Elective  Terminating Parties for
the  Termination  Amount or (2)  elect to pay the  Termination  Fee to  Elective
Terminating Parties (either of clause (A)(1) or (B)(2), a "Termination  Purchase
Right" and either of clause (A)(2) or (B)(1),  a "Termination  Sale Right"),  in
each case  following  completion of  Liquidation.  Any Elective  Non-Terminating
Party shall exercise the CalBear  Termination  Option by delivering a notice, in
any manner provided in Section 18.2, setting forth such Elective Non-Terminating
Party's  election  to  exercise  either its  Termination  Purchase  Right or its
Termination Sale Right within the applicable two (2) Business Day period.

               (iii) Transfer of Final Third Party Master  Agreements  Following
Event of Default or Termination.  In the event that the Liquidation  Date occurs
pursuant to Section  16.6(b)(iv)  through (viii),  subject to clause (iv) below,


                                       67
<PAGE>

the  Defaulting   Termination   Parties  shall  deliver  to  the  Non-Defaulting
Termination  Parties,  within two (2) Business Days  following the occurrence of
the Liquidation  Date and in any manner provided in Section 18.2, an irrevocable
notice (the "Default Termination Notice") setting forth (A) a Termination Amount
and (B) a binding  offer,  irrevocable  by its terms for two (2)  Business  Days
following  receipt  of the  Default  Termination  Notice  by the  Non-Defaulting
Termination  Parties  (the  "CalBear  Default  Option"),  (1) if the  Defaulting
Termination Parties are Calpine and the Calpine  Transaction  Parties, to either
(x) purchase the Final Third Party Master Agreements, in accordance with Section
16.6(d)(v) (including the last sentence thereof),  from Bear Stearns and CalBear
for the  Termination  Amount or (y)  receive  from Bear  Stearns and CalBear the
Termination Fee, or (2) if the Defaulting  Termination  Parties are Bear Stearns
and  CalBear,  to either (x) sell the Final Third Party  Master  Agreements,  in
accordance with Section  16.6(d)(v)  (including the last sentence  thereof),  to
Calpine and the Calpine  Transaction  Parties for the Termination  Amount or (y)
pay to Calpine and the Calpine  Transaction  Parties the Termination Fee (either
of clause  (1)(x) or  (2)(y),  a "Default  Purchase  Right" and either of clause
(1)(y) or (2)(x), a "Default Sale Right"), in each case following  completion of
Liquidation.  Any of the Non-Defaulting  Termination  Parties shall exercise the
CalBear Default Option by delivering a notice, in the manner provided in Section
18.2, setting forth such Non-Defaulting Termination Party's election to exercise
either its Default  Purchase Right or its Default Sale Right within such two (2)
Business Day period. If the Defaulting  Termination  Parties are Calpine and the
Calpine Transaction  Parties and the Defaulting  Termination Parties fail to (A)
deliver the Default  Termination  Notice or (B) comply with their  obligation to
purchase Final Third Party Master Agreements  following  exercise of the Default
Sale Right by the Non-Defaulting  Termination Parties,  CalBear shall retain the
Final Third Party Master  Agreements  following  completion of  Liquidation  and
Calpine  and the  Calpine  Transaction  Parties  shall  not  have  any  right to
purchase,  or any other right with  respect  to, the Final  Third  Party  Master
Agreements.  If the Defaulting  Termination Parties are Bear Stearns and CalBear
and  the  Defaulting  Termination  Parties  fail  to  (A)  deliver  the  Default
Termination  Notice,  (B) comply with their obligation to sell Final Third Party
Master  Agreements  following  exercise  of the  Default  Purchase  Right by the
Non-Defaulting  Termination  Parties, or (C) comply with their obligation to pay
the  Termination  Fee  following  exercise  of the  Default  Sale  Right  by the
Non-Defaulting  Termination Parties, Calpine and the Calpine Transaction Parties
shall have the right (but not the obligation),  exercisable within ten (10) days
following  such  failure to comply,  to purchase  for [*], the Final Third Party
Master  Agreements,  in accordance with Section  16.6(d)(v)  (including the last
sentence thereof), following the completion of Liquidation.

               (iv) Payment of Termination  Amount.  Promptly following exercise
of the Termination  Purchase  Right,  the  Termination  Sale Right,  the Default
Purchase Right or the Default Sale Right, as applicable, the Parties responsible
for payment of the  Termination  Amount with respect to such exercise  shall pay
the Termination  Amount in cash by wire transfer of immediately  available funds
to an account  designated by (A) Calpine or a Calpine  Transaction Party, in the
case of a payment of the Termination  Amount by Bear Stearns or CalBear,  or (B)
Bear Stearns or CalBear,  in the case of a payment of the Termination  Amount by
Calpine or a Calpine Transaction Party.


                                       68
<PAGE>

               (v) Obligation to Transfer  Final Third Party Master  Agreements.
The Parties  shall  cooperate  with each other and take any  actions  reasonably
necessary to cause the  consummation of the  Non-Renewal  Purchase Right and, in
the event that the Termination  Purchase Right,  the Termination Sale Right, the
Default  Purchase  Right or the  Default  Sale Right  requires a transfer of the
Final  Third  Party  Master  Agreements,  the  consummation  of the  Termination
Purchase Right,  the Termination  Sale Right,  the Default Purchase Right or the
Default Sale Right,  as  applicable,  including by  cooperating in obtaining any
applicable  Regulatory  Approvals  and any Third  Party  consents  or  releases.
Notwithstanding  anything to the contrary  contained  in this  Section  16.6(d),
CalBear  shall not be  required to transfer  any Third  Party  Master  Agreement
pursuant  to  this  Section  16.6(d)  (A)  if and  until  Calpine  or a  Calpine
Transaction  Party has paid the  Termination  Amount in accordance  with Section
16.6(d)(iv) or (B) if such Third Party Master  Agreement (1) requires consent to
transfer  from a Third  Party and such  consent  has not been  received  by Bear
Stearns within one hundred eight (180) days following the exercise by Calpine or
any of the  Calpine  Transaction  Parties  of their  right to  purchase,  or the
exercise by Bear Stearns or CalBear of their right to sell, as  applicable,  the
Final Third Party Master Agreements pursuant to this Section 16.6(d) or (2) does
not provide for the  unconditional  release of Bear  Stearns and its  Affiliates
from any  obligation to guarantee or otherwise  provide  credit  support for any
transaction under such Third Party Master Agreement,  unless such  unconditional
release of such  obligation is received by Bear Stearns within one hundred eight
(180) days  following the exercise by Calpine or any of the Calpine  Transaction
Parties of their right to  purchase,  or the exercise by Bear Stearns or CalBear
of their right to sell, as applicable,  the Final Third Party Master  Agreements
pursuant to this  Section  16.6(d).  If CalBear is not  required to transfer any
Third  Party  Master  Agreement  as a result  of clause  (B) in the  immediately
preceding  sentence,  (x) each of Bear  Stearns and CalBear  shall not, and Bear
Stearns  shall cause its  Affiliates  not to,  following the  Termination  Date,
transact any business pursuant to such Third Party Master Agreement, (y) CalBear
shall,  following the expiration of any applicable consent and/or release period
set forth in the immediately  preceding sentence,  reasonably promptly terminate
such Third Party Master Agreement in accordance with the terms thereof (provided
that  CalBear  shall not be required to  terminate  any such Third Party  Master
Agreement  in a manner that  results in Damages owed by CalBear to a Third Party
under such Third Party Master Agreement),  and (z) CalBear shall deliver written
evidence of such termination to Calpine.

               (vi) Closing of Transfer of Final Third Party Master  Agreements.
The  purchase and sale of the Final Third Party  Master  Agreements,  if any, in
accordance  with this  Section  16.6(d)  pursuant to any  exercised  Non-Renewal
Purchase Right,  Termination  Purchase Right,  Termination  Sale Right,  Default
Purchase Right or Default Sale Right, as applicable, shall take place as soon as
reasonably practicable, but in any event following the completion of Liquidation
and the receipt of any applicable  Regulatory Approvals and Third Party consents
and releases.

                                 ARTICLE XVII.
                             LIMITATION OF LIABILITY

  17.1    Limitation of Remedies.


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<PAGE>

     NOTWITHSTANDING ANY PROVISION OF THE TRANSACTION DOCUMENTS TO THE CONTRARY,
THE RIGHTS,  REMEDIES,  CLAIMS AND DAMAGES OF CALPINE,  THE CALPINE  TRANSACTION
PARTIES AND THE OTHER CALPINE PARTIES,  AND BEAR STEARNS,  CALBEAR AND THE OTHER
BEAR STEARNS PARTIES  (COLLECTIVELY,  FOR THE PURPOSES OF THIS ARTICLE XVII, THE
"REMEDIAL  PARTIES"),  IN CONNECTION  WITH,  ARISING OUT OF,  RESULTING  FROM OR
RELATING  OR  INCIDENT  TO,  WHETHER  DIRECTLY OR  INDIRECTLY,  THE  TRANSACTION
DOCUMENTS,  PERFORMANCE OR NONPERFORMANCE UNDER THE TRANSACTION  DOCUMENTS,  ANY
CALPINE EVENT OF DEFAULT OR BEAR STEARNS EVENT OF DEFAULT,  ANY MATTER DESCRIBED
IN SECTION  15.1,  OR ANY OTHER RIGHT OR DUTY  RELATED TO ANY OF THE  FOREGOING,
WHETHER ARISING UNDER CONTACT, TORT, COMMON LAW, STATUTE OR AT LAW OR IN EQUITY,
OR RELATED TO ANY FAULT, NEGLIGENCE,  GROSS NEGLIGENCE,  STRICT LIABILITY, FRAUD
OR MISCONDUCT, SHALL BE LIMITED TO THE EXTENT SET FORTH IN THIS ARTICLE XVII (IN
ADDITION TO ANY OTHER APPLICABLE LIMITATIONS IN THE TRANSACTION DOCUMENTS).

  17.2    Limitation of Monetary Damages.

          (A)  THE  INDEMNIFICATION  RIGHTS  PROVIDED  TO THE  REMEDIAL  PARTIES
PURSUANT TO ARTICLE XV OF THIS  AGREEMENT AND SECTION 6.3 OF THE TRADING  MASTER
AGREEMENT,  (B) ANY LIQUIDATED DAMAGES EXPRESSLY PROVIDED FOR IN THE TRANSACTION
DOCUMENTS,  AND (C) ANY OTHER EXPRESS  RIGHTS TO RECEIVE  PAYMENT OR INTEREST IN
THE TRANSACTION DOCUMENTS;  SHALL BE THE SOLE AND EXCLUSIVE MONETARY REMEDIES OF
THE REMEDIAL PARTIES, IN LIEU OF ANY OTHER RIGHT TO MONETARY DAMAGES.

  17.3    Limitation of Non-Monetary Damages.

          IN THE  EVENT  THAT  MONETARY  REMEDIES  FOR  ANY  APPLICABLE  BREACH,
VIOLATION OR DAMAGE ARE NOT PROVIDED FOR IN SECTION 17.2, THE SOLE AND EXCLUSIVE
REMEDIES OF THE REMEDIAL  PARTIES SHALL BE (A) TERMINATION OF THIS AGREEMENT AND
THE TRANSACTION  DOCUMENTS PURSUANT TO THE APPLICABLE PROVISIONS OF SECTION 16.6
OF THIS  AGREEMENT  OR (B)  EQUITABLE  REMEDIES TO THE EXTENT  AVAILABLE  TO THE
APPLICABLE REMEDIAL PARTY UNDER THE CIRCUMSTANCES UNDER SECTION 18.15.

  17.4    Limitation of Consequential Damages, Etc.

          EXCEPT WITH RESPECT TO THIRD PARTY CLAIMS IN SECTION  15.1(a)(ii)  AND
SECTION  15.1(b)(ii)  OF THIS  AGREEMENT AND THE LAST SENTENCE OF SECTION 6.3 OF
THE TRADING MASTER  AGREEMENT,  NONE OF THE REMEDIAL PARTIES SHALL BE LIABLE FOR
OR ENTITLED TO ANY  CONSEQUENTIAL,  INDIRECT,  SPECIAL,  PUNITIVE,  EXEMPLARY OR
INCIDENTAL DAMAGES.


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<PAGE>

  17.5    Liability for Acts or Omissions of Other Persons.

          BEAR STEARNS OR CALBEAR  SHALL NOT BE DEEMED TO HAVE VIOLATED OR BE IN
BREACH OF ANY REPRESENTATION,  WARRANTY, COVENANT OR AGREEMENT CONTAINED IN THIS
AGREEMENT  OR IN ANY OF THE  OTHER  TRANSACTION  DOCUMENTS  TO THE  EXTENT  SUCH
VIOLATION  OR BREACH  RESULTS  FROM OR ARISES  OUT OF ANY ACT OF  CALPINE OR ANY
CALPINE  TRANSACTION  PARTY OR OMISSION  BY CALPINE OR ANY  CALPINE  TRANSACTION
PARTY,  IN EACH CASE  CONSTITUTING  A  VIOLATION  OR  BREACH OF THE  TRANSACTION
DOCUMENTS.  CALPINE OR ANY CALPINE TRANSACTION PARTY SHALL NOT BE DEEMED TO HAVE
VIOLATED OR BE IN BREACH OF ANY REPRESENTATION,  WARRANTY, COVENANT OR AGREEMENT
CONTAINED IN THIS AGREEMENT OR IN ANY OF THE OTHER TRANSACTION DOCUMENTS IF SUCH
VIOLATION  OR BREACH  RESULTS  FROM OR ARISES OUT OF ANY ACT OF BEAR  STEARNS OR
CALBEAR OR OMISSION  BY BEAR  STEARNS OR CALBEAR,  IN EACH CASE  CONSTITUTING  A
VIOLATION OR BREACH OF THE TRANSACTION DOCUMENTS.

  17.6    Survival of Limitations.

          THE  LIMITATIONS,  RELEASES,  WAIVERS AND  DISCLAIMERS OF REMEDIES AND
LIABILITIES  EXPRESSED IN THIS AGREEMENT SHALL SURVIVE TERMINATION OR EXPIRATION
OF THE TRANSACTION DOCUMENTS.

                                 ARTICLE XVIII.
                                  MISCELLANEOUS

    8.1   Assignment.  Except  as  provided  in Section  3.3 or Section  3.4, as
applicable,  neither  this  Agreement  nor  any of  the  rights  or  obligations
hereunder  may be assigned by Calpine or any Calpine  Transaction  Party without
the prior  consent of Bear  Stearns and  CalBear,  or by Bear Stearns or CalBear
without  the prior  consent  of  Calpine  and each  Calpine  Transaction  Party;
provided that in the event of an assignment by a Party of this Agreement and all
of its rights and  obligations  hereunder to an  Affiliate  of such Party,  such
consent shall not be unreasonably withheld. Except as provided in Section 3.3 or
Section 3.4, as applicable,  none of the  Transaction  Documents other than this
Agreement,  nor any of the rights or obligations thereunder,  may be assigned by
any Calpine  Transaction Party without the prior consent of Bear Stearns,  or by
CalBear  without the prior consent of Calpine;  provided that in the event of an
assignment by a  Transaction  Party of a  Transaction  Document  other than this
Agreement  and all of its rights and  obligations  thereunder to an Affiliate of
such Party,  such consent shall not be  unreasonably  withheld.  This  Agreement
shall be binding  upon and inure to the benefit of the Parties  hereto and their
respective  successors  and  assigns,  and no other Person shall have any right,
benefit or obligation  hereunder,  except as  specifically  set forth in Section
18.18 hereof.

  18.2    Notices.


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<PAGE>

          All  notices,   consents,   waivers,   requests,   demands  and  other
communications which are required or may be given under this Agreement and:

          (a) concern (i) modifications of this Agreement, including pursuant to
Section  18.8, or (ii) Article XV,  Article XVI (other than Section  16.4(a) and
Section  16.5(a)),  or Section 18.4,  shall be in writing and shall be deemed to
have been duly given in writing when  received if personally  delivered,  or, if
sent to the mailing  address set forth below with  respect to notices  delivered
pursuant to this  Section  18.2(a) for any Party,  the  Business Day after it is
sent,  if sent  for  next day  delivery  to a  domestic  address  by  recognized
overnight delivery service (e.g., Federal Express);

          (b)  concern  Payments  (other  than  communications  that  are  given
pursuant  to Section  18.2(a)  and also  concern  Payments),  including  Section
16.4(a) or Section 16.5(a), shall be in writing and shall be deemed to have been
duly given in writing when transmitted if transmitted (A) to CalBear by telecopy
to the notice  address set forth below for Bear  Stearns or CalBear with respect
to  notices  delivered  pursuant  to  this  Section  18.2(b)  or (B) to  CMSC by
electronic  mail (including in portable  document format by electronic  mail) to
the notice  address set forth below for Calpine or a Calpine  Transaction  Party
with respect to notices delivered pursuant to this Section 18.2(b); and

          (c) concern any matter not  specifically  addressed in Section 18.2(a)
or Section  18.2(b)  shall be in  writing  and shall be deemed to have been duly
given in writing  when  received  if  personally  delivered,  or, if sent to the
notice  address set forth below with  respect to notices  delivered  pursuant to
this  Section  18.2(c)  for  any  Party,  when  transmitted  if  transmitted  by
electronic mail (including in portable document format by electronic mail);

provided,  that, in the case of Section 18.2(b) and Section 18.2(c), if any such
communication  is  transmitted  by telecopy or electronic  mail, as  applicable,
after 4:30 p.m.  New York City time on any day,  or at any time on a day that is
not a Business Day, such communication  shall be deemed to have been transmitted
at 9:00 a.m. New York City time on the  following  Business  Day; and  provided,
further,  that, in the case of Section 18.2(b),  if the sender of the electronic
mails with respect to such communication  receives an "out-of-office" or similar
notice with respect  thereto from each  addressee  thereof,  such  communication
shall nonetheless be deemed to be duly given in writing; and provided,  further,
that,  in the case of Section  18.2(b)  (except as provided  in the  immediately
preceding  proviso) and Section  18.2(c),  if all telecopies or electronic mails
with respect to such  communication  are returned to the sender as undeliverable
or the sender  receives  an  "out-of-office"  or  similar  notice  with  respect
thereto, such transmission shall not be deemed to be duly given in writing until
(i)  delivered to an alternate  recipient in compliance  with the  provisions of
Section  18.2(b)  or  Section  18.2(c),  as  applicable,  or  (ii)  received  if
personally  delivered,  or, if sent to the applicable  mailing address set forth
below with  respect to notices  delivered  pursuant  Section  18.2(b) or Section
18.2(c),  as  applicable,  for any Party,  the Business Day after it is sent, if
sent for  next day  delivery  to a  domestic  address  by  recognized  overnight
delivery service (e.g., Federal Express).

          Communications  to Calpine or a Calpine  Transaction Party pursuant to
          Section 18.2(a) shall be addressed to:


                                       72
<PAGE>

               Calpine Corporation
               717 Texas Avenue
               Houston, TX 77002
               Tel: (713) 830-8649
               Fax: (713) 570-4725
               Attention: Andrew Slocum
               E-mail:  aslocum@calpine.com

          In each case, with a copy to:

               Calpine Corporation
               50 West San Fernando Street
               San Jose, CA 95113
               Tel: (408) 792-1226
               Fax: (408) 794-2434
               Attention: Lisa Bodensteiner, Executive Vice President and
                            General Counsel
               E-mail:  lisab@calpine.com

          and with a copy to:

--------------------------------------------------------------------------------
Paul Posoli                              Rodney Malcolm
Executive Vice President                 Senior Vice President
Calpine Corporation                      Calpine Corporation
717 Texas Avenue                         717 Texas Avenue
Houston, TX  77002                       Houston, TX  77002
Tel:  (713) 830-8663                     Tel:  (713) 570-4816
Fax: (713) 570-4725                      Fax: (713) 570-4725
E-mail:  paulp@calpine.com               E-mail:  rodneym@calpine.com
--------------------------------------------------------------------------------

          Communications  to Calpine or a Calpine  Transaction Party pursuant to
Section 18.2(b) shall be addressed to:


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<PAGE>

--------------------------------------------------------------------------------
Andrew Slocum                            Janet Dixon
Vice President Risk Operations           Calpine Merchant Services Company, Inc.
Calpine Merchant Services Company, Inc.  717 Texas Avenue
717 Texas Avenue                         Houston, TX 77002
Houston, TX 77002                        Tel: (713) 830-8835
Tel: (713) 830-8649                      Fax: (713) 570-4725
Fax: (713) 570-4725                      E-mail:  jdixon@calpine.com
E-mail:  aslocum@calpine.com
--------------------------------------------------------------------------------
Randy Kruger                             Josh Pesikoff
Calpine Merchant Services Company, Inc.  Calpine Merchant Services Company, Inc.
717 Texas Avenue                         717 Texas Avenue
Houston, TX 77002                        Houston, TX 77002
Tel: (713) 570-4811                      Tel: (713) 570-4782
Fax: (713) 570-4725                      Fax: (713) 570-4725
E-mail:  rkruger@calpine.com             E-mail:  jpesikoff@calpine.com
--------------------------------------------------------------------------------


          Communications  to Calpine or a Calpine  Transaction Party pursuant to
Section 18.2(c) shall be addressed to:

--------------------------------------------------------------------------------
Paul Posoli                              Rodney Malcolm
Executive Vice President                 Senior Vice President
Calpine Corporation                      Calpine Corporation
717 Texas Avenue                         717 Texas Avenue
Houston, TX  77002                       Houston, TX  77002
Tel:  (713) 830-8663                     Tel:  (713) 570-4816
Fax: (713) 570-4725                      Fax: (713) 570-4725
E-mail:  paulp@calpine.com               E-mail:  rodneym@calpine.com
--------------------------------------------------------------------------------
Lisa Bodensteiner
Executive Vice President and
General Counsel
Calpine Corporation
50 West San Fernando Street
San Jose, CA 95113
Tel: (408) 792-1226
Fax: (408) 794-2434
E-mail:  lisab@calpine.com
--------------------------------------------------------------------------------


          Communications  to Bear Stearns or CalBear pursuant to Section 18.2(a)
shall be addressed to:

               The Bear Stearns Companies Inc.
               383 Madison Avenue


                                       74
<PAGE>

               New York, NY  10179
               Tel: (212) 272-4653
               Fax: (212) 272-8976
               Attention:  Andrew Kittell
               E-mail:  akittell@bear.com

          and with a copy to:

               The Bear Stearns Companies Inc.
               383 Madison Avenue
               New York, NY  10179
               Tel: (212) 272-7850
               Fax: (917) 849-1072
               Attention:  Michael Solender, General Counsel
               E-mail:  msolender@bear.com

          and with a copy to:

               Latham & Watkins LLP
               885 Third Avenue
               Suite 1000
               New York, NY  10022
               Tel:(212) 906-1200
               Fax:(212) 751-4864
               Attention:  Steven Della Rocca
               E-mail:  steven.della.rocca@lw.com

          and with a copy to:

--------------------------------------------------------------------------------
Francis Dunleavy                         Eli Wachtel
Senior Managing Director                 Senior Managing Director
Bear, Stearns & Co. Inc.                 Bear, Stearns & Co. Inc.
383 Madison Avenue                       383 Madison Avenue
New York, NY  10179                      New York, NY  10179
Tel: (212) 272-5141                      Tel: (212) 272-4808
Fax: (212) 272-8976                      Fax: (212) 272-5681
E-mail:  fdunleavy@bear.com              E-mail:  ewachtel@bear.com
--------------------------------------------------------------------------------


          Communications  to Bear Stearns or CalBear pursuant to Section 18.2(b)
shall be addressed to:

--------------------------------------------------------------------------------
Bill Hamilton                            Chip Steppacher
Bear, Stearns & Co. Inc.                 Bear, Stearns & Co. Inc.
383 Madison Avenue                       383 Madison Avenue
New York, NY  10179                      New York, NY  10179


                                       75
<PAGE>

Tel: (212) 272-6918                      Tel: (212) 272-2050
Fax: (212) 272-5921                      Fax: (212) 272-5921
E-mail:  whamilton@bear.com              E-mail:  csteppacher@bear.com
--------------------------------------------------------------------------------
Andrew Kittell                           Brian Anast
Bear, Stearns & Co. Inc.                 Bear, Stearns & Co. Inc.
383 Madison Avenue                       383 Madison Avenue
New York, NY  10179                      New York, NY  10179
Tel: (212) 272-4653                      Tel: (212) 272-4654
Fax: (212) 272-8976                      Fax: (212) 272-8976
E-mail:  akittell@bear.com               E-mail:  banast@bear.com
--------------------------------------------------------------------------------
Kristen Reifsnyder
Bear, Stearns & Co. Inc.
383 Madison Avenue
New York, NY  10179
Tel: (212) 272-6417
Fax: (212) 272-8888
E-mail:  kreifsnyder@bear.com
--------------------------------------------------------------------------------


          Communications  to Bear Stearns or CalBear pursuant to Section 18.2(c)
shall be addressed to:

--------------------------------------------------------------------------------
Francis Dunleavy                         Eli Wachtel
Senior Managing Director                 Senior Managing Director
Bear, Stearns & Co. Inc.                 Bear, Stearns & Co. Inc.
383 Madison Avenue                       383 Madison Avenue
New York, NY  10179                      New York, NY  10179
Tel: (212) 272-5141                      Tel: (212) 272-4808
Fax: (212) 272-8976                      Fax: (212) 272-5681
E-mail:  fdunleavy@bear.com              E-mail:  ewachtel@bear.com

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

or, in each case, to such other place and with such other copies as any Party
may designate as to itself and its Representatives by notice to the other
Parties that are not Affiliates of such Party.

  18.3    Choice of Law; Service of Process; Venue; Jury Trial Waiver.

          (a) Each of the  Parties  agrees that this  Agreement  and each of the
other  Transaction  Documents  to which it is a party  (including  any  claim or
controversy  arising  out  of or  relating  to  this  Agreement  or  such  other
Transaction  Document)  shall be construed and interpreted and the rights of the
Parties determined in accordance with the internal laws of the State of New York
without giving effect to any choice or conflict of law  provision,  principle or
rule  (whether  of the State of New York or any other  jurisdiction)  that would
cause the  application of the laws of any  jurisdiction  other than the State of
New York. Each of the Parties irrevocably consents to the service of any and all


                                       76
<PAGE>

process in any Action  arising out of or relating to this  Agreement,  the other
Transaction  Documents to which it is a party or the  transactions  contemplated
hereby or  thereby  by the  registered  or  certified  mailing of copies of such
process to the addresses of such Party  specified in Section  18.2.  Each of the
Parties consents and voluntarily  submits to personal  jurisdiction in the State
of New York and in the courts in such state  located in New York  County and the
United  States  District  Court  for the  Southern  District  of New York in any
proceedings arising out of or relating to this Agreement,  the other Transaction
Documents to which it is a party and the  transactions  contemplated  hereby and
thereby and,  subject to the  arbitration  provisions  set out in Section  18.4,
agrees  that all  claims  in  respect  of any such  proceeding  may be heard and
determined in any such court and that all claims  shall,  in respect of any such
proceeding, be brought, prior to appeal beyond such courts, in such courts. Each
Party  irrevocably  and  unconditionally  waives and agrees not to plead, to the
fullest  extent  permitted by law, any objection  that they may now or hereafter
have to the laying of venue or the  convenience  of the forum of any Action with
respect to this  Agreement,  the other  Transaction  Documents  to which it is a
party and the transactions contemplated hereby and thereby, in the United States
District Court for the Southern District of New York and the courts of the State
of New York located in New York County. Each Party agrees that a final judgment,
subject to appeal  rights,  in any proceeding so brought shall be conclusive and
may be  enforced  by suit on the  judgment  in any court or in any other  manner
provided by law or in equity.

          (b) Subject to the  arbitration  provisions  set out in Section  18.4,
each of the Parties agrees to commence any proceeding arising out of or relating
to this Agreement, the other Transaction Documents to which it is a party or the
transactions  contemplated hereby or thereby in the United States District Court
for the  Southern  District  of New York or the  courts of the State of New York
located in New York  County and that any  claims  shall,  in respect of any such
proceeding, initially be brought in such courts.

          (c) EACH OF THE PARTIES HERETO HEREBY  IRREVOCABLY  WAIVES ANY AND ALL
RIGHT TO TRIAL BY JURY IN ANY LEGAL PROCEEDING ARISING OUT OF OR RELATED TO THIS
AGREEMENT,  THE  OTHER  TRANSACTION  DOCUMENTS  TO WHICH  IT IS A PARTY,  OR THE
TRANSACTIONS CONTEMPLATED HEREBY OR THEREBY.

  18.4    Dispute Resolution; Arbitration.

          (a) In an effort to resolve  informally  and  amicably  any dispute or
Action that might  arise  between  the  Parties or their  respective  Affiliates
hereunder  or under  any of the other  Transaction  Documents,  Calpine  or Bear
Stearns  may by  providing  notice to the other  refer any matter in dispute for
resolution to Paul J. Posoli and Francis Dunleavy, respectively. Calpine or Bear
Stearns may change the designation of the applicable  aforementioned  individual
established  by the  previous  sentence  by notice to Bear  Stearns or  Calpine,
respectively.  If settlement  is not  thereafter  reached  through their efforts
within twenty (20) days following  such referral,  or such longer time period as
the Parties may agree,  then any Party may initiate  arbitration  proceedings as
set forth below to resolve the matter.


                                       77
<PAGE>

          (b) Each of the Parties agrees that,  notwithstanding  anything herein
to the  contrary,  any  dispute or Action not  otherwise  resolved  pursuant  to
Section  18.4(a)  shall  be  resolved  by  binding  arbitration  proceedings  in
accordance  with this Section 18.4.  Any dispute not  otherwise  resolved may be
submitted for arbitration hereunder by any Party delivering to the other Parties
that are not its  Affiliates a notice  demanding  arbitration  of the dispute in
accordance  with the commercial  arbitration  rules of the American  Arbitration
Association  ("AAA") then in effect.  To the extent that such provisions are not
inconsistent  with such rules,  the  remaining  provisions  of this Section 18.4
shall also apply to such proceedings.

          (c) Each of  Calpine  and Bear  Stearns,  within  thirty  (30) days of
delivery of the notice demanding arbitration,  shall select an arbitrator (each,
a "Party Arbitrator"). The Party Arbitrators shall select, within ten (10) days,
one neutral arbitrator,  who shall serve as the Chairman ("Chairman")  (together
with  the  Party  Arbitrators,  the  "Arbitration  Panel").  In the  absence  of
agreement  between the Party  Arbitrators  on  selection  of the  Chairman,  the
Chairman shall be selected by the AAA.

          (d) No member of the  Arbitration  Panel may have a direct or indirect
interest in any Party or the subject of the  arbitration;  provided however that
each of Calpine and Bear Stearns may  communicate  ex parte with its  respective
Party Arbitrator, but not the Chairman.

          (e) The place of the arbitration shall be a place mutually agreed upon
by the Parties at a site chosen by the  Arbitration  Panel or, in the absence of
agreement  among  the  Arbitration  Panel,  at a site  chosen  by the  Chairman;
provided,  however,  that if the Parties are not able to mutually agree upon the
place of arbitration, such place shall be New York, New York.

          (f) The  Arbitration  Panel shall determine the rules of procedure or,
in the absence of agreement  among the Arbitration  Panel,  the Federal Rules of
Civil Procedure shall govern the procedure for discovery as well as presentation
of the  evidence.  In any event,  the  Arbitration  Panel or, in the  absence of
agreement among the  Arbitration  Panel,  the Chairman,  shall have the right to
impose reasonable restrictions on the taking of discovery, including limitations
on the number of and length of depositions of witnesses.

          (g) The Arbitration  Panel shall render a reasoned decision in writing
within  thirty (30) days of the close of evidence.  Any award issued as a result
of such  arbitration  shall be final and binding between the parties thereto and
judgment upon the award rendered by the  arbitration  panel may be entered,  and
shall be enforceable, by any Governmental Authority having jurisdiction over the
party against whom enforcement is sought.

          (h) During the course of the arbitration, each Party shall pay its and
its Affiliates' own fees,  costs and expenses  (including  attorneys'  fees) and
Calpine,  on the one hand, and Bear Stearns,  on the other hand,  shall each pay
one-half of any fees,  costs and expenses of the  Arbitration  Panel;  provided,
however that the  Arbitration  Panel shall in no way award damages for any Claim
of a type  that are not  permitted  for such  Claim  under  New York law and the
provisions of the  Transaction  Documents or that exceed the limits,  if any, on
damages  afforded  by New  York  law  and  the  provisions  of  the  Transaction
Documents, particularly Article XVII.


                                       78
<PAGE>

          (i) Calpine and Bear  Stearns may mutually  agree,  each in their sole
discretion, to reduce any time periods specified in this Section 18.4 to resolve
any dispute or controversy on an expedited basis.

    18.5  Continued  Performance.  Each of the Parties agrees that it shall, and
shall cause each of its Affiliates that is a Party to, continue to perform under
this Agreement and the other Transaction Documents to which it is a party during
the  pendency  of  any  dispute,   arbitration  or  other  Action  hereunder  or
thereunder.  For the avoidance of doubt,  this Section 18.5 shall not prevent or
restrict the termination of, or limit the right of any Party to terminate or the
effect of the termination of, this Agreement or any other  Transaction  Document
in accordance with the terms hereof or thereof.

    18.6  Regulatory  Event.  Any  provision  of  this  Agreement  or the  other
Transaction   Documents  declared  or  rendered  unlawful  by  any  Governmental
Authority  or deemed  unlawful  because of a statutory or  regulatory  change or
interpretation  (individually  or  collectively,  such  events  referred to as a
"Regulatory  Event") will not otherwise affect the remaining lawful  obligations
that arise under this Agreement and the other Transaction Documents. Further, if
a Regulatory Event occurs, the Parties shall use their  commercially  reasonable
efforts  to modify  this  Agreement  and the  other  Transaction  Documents,  as
applicable,  in order to give effect to the original intention of the Parties in
a manner consistent with the Regulatory Event.

    18.7  Forward Contracts.  The Parties acknowledge and agree that all CalBear
Trades,  other than CalBear Trades with a maturity date less than two days after
the date the CalBear Trade is executed,  constitute  "forward  contracts" within
the meaning of the United States  Bankruptcy  Code. The Parties  acknowledge and
agree that CalBear is a "forward  contract  merchant"  within the meaning of the
United States Bankruptcy Code.

    18.8  Effectiveness;   Entire  Agreement;   Amendments  and  Waivers.   This
Agreement  shall  become  binding  upon each  Party  hereto  when such Party has
executed and delivered  this  Agreement.  This  Agreement,  and all exhibits and
schedules hereto,  constitutes the entire agreement among the Parties pertaining
to  the   subject   matter   hereof  and   supersedes   all  prior   agreements,
understandings,  negotiations and discussions,  whether oral or written,  of the
Parties; provided that the forms of agreements attached hereto as exhibits shall
be  superseded  by the copies of such  agreements  executed and delivered by the
respective parties thereto, the execution and delivery of such agreements by the
parties  thereto to be  conclusive  evidence  of such  parties'  approval of any
modification therein. Except as otherwise expressly set forth in this Agreement,
no amendment,  supplement,  waiver or other modification of this Agreement shall
be  binding  unless  agreed in  writing  by each  Party  hereto  indicating  its
intention to modify this  Agreement;  provided  that any waiver of a right under
this  Agreement  shall be binding if agreed in writing by the Party against whom
enforcement  of such waiver is sought.  Neither the failure nor any delay by any
Party in exercising  any right,  power or privilege  under this Agreement or the
other  Transaction  Documents  will  operate as a waiver of any right,  power or
privilege under this Agreement or the other Transaction Documents, and no waiver
of any of the  provisions of this Agreement or the other  Transaction  Documents
shall be deemed or shall  constitute a waiver of any other  provision  hereof or
thereof (whether or not similar),  nor shall such waiver constitute a continuing
waiver  unless  otherwise  expressly  provided in such waiver.  In addition,  no


                                       79
<PAGE>

notice to or demand on one Party  will be deemed a waiver of any  obligation  of
such  Party or of the right of the Party  giving  such  notice or demand to take
further  action  without  notice or demand as provided in this  Agreement or the
other Transaction Documents. Notwithstanding the foregoing, (a) Bear Stearns, in
its sole  discretion,  may modify  Schedule  3.7(a) in  accordance  with Section
3.7(a), and (b) Calpine,  in its sole discretion,  may modify Schedule 3.8(a) in
accordance with Section 3.8(a).

    8.9   Multiple  Counterparts.  This Agreement may be executed in one or more
counterparts,  each of  which  shall be  deemed  an  original,  but all of which
together shall  constitute one and the same  instrument.  This Agreement and the
signature  pages  hereto may be  delivered  by telecopy or other  electronic  or
digital transmission method.

   18.10  Invalidity.  In  addition to, and  not in limitation of, Section 18.6,
in the event that any one or more of the provisions  contained in this Agreement
or in any other instrument referred to herein, shall, for any reason, be held to
be invalid,  illegal or unenforceable in any respect, then to the maximum extent
permitted by law,  such  invalidity,  illegality or  unenforceability  shall not
affect any other provision of this Agreement or any other such instrument.

    8.11  Titles; Currency;  Schedules. The  titles, captions or headings of the
Articles and Sections  herein are inserted for convenience of reference only and
are not intended to be a part of or to affect the meaning or  interpretation  of
this Agreement.  Unless otherwise  specified,  all references  contained in this
Agreement  or in any other  Transaction  Document  to  dollars  or "$" will mean
United  States  Dollars.  Disclosure  of any item in any section or part of this
Agreement or the schedules hereto will not constitute disclosure of such item in
any other section or part of this Agreement or the schedules hereto,  whether or
not the  existence of the item or its  contents  should be or is relevant to any
other section or part of this Agreement or the schedules,  unless such relevance
is reasonably apparent on its face.

   18.12  Payments. Unless otherwise  specified, all Payment due pursuant to the
terms of this Agreement shall be due by 4:00 p.m. New York City time on the date
they are due pursuant to the terms hereof.

   18.13  Publicity.  No  Party shall, and each Party shall cause its Affiliates
and  their  Representatives  not to,  issue  any  press  release  regarding  the
transactions  contemplated  hereby  or by the  other  Transaction  Documents  or
consummated  hereunder or thereunder  without the prior approval of, in the case
of Calpine or any Calpine  Transaction  Party, Bear Stearns,  and in the case of
Bear  Stearns  or  CalBear,  Calpine,  in  each  case  such  approval  not to be
unreasonably  withheld.  Notwithstanding the foregoing,  nothing herein shall be
deemed to prohibit any Party from making any disclosure  which its counsel deems
reasonably  necessary in order to fulfill such  Party's  disclosure  obligations
imposed by Applicable  Law;  provided that each such Party shall,  to the extent
reasonably  practicable,   afford,  in  the  case  of  Calpine  or  any  Calpine
Transaction  Party,  Bear  Stearns,  or in the case of Bear  Stearns or CalBear,
Calpine,  the  opportunity  to review and comment on the proposed  disclosure in
advance of such issuance;  provided,  further,  that in the event that it is not
reasonably  practicable,  such Party shall  provide Bear Stearns or Calpine,  as


                                       80
<PAGE>

applicable, a copy promptly thereafter.  Reference is made to Section 3.5(b) for
other agreements with respect to press releases.

  18.14   Fees and Expenses.

          (a) Calpine.  Subject to the provisions of Article XV and Section 18.4
hereof, unless otherwise specifically provided in this Agreement or in any other
Transaction Document,  Calpine and the Calpine Transaction Parties shall pay all
of the fees, costs and expenses  incurred by Calpine or any Calpine  Transaction
Party incident to or in connection with the negotiation,  preparation, execution
and delivery of this Agreement.

          (b) Bear Stearns.  Subject to the provisions of Article XV and Section
18.4 hereof, unless otherwise  specifically provided in this Agreement or in any
other Transaction Document,  Bear Stearns and CalBear shall pay all of the fees,
costs and  expenses  incurred  by Bear  Stearns  or  CalBear  incident  to or in
connection  with the  negotiation,  preparation,  execution and delivery of this
Agreement.

   18.15  Specific  Performance; Remedies Cumulative. In the event of any actual
or  threatened  default  in, or breach  of,  any of the  terms,  conditions  and
provisions of this Agreement or the other Transaction Documents (other than Soft
Covenants),  any Party who is or is to be thereby  aggrieved will have the right
of specific  performance and injunctive relief giving effect to its rights under
this Agreement and the other  Transaction  Documents to the extent  permitted by
Applicable  Law.  Except as otherwise set forth herein,  all rights and remedies
under this Agreement and the other Transaction Documents will be cumulative, and
the exercise of one or more rights or remedies shall not prejudice or impair the
concurrent or subsequent exercise of other rights or remedies.

   18.16  Representation  of  Counsel;  Mutual Negotiation.  Each Party has been
represented  by  counsel  of its  choice in  negotiating  this  Agreement.  This
Agreement  shall therefore be deemed to have been negotiated and prepared at the
request,  direction and  construction  of each of the Parties,  at arm's length,
with the  advice  and  participation  of  counsel,  and will be  interpreted  in
accordance with its terms without favor to any Party.

   18.17  Knowledge.  Whenever  used  in   this  Agreement  or  any  Transaction
Documents,  "to the  knowledge  of" or a similar  phrase  shall  mean the actual
knowledge of (i) if a specified individual or individuals are referred to in any
provision of this Agreement or any  Transaction  Documents,  such  individual or
individuals,  or (ii) if no such individual or individuals are specified, any of
the individual  Representatives of the applicable Party or its Affiliates listed
on Schedule  18.17, in each case after such  individuals  undertook a reasonable
investigation.

   18.18  No Third Party  Beneficiaries.  This  Agreement  shall be binding upon
and inure  solely to the benefit of each Party,  and nothing in this  Agreement,
express or implied,  is intended  to or shall  confer upon any other  Person any
legal or equitable right, benefit or remedy of any nature whatsoever under or by
reason  of  this  Agreement,   including  by  way  of  subrogation,   except  as
specifically set forth in Article XV hereof.


                                       81
<PAGE>

   18.19  Time of Essence.  With regard to  all dates and time periods set forth
or referred to in this Agreement, time is of the essence.

   18.20  Force  Majeure.  In  the event of a Force  Majeure  with  respect to a
Party,  if such Party gives notice and details of the Force Majeure to the other
Party or Parties to whom  performance is owed as soon as  practicable,  then the
Party  claiming the Force Majeure shall be excused from the  performance  of its
obligations to the extent and for the period affected by the Force Majeure.  The
Party   claiming  the  Force  Majeure  shall  remedy  the  Force  Majeure  in  a
commercially reasonable manner as promptly as possible.

                            [signature page follows]



                                       82
<PAGE>









          IN WITNESS WHEREOF,  the Parties have caused this Agreement to be duly
executed on their respective behalf, by their respective officers thereunto duly
authorized, all as of the day and year first above written.

                               CALPINE CORPORATION


                               By:   /s/ ERIC PRYOR

                               Name:  Eric Pryor
                                      ------------------------------------------
                               Title: Executive Vice President
                                      ------------------------------------------


                               CALPINE ENERGY SERVICES, L.P.


                               By:    /s/ PAUL POSOLI

                               Name:  Paul Posoli
                                      ------------------------------------------
                               Title: President
                                      ------------------------------------------


                               THE BEAR STEARNS COMPANIES INC.


                               By:    /s/ WARREN J. SPECTOR

                               Name:  Warren J. Spector
                                      ------------------------------------------
                               Title: President, Co-Chief Operating Officer
                                      and Director
                                      ------------------------------------------






<PAGE>

















                                    EXHIBITS

                                     TO THE

                          MASTER TRANSACTION AGREEMENT




<PAGE>






                                    Exhibit A
                                    ---------

                      Form of Agency and Services Agreement







<PAGE>






                                    Exhibit B
                                    ---------

                        Form of Trading Master Agreement







<PAGE>






                                    Exhibit C
                                    ---------

                        Organizational Documents of CMSC







<PAGE>






                                    Exhibit D
                                    ---------

                       Organizational Documents of CalBear





<PAGE>




                                    Exhibit E
                                    ---------

                     Form of CMSC and CalBear Signature Page

                                 SIGNATURE PAGE
                                     TO THE
                          MASTER TRANSACTION AGREEMENT

          By execution of this signature page, each of Calpine Merchant Services
Company, Inc., a Delaware corporation ("CMSC") and CalBear Energy LP, a Delaware
limited  partnership  ("CalBear"),  in  accordance  with the terms of the Master
Transaction  Agreement (as defined  below),  in  consideration  of the premises,
mutual covenants and promises contained in the Master Transaction Agreement, and
for other good and valuable consideration, the receipt and adequacy of which are
hereby  acknowledged,  hereby  agrees  to  become  party  to, to be bound by the
obligations of, and to receive the benefits of, that certain Master  Transaction
Agreement,  dated as of September 7, 2005, by and among Calpine  Corporation,  a
Delaware  corporation,   Calpine  Energy  Services,  L.P.,  a  Delaware  limited
partnership,  and The Bear Stearns  Companies Inc., a Delaware  corporation,  as
modified from time to time thereafter (the "Master Transaction Agreement"),  and
each of CMSC and  CalBear  acknowledges  and  agrees  that it shall be "CMSC" or
"CalBear",  respectively,  and a "Party",  in each case as defined in the Master
Transaction Agreement, for all purposes thereunder.


Dated: [________], 2005


                            [signature page follows]



<PAGE>



                                      CALPINE MERCHANT SERVICES COMPANY, INC.,
                                      a Delaware corporation



                                      By:_______________________________
                                         Name:
                                         Title:


                                      CALBEAR ENERGY LP, a Delaware limited
                                      partnership

                                      By: [________]
                                      Its: General Partner

                                          By: [________]
                                          Its: Managing Member


                                          By:_______________________________
                                             Name:
                                             Title:






<PAGE>


                                    Exhibit F
                                    ---------

                             Form of Renewal Notice

                                 RENEWAL NOTICE
                           PURSUANT TO SECTION 16.2(A)
                                     OF THE
                          MASTER TRANSACTION AGREEMENT

          [NAME OF PARTY], together with its Affiliates that are Parties to that
certain  Master  Transaction  Agreement (as defined  below) hereby  deliver this
Renewal Notice to [BEAR STEARNS OR CALPINE,  AS APPLICABLE] and renew the Master
Transaction  Agreement  pursuant  to Section  16.2(a) of the Master  Transaction
Agreement, for [each of] the Renewal Period(s) commencing:

          [August 31, [____], [____] and [____];]

          [November 30, [____], [____] and [____];]

          [February 28 (or  February  29, in the event of a leap year),  [____],
[____] and [____]; and]

          [May 31, [____],  [____] and [____].]
until the end of [the last] such Renewal Period.

          Capitalized  terms used but not defined in this  Renewal  Notice shall
have the meaning  given to them in that certain  Master  Transaction  Agreement,
dated as of  September 7, 2005,  by and among  Calpine  Corporation,  a Delaware
corporation,  Calpine Energy Services, L.P., a Delaware limited partnership, and
The Bear Stearns Companies Inc., a Delaware  corporation,  as modified from time
to time thereafter (the "Master Transaction Agreement").

Dated: [________]

                                      [NAME OF PARTY], a [TYPE OF ENTITY]



                                      By:_______________________________
                                         Name:
                                         Title:




<PAGE>

















                                    SCHEDULES

                                     TO THE

                          MASTER TRANSACTION AGREEMENT






<PAGE>




                                 Schedule 1.1(a)
                                 ---------------

                           Calpine Existing Indentures


1.   Indenture,  dated  as of  May  16,  1996,  as  supplemented  by  the  First
     Supplemental  Indenture,  dated  as of  August  1,  2000,  and  the  Second
     Supplemental Indenture, dated as of April 26, 2004, between the Company and
     State Street Bank and Trust Company (as successor to Fleet National  Bank),
     as Trustee,  relating to $180,000,000 in aggregate  principal amount of the
     Company's 10-1/2% Senior Notes due 2006.

2.   Indenture,  dated  as of  July  8,  1997,  as  supplemented  by  the  First
     Supplemental  Indenture,  dated  as  of  September  10,  1997,  the  Second
     Supplemental  Indenture,   dated  as  of  July  31,  2000,  and  the  Third
     Supplemental Indenture, dated as of April 26, 2004, between the Company and
     The Bank of New York,  as Trustee,  relating to  $275,000,000  in aggregate
     principal amount of the Company's 8-3/4% Senior Notes due 2007.

3.   Indenture,  dated  as of March  31,  1998,  as  supplemented  by the  First
     Supplemental Indenture,  dated as of July 24, 1998, the Second Supplemental
     Indenture, dated as of July 31, 2000, and the Third Supplemental Indenture,
     dated as of April 26,  2004,  between the Company and The Bank of New York,
     as Trustee,  relating to $400,000,000 in aggregate  principal amount of the
     Company's 7-7/8% Senior Notes due 2008.

4.   Indenture,  dated  as of March  29,  1999,  as  supplemented  by the  First
     Supplemental  Indenture,  dated  as  of  July  31,  2000,  and  the  Second
     Supplemental Indenture, dated as of April 26, 2004, between the Company and
     The Bank of New York,  as Trustee,  relating to  $250,000,000  in aggregate
     principal amount of the Company's 7-5/8% Senior Notes due 2006.

5.   Indenture,  dated  as of March  29,  1999,  as  supplemented  by the  First
     Supplemental  Indenture,  dated  as  of  July  31,  2000,  and  the  Second
     Supplemental Indenture, dated as of April 26, 2004, between the Company and
     The Bank of New York,  as Trustee,  relating to  $350,000,000  in aggregate
     principal amount of the Company's 7-3/4% Senior Notes due 2009.


<PAGE>

6.   Indenture,  dated as of  August  10,  2000,  as  supplemented  by the First
     Supplemental  Indenture,  dated as of  September  28,  2000 and the  Second
     Supplemental Indenture, dated as of September 30, 2004, between the Company
     and  Wilmington  Trust Company,  as Trustee,  relating to  $250,000,000  in
     aggregate  principal  amount of the Company's 8-1/4% Senior Notes due 2005,
     $750,000,000 in aggregate  principal  amount of the Company's 8-5/8% Senior
     Notes  due  2010,  $2,000,000,000  in  aggregate  principal  amount  of the
     Company's  8-1/2%  Senior  Notes  due  2011,  $1,200,000,000  in  aggregate
     principal amount of the Company's 4% Convertible  Senior Notes due 2006 and
     $725,000,000  in aggregate  principal  amount of the  Company's  Contingent
     Convertible Notes due 2014.

7.   Amended and Restated  Indenture,  dated as of March 12,  2004,  between the
     Company and Wilmington Trust Company, as Trustee,  relating to $900,000,000
     in aggregate  principal  amount of the Company's  4.75%  Contingent  Senior
     Notes due 2023.

8.   Indenture,  dated as of July 16, 2003,  between the Company and  Wilmington
     Trust Company, as Trustee,  relating to $500,000,000 in aggregate principal
     amount of the Company's  Second Priority Senior Secured Floating Rate Notes
     due 2007.

9.   Indenture,  dated as of July 16, 2003,  between the Company and  Wilmington
     Trust  Company,  as  Trustee,   relating  to  $1,150,000,000  in  aggregate
     principal  amount of the Company's  8.500% Second  Priority  Senior Secured
     Notes due 2010.

10.  Indenture,  dated as of July 16, 2003,  between the Company and  Wilmington
     Trust  Company,  as  Trustee,   relating  to  $1,150,000,000  in  aggregate
     principal  amount of the Company's  8.750% Second  Priority  Senior Secured
     Notes due 2013.

11.  Indenture,  dated  as  of  November  18,  2003,  between  the  Company  and
     Wilmington Trust Company, as Trustee, relating to $400,000,000 in aggregate
     principal  amount of the Company's  9.875% Second  Priority  Senior Secured
     Notes due 2011.

12.  Indenture,  dated  as of  September  30,  2004,  between  the  Company  and
     Wilmington Trust Company, as Trustee, relating to $785,000,000 in aggregate
     principal  amount of the Company's  9.625% First  Priority  Senior  Secured
     Notes due 2014.





<PAGE>






                                 Schedule 1.1(b)
                                 ---------------

                         Calpine Restricted Transferees

[*] and their respective Affiliates.




<PAGE>







                                 Schedule 1.1(c)
                                 ---------------

                       Bear Stearns Restricted Transferees


[*] and their respective Affiliates.




<PAGE>







                                 Schedule 1.1(d)
                                 ---------------

                        Calpine Significant Subsidiaries

Calpine Generating Company, LLC
Calpine Power Company
Calpine Central, Inc.

                      Bear Stearns Significant Subsidiaries

Bear, Stearns & Co. Inc.
Bear, Stearns Securities International Limited
Bear, Stearns International Limited






<PAGE>







                                 Schedule 3.7(a)
                                 ---------------

                            Employees of Bear Stearns

[*]



<PAGE>







                                 Schedule 3.8(a)
                                 ---------------

                              Employees of Calpine

[*]





<PAGE>







                                  Schedule 9.1
                                  ------------

                     Calpine and Calpine Transaction Parties


Name                           Type of Entity       Jurisdiction of Organization
Calpine Corporation            Corporation          Delaware
CES Marketing VII, LLC         Limited Liability    Delaware
(to be known as Calpine        Company
Merchant Services
Company, Inc.)
Calpine Energy Services, L.P.  Limited Partnership  Delaware




<PAGE>







                                  Schedule 9.2
                                  ------------

                   Calpine Conflicts, Violations and Consents


Any notice  filings or other  approvals,  as needed  under the FPA,  for CMSC to
receive FERC approval  under Section 203 of the FPA for the  performance  of the
Services  by  CMSC  in  accordance  with  CalBear's   FERC-jurisdictional   rate
schedules,  for the provision of energy related services by CMSC to CES, for the
transfer of interests in CMSC's  predecessor,  CES  Marketing  VII,  LLC,  among
Affiliates of Calpine,  and for the name change from CES  Marketing  VII, LLC to
Calpine Merchant  Services  Company,  Inc. and any other notice filings or other
approvals required under the FPA.

Any material consent, waiver, agreement, Permit or approval or authorization of,
or material declaration,  filing, notice or registration to or with, or material
assignment  by, any Person or  Governmental  Authority,  that may be required in
connection with any specific CalBear Trade, including any RTO registrations.






<PAGE>







                                  Schedule 10.1
                                  -------------

                            Bear Stearns and CalBear


Name                           Type of Entity       Jurisdiction of Organization
The Bear Stearns
 Companies Inc.                Corporation          Delaware
Arroyo Energy LP               Limited partnership  Delaware
(to be known as CalBear
Energy LP)







<PAGE>







                                  Schedule 10.2
                                  -------------

                 Bear Stearns Conflicts, Violations and Consents


Any notice filings or other  approvals,  as needed under the FPA, for CalBear to
receive FERC approval  under Section 203 of the FPA for the  performance  of the
Services  by  CMSC  in  accordance  with  CalBear's   FERC-jurisdictional   rate
schedules, for the transfer of interests in CalBear's predecessor, Arroyo Energy
LP, among Affiliates of Bear Stearns, and for the name change from Arroyo Energy
LP to CalBear Energy LP and any other notice filings or other approvals required
under the FPA.

Any material consent, waiver, agreement, Permit or approval or authorization of,
or material declaration,  filing, notice or registration to or with, or material
assignment  by, any Person or  Governmental  Authority,  that may be required in
connection with any specific CalBear Trade, including any RTO registrations.






<PAGE>






                                  Schedule 12.9
                                  -------------

                       Opinions of Counsel to Bear Stearns




[*]

<PAGE>







                                  Schedule 13.9
                                  -------------

                         Opinions of Counsel to Calpine




[*]

<PAGE>




                                 Schedule 18.17
                                 --------------

                                    Knowledge



Representatives of Bear Stearns and CalBear

[*]

Representatives of Calpine, CMSC and CES

[*]



</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-31
<SEQUENCE>3
<FILENAME>ex31-1.txt
<TEXT>
                                                                    EXHIBIT 31.1


                                 CERTIFICATIONS

I, Peter Cartwright, certify that:

1. I have reviewed  this  quarterly  report on Form 10-Q of Calpine  Corporation
(the "registrant");

2. Based on my knowledge, this report does not contain any untrue statement of a
material fact or omit to state a material fact  necessary to make the statements
made, in light of the  circumstances  under which such statements were made, not
misleading with respect to the period covered by this report;

3.  Based  on my  knowledge,  the  financial  statements,  and  other  financial
information included in this report, fairly present in all material respects the
financial  condition,  results of operations and cash flows of the registrant as
of, and for, the periods presented in this report;

4.  The  registrant's  other  certifying  officer  and  I  are  responsible  for
establishing and maintaining  disclosure  controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal  control over financial
reporting  (as defined in Exchange Act Rules  13a-15(f) and  15d-15(f))  for the
registrant and have:

a) Designed such disclosure  controls and procedures,  or caused such disclosure
controls and  procedures to be designed  under our  supervision,  to ensure that
material  information  relating to the  registrant,  including its  consolidated
subsidiaries, is made known to us by others within those entities,  particularly
during the period in which this report is being prepared;

b) Designed  such  internal  control over  financial  reporting,  or caused such
internal control over financial  reporting to be designed under our supervision,
to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial  statements for external purposes in accordance
with generally accepted accounting principles;

c) Evaluated  the  effectiveness  of the  registrant's  disclosure  controls and
procedures and presented in this report our conclusions  about the effectiveness
of the disclosure  controls and procedures,  as of the end of the period covered
by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over
financial  reporting that occurred  during the  registrant's  most recent fiscal
quarter (the registrant's fourth fiscal quarter in the case of an annual report)
that has materially affected,  or is reasonably likely to materially affect, the
registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed,  based on our
most recent  evaluation of internal  control over  financial  reporting,  to the
registrant's  auditors  and the audit  committee  of the  registrant's  board of
directors (or persons performing the equivalent functions):

a) All  significant  deficiencies  and  material  weaknesses  in the  design  or
operation of internal  control over  financial  reporting  which are  reasonably
likely  to  adversely  affect  the  registrant's  ability  to  record,  process,
summarize and report financial information; and

b) Any  fraud,  whether  or not  material,  that  involves  management  or other
employees who have a significant role in the registrant's  internal control over
financial reporting.

Date: November ___, 2005

                              /s/ PETER CARTWRIGHT
                              --------------------
                                Peter Cartwright
                             CHAIRMAN, PRESIDENT AND
                             CHIEF EXECUTIVE OFFICER
                               CALPINE CORPORATION
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-31
<SEQUENCE>4
<FILENAME>ex31-2.txt
<TEXT>
                                                                    EXHIBIT 31.2


                                 CERTIFICATIONS

I, Robert D. Kelly, certify that:

1. I have reviewed  this  quarterly  report on Form 10-Q of Calpine  Corporation
(the "registrant");

2. Based on my knowledge, this report does not contain any untrue statement of a
material fact or omit to state a material fact  necessary to make the statements
made, in light of the  circumstances  under which such statements were made, not
misleading with respect to the period covered by this report;

3.  Based  on my  knowledge,  the  financial  statements,  and  other  financial
information included in this report, fairly present in all material respects the
financial  condition,  results of operations and cash flows of the registrant as
of, and for, the periods presented in this report;

4.  The  registrant's  other  certifying  officer  and  I  are  responsible  for
establishing and maintaining  disclosure  controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal  control over financial
reporting  (as defined in Exchange Act Rules  13a-15(f) and  15d-15(f))  for the
registrant and have:

a) Designed such disclosure  controls and procedures,  or caused such disclosure
controls and  procedures to be designed  under our  supervision,  to ensure that
material  information  relating to the  registrant,  including its  consolidated
subsidiaries, is made known to us by others within those entities,  particularly
during the period in which this report is being prepared;

b) Designed  such  internal  control over  financial  reporting,  or caused such
internal control over financial  reporting to be designed under our supervision,
to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial  statements for external purposes in accordance
with generally accepted accounting principles;

c) Evaluated  the  effectiveness  of the  registrant's  disclosure  controls and
procedures and presented in this report our conclusions  about the effectiveness
of the disclosure  controls and procedures,  as of the end of the period covered
by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant's internal control over
financial  reporting that occurred  during the  registrant's  most recent fiscal
quarter (the registrant's fourth fiscal quarter in the case of an annual report)
that has materially affected,  or is reasonably likely to materially affect, the
registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed,  based on our
most recent  evaluation of internal  control over  financial  reporting,  to the
registrant's  auditors  and the audit  committee  of the  registrant's  board of
directors (or persons performing the equivalent functions):

a) All  significant  deficiencies  and  material  weaknesses  in the  design  or
operation of internal  control over  financial  reporting  which are  reasonably
likely  to  adversely  affect  the  registrant's  ability  to  record,  process,
summarize and report financial information; and

b) Any  fraud,  whether  or not  material,  that  involves  management  or other
employees who have a significant role in the registrant's  internal control over
financial reporting.

Date: November ___, 2005

                               /s/ ROBERT D. KELLY
                               -------------------
                                 Robert D. Kelly
                          EXECUTIVE VICE PRESIDENT AND
                             CHIEF FINANCIAL OFFICER
                               CALPINE CORPORATION
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-32
<SEQUENCE>5
<FILENAME>ex32-1.txt
<TEXT>
                                                                    EXHIBIT 32.1


                            CERTIFICATION PURSUANT TO
                             18 U.S.C. SECTION 1350,
                             AS ADOPTED PURSUANT TO
                  SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002



In connection with the Quarterly  Report of Calpine  Corporation (the "Company")
on Form  10-Q for the  period  ending  September  30,  2005,  as filed  with the
Securities and Exchange  Commission on the date hereof (the  "Report"),  each of
the  undersigned  does hereby  certify,  pursuant to 18 U.S.C.  Section 1350, as
adopted pursuant to Section 906 of the  Sarbanes-Oxley Act of 2002, that, to the
best of his knowledge, based upon a review of the Report:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of
the Securities Exchange Act of 1934; and

(2) The  information  contained in the Report fairly  presents,  in all material
respects, the financial condition and results of operation of the Company.



/s/ PETER CARTWRIGHT                    /s/ ROBERT D. KELLY
----------------------------------      ----------------------------------------
Peter Cartwright                        Robert D. Kelly
Chairman, President and                 Executive Vice President and
Chief Executive Officer                 Chief Financial Officer
Calpine Corporation                     Calpine Corporation




Dated: November ___, 2005

A signed  original of this  written  statement  required by Section 906 has been
provided to Calpine  Corporation and will be retained by Calpine Corporation and
furnished to the Securities and Exchange Commission or its staff upon request.
</TEXT>
</DOCUMENT>
</SUBMISSION>
