
                                  UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION

                             Washington, D.C. 20549




                                    FORM 10-Q

[ X ]     QUARTERLY  REPORT  PURSUANT  TO SECTION 13 OR 15(d) OF THE  SECURITIES
          EXCHANGE ACT OF 1934 For the quarterly period ended March 31, 2001

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

   $.001 par value Common Stock 298,652,450 shares outstanding on May 14, 2001


<PAGE>

                      CALPINE CORPORATION AND SUBSIDIARIES
                               Report on Form 10-Q
                      For the Quarter Ended March 31, 2001
<TABLE>
<CAPTION>
                                      INDEX

PART I.  FINANCIAL INFORMATION                                          Page No.
<S>                                                                          <C>
         ITEM 1.  Financial Statements
                  Consolidated Condensed Balance Sheets
                    March 31, 2001 and December 31, 2000.......................3
                  Consolidated Condensed Statements of Operations
                    For the Three Months Ended March 31, 2001 and 2000.........4
                  Consolidated Condensed Statements of Cash Flows
                    For the Three Months Ended March 31, 2001 and 2000.........5
                  Notes to Consolidated Condensed Financial Statements
                    March 31, 2001.............................................6

         ITEM 2.  Management's Discussion and Analysis of Financial
                    Condition and Results of Operations.......................14

         ITEM 3.  Quantitative and Qualitative Disclosures About
                    Market Risk...............................................22

PART II. OTHER INFORMATION

         ITEM 6.  Exhibits and Reports on Form 8-K............................22
</TABLE>


Signatures....................................................................24

<PAGE>

PART I.  FINANCIAL INFORMATION

         ITEM 1.  Financial Statements

                      CALPINE CORPORATION AND SUBSIDIARIES
                      CONSOLIDATED CONDENSED BALANCE SHEETS
                      March 31, 2001 and December 31, 2000
               (in thousands, except share and per share amounts)
<TABLE>
<CAPTION>
                                                                          March 31,      December 31,
                                                                            2001             2000
                                                                        ------------     ------------
                                                                         (unaudited)
                                     ASSETS
<S>                                                                     <C>              <C>
Current assets:
  Cash and cash equivalents ........................................... $    870,079     $    588,698
  Accounts receivable, net of allowance of $16,808 and $11,078 ........      683,514          649,422
  Inventories .........................................................       40,880           36,883
  Prepaid expenses ....................................................       65,226           27,515
  Other current assets ................................................      436,517           41,165
                                                                        ------------     ------------
          Total current assets ........................................    2,096,216        1,343,683
                                                                        ------------     ------------
Property, plant and equipment, net ....................................    8,204,452        7,459,055
Investments in power projects .........................................      229,106          205,621
Project development costs .............................................       57,807           38,597
Notes receivable ......................................................      249,835          217,927
Restricted cash .......................................................      125,208           88,618
Deferred financing costs ..............................................      155,930          139,631
Other assets ..........................................................      400,252          244,125
                                                                        ------------     ------------
          Total assets ................................................ $ 11,518,806     $  9,737,257
                                                                        ============     ============
                      LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
  Notes payable and borrowings under lines of credit,
    current portion ................................................... $        851     $      1,087
  Accounts payable ....................................................      631,738          765,613
  Project financing, current portion ..................................       91,571           58,486
  Capital lease obligation, current portion ...........................        2,050            1,985
  Income taxes payable ................................................       47,172           63,409
  Accrued payroll and related expenses ................................       42,216           53,667
  Accrued interest payable ............................................       75,600           75,865
  Other current liabilities ...........................................      532,243          149,080
                                                                        ------------     ------------
          Total current liabilities ...................................    1,423,441        1,169,192
                                                                        ------------     ------------
Notes payable and borrowings under lines of credit,
  net of current portion ..............................................      133,955          195,862
Project financing, net of current portion .............................    1,646,564        1,473,869
Senior notes ..........................................................    3,701,750        2,551,750
Capital lease obligation, net of current portion ......................      208,840          208,876
Deferred income taxes, net ............................................      524,851          567,292
Deferred lease incentive ..............................................       59,800           60,676
Deferred revenue ......................................................      105,366           92,511
Other liabilities .....................................................      241,186           20,389
                                                                        ------------     ------------
          Total liabilities ...........................................    8,045,753        6,340,417
                                                                        ------------     ------------
Company-obligated mandatorily redeemable convertible
  preferred securities of subsidiary trusts ...........................    1,122,686        1,122,490
Minority interests ....................................................       41,180           37,576
Stockholders' equity:
  Preferred stock, $.001 par value per share;
    authorized 10,000,000 shares; none issued
    and outstanding in 2001 and 2000 ..................................         --               --
  Common stock, $.001 par value per share;
    authorized 500,000,000 shares in 2001 and 2000;
    issued and outstanding 285,113,768 shares in 2001
    and 283,715,058 shares in 2000 ....................................          285              284
  Additional paid-in capital ..........................................    1,734,202        1,700,505
  Retained earnings ...................................................      631,394          536,617
  Accumulated other comprehensive loss ................................      (56,694)            (632)
                                                                        ------------     ------------
          Total stockholders' equity ..................................    2,309,187        2,236,774
                                                                        ------------     ------------
          Total liabilities and stockholders' equity .................. $ 11,518,806     $  9,737,257
                                                                        ============     ============

              The accompanying notes are an integral part of these
                  consolidated condensed financial statements.
</TABLE>

<PAGE>
                      CALPINE CORPORATION AND SUBSIDIARIES
                 CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS
               For  the Three Months Ended March 31, 2001 and 2000
                    (in thousands, except per share amounts)
                                   (unaudited)
<TABLE>
<CAPTION>
                                                                Three Months Ended
                                                                     March 31,
                                                            --------------------------
                                                                2001           2000
<S>                                                         <C>            <C>
Revenue:
  Electric generation and marketing revenue .............   $ 1,050,067    $   206,068
  Oil and gas production and marketing revenue ..........       175,957         17,179
  Income from unconsolidated
    investments in power projects .......................           563          9,774
  Other revenue .........................................         3,262          2,381
                                                            -----------    -----------
    Total revenue .......................................     1,229,849        235,402
                                                            -----------    -----------

Cost of revenue:
  Power plant generating and marketing expense ..........       551,735         52,885
  Oil and gas production and marketing expense ..........       131,711         10,413
  Fuel expenses .........................................       257,014         73,652
  Depreciation expenses .................................        52,910         27,818
  Operating lease expenses ..............................        28,011         10,458
  Other expenses ........................................         2,499          1,501
                                                            -----------    -----------
    Total cost of revenue ...............................     1,023,880        176,727
                                                            -----------    -----------
Gross profit ............................................       205,969         58,675

Project development expenses ............................        15,839          3,755
General and administrative expenses .....................        32,712          8,619
                                                            -----------    -----------
    Income from operations ..............................       157,418         46,301

Interest expense ........................................        15,705         17,907
Distributions on trust preferred securities .............        15,175          6,978
Interest income .........................................       (19,359)        (7,562)
Other income ............................................       (10,787)          (836)
                                                            -----------    -----------
    Income before provision for income taxes ............       156,684         29,814
Provision for income taxes ..............................        62,943         11,687
                                                            -----------    -----------
    Income before cumulative effect of a change in
      accounting principle ..............................        93,741         18,127
Cumulative effect of a change in accounting
      principle, net of tax of $668 and $-- .............         1,036           --
                                                            -----------    -----------
    Net income ..........................................   $    94,777    $    18,127
                                                            ===========    ===========

Basic earnings per common share:
  Weighted average shares of common stock outstanding ...       284,160        253,347
  Income before cumulative effect of a change in
    accounting principle ................................   $      0.33    $      0.07
  Cumulative effect of a change in accounting principle     $      --      $      --
                                                            -----------    -----------
  Net income ............................................   $      0.33    $      0.07
                                                            ===========    ===========
Diluted earnings per common share:
  Weighted average shares of common stock outstanding
    before dilutive effect of certain trust preferred
    securities ..........................................       299,927        269,255
  Income before dilutive effect of certain trust
    preferred securities and  cumulative effect of a
    change in accounting principle ......................   $      0.31    $      0.07
  Dilutive effect of certain trust preferred
    securities (1) ......................................   $      0.01    $      --
                                                            -----------    -----------
  Income before cumulative effect of a change in
    accounting principle ................................   $      0.30    $      0.07
  Cumulative effect of a change in accounting principle..   $      --      $      --
                                                            -----------    -----------
  Net Income ............................................   $      0.30    $      0.07
                                                            ===========    ===========

(1)  Includes the dilutive  effect of the assumed  conversion  of certain  trust
     preferred  securities.  For the three  months  ended  March 31,  2001,  the
     assumed  conversion  calculation  adds  32,969  shares of common  stock and
     $5,423 to the net income results,  representing  the after tax distribution
     expense on certain  trust  preferred  securities  avoided upon  conversion.
     These  securities  were not  dilutive  for the three months ended March 31,
     2000, and were therefore excluded from the calculation for that period.

              The accompanying notes are an integral part of these
                  consolidated condensed financial statements.
</TABLE>
<PAGE>
                      CALPINE CORPORATION AND SUBSIDIARIES
                 CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
               For the Three Months Ended March 31, 2001 and 2000
                                 (in thousands)
                                   (unaudited)
<TABLE>
<CAPTION>
                                                               Three Months Ended
                                                                    March 31,
                                                           --------------------------
                                                                2001           2000
                                                           -----------    -----------
<S>                                                        <C>            <C>
Cash flows from operating activities:
  Net income ...........................................   $    94,777    $    18,127
  Adjustments to reconcile net income to net cash
    provided by operating activities:
    Depreciation and amortization ......................        58,491         29,264
    Deferred income taxes, net .........................       (37,229)        (8,862)
    Income from unconsolidated investments
      in power projects ................................          (563)        (9,774)
    Distributions from unconsolidated power projects ...         1,213         10,260
    Minority interest ..................................         3,604           (224)
    Change in derivative value .........................       162,172           --
    Change in operating assets and liabilities,
      net of effects of acquisitions:
      Accounts receivable ..............................       (34,092)         3,143
      Inventories ......................................        (3,997)           594
      Other current assets .............................      (420,756)        (6,734)
      Notes receivable .................................        (7,959)        (4,794)
      Other assets .....................................      (156,127)         7,317
      Accounts payable and accrued expenses ............      (145,215)       (15,032)
      Other current liabilities ........................       395,642            681
                                                           -----------    -----------
          Net cash provided by (used in)
          operating activities .........................       (90,039)        23,966
                                                           -----------    -----------

Cash flows from investing activities:
  Purchases of property, plant and equipment ...........      (798,307)      (280,085)
  Acquisitions, net of cash acquired ...................          --         (148,709)
  Capital expenditures on joint ventures ...............       (32,331)       (94,263)
  Maturities of collateral securities ..................         2,885          1,630
  Project development costs ............................       (19,210)       (43,181)
  Decrease (increase) in restricted cash ...............       (51,964)           231
  Increase in notes receivable .........................       (21,588)          --
  Other ................................................         8,384           (236)
                                                           -----------    -----------
          Net cash used in investing activities ........      (912,131)      (564,613)
                                                           -----------    -----------

Cash flows from financing activities:
  Borrowings from project financing ....................       609,354         99,877
  Repayments of  notes payable and borrowings under
    lines of credit ....................................       (61,907)        (5,503)
  Repayments of project financing ......................      (403,810)          --
  Proceeds from issuance of Senior Notes ...............     1,150,000           --
  Proceeds from issuance of trust preferred securities .          --          360,000
  Proceeds from issuance of common stock ...............        12,249          2,826
  Financing costs ......................................       (24,927)       (15,333)
  Other ................................................         2,592           --
                                                           -----------    -----------
          Net cash provided by financing activities ....     1,283,551        441,867
                                                           -----------    -----------
Net increase (decrease) in cash and cash equivalents ...       281,381        (98,780)
Cash and cash equivalents, beginning of period .........       588,698        349,371
                                                           -----------    -----------
Cash and cash equivalents, end of period ...............   $   870,079    $   250,591
                                                           ===========    ===========
Cash paid during the period for:
  Interest .............................................   $   119,992    $    19,726
  Income taxes .........................................   $    65,657    $    13,621


              The accompanying notes are an integral part of these
                  consolidated condensed financial statements.
</TABLE>
<PAGE>
                      CALPINE CORPORATION AND SUBSIDIARIES
              NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
                                 March 31, 2001
                                   (unaudited)


1.   Organization and Operation of the Company

Calpine Corporation  ("Calpine" or "the Company"),  a Delaware corporation,  and
subsidiaries  (collectively,  the  "Company")  is engaged in the  generation  of
electricity  in the United States and Canada.  In pursuing this single  business
strategy, the Company is involved in the development, acquisition, ownership and
operation of power  generation  facilities and the sale of  electricity  and its
by-product,  thermal  energy,  primarily  in the form of steam.  The Company has
ownership  interests  in and operates  gas-fired  cogeneration  facilities,  gas
fields,  gathering  systems  and gas  pipelines,  geothermal  steam  fields  and
geothermal power generation  facilities in the United States and Canada. Each of
the generation facilities produces and markets electricity for sale to utilities
and other third  party  purchasers.  Thermal  energy  produced by the  gas-fired
cogeneration facilities is primarily sold to governmental and industrial users.


2.   Summary of Significant Accounting Policies

Basis of Interim Presentation -- The accompanying interim consolidated condensed
financial  statements of the Company have been prepared by the Company,  without
audit by independent public  accountants,  pursuant to the rules and regulations
of the Securities  and Exchange  Commission.  In the opinion of management,  the
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 have been
condensed  or  omitted  from  these  statements   pursuant  to  such  rules  and
regulations  and,  accordingly,  should be read in conjunction  with the audited
consolidated  financial  statements  of the Company  included  in the  Company's
annual report on Form 10-K for the year ended December 31, 2000. The results for
interim  periods are not  necessarily  indicative  of the results for the entire
year.

Use of Estimates in  Preparation of Financial  Statements -- The  preparation of
financial statements in conformity with generally accepted accounting principles
in the United States requires  management to make estimates and assumptions that
affect the  reported  amounts  of assets  and  liabilities,  and  disclosure  of
contingent  assets and  liabilities at the date of the financial  statements and
the  reported  amounts of revenues  and expenses  during the  reporting  period.
Actual results could differ from those estimates. The most significant estimates
with regard to these financial statements relate to future development costs and
useful lives of the generation facilities.

Revenue  Recognition -- The Company is first and foremost an electric generation
company,  operating  a  portfolio  of mostly  wholly-owned  plants but also some
plants in which its  ownership  interest is 50% or less and which are  accounted
for under  the  equity  method.  In  conjunction  with its  electric  generation
business, the Company also produces, as a by-product, thermal energy for sale to
customers,  principally  steam hosts at its cogeneration  sites. In addition the
Company  acquires and produces natural gas for its own consumption and sells the
balance and small  amounts of oil to third  parties.  To protect and enhance the
profit potential of its electric  generation plants,  the Company's  subsidiary,
Calpine  Energy  Services,  LP ("CES"),  enters into  electric  and gas hedging,
balancing and related  transactions  in which  purchased  electricity and gas is
resold to third parties. CES acts as a principal, takes title to the commodities
purchased for resale and assumes the risks and rewards of ownership.  Therefore,
in accordance  with Staff  Accounting  Bulletin No. 101 and the Emerging  Issues
Task Force  ("EITF") Issue No. 99-19,  CES recognizes  revenue on a gross basis,
except in the case of qualifying hedge transactions,  in which case the net gain
or loss from the hedging instrument is recorded in income against the underlying
hedged  item when the effects of the hedged item are  recognized.  Hedged  items
typically  include sales to third parties of natural gas produced,  purchases of
natural gas to fuel power plants, and sales of generated  electricity.  Finally,
the Company,  through Power Systems Mfg., LLC ("PSM"),  designs and manufactures
spare parts for gas  turbines.  PSM also  generates  small amounts of revenue by
occasionally   loaning  to  power  projects  and  by  providing   operation  and
maintenance ("O&M") services to unconsolidated power plants.  Further details of
the Company's revenue  recognition  policy for each type of revenue  transaction
are provided below:

     Electric  Generation  and  Marketing  Revenue - This  category  of  revenue
     includes  electricity  and steam sales,  Statement of Financial  Accounting
     Standards No. 133 ("SFAS 133"),  "Accounting for Derivative Instruments and
     Hedging  Activities," gains and losses from electric power derivatives (see
     "New Accounting  Pronouncements") and sales of purchased power. The Company
     actively   manages  the  revenue  stream  for  its  portfolio  of  electric
     generating  facilities  through  its  wholly-owned  subsidiary,   CES.  CES
     performs a  market-based  allocation of electric  generation  and marketing
     revenue  to  electricity  and  steam  sales.  That  allocation  is based on
     electricity  delivered by the Company's electric  generating  facilities to
     serve CES contracts. As the Company actively manages the revenue stream for
     its  portfolio of electric  generating  facilities,  it is  appropriate  to
     review the Company's  financial  performance using all electric  generation
     and marketing revenue.

          Electricity  and Steam Sales - For  electricity  sales by plants under
          direct  contracts  with third  parties,  electrical  energy revenue is
          recognized  upon  transmission  to  the  customer,  and  capacity  and
          ancillary  revenue  is  recognized  when   contractually   earned.  In
          accordance with EITF Issue No. 91-6,  revenues from contracts  entered
          into or  acquired  since May 1992,  such as those  relating to Calpine
          Geysers  Company,  are  recognized  at the lesser of amounts  billable
          under the contract or amounts recognizable at an average rate over the
          term of the  contract.  For  electricity  sales by  plants  not  under
          contracts  with third  parties,  revenue is recognized as described in
          Note 8. Net  gains or losses  from  qualified  hedges  of  electricity
          positions are included in electricity and steam sales.  Calpine Gilroy
          Cogen, LP ("Gilroy") had a long-term power purchase  agreement ("PPA")
          with Pacific Gas and Electric  Company ("PG&E") for the sale of energy
          through 2018.  The terms of the PPA provided for 120 megawatts of firm
          capacity and up to 10 megawatts of as-delivered  capacity. On December
          2, 1999,  the  California  Public  Utilities  Commission  approved the
          restructuring  of the PPA between Gilroy and PG&E.  Under the terms of
          the restructuring,  PG&E and Gilroy are each released from performance
          under the PPA  effective  November  1,  2002.  Under the  restructured
          contract,  in addition to the normal capacity  revenue for the period,
          Gilroy  will earn from  September  1999 to October  2002  restructured
          capacity  revenue it would have earned over the November  2002 through
          March  2018 time  period,  for  which  PG&E  will  issue  notes to the
          Company.  At March 31,  2001,  Gilroy had $68.3  million of such notes
          receivable  from PG&E.  These notes are  scheduled  to be paid by PG&E
          during the period from February 2003 to September 2014 (See Note 7).

          SFAS 133 Gains or Losses from  Electric  Power  Derivatives  - Certain
          power  derivatives  are not eligible for hedge  accounting  under SFAS
          133, and the change in fair value of such  derivatives  is recorded as
          revenue (see New Accounting  Pronouncements).  The ineffective portion
          of power derivatives designated as hedges is recorded to revenue using
          the dollar offset method.

          Sales of Purchased Power - The Company  recognizes  revenue from power
          hedging,  balancing and related  activities  through its  wholly-owned
          subsidiary, CES. Revenue generated from CES through sales of purchased
          power to third parties is recorded as described in Note 8.

     Oil and Gas  Production  and  Marketing  Revenue - This category of revenue
     includes  sales to third parties of gas, oil and related  products that are
     produced  by our  Calpine  Natural  Gas  and  Calpine  Canada  Natural  Gas
     subsidiaries and also sales of purchased gas.

          Sales to Third  Parties  of Gas,  Oil and  Related  Products  That Are
          Produced  by the  Company  -  Revenue  from the  sale of crude  oil is
          recognized  upon the  passage of title,  net of  royalties  and net of
          gains or losses  from  qualified  hedges.  Revenue  from  natural  gas
          production is recognized using the sales method,  net of royalties and
          net of gains or losses from qualified hedges.

          Sales of  Purchased  Gas - The  Company  recognizes  revenue  from gas
          hedging,  balancing  and related  activities  through its wholly-owned
          subsidiary, CES. Revenue generated from CES through sales of purchased
          gas to third parties is recorded as described in Note 8.

     Income from Unconsolidated Investments in Power Projects - The Company uses
     the equity  method to  recognize  as revenue  its pro rata share of the net
     income  or  loss of the  unconsolidated  investment  until  such  time,  if
     applicable,  as the Company's  investment is reduced to zero, at which time
     equity   income  is  generally   recognized   only  upon  receipt  of  cash
     distributions from the investee.

     Other  Revenues - This category of revenue  includes O&M contract  revenue,
     interest income on loans to power projects, PSM revenue from sales to third
     parties and miscellaneous revenue.

          O&M Contract Revenue - The Company performs operations and maintenance
          services for some of the projects in which it has an interest. Revenue
          from investees on these  contracts is recognized when the services are
          performed.

          Interest Income on Loans to Power Projects - The Company recognizes as
          revenue interest income on loans to power projects in which it invests
          as the interest is earned and realizable.

          PSM Revenue - The Company  recognizes  revenue from its PSM subsidiary
          as products are  delivered  to the customer for smaller  orders and on
          the percentage of completion  method for certain  special large orders
          under which work is performed over an extended time period.

Energy Marketing Operations -- The Company,  through its wholly-owned subsidiary
CES,  markets  energy  services to utilities,  wholesalers,  and end users.  CES
provides these services by entering into contracts to purchase or supply energy,
primarily,  at specified  delivery points and specified  future dates.  CES also
utilizes financial instruments to manage its exposure to electricity and natural
gas price fluctuations,  and to a lesser degree, price fluctuations of crude oil
and refined  products.  The Company  actively  manages  its  positions,  and the
Company's policy prohibits  positions that exceed  production  capacity and fuel
requirements. The Company's credit risk associated with energy contracts results
from the risk-of-loss on non-performance by counterparties.  The Company reviews
and assesses  counterparty  risk to limit any material  impact on its  financial
position  and  results  of   operations.   The  Company   does  not   anticipate
non-performance by the counterparties.

New Accounting  Pronouncements -- On January 1, 2001, the Company  adopted  SFAS
133. The Company currently holds four classes of derivative instruments that are
impacted by the new  pronouncement  - interest rate swaps,  commodity  financial
instruments, commodity contracts, and physical options. Additionally, one of the
Company's unconsolidated investees holds two foreign exchange forward contracts.

The Company holds various interest rate swap agreements to hedge against changes
in floating interest rates on certain of its project  financing  facilities (see
Note 8 to the  Company's  Year 2000 Form 10-K  report).  The interest  rate swap
agreements  effectively  convert  floating  rates into  fixed  rates so that the
Company can predict with greater  assurance what its future  interest costs will
be and protect itself against increases in floating rates.

The Company enters into commodity  financial  instruments to convert floating or
indexed  electricity  and gas (and to a lesser  extent oil and refined  product)
prices  to  fixed  prices,  thus,  lessening  the  Company's   vulnerability  to
reductions in electric prices for the electricity it generates, to reductions in
gas prices for the gas it produces  and to  increases in gas prices for the fuel
it  consumes in its power  plants.  The Company  seeks to  "self-hedge"  its gas
consumption exposure to the maximum extent with its gas production position.

The Company routinely  negotiates commodity contracts for sales of its generated
electricity  and  sales  of its  natural  gas  production  to  ensure  favorable
utilization of generation and production  assets.  Under SFAS 133 such contracts
are often  considered  derivatives  but are  generally  eligible  for the normal
purchase and sales exception. However, certain contracts, such as capacity sales
contracts,   are  currently   considered   ineligible   for  hedge   accounting.
Nonetheless,  they are an important  means of selling  generated  electricity to
customers who need the  flexibility to match their purchases with their electric
loads, since electricity cannot be stored.

The Company also enters into physical options for short-term  periods (typically
one month) to balance its short-term generating position. The options, which the
Company may write or purchase,  typically  provide for a premium  component  and
firm price for energy when exercised.

Upon adoption of SFAS 133, the fair values of all  derivative  instruments  were
recorded  on the  balance  sheet as assets  or  liabilities.  The fair  value of
derivative  instruments  is estimated  based on present  value  adjusted  quoted
market prices of comparable  contracts.  For  derivative  instruments  that were
designated  as  hedges,  the  difference  between  the  carrying  values  of the
derivatives  and their fair  values at the date of  adoption  was  recorded as a
transition adjustment.  All such derivatives were designated as cash flow hedges
and were highly effective.  Accordingly, a transition adjustment was recorded as
a  cumulative-effect-type  adjustment to accumulated other comprehensive  income
("OCI").  Certain of the  Company's  capacity  sales  contracts  are  considered
derivatives  not eligible for hedge  accounting  under the Financial  Accounting
Standards Board's ("FASB") tentative conclusion on SFAS 133 Implementation Issue
No. C15. For such capacity contracts, their respective fair values were recorded
on the  income  statement  as a  cumulative  effect  of a change  in  accounting
principle.

At the end of each quarter, the changes in fair values of derivative instruments
designated  as cash flow hedges are recorded on the balance sheet as an asset or
liability.  In the case of the  effective  portion of a hedge,  an adjustment is
recorded  to  OCI.  In the  case  of the  ineffective  portion  of a  hedge,  an
adjustment is calculated using the dollar offset method and charged to income or
expense on the  income  statement.  The  changes  in fair  values of  derivative
instruments  that are not  designated  as effective  hedges,  or for which hedge
accounting is not  allowable,  such as certain of the Company's  capacity  sales
contracts,  are recorded on the balance  sheet as assets or  liabilities  and an
offset is charged to income or expense on the income statement.

At March 31, 2001, the FASB had not resolved SFAS 133  Implementation  Issue No.
C15  dealing  with a  proposed  electric  industry  normal  purchases  and sales
exception for capacity sales  transactions ("The Eligibility of Option Contracts
on  Electricity  for the Normal  Purchases  and Normal  Sales  Exception").  The
Company does not assume the FASB will permit use of this  exception for capacity
sales contracts.  Certain capacity sales contracts currently held by the Company
meet the  criteria of SFAS 133  Implementation  Issue No. C15 and are  therefore
subject to the FASB's final decision  expected in June 2001.  Pending the FASB's
final decision, the Company assumes that these contracts will not be exempt from
derivative  accounting  treatment under the normal purchases and sales exemption
unless they meet "requirements contract" guidelines under SFAS 133.

The table below reflects the amounts (in thousands) that are recorded as assets,
liabilities,  income,  expense,  and OCI on March  31,  2001  for the  Company's
derivative instruments.

<TABLE>
<CAPTION>
                                                                       Interest    Commodity
                                                                         Rate      Derivative
                                                                         Swaps     Instruments
                                                                       ---------   -----------
<S>                                                                    <C>          <C>
Current derivative asset (1)........................................   $    --      $ 391,291
Long-term derivative asset (2)......................................        --        162,488
                                                                       ---------    ---------
  Total assets .....................................................   $    --      $ 553,779
                                                                       =========    =========
Current derivative liability (3)....................................         484      408,297
Long-term derivative liability (4)..................................      36,086      186,393
                                                                       ---------    ---------
  Total liabilities ................................................   $  36,570    $ 594,690
                                                                       =========    =========
Total comprehensive loss ...........................................     (35,898)     (67,330)
Reclassification adjustment for activity included in net
income .............................................................        --         17,047
Income tax benefit .................................................      12,875       19,736
                                                                       ---------    ---------
  Net comprehensive loss ...........................................   $ (23,023)   $ (30,547)
                                                                       =========    =========
Income on electricity contracts (5).................................        --          1,306
Income on natural gas contracts (6).................................        --          7,550
Income tax expense .................................................        --         (3,476)
                                                                       ---------    ---------
  Income included in income from operations ........................   $    --      $   5,380
                                                                       =========    =========
Cumulative effect of a change in accounting principle (net of tax)..   $    --      $   1,036

(1)  Included in other current assets
(2)  Included in other assets
(3)  Included in other current liabilities
(4)  Included in other liabilities
(5)  Included in electric generation and marketing revenue.
(6)  Included in fuel expense in cost of revenue.
</TABLE>

During the three months ended March 31, 2001, the Company  recognized a net gain
of $6.4 million in earnings representing the amount of hedge ineffectiveness and
changes  in fair  value  of  derivatives  for  which  hedge  accounting  was not
available.  Of this amount,  $1.0 million was recorded on January 1, 2001 as the
cumulative  effect of a change in  accounting  principle and the balance of $5.4
million was recorded in current  earnings.  A $0.4 million loss  associated with
hedge  ineffectiveness  is  offset  by  a  $5.8  million  gain  associated  with
derivative instruments excluded from the assessment of hedge effectiveness.  The
Company did not exclude any  components of the derivative  instruments'  gain or
loss  from  the   assessment   of  hedge   effectiveness   and  there   were  no
reclassifications  into earnings as a result of the discontinuance of hedges. As
of March 31, 2001,  the maximum length of time over which the Company is hedging
its exposure to the variability in future cash flows for forecasted transactions
is 17.5  years.  The Company  estimates  that  losses of $20.2  million  will be
reclassified  from  accumulated  OCI into  earnings  during  2001 as the  hedged
transactions affect earnings.

Reclassifications  --  Prior  period  amounts  in  the  consolidated   financial
statements  have  been  reclassified  where  necessary  to  conform  to the 2001
presentation.

<PAGE>


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

Property, plant and equipment, net consisted of the following (in thousands):

<TABLE>
<CAPTION>
                                                     March 31,    December 31,
                                                       2001           2000
                                                   ------------   ------------
<S>                                                <C>            <C>
Geothermal properties ..........................   $   341,086    $   334,585
Oil and gas properties .........................       647,962        658,547
Buildings, machinery and equipment .............     1,981,838      1,927,642
Power sales agreements .........................       132,121        159,337
Gas contracts ..................................       152,353        132,748
Other ..........................................       155,416        145,653
                                                   -----------    -----------
                                                     3,410,776      3,358,512
Less accumulated depreciation and amortization..      (385,657)      (328,461)
                                                   -----------    -----------
                                                     3,025,119      3,030,051
Land ...........................................        13,932         12,578
Construction in progress .......................     5,165,401      4,416,426
                                                   -----------    -----------
Property, plant and equipment, net .............   $ 8,204,452    $ 7,459,055
                                                   ===========    ===========
</TABLE>

Construction in progress is primarily  attributable to gas-fired  projects under
construction. Upon commencement of plant operation, these costs are transferred
to buildings, machinery and equipment.

Capitalized  Interest -- The Company capitalizes interest on capital invested in
projects during the advanced stages of development and the construction  period.
For the three  months  ended March 31, 2001 and 2000,  the Company  recorded net
interest  expense  of $15.7  million  and  $17.9  million,  respectively,  after
capitalizing  $69.3 million and $22.7  million of interest on general  corporate
funds used for construction in the first quarter of 2001 and 2000, respectively,
and after  recording  $34.7 million and $7.2 million of interest  capitalized on
funds borrowed for specific  construction  projects in the first quarter of 2001
and 2000, respectively. The cash paid for interest during the three months ended
March 31, 2001 was $16.0  million,  net of capitalized  interest.  For the three
months ended March 31, 2000 capitalized interest exceeded cash paid for interest
by  $10.2  million  due  to  timing  differences.  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 increase in the
amount of  interest  capitalized  during the three  months  ended March 31, 2001
reflects the  significant  increase in the  Company's  power plant  construction
program.


4.   Investments in Power Projects

The following details the Company's income and distributions from investments in
power projects (in thousands):

<TABLE>
<CAPTION>
                              Ownership         Income (Loss)         Distributions
                             Interest at        For the three months ended March 31,
                            March 31, 2001    2001        2000        2001       2000
                            --------------  --------    --------    --------   --------
<S>                             <C>         <C>         <C>         <C>        <C>
Lockport Power Plant ........    11.4%      $ 1,732     $ 1,038     $ 1,058    $   910
Gordonsville Power Plant ....    50.0%        1,674       1,965        --         --
Bayonne Power Plant .........    (1)            154         672         155        748
Sumas Power Plant ...........    (2)           --         7,089        --        7,089
Stony Brook Power Plant .....   100.0%         --          (399)       --        1,364
Kennedy International
  Airport Power Plant .......   100.0%         --        (1,267)       --         --
Androscoggin Energy Center ..    32.3%       (1,154)       --          --         --
Grays Ferry Power Plant .....    40.0%       (1,368)        481        --         --
Other .......................     --           (475)        195        --          149
                                            -------     -------     -------    -------
        Total ...............               $   563     $ 9,774     $ 1,213    $10,260
                                            =======     =======     =======    =======
</TABLE>

(1)  The Company sold its 7.5% interest in this facility on March 12, 2001.
(2)  From January 1, 1998 through  December,  2000, the Company  recorded income
     equal to the amount of cash received from  partnership  distributions.  The
     Company received  distributions at a rate of 70% of project cash flow until
     December  2000  when,  in  accordance  with the  partnership  agreement,  a
     cumulative  24.5%  pre-tax  rate  of  return  was  earned  on its  original
     investment.  As a result,  the Company's equity interest in the partnership
     has been reduced to 0.1%,  and the Company  received no  distributions  and
     recorded no income in the three months ended March 31, 2001.

The Company provides for deferred taxes to the extent that distributions  exceed
earnings.


5.   Senior Notes

On February 15, 2001, the Company  completed a public  offering of $1.15 billion
of its 8 1/2% Senior Notes Due 2011 ("Senior Notes due 2011").  The Senior Notes
due 2011 bear interest at 8 1/2% per year, payable  semi-annually on February 15
and August 15 and mature on February 15, 2011.  The Senior Notes due 2011 may be
redeemed at any time prior to maturity  at a  redemption  price equal to 100% of
their  principal  amount plus  accrued  and unpaid  interest  plus a  make-whole
premium.


6.   Comprehensive Income

Statement of Accounting  Standards No. 130,  "Reporting  Comprehensive  Income,"
requires  the  reporting  of  comprehensive  income in  addition  to net income.
Comprehensive  income is the total of net income and all other non-owner changes
in equity.  Comprehensive  income  includes net income and unrealized  gains and
losses from derivative  instruments that qualify as hedges per SFAS No. 133. The
Company reports accumulated other comprehensive loss in its consolidated balance
sheet.  The  transition  adjustment  from SFAS No. 133 is  discussed  in Note 2,
"Summary of Significant  Accounting  Policies".  Total  comprehensive  income is
summarized as follows (in thousands):

<TABLE>
<CAPTION>
                                                               Three Months
                                                              Ended March 31,
                                                              2001        2000
                                                            --------    --------
<S>                                                         <C>         <C>
Net income ..............................................   $ 94,777    $ 18,127
Other comprehensive income:
  Unrecognized loss on cash flow hedges .................    (86,181)       --
  Loss on foreign currency translation ..................     (3,124)       --
  Income tax benefit ....................................     32,611        --
                                                            --------    --------
    Accumulated other comprehensive loss, net of tax ....    (56,694)       --
                                                            --------    --------
Total comprehensive income ..............................   $ 38,083    $ 18,127
                                                            ========    ========
</TABLE>

7.   Significant Customers

The Company's  Qualifying  Facility ("QF") subsidiaries sell power to PG&E under
the terms of long-term QF contracts at eleven facilities. On April 6, 2001, PG&E
filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy
Code. PG&E is the regulated subsidiary of PG&E Corporation,  and the information
on PG&E disclosed  below excludes PG&E  Corporation's  non-regulated  subsidiary
activity.  The  Company  has  transactions  with  certain  of the  non-regulated
subsidiaries, which have not been affected by PG&E's bankruptcy.

Revenues earned from PG&E for the quarters ended March 31, 2001 and 2000 were as
follows (in thousands):

<TABLE>
<CAPTION>
                          March 31, 2001         March 31, 2000
                          --------------         --------------
<S>                          <C>                    <C>
Revenues:
PG&E .....................   $170,968               $ 41,159
</TABLE>


Receivables  at April 6, 2001,  March 31,  2001,  and  December 31, 2000 were as
follows (in thousands):

<TABLE>
<CAPTION>
                                   April 6, 2001       March 31, 2001     December 31, 2000
                                    (estimate)
                               --------------------    --------------     -----------------
<S>                                   <C>                 <C>                 <C>
Receivables:
PG&E accounts receivable (1)...       $270,108            $265,969            $204,448
PG&E notes receivable (2)......         68,664              68,300              62,336
                                      --------            --------            --------
            PG&E total ........       $338,772            $334,269            $266,784
                                      ========            ========            ========

(1)  See Note 10 for further discussion of the California power market.
(2)  Payments of the notes  receivable  are  scheduled  from February 2003 until
     September 2014 (See Note 2 for further discussion).
</TABLE>

The Company believes that the economic  attractiveness  of the QF contract rates
makes it probable that the contracts  will be assumed by PG&E in its  bankruptcy
proceedings.  Assumption  requires that PG&E cure defaults in payments to the QF
facilities.  Further,  as noted above,  PG&E has various  legal  remedies it may
pursue to recover its excess costs of power  purchases from rate payers.  SFAS 5
requires two  conditions  to be met to establish a reserve  relating to the PG&E
receivables.  The  loss  has to be  both  probable  and  able  to be  reasonably
estimated.  Based on the above,  the Company does not believe a loss is probable
and, in addition,  it does not have a reasonable basis for estimating the amount
of loss, if any. Accordingly,  the Company has not established a reserve against
these QF contract receivables.

The Company also had a combined accounts  receivable balance of $12.6 million as
of March 31, 2001 from the California  Independent  System Operator  Corporation
("CAISO") and Automated Power Exchange, Inc. ("APX"). CAISO's ability to pay the
Company is directly  impacted by PG&E's  ability to pay CAISO.  APX's ability to
pay the  Company  is  impacted  by PG&E's  ability to pay the  California  Power
Exchange,  which in turn pays APX for energy  deliveries by the Company  through
APX.  The  Company  has   provided  a  complete   reserve   against   collection
uncertainties for these receivable balances.

8.   Purchased Power and Gas Sales and Expense

The  Company  records  the cost of gas  consumed  in its  power  plants  as fuel
expense,  while gas purchased  from third  parties,  for hedging,  balancing and
related  activities,  is recorded as purchased gas expense, a component of oil &
gas production and marketing  expense.  CES records the actual revenues received
from  third  parties  as  sales  of  purchased  gas,  a  component  of oil & gas
production and marketing revenue.

The cost of power  purchased  from third  parties,  for hedging,  balancing  and
related  purposes,  is recorded  as  purchased  power  expense,  a component  of
electric generation and marketing expense. The Company, through its wholly-owned
subsidiary, CES, markets on a system basis both power generated by its plants in
excess of amounts under direct contract between the plant and a third party, and
power  purchased from third parties.  Total revenue  realized from CES marketing
activity is  allocated  first to  electricity  and steam  sales,  a component of
electricity generation and marketing revenue, based on actual production, and on
market-based  prices  established  annually,  for  each of the  Company's  power
plants.  The residual revenue realized is allocated to sales of purchased power,
also a component of electricity generation and marketing revenue.

Although the Company believes it is most meaningful to review the combined total
of electric generation and marketing revenue, the table below shows the relative
levels and growth of power and gas hedging, balancing and related activity based
on the revenue allocation methodology described above.

<TABLE>
<CAPTION>
                                       Three months ended
                                           March 31,
                                        2001       2000
                                      --------   --------
<S>                                   <C>        <C>
Sales of purchased power..........    $453,602   $ 12,144
Sales of purchased gas............     129,172      8,604
                                      --------   --------
         Total ...................    $582,774   $ 20,748
                                      ========   ========
Purchased power expense...........    $456,266   $ 11,247
Purchased gas expense.............     118,628      7,739
                                      --------   --------
         Total....................    $574,894   $ 18,986
                                      ========   ========
</TABLE>

9.   Earnings per Share

Basic  earnings  per common  share were  computed by dividing  net income by the
weighted  average  number of  common  shares  outstanding  for the  period.  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 trust preferred  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 earnings per common share to diluted earnings per share
is shown in the following table (in thousands  except per share data). All share
data has been adjusted to reflect the two-for-one stock splits effective June 8,
2000 and November 14, 2000.

<TABLE>
<CAPTION>
                                                       Periods Ended March 31,
                                                  2001                          2000
                                     ---------------------------   ---------------------------
                                       Net                           Net
                                      Income     Shares     EPS     Income     Shares     EPS
                                     ---------------------------------------------------------

<S>                                  <C>         <C>       <C>     <C>         <C>       <C>
Basic earnings per common share:

Income before cumulative
 effect of a change in
 accounting principle ............   $ 93,741    284,160   $0.33   $ 18,127    253,347   $0.07

Cumulative effect of a
 change in accounting
 principle, net of tax ...........      1,036       --      --         --         --      --
                                     --------   --------   -----   --------   --------   -----
Net income .......................   $ 94,777    284,160   $0.33   $ 18,127    253,347   $0.07
                                     ========   ========   =====   ========   ========   =====
Common shares issuable upon
 exercise of stock options
 using treasury stock method .....                15,767                        15,908
                                                --------                      --------
Diluted earnings per common share:

Income before dilutive
 effect of certain trust
 preferred securities and
 cumulative effect of a
 change in accounting
 principle .......................   $ 93,741    299,927   $0.31   $ 18,127    269,255   $0.07

Dilutive effect of certain
 trust preferred securities ......      5,423     32,969   (0.01)       --         --      --
                                     --------   --------   -----   --------   --------   -----
Income before cumulative
 effect of a change in
 accounting principle ............     99,164    332,896    0.30     18,127    269,255    0.07

Cumulative effect of a
 change in accounting
 principle, net of tax............      1,036       --      --         --         --      --
                                     --------   --------   -----   --------   --------   -----
Net income .......................   $100,200    332,896   $0.30   $ 18,127    269,255   $0.07
                                     ========   ========   =====   ========   ========   =====
</TABLE>

Unexercised employee stock options to purchase 280,849 and 275,380 shares of the
Company's  common  stock  during the three months ended March 31, 2001 and 2000,
respectively, were not included in the computation of diluted shares outstanding
because such inclusion would be anti-dilutive.

10.  Subsequent Events

California Power Market

On April 6, 2001, PG&E filed for bankruptcy  protection  under Chapter 11 of the
United States  Bankruptcy  Code.  As of April 6, 2001,  the Company had recorded
approximately  $270.1  million in accounts  receivable  with PG&E,  plus a $68.7
million  note  receivable  not yet due and  payable.  The  Company is  currently
selling power to PG&E pursuant to long-term QF contracts,  and PG&E is paying on
a current basis for these purchases since its bankruptcy filing. The Company has
discussed  the PG&E  situation  with its  external  advisors.  Based upon public
statements made by PG&E since its bankruptcy  filing,  and the favorable pricing
under Calpine's QF contracts, the Company is confident that PG&E will pay it for
all past due power sales.  However,  the timing of any such  payments  cannot be
predicted.  The Company  recognizes that uncertainty  exists with respect to the
outcome of the PG&E bankruptcy,  but we have no reasonable basis at this time to
estimate any potential loss with respect to these  receivables.  Therefore,  the
Company has not  provided for a reserve  against  collection  uncertainties  for
these receivables at this time.  However,  the Company continues to monitor this
situation and will consider any additional facts as they arise.

Other Subsequent Events

On  April 3,  2001,  the  Company  acquired  all of the  common  shares  of WRMS
Engineering,  Inc.  ("WRMS"),  a  San  Jose,  California-based  engineering  and
architectural  firm  specializing in critical use facilities for the commercial,
industrial  and  governmental   sectors,   including   hospitals,   bio-research
facilities,  telecommunication  and data  centers,  fossil fuel plants and waste
treatment  facilities,   through  a  stock-for-stock   exchange  in  which  WRMS
shareholders  received a total of 151,176  shares of Calpine  common stock.  The
aggregate value of the transaction is approximately $7.5 million,  excluding the
assumed indebtedness of WRMS.

On April 11, 2001, the Company acquired the development  rights from Enron North
America for the 750-megawatt  natural  gas-fired  Pastoria Energy Center planned
for Kern County,  California.  The project was licensed by the California Energy
Commission in December 2000. Construction is expected to begin during the summer
of 2001 with commercial operation scheduled for the summer of 2003.

On April 19, 2001,  we  announced  the purchase of 35 model 7FB and 11 model 7FA
gas-fired turbines from GE Power Systems. We will take delivery of 5 turbines in
2002,  with the remainder of the contract to be filled by the end of 2005.  With
this  purchase,  we have firm orders in place for the  delivery of 203  turbines
which,   when  operated  in  a   combined-cycle   configuration,   will  produce
approximately 50,000 megawatts of baseload capacity.

On April 19,  2001,  the  Company  closed the  acquisition  of all of the common
shares of Encal Energy Ltd., a Calgary,  Alberta-based natural gas and petroleum
exploration and development company, through a stock-for-stock exchange in which
Encal shareholders  received,  in exchange for each share of Encal common stock,
 .1493 shares of Calpine common equivalent shares (called "exchangeable  shares")
of the Company's subsidiary,  Calpine Canada Holdings Ltd. A total of 16,603,633
exchangeable shares, valued at $851.2 million, were issued to Encal shareholders
in  exchange  for  their  Encal  common  stock.  Each   exchangeable   share  is
exchangeable  for one share of Calpine common stock.  The aggregate value of the
transaction  is   approximately   U.S.  $1.1  billion,   including  the  assumed
indebtedness of Encal.  The acquisition  will be accounted for under the pooling
of  interests  method.  With the  addition of Encal's  assets,  which  currently
produce  approximately  230 million cubic feet of gas  equivalent  ("mmcfe") per
day, net of royalties,  the Company's net  production is expected to increase to
390 mmcfe per day in North America, enough to fuel approximately 2,300 megawatts
of its power fleet.  For the three  months  ended March 31, 2001,  the pro forma
combined  results of the merger would have resulted in revenues of approximately
$1.4 billion,  net income of $119.7  million,  basic earning per share of $0.40,
and diluted earning per share of $0.36.  These results exclude  one-time pooling
expenses,  the  majority of which will be reported  in the second  quarter  2001
results.

On April 25, 2001, the Company's wholly-owned financing company,  Calpine Canada
Energy Finance ULC, completed a public offering of $1.5 billion of 8 1/2% Senior
Notes  Due  2008  priced  at  99.768%.   These   senior   notes  are  fully  and
unconditionally guaranteed by the Company.

On April 30,  2001,  Calpine  completed  the sale of $1.0 billion of zero coupon
convertible  debentures due 2021 in a private  placement  under Rule 144A of the
Securities  Act of 1933.  The  securities  are  convertible  into Calpine common
shares  at a price of $75.35 at the  option of the  holder at any time.  Holders
also have the right to require Calpine to repurchase  their  debentures in 2002,
2004, 2006, 2008, 2011 and 2016 at a specified price in cash or our common stock
at the option of Calpine,  except on 2016 when the repurchase price must be paid
in cash.  The debentures are redeemable at the option of Calpine after 2004 at a
specified price in cash or our common stock.  Proceeds from the offering will be
used to refinance  certain debt, for working  capital and for general  corporate
purposes. The indenture relating to these securities has not been filed with the
Securities and Exchange  Commission at the date of this filing. The Company will
furnish a copy to the Securities and Exchange Commission upon request.


ITEM 2. Management's  Discussion and Analysis of Financial Condition and Results
        of Operations

Except for  historical  financial  information  contained  herein,  the  matters
discussed  in  this  quarterly   report  may  be  considered   "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,
including  statements  regarding the intent,  belief or current  expectations of
Calpine  Corporation ("the Company") and its management.  Prospective  investors
are cautioned  that any such  forward-looking  statements  are not guarantees of
future  performance and involve a number of risks and  uncertainties  that could
materially  affect  actual  results  such as, but not limited to, (i) changes in
government regulations, including pending changes in California, and anticipated
deregulation of the electric energy industry,  (ii) commercial operations of new
plants  that may be delayed or  prevented  because  of various  development  and
construction  risks,  such as a failure to obtain  financing  and the  necessary
permits to operate or the failure of  third-party  contractors  to perform their
contractual  obligations,  (iii) cost estimates are preliminary and actual costs
may be higher than  estimated,  (iv) the assurance that the Company will develop
additional  plants,  (v) a competitor's  development of a lower-cost  generating
gas-fired  power plant,  (vi) the risks  associated  with  marketing and selling
power from power plants in the newly competitive energy market,  (vii) the risks
associated with marketing and selling combustion turbine parts and components in
the competitive  combustion  turbine parts market,  (viii) the risks  associated
with  engineering,  designing  and  manufacturing  combustion  turbine parts and
components,  (ix) delivery and  performance  risks  associated  with  combustion
turbine  parts and  components  attributable  to  production,  quality  control,
suppliers and transportation,  (x) the successful  exploitation of an oil or gas
resource that  ultimately  depends upon the geology of the  resource,  the total
amount  and  cost to  develop  recoverable  reserves,  and  operational  factors
relating to the extraction of natural gas, and (xi) other risks  identified from
time to time in our  reports  and  registration  statements  filed with the SEC,
including the risk factors  identified in our Annual Report on Form 10-K for the
year ended  December  31,  2000,  which is  incorporated  by  reference  in this
offering circular.

The California  energy market remains  uncertain.  Management is working closely
with a number of parties to resolve the current uncertainty.  This is an ongoing
process and, therefore,  the outcome cannot be predicted. It is possile that any
such  outcome  will  include  changes in  government  regulations,  business and
contractual  relationships  or other  factors that could  materially  affect the
Company.  For  example,  although  we believe it is in PG&E's  best  interest to
assume its QF contracts  with Calpine in  bankruptcy,  it is possible  that PG&E
will elect not to do so. Nothwithstanding these uncertainties, we believe that a
final resolution of the situation in the California  energy market will not have
a material adverse impact on the Company.


Overview

Calpine is engaged in the development,  acquisition, ownership, and operation of
power generation facilities and the sale of electricity and steam principally in
the United States. At May 9, 2001, we had interests in 50 operating power plants
representing 6,362 megawatts of net capacity.

On January 11,  2001,  we jointly  announced  with  Western Hub  Properties  LLC
("WHP") that WHP's wholly-owned subsidiary,  Lodi Gas Storage, LLC, entered into
a long-term firm agreement to supply Calpine with storage services at WHP's Lodi
Gas Storage facility near Lodi, California.  The storage arrangement can provide
up to 4 billion  cubic feet of working gas  inventory  and daily  deliverability
equal  to   approximately  20  percent  of  our  western  region  peak  day  gas
requirements in 2002. The Lodi Gas Storage  Project,  located  approximately  50
miles east of San Francisco,  began  construction in April of 2001 and operation
is scheduled to begin in late 2001.

On January 17, 2001, our wholly-owned  subsidiary,  SkyGen Energy LLC ("SkyGen")
announced  plans to build,  own and operate an  850-megawatt  natural  gas-fired
cogeneration  facility in Augusta,  Georgia.  The proposed Augusta Energy Center
will be fueled by clean  natural  gas and will  supply  energy to DSM  Chemicals
North  America,  Inc.  for  use in its  production  processes.  Construction  is
expected to begin in the third quarter of 2001.

On January 26, 2001, we announced the acquisition of the development rights from
Cogentrix,  an independent  power company based in North Carolina,  for the 577-
megawatt Washington Parish Energy Center, located near Bogalusa,  Louisiana.  We
are managing construction of the facility, which began in January 2001.

On February 12, 2001, we announced that the Florida  Public  Service  Commission
approved a joint application filed by Calpine and Seminole Electric Cooperative,
Inc., under which we will build a 590-megawatt  combined-cycle  power generating
facility,  the  Osprey  Energy  Center,  to supply  electric  power to help meet
Seminole's members' power needs.

On February 13, 2001, we announced  that our  wholly-owned  subsidiary,  SkyGen,
entered into an agreement to supply Alliant Energy's Wisconsin Power & Light Co.
("WP&L") 453  megawatts of electric  capacity and energy from the proposed  600-
megawatt  RiverGen Energy Center,  which will be located next to WP&L's existing
power plant near Beloit,  Wisconsin.  The power sales agreement is for a term of
ten years.  Construction  of the  RiverGen  Energy  Center is  expected to begin
during the fourth quarter of 2001, with commercial  operation scheduled for late
2003.

On February 15, 2001,  we completed a public  offering of $1.15 billion of our 8
1/2% Senior Notes due 2011.  The Senior  Notes due 2011 bear  interest at 8 1/2%
per year, payable semi-annually and mature on February 15, 2011.

On March 16,  2001,  we  announced  that our  wholly-owned  subsidiary,  SkyGen,
entered into a 10-year agreement to supply Xcel Energy,  formerly Public Service
Co. of Colorado, with 336 megawatts of peaking capacity. Power will be delivered
from the proposed  Colorado Energy Center,  a $100 million  electric  generating
facility to be located east of Denver in the City of Aurora. Construction of the
Colorado  Energy  Center is  expected to begin  during the summer of 2002,  with
commercial operation scheduled for 2003.

On March 22, 2001, we announced  plans to build,  own and operate a 600-megawatt
electric  generating  facility  to be  located  near the town of  Hudson in Weld
County,  Colorado.  The proposed Rocky  Mountain  Energy Center will supply Xcel
Energy,  formerly  Public  Service Co. of Colorado,  with up to 600 megawatts of
electricity for a period of ten years. Construction of the $360 million facility
is expected to begin in 2002 with commercial operation scheduled for May 2004.

On March 27, 2001, we announced plans to build, own and operate a 1,000-megawatt
natural  gas-fired  power facility in Deer Park,  Texas.  The proposed Deer Park
Energy Center will supply steam to Shell Chemical  Company and electric power to
the wholesale  market.  Construction for the Deer Park Energy Center is expected
to begin in July  2001,  with the  first  phase of the  project  operational  by
January 2003 and the second, larger phase operational by June 2004.

Transactions  Announced or Consummated  Subsequent to March 31, 2001, and Recent
Developments

On April 3, 2001, we announced that our affiliate,  Calpine Power America, L.P.,
was certified as a Retail Energy Provider in the Electric Reliability Council of
Texas  ("ERCOT").  This allows us to offer services to a full range of wholesale
and  retail  customers  in  Texas.  Calpine  Power  America  will  sell to large
industrials,  in addition to  municipalities,  cooperatives,  and investor-owned
utilities.  Additionally,  we received an ERCOT  certification to be a Qualified
Scheduling Entity ("QSE").  As a QSE, Calpine Power Management,  L.P. may act on
behalf of generators  and consumers in the region and would be  responsible  for
scheduling  the generation of energy  flowing to the  electricity  grid with the
ERCOT Independent System Operator.

On April 3, 2001, we acquired all of the common shares of WRMS Engineering, Inc.
("WRMS"),  a San  Jose,  California-based  engineering  and  architectural  firm
specializing  in critical use  facilities  for the  commercial,  industrial  and
governmental   sectors,    including   hospitals,    bio-research    facilities,
telecommunication  and data  centers,  fossil  fuel  plants and waste  treatment
facilities,  through  a  stock-for-stock  exchange  in which  WRMS  shareholders
received a total of 151,176 shares of Calpine common stock.  The aggregate value
of  the  transaction  is  approximately  $7.5  million,  excluding  the  assumed
indebtedness of WRMS.

On April 11, 2001, we acquired the  development  rights from Enron North America
for the 750-megawatt  natural gas-fired  Pastoria Energy Center planned for Kern
County,  California.  The $500 million  project was  licensed by the  California
Energy Commission in December 2000. Construction is expected to begin during the
summer of 2001 with commercial operation scheduled for the summer of 2003.

On  April  17,  2001,  we  acquired  the   development   rights  from  Kirkland,
Washington-based  National Energy Systems Company for the  248-megawatt  natural
gas-fired  Goldendale Energy Center planned for Goldendale,  Washington.  Energy
generated from the Goldendale  facility will be sold directly into the Northwest
Power Pool.  Construction  commenced in April 2001,  and energy  deliveries  are
scheduled to begin July 1, 2002.

On April 19, 2001,  we  announced  the purchase of 35 model 7FB and 11 model 7FA
gas-fired turbines from GE Power Systems. We will take delivery of 5 turbines in
2002,  with the remainder of the contract to be filled by the end of 2005.  With
this  purchase,  we have firm orders in place for the delivery of 203  turbines,
which,   when  operated  in  a  combined-cycle   configuration,   will  produce
approximately 50,000 megawatts of baseload capacity.

On April 19,  2001,  we closed the  acquisition  of all of the common  shares of
Encal  Energy  Ltd.,  a  Calgary,   Alberta-based   natural  gas  and  petroleum
exploration and development company, through a stock-for-stock exchange in which
Encal shareholders  received,  in exchange for each share of Encal common stock,
 .1493 shares of Calpine  common  equivalent  shares of our  subsidiary,  Calpine
Canada Holdings Ltd. A total of 16,603,633 Calpine common equivalent shares were
issued to Encal  shareholders  in exchange  for their Encal common  stock.  Each
Calpine common  equivalent share is exchangeable for one share of Calpine common
stock.  The  aggregate  value of the  transaction  is  approximately  U.S.  $1.1
billion,  including the assumed  indebtedness of Encal. This acquisition will be
accounted  for under the  pooling of  interests  method.  With the  addition  of
Encal's assets, which currently produce  approximately 230 million cubic feet of
gas  equivalent  ("mmcfe")  per day, net of  royalties,  our net  production  is
expected  to  increase  to 390  mmcfe per day in North  America,  enough to fuel
approximately 2,300 megawatts of our power fleet.

On April 25, 2001, through our wholly-owned  financing  company,  Calpine Canada
Energy  Finance  ULC, we  completed a public  offering of $1.5 billion of 8 1/2%
Senior  Notes  Due 2008  priced at  99.768%.  These  senior  notes are fully and
unconditionally guaranteed by us.

On April  30,  2001,  we  completed  the  sale of $1.0  billion  of zero  coupon
convertible  debentures due 2021 in a private  placement  under Rule 144A of the
Securities  Act of 1933.  The  securities  are  convertible  into Calpine common
shares  at a price of $75.35 at the  option of the  holder at any time.  Holders
have the right to require us to repurchase their debentures in 2002, 2004, 2006,
2008,  2011 and 2016 at a  specified  price in cash or our  common  stock at our
option,  except  on 2016 when the  repurchase  price  must be paid in cash.  The
debentures  are  redeemable  at the option of Calpine  after 2004 at a specified
price in cash or our common  stock.  Proceeds  from the offering will be used to
refinance certain debt, for working capital and for general corporate  purposes.
The  indenture  relating  to  these  securities  has not  been  filed  with  the
Securities and Exchange Commission at the date of this filing. We will furnish a
copy to the Securities and Exchange Commission upon request.

On May 2, 2001, we jointly  announced with Kinder Morgan Energy  Partners,  L.P.
plans to develop the Sonoran  Pipeline,  subject to a successful open season and
all other  approvals.  As proposed,  the Sonoran  Pipeline will be a 1,160-mile,
high-pressure  interstate  natural  gas  pipeline  from  the San  Juan  Basin in
northern New Mexico to markets in California.  The  interstate  pipeline will be
evaluated and developed in two phases, which will be subject to the jurisdiction
of the Federal Energy Regulatory  Commission ("FERC").  The first phase will run
from the San Juan Basin to the California border with the second phase extending
from the California border to the San Francisco Bay area. The first phase of the
pipeline is expected to be completed in the summer of 2003.

On May 9, 2001,  we  announced  that our  emergency  energy  proposal to the San
Francisco  Public Utilies  Commission was approved by the San Francisco Board of
Supervisors.  Under the terms of this contract, we will guarantee to provide San
Francisco  with 50 megawatts of  electricity  24  hours-a-day  for the next five
years starting July 1, 2001.

Recent  Developments  in the California  Power Market.  The  deregulation of the
California power market has produced  significant  unanticipated  results in the
past year.  The  deregulation  froze the rates that  utilities  can charge their
retail and business  customers in California  and  prohibited the utilities from
buying power on a forward basis, while wholesale power prices were not subjected
to limits.

In the past  year,  a series of  factors  have  reduced  the  supply of power to
California,  which  has  resulted  in  wholesale  power  prices  that  have been
significantly higher than historical levels. Several factors contributed to this
increase. These included:

     -    significantly  increased  volatility in prices and supplies of natural
          gas;

     -    an  unusually  dry fall and  winter in the  Pacific  Northwest,  which
          reduced the amount of available  hydroelectric  power from that region
          (typically,  California  imports  a  portion  of its  power  from this
          source);

     -    the large number of power generating  facilities in California nearing
          the end of their useful lives, resulting in increased downtime (either
          for repairs or because they have exhausted their air pollution credits
          and  replacement  credits  have  become  too  costly to acquire on the
          secondary market); and

     -    continued  obstacles to new power plant  construction  in  California,
          which  deprived the market of new power  sources  that could have,  in
          part, ameliorated the adverse effects of the foregoing factors.

As a result of this situation,  two major California  utilities that are subject
to the retail rate freeze,  including  Pacific Gas & Electric Company  ("PG&E"),
have faced wholesale prices that far exceed the retail prices they are permitted
to  charge.  This  has led to  significant  under-recovery  of  costs  by  these
utilities.  As a consequence,  these utilities have defaulted under a variety of
contractual obligations, including payment obligations to power generators. PG&E
has  defaulted  on  payment  obligations  to us under our  long-term  qualifying
facility ("QF")  contracts,  which are subject to federal  regulation  under the
Public Utility Regulatory  Policies Act of 1978, as amended ("PURPA").  On April
6, 2001,  PG&E filed for  bankruptcy  protection  under Chapter 11 of the United
States Bankruptcy Code. As of April 6, 2001, we had recorded  approximately $270
million in accounts  receivable  with PG&E, plus a $68.7 million note receivable
not yet due and payable.  We are  currently  selling  power to PG&E  pursuant to
long-term  QF  contracts,  and PG&E is  paying  on a  current  basis  for  these
purchases since its bankruptcy filing. We have discussed the PG&E situation with
our  external  advisors.  Based upon  public  statements  made by PG&E since its
bankruptcy  filing,  and the favorable  pricing  under our QF contracts,  we are
confident  that  PG&E  will pay us for all past due power  sales.  However,  the
timing of any such payments cannot be predicted.  We recognize that  uncertainty
exists  with  respect  to the  outcome  of the PG&E  bankruptcy,  but we have no
reasonable  basis at this time to estimate  any  potential  loss with respect to
these  receivables.  Therefore,  we have  not  provided  for a  reserve  against
collection  uncertainties  for  these  receivables  at this  time.  However,  we
continue to monitor this  situation  and will consider any  additional  facts as
they arise.

The QF contracts are in place at eleven of our facilities  and represent  nearly
600 megawatts of electricity for Northern California customers. The QF contracts
provide  that  the  California  Public  Utilities  Commission  ("CPUC")  has the
authority to determine the appropriate  utility "avoided cost" to be used to set
energy  payments  for certain QF  contracts,  including  those for all of our QF
plants in  California  which sell power to PG&E.  Section 390 of the  California
Public Utility Code provided QFs the option to elect to receive energy  payments
based  on the  California  Power  Exchange  ("PX")  market  clearing  price.  In
mid-2000,  our QF facilities elected this option and 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. Since that time, the CPUC
has ordered that the price to be paid for energy  deliveries by QFs electing the
PX Price shall be based on a natural gas  cost-based  "transition  formula." The
CPUC has  conducted  proceedings  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.  It is possible  that the CPUC
could  order  a  payment   adjustment   based  on  a  different   energy   price
determination. We believe that the PX Price was the appropriate price for energy
payments but there can be no assurance that this will be the outcome of the CPUC
proceedings.

California  has adopted  legislation  permitting it to issue  long-term  revenue
bonds to provide  funding for  wholesale  purchases of power.  The bonds will be
repaid  with the  proceeds  of  payments  by retail  customers  over  time.  The
California Department of Water Resources ("DWR") sought bids for long-term power
supply contracts.  We successfully bid in that auction,  and recently announced,
as indicated  below,  that we have signed three long-term power supply contracts
with DWR.

On  February  7, 2001,  we  announced  the  signing of a 10-year,  $4.6  billion
fixed-price contract with DWR to provide electricity to the State of California.
We  committed  to  sell up to  1,000  megawatts  of  electricity,  with  initial
deliveries of 200 megawatts  starting  October 1, 2001,  and increasing to 1,000
megawatts by January 1, 2004.  This  contract will  continue  through 2011.  The
electricity will be sold directly to DWR on a 24-hour,  7-day-a-week basis. This
contract is contingent upon the Company's satisfaction,  in its sole discretion,
that  adequate  provisions  have been made by DWR to assure the  Company of full
payment  under the terms of the  contract  (including,  but not  limited to, the
terms and  conditions of any bonds issued by DWR to provide funds for payment of
its obligations under the contract).

On February 28,  2001,  we announced  the signing of two  long-term  power sales
contracts  with DWR.  Under the terms of the  first  contract,  a $5.2  billion,
10-year,  fixed-price  contract,  we committed to sell up to 1,000  megawatts of
generation.  Initial  deliveries  are  scheduled  to begin July 1, 2001 with 200
megawatts  and increase to 1,000  megawatts by as early as July 2002.  Under the
terms of the second contract, a 20-year contract totaling up to $3.1 billion, we
will supply DWR with up to 495 megawatts of peaking  generation,  beginning with
90 megawatts  as early as August 2001,  and  increasing  up to 495  megawatts as
early  as  August  2002.   This  contract  is  contingent   upon  the  Company's
satisfaction, in its sole discretion, that adequate provisions have been made by
DWR to assure  the  Company  of full  payment  under  the terms of the  contract
(including,  but not limited to, the terms and conditions of any bonds issued by
DWR to provide funds for payment of its obligations under the contract).

On March 13, 2001, we announced  the signing of a two-month  deal to provide 555
megawatts of  electricity  to DWR from our new South Point Energy  Center during
plant testing, effective immediately through May 15, 2001.

FERC  Investigation into California  Wholesale  Markets.  Beginning in May 2000,
wholesale energy prices in the California markets increased to levels well above
1999 levels.  In response,  on June 28, 2000, the  Independent  System  Operator
("ISO")  Board of  Governors  reduced  the  price  cap  applicable  to the ISO's
wholesale energy and ancillary  services markets from $750/MWh to $500/MWh.  The
ISO  subsequently  reduced the price cap to  $250/MWh on August 1, 2000.  During
this  period,  however,  the PX  maintained  a separate  price cap set at a much
higher level applicable to the "day-ahead" and "day-of" markets  administered by
the PX. On August 23, 2000, the FERC denied a complaint  filed August 2, 2000 by
San Diego Gas & Electric Company  ("SDG&E") that sought to extend the ISO's $250
price cap to all California energy and ancillary  service markets,  not just the
markets administered by the ISO. However, in its order denying the relief sought
by SDG&E,  the FERC  instructed  its staff to initiate an  investigation  of the
California power markets and to report its findings to the FERC and held further
hearing procedures in abeyance pending the outcome of this investigation.

On November 1, 2000,  the FERC released a Staff Report  detailing the results of
the  Staff  investigation,  together  with  an  "Order  Proposing  Remedies  for
California Wholesale Markets" ("November 1 Order"). In the November 1 Order, the
FERC found that the  California  power  market  structure  and market rules were
seriously  flawed and that these flaws,  together with short supply  relative to
demand,  resulted in unusually high energy prices. The November 1 Order proposed
specific remedies to the identified market flaws, including: (a) imposition of a
so-called  "soft"  price cap at  $150/MWh  to be  applied to both the PX and ISO
markets,  which would allow bids above $150/MWh to be accepted, but will subject
such bids to certain  reporting  obligations  requiring  sellers to provide cost
data and/or identify applicable  opportunity costs and specifying that such bids
may  not  set  the  overall  market  clearing  price,  (b)  elimination  of  the
requirement  that the  California  utilities  sell into and buy from the PX, (c)
establishment  of independent  non-stakeholder  governing boards for the ISO and
the PX, and (d)  establishment  of penalty  charges  for  scheduling  deviations
outside of a  prescribed  range.  In the  November 1 Order the FERC  established
October 2, 2000,  the date 60 days after the filing of the SDG&E  complaint,  as
the "refund  effective  date."  Under the  November 1 Order,  rates  charged for
service after that date through  December 31, 2002 will remain subject to refund
if  determined  by the  FERC  not to be just  and  reasonable.  While  the  FERC
concluded that the Federal Power Act and prior court decisions interpreting that
act strongly  suggested that refunds would not be permissible for charges in the
period  prior to  October  2,  2000,  it noted  that it was  willing  to explore
proposals for equitable relief with respect to charges made in that period.  All
of our receivables from PG&E relate to energy generated by QF facilities.  Under
FERC  regulations,  QF contracts  are exempt from  regulation  under the Federal
Power Act, which is the legislation  that provides the authority for the FERC to
compel  refunds or frame other  equitable  relief with respect to the California
wholesale  markets.  See "Government  Regulation -- Federal Energy Regulation --
Federal  Power Act  Regulation"  set forth in our Annual Report on Form 10-K for
the year ended December 31, 2000. Therefore, we believe that any refund or other
equitable  remedy  that the FERC  may  impose  with  respect  to the  California
wholesale  markets will not affect our ability to pursue  payment by PG&E of all
past due amounts as described above.

On December 15, 2000, the FERC issued a subsequent  order that affirmed in large
measure the  November 1 Order (the  "December 15 Order").  Various  parties have
filed requests for  administrative  rehearing and for judicial review of aspects
of the FERC's  December  15 Order.  The  outcome of these  proceedings,  and the
extent to which the FERC or a reviewing court may revise aspects of the December
15 Order or the extent to which these  proceedings  may result in a refund of or
reduction in the amounts charged by our  subsidiaries  for power sold in the ISO
and PX markets, cannot be determined at this time.

In its Decision 01-03-067 mailed on March 28, 2001 (the "March  Decision"),  the
CPUC changed the formulation of the short run avoided cost ("SRAC") calculation.
The March  Decision is subject to pending  challenges  filed at the CPUC and the
Federal Energy  Regulatory  Commission.  If the March Decision  withstands these
challenges,  this change in the SRAC formula will reduce the energy  payments to
us under our QF contracts. It is difficult at this time to predict the magnitude
of any such  reduction  given  the  recent  date of the March  Decision  and its
uncertain status due to the challenges noted above.  However, we believe that it
is unlikely that the March Decision could have a material  adverse impact on our
results of operations or financial condition.

Selected Operating Information

Set forth below is certain selected  operating  information for our power plants
and steam  fields,  for which  results are  consolidated  in our  statements  of
operations.  Results vary for the three months ended March 31, 2001, as compared
to the same period in 2000,  primarily due to the consolidation of acquisitions,
favorable  energy  pricing,  and increased  production.  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  thermal  sales and other
revenue.

<TABLE>
<CAPTION>
                                                 Three Months Ended
                                                       March 31,
                                              -----------------------------
                                                 2001               2000
                                              ----------         ----------
                                            (in thousands, except production
                                                    and pricing data)
                                                       (unaudited)
<S>                                           <C>                <C>
Electricity and steam revenue:
       Energy .............................   $  454,851         $  124,483
       Capacity ...........................   $   98,258         $   55,483
       Thermal and other ..................   $   42,050         $   13,958
Megawatt hours produced ...................    7,239,199          4,381,189
Average energy price per megawatt hour.....   $    62.83         $    28.41
</TABLE>


Megawatt hours  produced at the power plants  increased 65% for the three months
ended March 31, 2001 as compared with the same period in 2000,  primarily due to
1,848,658  megawatt  hours of  production  generated  by power  plants that were
either acquired or commenced  commercial operation subsequent to March 31, 2000,
648,666  megawatt  hours of  production  as a  result  of the  expansion  of the
Pasadena  facility  completed  during July 2000,  and 360,686  megawatt hours of
production due to higher operation at certain of the Company's other facilities.


Results of Operations

Three Months Ended March 31, 2001 Compared to Three Months Ended March 31, 2000

Revenue -- Total revenue increased 422% to $1,229.8 million for the three months
ended March 31, 2001 compared to $235.4 million for the same period in 2000.

     Electric  generation  and  marketing  revenue  increased  410% to  $1,050.1
     million in 2001 compared to $206.1  million in 2000.  Approximately  $401.2
     million of the $844.0  million  variance was due to  electricity  and steam
     sales,  which increased due to our growing  portfolio and favorable  energy
     pricing.  Our  revenues  for the period  ended March 31,  2001  include the
     consolidated  results of eleven  additional  facilities that we acquired or
     completed construction on subsequent to March 31, 2000. Our power marketing
     activities contributed an additional $441.5 million during the three months
     ended March 31, 2001. This is due to the marketing of power generated by us
     in 2001 in addition to increased price hedging  activity to protect against
     market volatility.

     Oil and gas production and marketing revenue increased to $176.0 million in
     2001 compared to $17.2 million in 2000. The majority of the increase is due
     to marketing  activities relating to purchased gas sold to third parties in
     hedging,  balancing and related transactions.  Additionally,  approximately
     $38.2  million of the variance  relates to increased  commodity  prices and
     sales to third parties from  production of reserves  acquired in Canada and
     in the United States.

     Income from  unconsolidated  investments in power projects decreased 94% to
     $0.6 million in 2001 compared to $9.8 million  during 2000. The variance is
     primarily due to the contractual  reduction in distributions from the Sumas
     Power Plant.

     Other  revenue  increased  38% to $3.3  million  in 2001  compared  to $2.4
     million in 2000. This increase is due primarily to $1.6 million  recognized
     in 2001 from our  custom  turbine  parts  manufacturing  subsidiary,  Power
     Systems Mfg., LLC, and is partially offset by a decrease in interest income
     on loans to power projects.

Cost of revenue -- Cost of revenue  increased  479% to $1,023.9  million in 2001
compared to $176.7 million in 2000.  Approximately  $445.0 million of the $847.2
million  increase  relates to the cost of power purchased by our energy services
organization.  Similarly,  oil and gas production and marketing  expense grew by
$110.9  million,  largely  due to $118.6  million of expense for the cost of gas
purchased by the energy services  organization,  compared to $7.7 million in the
first quarter of 2000. Fuel expenses  increased 249%, from $73.7 million in 2000
to $257.0 million in 2001, due to a 65% increase in megawatt hours generated and
a significant  increase in fuel price.  Depreciation  expenses increased by 90%,
from $27.8  million in the first  quarter of 2000 to $52.9  million in the first
quarter of 2001, due to eleven additional power facilities in operation at March
31, 2001 as compared  to the same  period in 2000,  and due to $14.0  million in
higher  depreciation  and depletion in our oil and gas  operating  subsidiaries.
Operating  lease expenses  increased by $17.6 million due to leases entered into
or  acquired  in  connection  with our  Pasadena,  Tiverton,  Rumford,  and KIAC
facilities subsequent to March 31, 2000.

General  and  administrative  expenses -- General  and  administrative  expenses
increased  280% to $32.7  million for the three  months  ended March 31, 2001 as
compared  to $8.6  million  for the same  period  in 2000.  The  increases  were
attributable  to continued  growth in personnel and  associated  overhead  costs
necessary  to support the  overall  growth in our  operations  and due to recent
acquisitions, including power facilities and natural gas operations.

Interest  expense -- Interest  expense  decreased  12% to $15.7  million for the
three  months ended March 31,  2001,  from $17.9  million for the same period in
2000. The decrease was primarily due to the  capitalization  of $69.3 million of
interest on general  corporate funds invested in  construction  projects for the
three months ended March 31, 2001, as compared to $22.7 million  capitalized  on
general  corporate funds for the same period in 2000. The increase in the amount
of interest  capitalized  reflects the  significant  increase in our power plant
construction program.

Distributions on trust preferred  securities -- Distributions on trust preferred
securities  increased  117% to $15.2  million for the first three months in 2001
compared to $7.0 million for the  corresponding  months in 2000. The increase is
attributable to the issuance of additional trust preferred  securities in August
2000,  as well as a full quarter of  distributions  on the January 2000 offering
and the subsequent exercise of the purchasers' option.

Interest income -- Interest income increased 155% to $19.4 million for the three
months  ended  March 31, 2001  compared  to $7.6  million for the same period in
2000. This increase is due primarily to the  significantly  higher cash balances
that we have maintained.

Other  income -- Other  income  increased  to $10.8  million  in  2001 from $0.8
million  in 2000  primarily  due to a gain on the sale of our  interests  in the
Elwood development project and the Bayonne facility.

Provision  for income taxes -- The effective  income tax rate was  approximately
40.2%  and  39.2%  for  the  three   months  ended  March  31,  2001  and  2000,
respectively.  The increase in the rate is primarily due to our  expansion  into
Canadian natural gas production markets subsequent to March 31, 2000.

Cumulative  effect of a change in  accounting  principle  -- The $1.0 million of
additional  income, net of tax, is due to the adoption of Statement of Financial
Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities,"  amended  by SFAS  No.  137 and  SFAS  No.  138  ("SFAS  133")  and
represents a  mark-to-market  value of certain  capacity  sales  contracts as of
January 1, 2001.

Liquidity and Capital Resources

To date, we have obtained cash from our operations,  borrowings under our credit
facilities and other working  capital  lines,  sale of debt,  equity,  and trust
preferred  securities,  and proceeds from  non-recourse  project  financing.  We
utilized  this  cash to fund our  operations,  service  debt  obligations,  fund
acquisitions, develop and construct power generation facilities, finance capital
expenditures and meet our other cash and liquidity needs.

For the three months ended March 31, 2001 our cash used in operating  activities
was $90.0 million  primarily  due to a decrease in accounts  payable and accrued
expenses,   implementation   of  SFAS  133  and  the  aging  of  our  California
receivables.

Outlook

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

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

          At May 9,  2001,  we had  twenty-seven  projects  under  construction,
          representing an additional 14,841 megawatts of net capacity.  Included
          in these  twenty-seven  projects  is an  expansion  of our Broad River
          Energy Center, which represents 360 megawatts.  We have also announced
          plans  to  develop  thirty   additional  power  generation   projects,
          representing  a net  capacity of 16,835  megawatts.  Included in these
          thirty development projects are seven expansion projects  representing
          917  megawatts:  Pine  Bluff  Energy  Center,  DePere  Energy  Center,
          Auburndale and the California  Peakers (which encompass  expansions of
          the Gilroy Power Plant,  the Watsonville  Power Plant, the Greenleaf 2
          Power Plant and the King City Power Plant.)

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

     -    Enhance the performance and efficiency of existing power projects.  We
          continually  seek to maximize  the power  generation  potential of our
          operating  assets and minimize our operation and maintenance  expenses
          and  fuel  costs.  This  will  become  even  more  significant  as our
          portfolio of power  generation  facilities  expands to 76 power plants
          with a net  capacity  of 21,203  megawatts,  after  completion  of our
          projects  currently  under  construction.  We focus on  operating  our
          plants as an integrated system of power  generation,  which enables us
          to minimize costs and maximize operating efficiencies. We believe that
          achieving  and   maintaining   a  low cost  of   production   will  be
          increasingly  important to compete effectively in the power generation
          industry.


Risk Factors

As a result of the California Power Market situation, as described in the Recent
Developments  section,  two major  California  utilities that are subject to the
retail rate freeze,  including PG&E, have faced wholesale prices that far exceed
the retail  prices they are  permitted  to charge.  This has led to  significant
under-recovery  of costs by these utilities.  As a consequence,  these utilities
have defaulted  under a variety of contractual  obligations,  including  payment
obligations to power generators. PG&E has defaulted on payment obligations to us
under our long-term QF contracts,  which are subject to federal regulation under
PURPA. On April 6, 2001, PG&E filed for bankruptcy  protection  under Chapter 11
of the United  States  Bankruptcy  Code.  As of April 6, 2001,  we had  recorded
approximately  $270.1  million in accounts  receivable  with PG&E,  plus a $68.7
million note receivable not yet due and payable.  We are currently selling power
to PG&E  pursuant to  long-term  QF  contracts,  and PG&E is paying on a current
basis for these  purchases  since its bankruptcy  filing.  We have discussed the
PG&E situation with our external advisors.  Based upon public statements made by
PG&E  since  its  bankruptcy  filing,  and the  favorable  pricing  under our QF
contracts,  we are confident that PG&E will pay us for all past due power sales.
However,  the  timing of any such  payments  cannot be  predicted.  Although  we
believe  there  are  compelling  economic  reasons  for  PG&E to  assume  our QF
contracts,  there is no assurance  that it will do so. Failure of PG&E to assume
these  contracts  would  enable  Calpine  to sell in the open  market  at prices
currently well in excess of the QF contract rates. We recognize that uncertainty
exists  with  respect  to the  outcome  of the PG&E  bankruptcy,  but we have no
reasonable  basis at this time to estimate  any  potential  loss with respect to
these  receivables.  Therefore,  we have  not  provided  for a  reserve  against
collection  uncertainties  for  these  receivables  at this  time.  However,  we
continue to monitor this  situation and will continue to consider any additional
facts as they arise.


Financial Market Risks

From time to time, we use interest rate swap agreements to mitigate our exposure
to interest rate fluctuations.  We do not use derivative  financial  instruments
for speculative or trading  purposes.  The following  table  summarizes the fair
market value of our existing  interest rate swap agreements as of March 31, 2001
(dollars in thousands):
<TABLE>
<CAPTION>
                                Notional        Weighted
                                Principal        Average           Fair
        Maturity Date            Amount       Interest Rate    Market Value
        -------------           --------      -------------    ------------
        <S>                     <C>               <C>            <C>
        2001 ..............     $ 67,281          7.4%           $   (484)
        2007 ..............       38,150          8.0              (4,428)
        2007 ..............       38,150          8.0              (4,411)
        2007 ..............       29,757          7.9              (3,901)
        2007 ..............       29,757          7.9              (3,885)
        2009 ..............       15,000          6.9                (929)
        2011 ..............       57,050          6.9              (3,749)
        2012 ..............      120,771          6.5              (6,548)
        2014 ..............       72,334          6.7              (4,306)
        2015 ..............       22,500          7.0              (1,997)
        2017 ..............       49,771          5.9                (206)
        2018 ..............       17,500          7.0              (1,724)
                                --------          ---            --------
                Total .....     $558,021          7.0%           $(36,568)
                                ========          ===            ========
</TABLE>

Short-term  investments.  As of March 31, 2001, we had short-term investments of
$492.9  million.   These  short-term   investments   consist  of  highly  liquid
investments with maturities less than three months.  We have the ability to hold
these investments to maturity, and as a result, we would not expect the value of
these  investments to be affected to any  significant  degree by the effect of a
sudden change in market interest rates.

Energy price  fluctuations.  We enter into derivative  commodity  instruments to
reduce our exposure to the impact of price fluctuations,  primarily  electricity
and natural  gas prices.  All  transactions  are subject to our risk  management
policy  which  prohibits  positions  that exceed  production  capacity  and fuel
requirements.  Derivative  commodity  instruments  are  accounted  for under the
requirements of SFAS 133.

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

<TABLE>
<CAPTION>
                                                              Change in Fair
                                                                Value From
                                                               10% Adverse
                                          Fair Value           Price Change
                                          ----------          --------------
<S>                                       <C>                   <C>
At March 31, 2001
  Crude oil .......................       $    --               $    --
  Refined products ................            --                    --
  Electricity .....................        (159,597)              (84,806)
  Natural gas .....................         118,685              (253,303)
                                          ---------             ---------
          Total ...................       $ (40,912)            $(338,109)
                                          =========             =========
</TABLE>

Derivative  commodity  instruments  included in the table are those  included in
Note 2 to the Consolidated  Condensed Condensed Financial  Statements.  The fair
value of  derivative  commodity  instruments  included in the table is estimated
based on present value  adjusted  quoted market prices of comparable  contracts.
During the three  months  ended March 31, 2001,  significant  electricity  price
volatility  occurred in the western United States.  The fair value of derivative
commodity  instruments  includes the effect of increased power prices versus our
forward sales  commitments.  Derivative  commodity  instruments  offset physical
positions exposed to the cash market.  None of the offsetting physical positions
are included in the above table.

Price  changes  were  calculated  by  assuming an  across-the-board  ten percent
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  ten  percent  change in prompt  month  prices,  the fair  value of
Calpine's  derivative  portfolio would typically  change less than that shown in
the table due to lower volatility in out-month prices.

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk

See "Financial Market Risks" in ITEM 2.

PART II. OTHER INFORMATION



ITEM 6. Exhibits and Reports on Form 8-K

(a)  Exhibits

The following exhibits are filed herewith unless otherwise indicated:


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

 2.1 Combination Agreement, dated as of February 7, 2001, by and between Calpine
     Corporation and Encal Energy Ltd.
*2.2 Amending  Agreement  to the  Combination  Agreement,  dated as of March 16,
     2001, between Calpine Corporation and Encal Energy Ltd. (a)
 2.3 Form of Plan of Arrangement Under Section 186 of the Business  Corporations
     Act  (Alberta)  (included  as  Exhibit  A to  Exhibit  2.1)  Involving  and
     Affecting  Encal  Energy  Ltd.  and the  Holders of its  Common  Shares and
     Options
*3.1 Amended and Restated  Certificate of Incorporation  of Calpine  Corporation
     (b)
*3.2 Certificate of Correction of Calpine Corporation(b)
*3.3 Certificate  of Designation of Series A  Participating  Preferred  Stock of
     Calpine Corporation (b)
*3.4 Amended  Certificate  of Designation  of Series A  Participating  Preferred
     Stock of Calpine Corporation (b)
 3.5 Certificate of Designation  of Special  Voting  Preferred  Stock of Calpine
     Corporation
*3.5 Amended and Restated By-laws of Calpine Corporation (c)
 4.1 Form of Exchangeable  Share  Provisions and Other Provisions to Be Included
     in the Articles of Calpine Canada  Holdings Ltd.  (included as Exhibit B to
     Exhibit 2.1)
 4.2 Form of Support  Agreement  between Calpine  Corporation and Calpine Canada
     Holdings Ltd. (included as Exhibit C to Exhibit 2.1)
*4.3 Indenture  dated as of August 10, 2000,  between  Calpine  Corporation  and
     Wilmington Trust Company, as Trustee (d)
*4.4 First  Supplemental  Indenture  dated as of  September  28,  2000,  between
     Calpine Corporation and Wilmington Trust Company, as Trustee (e)
*4.5 Indenture dated as of April 25, 2001, between Calpine Canada Energy Finance
     ULC and Wilmington Trust Company, as Trustee (f)
*4.6 Guarantee  Agreement dated as of April 25, 2001, by Calpine  Corporation as
     guarantor of debt securities of Calpine Canada Energy Finance ULC (f)
 9.1 Form of Voting and Exchange Trust Agreement  between  Calpine  Corporation,
     Calpine  Canada  Holdings  Ltd. and CIBC Mellon Trust  Company,  as Trustee
     (included as Exhibit D to Exhibit 2.1)
10.1 Amended and Restated Credit Agreement, dated as of February 15, 2001, among
     Calpine  Construction  Finance Company,  L.P., The Bank of Nova Scotia,  as
     Administrative  Agent,  and  the  Banks  party  thereto  (g)
----------
*    Incorporated  by  reference.

(a)  Incorporated by reference to Calpine Corporation's  Registration  Statement
     on Form S-3/A (File No. 333-56712).

(b)  Incorporated  by reference to Calpine  Corporation's  Annual Report on Form
     10-K for the year ended December 31, 2000,  filed with the SEC on March 15,
     2001.

(c)  Incorporated  by reference to Calpine  Corporation's  Annual Report on Form
     10-K dated  December  31,  1999 and filed on  February  29,  2000 (File No.
     001-12079).

(d)  Incorporated by reference to Calpine Corporation's  Registration  Statement
     on Form S-3/A (File No. 333-72583).

(e)  Incorporated  by reference to Calpine  Corporation's  Annual Report on Form
     10-K  dated  December  31,  2000 and  filed on March  15,  2001  (File  No.
     001-12079).

(f)  Incorporated by reference to Calpine Corporation's  Registration  Statement
     on Form S-3/A (File No. 333-57338).

(g)  Approximately  24 pages of this  exhibit  have been  omitted  pursuant to a
     request for  confidential  treatment.  The omitted  language has been filed
     separately with the Securities and Exchange Commission.


(b)  Reports on Form 8-K

The registrant filed the following reports on Form 8-K during the quarter ended
March 31, 2001:

<TABLE>
<CAPTION>
      Date of Report               Date Filed                Item Reported
     ----------------           ----------------             -------------
     <S>                        <C>                               <C>
     February 8, 2001           February 9, 2001                  5, 7
</TABLE>

<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/ Ann B. Curtis                                 Date:   May 15, 2001
         ---------------------------
         Ann B. Curtis
         Executive Vice President
         (Chief Financial Officer)

By:      /s/ Charles B. Clark, Jr.                         Date:   May 15, 2001
         ---------------------------
         Charles B. Clark,  Jr.
         Vice  President  and  Corporate Controller
         (Chief Accounting Officer)




