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 September 30, 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:
305,317,613 shares of Common Stock, par value $.001 per share, outstanding on November 12, 2001
CALPINE CORPORATION AND SUBSIDIARIES
 Report on Form 10-Q
For the Quarter Ended September 30, 2001
INDEX

                                                                                                                PAGE NO.
PART I - FINANCIAL INFORMATION
          ITEM 1. Financial Statements.

                    Consolidated Condensed Balance Sheets September 30, 2001 and December 31, 2000.............    3

                    Consolidated Condensed Statements of Operations For the Three and Nine Months
                    Ended September 30, 2001 and 2000..........................................................    4

                    Consolidated Condensed Statements of Cash Flows For the Nine Months
                    Ended September 30, 2001 and 2000..........................................................    5

                    Notes to Consolidated Condensed Financial Statements September 30, 2001....................    6

          ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations........   17

          ITEM 3. Quantitative and Qualitative Disclosures About Market Risk...................................   25

PART II - OTHER INFORMATION

          ITEM 1. Legal Proceedings............................................................................   25

          ITEM 2. Changes in Securities and Use of Proceeds....................................................   25

          ITEM 4. Submission of Matters to a Vote of Security Holders..........................................   25

          ITEM 6. Exhibits and Reports on Form 8-K.............................................................   25

Signatures.....................................................................................................   28	

2
 
PART I - FINANCIAL INFORMATION
ITEM 1. Financial Statements.
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
September 30, 2001 and December 31, 2000
 (in thousands, except share and per share amounts)

(unaudited)

                                                                                                 SEPTEMBER 30,     DECEMBER 31,
                                                                                                     2001              2000
                                                                                                 -------------     ------------
                                           ASSETS
Current assets:
   Cash and cash equivalents..................................................................     $   476,374      $   596,077
   Accounts receivable, net of allowance of $18,825 and $11,555...............................       1,054,843          727,893
   Inventories................................................................................          77,391           44,456
   Prepaid expense............................................................................         237,457           27,515
   Other current assets.......................................................................         749,974           41,165
                                                                                                   -----------      -----------
      Total current assets....................................................................       2,596,039        1,437,106
                                                                                                   -----------      -----------
Property, plant and equipment, net............................................................      13,932,640        7,979,160
Investments in power projects.................................................................         335,182          205,621
Project development costs.....................................................................          89,772           38,597
Notes receivable..............................................................................         443,676          217,927
Restricted cash...............................................................................         109,193           88,618
Deferred financing costs......................................................................         165,974          112,049
Long-term receivable..........................................................................         271,567               --
Other assets..................................................................................         865,241          244,125
                                                                                                   -----------      -----------
      Total assets............................................................................     $18,809,284      $10,323,203
                                                                                                   ===========      ===========
                           LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
   Notes payable and borrowings under lines of credit, current portion........................     $     1,120      $     1,087
   Project financing, current portion.........................................................           1,626           58,486
   Capital lease obligation, current portion..................................................           2,188            1,985
   Zero-Coupon Convertible Debentures Due 2021................................................       1,000,000               --
   Accounts payable...........................................................................       1,253,052          843,641
   Income taxes payable.......................................................................          83,821           63,409
   Accrued payroll and related expense........................................................          55,596           53,667
   Accrued interest payable...................................................................         120,375           77,878
   Other current liabilities..................................................................         951,459          149,080
                                                                                                   -----------      -----------
      Total current liabilities...............................................................       3,469,237        1,249,233
                                                                                                   -----------      -----------
Notes payable and borrowings under lines of credit, net of current portion....................         206,120          455,067
Project financing, net of current portion.....................................................       2,620,536        1,473,869
Senior notes..................................................................................       6,300,040        2,551,750
Capital lease obligation, net of current portion..............................................         207,149          208,876
Deferred income taxes, net....................................................................       1,073,118          618,529
Deferred lease incentive......................................................................          58,113           60,676
Deferred revenue..............................................................................         102,758           92,511
Other liabilities.............................................................................         677,789           30,529
                                                                                                   -----------      -----------
      Total liabilities.......................................................................      14,714,860        6,741,040
                                                                                                   -----------      -----------
Company-obligated mandatorily redeemable convertible preferred securities of subsidiary trusts       1,122,846        1,122,490
Minority interests............................................................................          79,651           37,576

Stockholders' equity:
   Preferred stock, $.001 par value per share; authorized 10,000,000 shares; issued and
      outstanding one share in 2001 and 2000..................................................              --               --
   Common stock, $.001 par value per share; authorized 1,000,000,000 shares in 2001 and
      500,000,000 shares in 2000; issued and outstanding 305,159,897 shares in 2001 and
      300,074,078 shares in 2000..............................................................             305              300
   Additional paid-in capital.................................................................       2,018,760        1,896,987
   Retained earnings..........................................................................       1,096,022          547,895
   Accumulated other comprehensive loss.......................................................        (223,160)         (23,085)
                                                                                                   -----------      -----------
      Total stockholders' equity..............................................................       2,891,927        2,422,097
                                                                                                   -----------      -----------
      Total liabilities and stockholders' equity..............................................     $18,809,284      $10,323,203
                                                                                                   ===========      ===========	

The accompanying notes are an integral part of these consolidated condensed financial statements.
3
 
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS
For the Three and Nine Months Ended September 30, 2001 and 2000
 (in thousands, except per share amounts)

(unaudited)

                                                                        THREE MONTHS ENDED            NINE MONTHS ENDED
                                                                           SEPTEMBER 30,                  SEPTEMBER 30,
                                                                     -------------------------     -------------------------
                                                                         2001          2000            2001          2000
                                                                     -----------    ----------     -----------    ----------
Revenue:
  Electric generation and marketing revenue........................  $ 2,755,603    $  643,782     $ 5,063,010    $1,191,461
  Oil and gas production and marketing revenue.....................      139,382        92,851         768,253       229,478
  Income from unconsolidated investments in power projects.........        6,859         7,224           9,022        21,841
  Other revenue....................................................       14,261           957          28,444         4,388
                                                                     -----------    ----------     -----------    ----------
      Total revenue................................................    2,916,105       744,814       5,868,729     1,447,168
                                                                     -----------    ----------     -----------    ----------
Cost of revenue:
  Electric generation and marketing expense........................    1,864,069       117,348       3,147,301       248,955
  Oil and gas production and marketing expense.....................       71,216        30,090         469,765        85,633
  Fuel expense.....................................................      322,100       185,619         807,544       363,315
  Depreciation expense.............................................       91,514        59,125         235,671       154,940
  Operating lease expense..........................................       27,830        25,230          83,290        46,360
  Other expense....................................................        3,485         1,143           9,474         3,923
                                                                     -----------    ----------     -----------    ----------
      Total cost of revenue........................................    2,380,214       418,555       4,753,045       903,126
                                                                     -----------    ----------     -----------    ----------
      Gross profit.................................................      535,891       326,259       1,115,684       544,042
Project development expense........................................        4,894         6,091          25,105        15,074
General and administrative expense.................................       29,859        28,147         116,481        57,295
Merger expense.....................................................           --            --          41,627            --
                                                                     -----------    ----------     -----------    ----------
      Income from operations.......................................      501,138       292,021         932,471       471,673
Other expense (income):
  Interest expense.................................................       49,695        29,058         112,951        69,013
  Distributions on trust preferred securities......................       15,385        12,650          45,947        28,713
  Interest income..................................................      (21,073)      (15,896)        (60,962)      (29,073)
  Other expense (income), net......................................       (7,875)        1,183         (16,893)        1,439
                                                                     -----------    ----------     -----------    ----------
      Income before provision for income taxes.....................      465,006       265,026         851,428       401,581
Provision for income taxes.........................................      144,207       106,481         303,037       162,427
                                                                     -----------    ----------     -----------    ----------
      Income before extraordinary charge and cumulative effect
        of a change in accounting principle........................      320,799       158,545         548,391       239,154
Extraordinary charge, net of tax benefit...........................           --        (1,235)         (1,300)       (1,235)
Cumulative effect of a change in accounting principle..............           --            --           1,036            --
                                                                     -----------    ----------     -----------    ----------
       Net income..................................................  $   320,799    $  157,310     $   548,127    $  237,919
                                                                     ===========    ==========     ===========    ==========
Basic earnings per common share:
   Weighted average shares of common stock outstanding.............      304,666       285,143         302,649       275,392
   Income before extraordinary charge and cumulative effect
     of a change in accounting principle...........................  $      1.05    $     0.56     $      1.81    $     0.87
   Extraordinary charge............................................  $        --    $    (0.01)    $        --    $    (0.01)
   Cumulative effect of a change in accounting principle...........  $        --    $       --     $        --    $       --
                                                                     -----------    ----------     -----------    ----------
     Net income....................................................  $      1.05    $     0.55     $      1.81    $     0.86
                                                                     ===========    ==========     ===========    ==========
Diluted earnings per common share:
   Weighted average shares of common stock outstanding before
     dilutive effect of certain convertible securities.............      318,552       302,239         317,880       291,705
   Income before dilutive effect of certain convertible
     securities, extraordinary charge and cumulative effect of
     a change in accounting principle..............................  $      1.01    $     0.52     $      1.73    $     0.82
   Dilutive effect of certain convertible securities (1)...........  $     (0.13)   $    (0.03)    $     (0.16)   $    (0.03)
                                                                     ------------   ----------     ------------   ----------
   Income before extraordinary charge and cumulative effect of a
     change in accounting principle................................  $      0.88    $     0.49     $      1.57    $     0.79
   Extraordinary charge............................................  $        --    $    (0.01)    $       --     $    (0.01)
   Cumulative effect of a change in accounting principle...........  $        --    $       --     $       --     $       --
                                                                     -----------    ----------     -----------    ----------
     Net income....................................................  $      0.88    $     0.48     $      1.57    $     0.78
                                                                     ============   ==========     ===========    ==========	

(1) Includes the effect of the assumed conversion of certain convertible securities. For the three and nine months ended September 30, 2001, the assumed conversion calculation adds 58,153 and 52,353 shares of common stock and $12,470 and $33,204 to the net income results, representing the after tax expense on certain convertible securities avoided upon conversion. For the three and nine months ended September 30, 2000, the assumed conversion calculation adds 39,573 and 31,338 shares of common stock and $7,696 and $15,373 to the net income results.
The accompanying notes are an integral part of these consolidated condensed financial statements.
4
 
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
For the Nine Months Ended September 30, 2001 and 2000
 (in thousands)

(unaudited)

                                                                                          NINE MONTHS ENDED SEPTEMBER 30,
                                                                                          -------------------------------
                                                                                              2001              2000
                                                                                          -----------       -----------
Cash flows from operating activities:
   Net income.........................................................................    $   548,127       $   237,919
   Adjustments to reconcile net income to net cash provided by operating activities:
      Depreciation and amortization...................................................        242,547           160,373
      Deferred income taxes, net......................................................        202,444            97,355
      Income from unconsolidated investments in power projects........................         (9,022)          (21,841)
      Distributions from unconsolidated investments in power projects.................          3,596            26,717
      Change in long-term liabilities.................................................        459,657            (3,465)
      Minority interest...............................................................         (3,198)            2,144
      Change in operating assets and liabilities, net of effects of
       acquisitions:
      Accounts receivable.............................................................       (561,964)         (227,017)
      Inventories.....................................................................        (30,025)           (7,579)
      Other current assets............................................................       (890,898)           (7,151)
      Notes receivable................................................................        (74,709)          (36,650)
      Other assets....................................................................       (627,076)            9,548
      Accounts payable and accrued expense............................................        421,451           106,715
      Other current liabilities and deferred revenue..................................        806,786            (1,814)
                                                                                          -----------       -----------
         Net cash provided by operating activities....................................        487,716           335,254
                                                                                          -----------       -----------
Cash flows from investing activities:
   Purchases of property, plant and equipment.........................................     (4,473,444)       (1,827,640)
   Acquisitions, net of cash acquired.................................................     (1,303,366)         (369,036)
   Proceeds from sale and leaseback of plant..........................................             --           400,000
   Capital expenditures on joint ventures.............................................       (103,496)         (168,234)
   Maturities of collateral securities................................................          4,035             4,745
   Project development costs..........................................................        (55,734)           (3,689)
   Increase in notes receivable.......................................................       (140,152)          (78,383)
   Decrease (increase) in restricted cash.............................................        (35,740)           11,988
   Other..............................................................................          8,384           (12,505)
                                                                                          -----------       -----------
         Net cash used in investing activities........................................     (6,099,513)       (2,042,754)
                                                                                          -----------       -----------
Cash flows from financing activities:
   Proceeds from notes payable and borrowings under lines of credit...................        141,543           929,637
   Repayments of notes payable and borrowings under lines of credit...................       (444,820)         (991,989)
   Proceeds from project financing....................................................      2,324,209           463,105
   Repayments of project financing....................................................     (1,234,776)         (579,047)
   Proceeds from issuance of senior notes.............................................      3,853,290         1,000,000
   Repayment of senior notes..........................................................       (105,000)               --
   Proceeds from issuance of preferred securities.....................................             --           877,500
   Proceeds from issuance of convertible securities...................................      1,000,000                --
   Proceeds from issuance of common stock.............................................         62,283           803,812
   Financing costs....................................................................        (84,649)          (76,389)
   Write-off of deferred financing costs..............................................             --             2,031
   Other..............................................................................        (19,986)           12,365
                                                                                          -----------       -----------
         Net cash provided by financing activities....................................      5,492,094         2,441,025
                                                                                          -----------       -----------
Net increase (decrease) in cash and cash equivalents..................................       (119,703)          733,525
Cash and cash equivalents, beginning of period........................................        596,077           349,371
                                                                                          -----------       -----------
Cash and cash equivalents, end of period..............................................    $   476,374       $ 1,082,896
                                                                                          ===========       ===========
Cash paid during the period for:
   Interest...........................................................................    $   381,772       $   154,668
   Income taxes.......................................................................    $   584,062       $    41,035	

The accompanying notes are an integral part of these consolidated condensed financial statements.
5
CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
 September 30, 2001
(unaudited)
1. Organization and Operation of the Company
Calpine Corporation ("Calpine"), a Delaware corporation, and subsidiaries (collectively, "the Company") is engaged in the generation of electricity in the United States, Canada and the United Kingdom. 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 power generation and cogeneration facilities, gas fields, gathering systems and gas pipelines, geothermal steam fields and geothermal power generation facilities in the United States, Canada and the United Kingdom. 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. Gas produced and not physically delivered to the Company's generating plants is sold to third parties.
2. Summary of Significant Accounting Policies
Basis of Interim Presentation -- The accompanying unaudited interim consolidated condensed financial statements of the Company have been prepared by the Company pursuant to the rules and regulations of the 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. The Company's historical amounts have been restated to reflect the pooling-of-interests transaction completed during the second quarter of 2001 for the acquisition of Encal Energy Ltd. ("Encal"). Certain information and note disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles in the United States have been condensed or omitted from these statements pursuant to such rules and regulations and, accordingly, these financial statements should be read in conjunction with the audited consolidated financial statements of the Company for the year ended December 31, 2000 included in the Company's September 10, 2001 Current Report on Form 8-K which gives retroactive effect to the merger with Encal. 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 revenue and expense during the reporting period. Actual results could differ from those estimates. The most significant estimates with regard to these financial statements relate to future development costs, useful lives of the generation facilities, and depletion, depreciation and impairment of natural gas and petroleum property and equipment.
Revenue Recognition -- The Company is primarily 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, through its 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 financial swap 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. The Company also generates small amounts of revenue by occasionally loaning funds 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:
6
Electric Generation and Marketing Revenue -- This includes electricity and steam sales, gains and losses from electric power derivatives and sales of purchased power. The Company actively manages the revenue stream for its portfolio of electric generating facilities. 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 generation facilities, it is appropriate to review the Company's financial performance using all electric generation and marketing revenue.
Oil and Gas Production and Marketing Revenue -- This includes sales to third parties of gas, oil and related products that are produced by the Company's Calpine Natural Gas and Calpine Canada Natural Gas subsidiaries and also sales of purchased gas.
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, 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 Revenue -- This includes O&M contract revenue, interest income on loans to power projects, PSM revenue from sales to third parties and miscellaneous revenue.
Energy Marketing Operations -- The Company 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. 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 closely monitors and manages its exposure to all of its counterparties as discussed in Note 11.
New Accounting Pronouncements -- In June 2001, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 141, "Business Combinations", which supersedes Accounting Principles Board ("APB") Opinion No. 16, "Business Combinations" and SFAS No. 38, "Accounting for Preacquisition Contingencies of Purchased Enterprises". SFAS No. 141 eliminates the pooling-of-interests method of accounting for business combinations and modifies the recognition of intangible assets and disclosure requirements. The elimination of the pooling-of-interests method is effective for transactions initiated after June 30, 2001. The remaining provisions of SFAS No. 141 will be effective for transactions accounted for using the purchase method that are completed after June 30, 2001. The Company does not believe that SFAS No. 141 will have a material effect on its consolidated financial statements.
In June 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible Assets", which supersedes APB Opinion No. 17, "Intangible Assets". SFAS No. 142 eliminates the current requirement to amortize goodwill and indefinite-lived intangible assets, extends the allowable useful lives of certain intangible assets, and requires impairment testing and recognition for goodwill and intangible assets. SFAS No. 142 will apply to goodwill and other intangible assets arising from transactions completed both before and after its effective date. The provisions of SFAS No. 142 are required to be applied starting with fiscal years beginning after December 15, 2001. The Company does not believe that SFAS No. 142 will have a material effect on its consolidated financial statements. The Company expects to have an unamortized goodwill balance at December 31, 2001 of $24.4 million which is being amortized over periods of 10 to 20 years. The annual amortization that will be eliminated is $1.6 million.
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations", which amends SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies". SFAS No. 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. SFAS No. 143 is effective for financial statements issued for fiscal years beginning after June 15, 2002. The Company does not believe that SFAS No. 143 will have a material effect on its consolidated financial statements.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets", which supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of", and the accounting and reporting provisions of APB Opinion No. 30, "Reporting the Results of Operations -- Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions", for the disposal of a segment of a business (as previously defined in that APB Opinion). SFAS No. 144 establishes a single accounting model, based on
7
\
the framework established in SFAS No. 121, for long-lived assets to be disposed of by sale. SFAS No. 144 also resolves several significant implementation issues related to SFAS No. 121, such as eliminating the requirement to allocate goodwill to long-lived assets to be tested for impairment and establishing criteria to define whether a long-lived asset is held for sale. SFAS No. 144 is effective for financial statements issued for fiscal years beginning after December 15, 2001. The Company does not believe that SFAS No. 144 will have a material effect on its consolidated financial statements.
Reclassifications -- Prior period amounts in the consolidated condensed financial statements have been reclassified where necessary to conform to the 2001 presentation.
3. Property, Plant and Equipment, Net, and Capitalized Interest
Property, plant and equipment, net, consisted of the following (in thousands):

                                                        SEPTEMBER 30,  DECEMBER 31,
                                                            2001           2000
                                                        -------------  ------------
Geothermal properties................................    $   372,282    $  334,585
Oil and gas properties...............................      2,232,865     1,441,175
Buildings, machinery and equipment...................      5,157,849     1,951,250
Power sales agreements...............................        143,330       162,086
Gas contracts........................................        140,221       129,999
Other................................................        232,376       145,877
                                                         -----------    ----------
                                                           8,278,923     4,164,972
Less: accumulated depreciation and amortization......       (868,167)     (614,816)
                                                         -----------    ----------
                                                           7,410,756     3,550,156
Land.................................................         71,964        12,578
Construction in progress.............................      6,449,920     4,416,426
                                                         -----------    ----------
Property, plant and equipment, net...................    $13,932,640    $7,979,160
                                                         ===========    ==========	

Construction in progress is primarily attributable to gas-fired projects under construction. Upon commencement of commercial 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, in accordance with SFAS No. 34, as amended by SFAS No. 58. For the nine months ended September 30, 2001 and 2000, the Company recorded net interest expense of $113.0 million and $69.0 million, respectively, after capitalizing $246.3 million and $96.7 million, respectively, of interest on general corporate funds used for construction and after recording $94.9 million and $22.8 million, respectively, of interest capitalized on funds borrowed for specific construction projects. Upon commencement of commercial 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 nine months ended September 30, 2001, reflects the significant increase in the Company's power plant construction program.
4. Notes Receivable
As of September 30, 2001 and December 31, 2000, the components of notes receivable were (in thousands):

                                                        SEPTEMBER 30,  DECEMBER 31,
                                                            2001           2000
                                                        -------------  ------------
PG&E note............................................     $ 105,630      $  62,336
Delta note...........................................       271,759        112,050
Metcalf note.........................................        30,176             --
Other................................................        46,634         43,724
                                                          ---------      ---------
         Total notes receivable......................       454,199        218,110
Less: Notes receivable, current portion..............       (10,523)          (183)
                                                          ---------      ---------
Notes receivable, net of current portion.............     $ 443,676      $ 217,927
                                                          =========      =========	

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
8
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 issues notes to the Company. These notes will be paid by PG&E during the period from February 2003 to September 2014.
In 1999, the Company, together with Bechtel Enterprises ("Bechtel"), began the development of an 880-megawatt gas-fired cogeneration project in Pittsburg, California. As part of this joint venture, the Company has an interest bearing note from the project, Delta Energy Center, LLC.
In 1999, the Company, together with Bechtel, began the development of a 579-megawatt gas-fired cogeneration project in San Jose, California. As part of this joint venture, the Company has an interest bearing note from the project, Metcalf Energy Center, LLC.
See Note 15 for a discussion of the Company's purchase of Bechtel's interests in the Delta, Metcalf and Russell City Energy Centers.
5. Acquisitions and Asset Purchases
On July 10, 2001, the Company acquired the 500-megawatt natural gas-fired, combined-cycle Otay Mesa Generating Project in San Diego County from the PG&E National Energy Group. Construction began in September 2001 and completion is scheduled for mid-2003. Under the terms of the sale, the Company will build, own and operate the facility, and PG&E National Energy Group will contract for up to 250 megawatts of output. The balance of the output will be sold into the California wholesale market through CES.
On August 15, 2001, the Company acquired approximately 86% of the voting stock of Michael Petroleum Corporation, a Houston, Texas-based natural gas exploration and development company, for $273.6 million and the assumption of $54.5 million of debt. The acquisition includes 204 billion cubic feet equivalent of proven natural gas reserves currently producing 43 mmcfe per day and an inventory of drilling locations within a 94,000 acreage position in close proximity to the South Texas Magic Valley and Hidalgo Energy Centers. See Note 15 for a discussion of the Company's purchase of the remaining interest in Michael Petroleum Corporation.
On August 24, 2001, the Company acquired and assumed operations of the Saltend Energy Centre, a 1,200-megawatt natural gas-fired power plant located at Saltend near Hull, Yorkshire, England. The Company purchased the cogeneration facility from an affiliate of Entergy Corporation for L562.5 million (US$814.4 million at exchange rates at the closing of the acquisition). The Saltend Energy Centre began commercial operation in November 2000 and is one of the largest natural gas-fired electric power generating facilities in England. Saltend provides electricity and steam for BP Chemicals' Hull Works plant under the terms of a 15-year agreement. The balance of the plant's output is sold into the deregulated United Kingdom power market.
On September 12, 2001, the Company purchased the remaining 33.3% interests in the 247-megawatt Hog Bayou Energy Center and the 213-megawatt Pine Bluff Energy Center from Houston, Texas-based Intergen (North America), Inc. for approximately $9.6 million.
On September 20, 2001, the Company's wholly owned subsidiary, Canada Power Holdings Ltd., acquired and assumed operations of two Canadian power generating facilities from British Columbia-based Westcoast Energy Inc. for C$333.1 million (US$212.1 million at exchange rates at the closing of the acquisition). The Company acquired a 100% interest in the Island Cogeneration facility, a 250-megawatt natural gas-fired electric generating facility in the commissioning phase of construction and located near Campbell River, British Columbia on Vancouver Island. This facility will provide electricity to BC Hydro under the terms of a 20-year agreement and steam to Norske Skog under the terms of a 15-year agreement. The Company also acquired a 50% interest in the 50-megawatt Whitby Cogeneration facility located in Whitby, Ontario. This facility delivers electricity to Ontario Energy Financial Corporation under the terms of a 20-year agreement and provides steam to Atlantic Packaging.
6. Financing
The Company drew $838.3 million on the Calpine Construction Finance Company debt revolvers during the quarter, which brought the Company's outstanding draws to $2.5 billion.
During the third quarter, the Company borrowed a total of $1.2 billion under three bridge credit facilities to finance several acquisitions (see Note 5). These facilities were refinanced with long-term Senior Notes in the fourth quarter of 2001. See Note 15 for further discussion.
7. Equity
9
On July 26, 2001, the Company filed amended certificates with the Delaware Secretary of State to increase the number of authorized shares of common stock to 1,000,000,000 from 500,000,000 and the number of authorized shares of Series A Participating Preferred Stock to 1,000,000 from 500,000.
8. Derivative Instruments
On January 1, 2001, the Company adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." The Company currently holds five classes of derivative instruments that are impacted by the new pronouncement - interest rate swaps, forward interest rate agreements, commodity financial instruments, commodity contracts, and physical options. Additionally, one of the Company's unconsolidated investees holds two foreign exchange forward contracts.
The Company enters into various interest rate swap agreements to hedge against changes in floating interest rates on certain of its project financing facilities. 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 various forward interest rate agreements to hedge against interest rate fluctuations that may occur after the Company has decided to issue long-term fixed rate debt but before the debt is actually issued. The forward interest rate agreements effectively prevent the interest rates on anticipated future long-term debt from increasing beyond a certain level, allowing the Company to predict with greater assurance what its future interest costs on fixed rate long-term debt will be.
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 in order to lessen its 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 enters into commodity contracts for sales of its generated electricity and sales of its natural gas production to ensure favorable utilization of generation and production assets. Such contracts often meet the criteria of SFAS No. 133 as derivatives but are generally eligible for the normal purchase and sales exception under SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities - An Amendment of FASB Statement No. 133." For those that are not deemed normal purchases and sales, most can be designated as hedges of the underlying production of gas or electricity.
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 No. 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 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. At adoption, such derivatives were designated as cash flow hedges and were deemed highly effective. Accordingly, a transition adjustment was recorded to accumulated other comprehensive income ("OCI"). In the case of capacity sales contracts, a transition adjustment was recorded to earnings as a gain from the 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 in OCI for the effective portion and in current earnings, using the dollar offset method, for the ineffective portion. The changes in fair values of derivative instruments designated as fair value hedges are recorded in current earnings, as are the changes in fair values of the contracts being hedged. The changes in fair values of derivative instruments that are not designated as hedges are recorded in current earnings.
10
On June 27, 2001, the FASB cleared SFAS No. 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"). On October 10, 2001, the FASB revised the criteria for qualifying for the "normal" exception. As a result of Issue No. C15, as revised, the Company expects that certain of its existing and future capacity sales contracts will qualify for the normal purchases and sales exception.
The table below reflects the amounts (in thousands) that are recorded as assets, liabilities and in OCI at September 30, 2001 for the Company's derivative instruments.

                                                                     INTEREST RATE      COMMODITY        TOTAL
                                                                      DERIVATIVE        DERIVATIVE     DERIVATIVE
                                                                      INSTRUMENTS       INSTRUMENTS    INSTRUMENTS
                                                                     -------------     -----------    -----------
Current derivative asset (1).......................................     $     --        $  663,840      $  663,840
Long-term derivative asset (2).....................................           --           541,898         541,898
                                                                        --------        ----------      ----------
   Total assets....................................................     $     --        $1,205,738      $1,205,738
                                                                        ========        ==========      ==========
Current derivative liability (3)...................................     $ 18,995        $  725,327      $  744,322
Long-term derivative liability (4).................................       56,476           600,840         657,316
                                                                        --------        ----------      ----------
     Total liabilities.............................................     $ 75,471        $1,326,167      $1,401,638
                                                                        ========        ==========      ==========
Total comprehensive loss...........................................     $(84,585)       $ (354,011)     $ (438,596)
Reclassification adjustment for activity included in net income....        9,085           122,809         131,894
Income tax benefit.................................................       28,300            90,842         119,142
                                                                        --------        ----------      ----------
     Net comprehensive loss........................................     $(47,200)       $ (140,360)     $ (187,560)
                                                                        ========        ==========      ==========	

(1) Included in other current assets.
(2) Included in other assets.
(3) Included in other current liabilities.
(4) Included in other liabilities.
The asset and liability balances for the Company's commodity derivative instruments represent the net totals after offsetting certain assets against certain liabilities under the criteria of FASB Interpretation No. 39, "Offsetting of Amounts Related to Certain Contracts (an Interpretation of APB Opinion No. 10 and FASB Statement No. 105)" ("FIN 39"). For a given contract, FIN 39 will allow the offsetting of assets against liabilities so long as four criteria are met: each of the two parties under contract owes the other determinable amounts; the party reporting under the offset method has the right to set off the amount it owes against the amount owed to it by the other party; the party reporting under the offset method intends to exercise its right to set off, and; the right of set off is enforceable by law. The table below reflects both the amounts (in thousands) recorded as assets and liabilities by the Company and the amounts that would have been recorded had the Company's commodity derivative instrument contracts not qualified for offsetting as of March 31, June 30, and September 30, 2001, respectively:

                                         MARCH 31, 2001              JUNE 30, 2001           SEPTEMBER 30, 2001
                                      --------------------       ----------------------    -----------------------
                                        GROSS         NET          GROSS         NET         GROSS         NET
                                      ----------   --------      ----------   ---------    ---------    ----------

Current Derivative Asset              $1,000,129   $391,291      $2,304,337   $1,048,198   $2,800,765   $  663,840
Long-Term Derivative Asset               290,237    162,488       1,359,347      874,306    1,956,502      541,898
                                      ----------    -------       ---------    ---------    ---------    ---------
Total Derivative Assets               $1,290,366   $553,779      $3,663,684   $1,922,504   $4,757,267   $1,205,738
                                      ==========    =======       =========    =========    =========    =========
Current Derivative Liability          $1,017,136   $408,297      $1,933,184   $  677,045   $2,674,578   $  725,327
Long-Term Derivative Liability           314,141    186,393       1,429,490      944,448    2,203,119      600,840
                                      ----------    -------       ---------    ---------    ---------    ---------
Total Derivative Liabilities          $1,331,277   $594,690      $3,362,674   $1,621,493   $4,877,697   $1,326,167
                                      ==========    =======       =========    =========    =========    =========	

The table above excludes the value of interest rate derivative instruments.
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During the three and nine months ended September 30, 2001, the Company recognized gains (losses) on derivatives not designated as hedges of $13.6 million and $83.3 million, respectively, which were recorded in electric generation and marketing revenue, and $(4.1) and $30.4 million, respectively, which were recorded in fuel expense.
During the three and nine months ended September 30, 2001, the Company recognized pre-tax gains (losses) of $49,748 and $(3.4) million, respectively, related to hedge ineffectiveness on gas and crude oil contracts, which are included in fuel expense. For the three and nine months ended September 30, 2001, the Company recognized no gains or losses related to hedge ineffectiveness on electricity contracts. During the three and nine months ended September 30, 2001, the Company excluded from the assessment of hedge effectiveness the extrinsic values of certain options used in costless collar arrangements to hedge its crude oil production. The Company recorded a gain of $2.4 million for the three and nine month periods ended September 30, 2001 associated with the extrinsic value of these options. The Company excluded no components of any other derivative instruments in assessing hedge effectiveness.
As of September 30, 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 years. The Company estimates that pretax gains related to the transition adjustment associated with the adoption of SFAS No. 133 of $8.5 million will be reclassified from accumulated OCI into earnings during the next three months. For derivative contracts entered into after January 1, 2001, the Company estimates that pretax gains of $87.9 million will be reclassified from accumulated OCI into earnings during the next twelve months as the hedged transactions affect earnings.
See the Form 8-K filed on September 5, 2001 for a further discussion of the Company's accounting policies related to derivative accounting.
9. Comprehensive 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. The Company reports accumulated other comprehensive income (loss) in its consolidated balance sheet. Total comprehensive income is summarized as follows (in thousands):

                                                               THREE MONTHS ENDED          NINE MONTHS ENDED
                                                                  SEPTEMBER 30,               SEPTEMBER 30,
                                                           -----------------------        ---------------------
                                                              2001          2000            2001        2000
                                                           ----------    ---------        ---------   ---------
Net income.........................................        $  320,799    $ 157,310        $ 548,127   $ 237,919
                                                           ----------    ---------        ---------   ---------
Other comprehensive income:
     Unrealized loss on cash flow hedges...........          (479,490)          --         (306,702)         --
     Loss on foreign currency translation..........           (18,330)      (5,570)         (20,186)     (5,570)
     Income tax benefit............................           196,249        2,105          126,813       2,105
                                                           ----------    ---------        ---------   ---------
        Other comprehensive loss, net of tax.......          (301,571)      (3,465)        (200,075)     (3,465)
                                                           ----------    ---------        ---------   ---------
Total comprehensive income.........................        $   19,228    $ 153,845        $ 348,052   $ 234,454
                                                           ==========    =========        =========   =========	

10. 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 the cost of gas purchased and resold, a component of oil and gas production and marketing expense. The Company records the actual revenue received from third parties as sales of purchased gas, a component of oil and gas production and marketing revenue.
The cost of power purchased from third parties, for hedging, balancing and related activities, is recorded as purchased power expense, a component of electric generation and marketing expense. The Company 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.
The table below shows the relative levels and growth of power and gas hedging, balancing and related activity (in thousands).

                                                               THREE MONTHS ENDED           NINE MONTHS ENDED
                                                                  SEPTEMBER 30,               SEPTEMBER 30,
                                                            ----------------------        ---------------------
                                                               2001         2000             2001        2000
                                                            ----------    --------        ----------   --------
Sales of purchased power.............................       $2,028,280    $ 55,525        $3,165,078   $ 96,646
Sales of purchased gas...............................           56,917       9,985           412,782     26,316
                                                            ----------    --------        ----------   --------
          Total......................................       $2,085,197    $ 65,510        $3,577,860   $122,962
                                                            ==========    ========        ==========   ========
Purchased power expense..............................       $1,764,531    $ 54,058        $2,876,119   $ 96,910
Purchased gas expense................................           52,856       9,423           389,814     24,642
                                                            ----------    --------        ----------   --------
         Total.......................................       $1,817,387    $ 63,481        $3,265,933   $121,552
                                                            ==========    ========        ==========   ========	

12
11. Significant Customers
The Company's significant customers at September 30, 2001 were certain subsidiaries of Enron Corp. ("Enron") and PG&E.
Enron
In 2001 the Company, primarily through its CES subsidiary, has transacted a significant volume of business with units of Enron. Most of these transactions are contracts for sales and purchases of power and gas for hedging and optimization purposes, some of which extend out as far as 2009. In October and November of 2001, Enron announced a series of developments including restatement of the last four years of earnings, an investigation by the Securities and Exchange Commission relating to the adequacy of Enron's disclosures of certain off-balance sheet financial transactions or structures and dismissals of certain members of senior management. Additionally, there have been downgrades of its debt by the rating agencies and press reports about liquidity concerns. These developments have culminated in press reports on November 9, 2001 that Enron has agreed to be acquired by Dynegy Inc. ("Dynegy"), a competitor of both Enron and the Company. The acquisition is reported to involve an imminent significant infusion of cash into Enron by ChevronTexaco Corporation, which is reported to hold a 26.5% interest in Dynegy.
For the three and nine months ended September 30, 2001, $767.9 million or 26.3%, and $1,329.8 million or 22.7%, of the Company's revenue was with Enron subsidiaries, primarily Enron Power Marketing, Inc. ("EPMI") and Enron North America Corp. ("ENA"). The Company, primarily CES, purchases significant amounts of fuel and power from ENA and EPMI, giving rise to current accounts payable and open contract fair value positions. These purchases must be included in an overall understanding of the Company's Enron exposure. For the three months ended September 30, 2001, CES had fuel and power purchases from ENA and EMPI of $905.3 million. For the nine months ended September 30, 2001, CES had fuel and power purchases from ENA and EMPI of $1,358.7 million. The sales to and purchases from various Enron subsidiaries are mostly hedging and optimization transactions, and in most cases the purchases and sales are not related and should not be netted to try to gauge the profitability of transactions with Enron subsidiaries.
ENA is the parent corporation of EPMI. Enron is the direct or indirect parent corporation of ENA. In assessing its exposure to Enron subsidiaries and affiliates, the Company analyzes its accounts receivable and accounts payable balances on contracts that have already settled and also the fair value (mark to market value) of the contracts that have not settled. In the event of a default by one or more of the Enron subsidiaries and affiliates, the Company might terminate some or all of the open contracts, in which case the Company would have an exposure to realize the fair value of positive ("in the money") contracts. In managing the overall credit exposure to each other, Calpine and Enron have entered into a netting agreement in which they net or offset overall mark to market exposures from all transactions between certain Enron subsidiaries and CES to liabilities between those entities.
Following are the net accounts receivable (payable) balances as well as the fair value of the open contracts with Enron subsidiaries and affiliates at November 12, 2001. The positive net positions have realization exposure, while the negative net positions are existing or potential obligations.

                                 Net Accounts          Fair Value of
(in millions)                Receivable (Payable)      Open Positions         Total
                             --------------------      --------------        ----------
ENA                                $ 0.8                $(216.0)              $(215.2)
EPMI                                34.3                  117.0                 151.3
                                  ------                -------               -------
Total from ENA and EPMI             35.1                  (99.0)                (63.9)
Enron Canada                          --                  (19.0)                (19.0)
Citrus Trading Corp.(1)             (1.8)                  70.0                  68.2
Other                                0.6                     --                   0.6	

(1) A subsidiary of Citrus Corp., which is 50% owned by a subsidiary of Enron and 50% owned by El Paso Corporation.
Based on the above, the Company had no net exposure to Enron at November 12, 2001. Additionally, the Company believes that its Citrus Trading Corp. exposure is mitigated by the fact that its parent, Citrus Corp., is 50% owned by El Paso Corporation. The Company has not established any reserve against Enron exposure.
The Company's treasury department includes a credit group focused on monitoring and managing counterparty risk. The credit group monitors the net exposure with each counterparty on a daily basis. The analysis is performed on a mark to market basis using the forward curves audited by the Company's Risk Controls group. The net exposure is compared against a counterparty credit risk threshold which is determined based on the counterparty's credit ratings, evaluation of the financial statements and bond values. The credit department monitors these thresholds to determine the need for additional collateral or an adjustment to activity with the counterparty.
The Company will continue to evaluate the Enron risk in the same manner as discussed above. The Company will adjust its threshold for Enron exposure based on factors discussed above and will continue to monitor the exposure on a daily basis.
PG&E
The Company's northern California Qualifying Facility ("QF") subsidiaries sell power to PG&E under the terms of long-term 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. On July 12, 2001, the U.S. Bankruptcy Court for the Northern District of California approved the agreement the Company had entered into with PG&E to modify and assume all of Calpine's QF contracts with PG&E. Under the terms of the agreement, the Company will continue to receive its contractual capacity payments plus a five-year fixed energy price component that averages 5.37 cents per kilowatt-hour in lieu of the short run avoided cost. In addition, all past due receivables under the QF contracts were elevated to administrative priority status and will be paid to the Company, with interest, upon the effective date of a confirmed plan of reorganization. On September 20, 2001, PG&E filed its proposed plan of reorganization with the bankruptcy court.
The Company's QF contracts with PG&E 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 the Company's QF plants in California which sell power to PG&E. Section 390 of the California Public Utility Code provides QFs the option to elect to receive energy payments based on the California Power Exchange ("PX") market clearing price. In mid 2000, the Company's 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 (R.99-11-022) to determine whether the PX Price was the appropriate price for the energy component upon which to base payments to QFs which had elected the PX-based pricing option. The CPUC has issued a proposed decision to the effect that the PX price was the appropriate price for energy payments under the California Public Utility Code. However, a final decision has not been issued to date. Therefore, it is possible that the CPUC could order a payment adjustment based on a different energy price determination. The Company believes 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.
On March 28, 2001, the CPUC issued an order (Decision 01-03-067) (the "March 2001 Decision") proposing to change, on a prospective basis, the composition of the short run avoided cost ("SRAC") energy price formula, which is reset monthly, used by the California utilities in QF contracts. Prior to the March 2001 Decision, CPUC regulations calculated SRAC based on 50% Topock and 50% Malin border gas indices. In the March 2001 Decision, the CPUC changed this formulation to eliminate the prices at Topock from the SRAC formula. The March 2001 Decision is subject to challenges at the CPUC and the Federal Energy Regulatory Commission ("FERC").
On June 14, 2001, however, the CPUC issued an order (Decision 01-06-015) (the "June 2001 Decision") that authorized the California utilities, including PG&E, to amend QF contracts to elect a fixed energy price component that averages 5.37 cents per kilowatt-hour for a five-year term under those contracts in lieu of using the SRAC energy price formula. By this order, the CPUC authorized the QF contract energy price amendments without further CPUC concurrence. As part of the agreement the Company entered into with PG&E pursuant to which PG&E, in bankruptcy, agreed to assume its QF contracts with Calpine, PG&E agreed with the Company to amend these contracts to adopt the fixed price component that averages 5.37 cents pursuant to the June 2001 Decision. This election became effective as of July 16, 2001. As a result of the June 2001 Decision and the Company's agreement with PG&E to amend the QF contracts to adopt the fixed price energy component, the energy price component in Calpine's QF contracts is now fixed for five years and the Company is no longer subject to any uncertainty that may have existed with respect to this component of Calpine's QF contract pricing as a result of the March 2001 Decision. Further, the March 2001 Decision has no bearing on PG&E's agreement with the Company to assume the QF contracts in bankruptcy or on the amount of the receivable that was so assumed.
Revenues earned from PG&E for the three and nine months ended September 30, 2001 and 2000 were as follows (in thousands):

                              THREE MONTHS ENDED SEPTEMBER 30,       NINE MONTHS ENDED SEPTEMBER 30,
                              --------------------------------       -------------------------------
                                   2001            2000                   2001          2000
                                --------        ---------               --------      --------
Revenues:
PG&E.........................   $159,052        $203,894                $449,047      $342,923	

13
PG&E receivables at September 30, 2001, April 6, 2001 (the date of PG&E's bankruptcy filing), and December 31, 2000, were as follows (in thousands):

                                                        SEPTEMBER 30, 2001       APRIL 6, 2001        DECEMBER 31, 2000
                                                        ------------------       -------------        -----------------
Receivables:
PG&E..............................................         $    292,055          $    265,588           $   204,448	

Of the $292.1 million PG&E receivable balance at September 30, 2001, the pre-petition balance of $265.6 million remains unreserved and is classified as a long-term receivable. Through September 30, 2001, as a result of PG&E's decision to assume its QF contracts with Calpine, the Company has recorded $6.0 million of interest income which is included in the long-term receivable balance. PG&E has paid and continues to pay currently for energy deliveries made after April 6, 2001.
The Company had a combined accounts receivable balance of $20.5 million as of September 30, 2001 from the California Independent System Operator Corporation ("CAISO") and Automated Power Exchange, Inc. ("APX"). Of this balance, $10.0 million relates to past due balances prior to the PG&E bankruptcy filing. The Company has provided a full reserve for these past due receivables. 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 directly impacted by PG&E's ability to pay the PX, which in turn would pay APX for energy delivered by the Company through APX. As noted above, the PX ceased operating in January 2001. See Note 15 for an update on the FERC investigation into the California wholesale markets.
The Company also had an accounts receivable balance of $107.2 million at September 30, 2001 from the California Department of Water Resources. As of November 12, 2001, the California Department of Water Resources is paying currently and the Company accordingly has determined that there is no reserve needed.
12. 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 convertible securities into the Company's common stock is based on the dilutive common share equivalents and the after tax distribution expense avoided upon conversion. The reconciliation of basic 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 split that became effective on November 14, 2000.

                                                                                  PERIODS ENDED SEPTEMBER 30,
                                                                -----------------------------------------------------------------
                                                                               2001                            2000
                                                                ------------------------------    -------------------------------
                                                                    NET                              NET
                                                                  INCOME      SHARES     EPS        INCOME      SHARES      EPS
                                                                ---------   ---------   ------    ---------    ---------   ------
THREE MONTHS:
Basic earnings per common share:
Income before extraordinary charge and cumulative
  effect of a change in accounting principle .............      $ 320,799     304,666   $ 1.05    $ 158,545      285,143   $ 0.56
Extraordinary charge, net of tax benefit .................             --          --       --       (1,235)          --    (0.01)
Cumulative effect of a change in accounting principle,
  net of tax .............................................             --          --       --           --           --       --
                                                                ---------   ---------   ------    ---------    ---------   ------
Net income ...............................................      $ 320,799     304,666   $ 1.05    $ 157,310      285,143   $ 0.55
                                                                ---------   ---------   ------    ---------    ---------   ------
Common shares issuable upon exercise of stock options
  using treasury stock method ............................                     13,886                             17,096
                                                                            ---------                          ---------
Diluted earnings per common share:
Income before dilutive effect of certain convertible
  securities, extraordinary charge and cumulative effect
  of a change in accounting principle ....................      $ 320,799     318,552   $ 1.01    $ 158,545      302,239   $ 0.52
Dilutive effect of certain convertible securities ........         12,470      58,153    (0.13)       7,696       39,573    (0.03)
                                                                ---------   ---------   ------    ---------    ---------   ------
Income before  extraordinary  charge and cumulative effect
  of a change in accounting principle ....................        333,269     376,705     0.88      166,241      341,812     0.49
Extraordinary charge, net of tax benefit .................             --          --       --       (1,235)          --    (0.01)
Cumulative effect of a change in accounting principle,	

14

                                                                                  PERIODS ENDED SEPTEMBER 30,
                                                                -----------------------------------------------------------------
                                                                               2001                            2000
                                                                ------------------------------    -------------------------------
                                                                    NET                             NET
                                                                  INCOME      SHARES      EPS      INCOME      SHARES      EPS
                                                                ---------   ---------   ------    ---------    -------   -------

  net of tax..............................................            --          --         --         --          --         --
                                                                --------    --------    -------    --------    --------   -------
Net income................................................      $333,269     376,705    $  0.88    $165,006     341,812   $  0.48
                                                                --------    --------    -------    --------    --------   -------
NINE MONTHS:
Basic earnings per common share:
Income before  extraordinary  charge and cumulative
  effect of a change in accounting principle..............      $548,391     302,649    $  1.81    $239,154     275,392   $  0.87
Extraordinary charge, net of tax benefit..................        (1,300)         --         --      (1,235)         --     (0.01)
Cumulative effect of a change in accounting principle,
  net of tax..............................................         1,036          --         --          --          --        --
                                                                --------    --------    -------    --------    --------   -------
Net income................................................      $548,127     302,649    $  1.81    $237,919     275,392   $  0.86
                                                                --------    --------    -------    --------    --------   -------
Common shares issuable upon exercise of stock options
  using treasury stock method.............................                    15,231                             16,313
                                                                            --------                           --------
Diluted earnings per common share:
Income before dilutive effect of certain convertible
  securities, extraordinary charge and cumulative effect
  of a change in accounting principle.....................      $548,391     317,880    $  1.73    $239,154     291,705   $  0.82
Dilutive effect of certain convertible securities.........        33,204      52,353      (0.16)     15,373      31,338     (0.03)
                                                                --------    --------    -------    --------    --------   -------
Income before  extraordinary  charge and cumulative effect
  of a change in accounting principle.....................       581,595     370,233       1.57     254,527     323,043      0.79
Extraordinary charge, net of tax benefit..................        (1,300)         --         --      (1,235)         --     (0.01)
Cumulative effect of a change in accounting principle,
  net of tax..............................................         1,036          --         --          --          --        --
                                                                --------    --------    -------    --------    --------   -------
Net income................................................      $581,331     370,233    $  1.57    $253,292     323,043   $  0.78
                                                                ========    ========    =======    ========    ========   =======	

Unexercised employee stock options to purchase approximately 2,683,858 and 134,820 shares of the Company's common stock during the nine months ended September 30, 2001 and 2000, respectively, were not included in the computation of diluted shares outstanding because such inclusion would have been anti-dilutive.
13. Commitments and Contingencies
Capital Expenditures -- During the third quarter of 2001, the Company entered into commitments for 12 steam turbine generators from Siemens Westinghouse, one steam turbine generator from Fuji and three combustion turbine generators from Siemens Westinghouse. The above brought the total number of combustion and steam turbines on order to 320 with an approximate value of $9.7 billion, which includes turbines delivered to projects under construction.
Litigation -- An action was filed against Lockport Energy Associates, L.P. ("Lockport") and the New York Public Service Commission ("NYPSC") in August 1997 by New York State Electricity and Gas Company ("NYSEG") in the Federal District Court for the Northern District of New York. NYSEG requested the Court to direct NYPSC and FERC to modify contract rates to be paid to the Lockport Power Plant. In October 1997, NYPSC filed a cross-claim alleging that the FERC violated the Public Utility Regulatory Policies Act of 1978, as amended ("PURPA"), and the Federal Power Act by failing to reform the NYSEG contract that was previously approved by the NYPSC. On September 29, 2000, the New York Federal District Court dismissed NYSEG's complaint and NYPSC's cross-claim. The Court stated that FERC has no authority to alter or waive its regulations or exemptions to alter the terms of the applicable power purchase agreements and that Qualifying Facilities are entitled to the benefit of their bargain, even if at the expense of NYSEG and its ratepayers. NYSEG has filed an appeal with respect to this decision. In any event, the Company retains the right to require The Brooklyn Union Gas Company to purchase its interest in the Lockport Power Plant for $18.9 million, less equity distributions received by the Company, at any time before December 19, 2001. On October 5, 2001, the United States Court of Appeals affirmed the judgment of the federal district court and dismissed all of the claims raised by NYSEG against Lockport.
The Company is involved in various other claims and legal actions arising out of the normal course of business. The Company does not expect that the outcome of these proceedings will have a material adverse effect on the Company's financial position or results of operations.
14. Operating Segments for the Three and Nine Months Ended September 30, 2001
15
The Company's primary operating segments are electric generation and marketing; oil and gas production and marketing; and corporate activities and other. Electric generation and marketing includes the development, acquisition, ownership and operation of power production facilities, the sale of electricity and steam and electricity hedging and related activity. Oil and gas production and marketing includes the ownership and operation of gas fields, gathering systems and gas pipelines for internal gas consumption, third party sales and oil and gas hedging and related activity. Corporate activities and other consists primarily of financing activities, general and administrative costs and consolidating eliminations. Certain costs related to company-wide functions are allocated to each segment. However, interest on corporate debt is maintained at corporate and is not allocated to the segments. Due to the integrated nature of the business segments, estimates and judgments have been made in allocating certain revenue and expense items. The Company evaluates performance of these operating segments based upon several criteria including profits before tax.

                                                                     OIL AND GAS
                                        ELECTRIC GENERATION          PRODUCTION
                                           AND MARKETING            AND MARKETING      CORPORATE AND OTHER          TOTAL
                                       ----------------------   --------------------   -------------------    ---------------------
                                          2001         2000        2001       2000       2001       2000         2001        2000
                                       ----------   ---------   ---------   --------   --------  ---------     ----------  ---------
For the three months ended
  September 30, 2001 and 2000:
Revenues.............................  $2,765,101   $ 651,336   $ 155,191   $114,635   $ (4,187)  $(21,157)   $2,916,105  $ 744,814
Income before taxes and
 extraordinary charge................     470,545     258,484      15,656     38,934    (21,195)   (32,392)      465,006    265,026	

                                                                     OIL AND GAS
                                        ELECTRIC GENERATION          PRODUCTION
                                           AND MARKETING            AND MARKETING     CORPORATE AND OTHER             TOTAL
                                       ----------------------   --------------------  -------------------      ---------------------
                                          2001         2000        2001       2000      2001       2000          2001        2000
                                       ----------   ---------   ---------   --------  ---------  ---------     ----------  ---------

For the nine months ended
  September 30, 2001 and 2000:
Revenues.............................. $5,077,435   $1,213,857  $ 869,002   $262,849  $ (77,708)  $(29,538)   $5,868,729  $1,447,168
Merger expense........................         --           --     41,627         --         --         --        41,627          --
Income before taxes, extraordinary
  charge and cumulative effect of a
  change in accounting principle......    776,687      414,432    187,376     66,310   (112,635)   (79,161)      851,428     401,581	

                                                       ELECTRIC         OIL AND GAS
                                                      GENERATION        PRODUCTION       CORPORATE
                                                     AND MARKETING     AND MARKETING     AND OTHER         TOTAL
                                                     -------------     -------------    ----------       -----------
Total assets:
September 30, 2001.................................   $8,454,410        $ 3,236,573      $ 7,118,301     $18,809,284	

For the three months ended September 30, 2001 and 2000, there were intersegment revenues of approximately $15.9 million and $22.1 million, respectively. For the nine months ended September 30, 2001 and 2000, there were intersegment revenues of approximately $100.8 million and $33.9 million, respectively. The elimination of these intersegment revenues, which primarily relate to the use of internally procured gas for the Company's power plants, are included in the Corporate and Other reporting segment.
15. Subsequent Events
FERC Investigation into California Wholesale Markets -- FERC ordered all sellers and buyers in wholesale power markets administered by the California ISO, as well as representatives of the State of California, to participate in a settlement conference before a FERC administrative judge. The settlement discussions were intended to resolve all issues that remain outstanding to resolve past accounts, including sellers' claims for unpaid invoices, and buyers' claims for refunds of alleged overcharges, for past periods. The settlement discussions began on June 25, 2001, and ended on July 9, 2001. The Chief Administrative Law Judge issued his report and recommendations to FERC on July 12, 2001. On July 25, 2001, FERC ordered an expedited fact-finding hearing to calculate refunds for spot market transactions in California. The hearing has been delayed pending the submission by the California ISO and the
16
California Power Exchange of data for the purpose of developing the factual basis needed to implement the refund methodology and order refunds. The FERC Administrative Law Judge presiding over this hearing recently announced that this information must be submitted not later than December 7, 2001, and the deadline for completion of the hearing is March 8, 2002. While it is not possible to predict the amount of any refunds until the hearings take place, based upon the information available at this time, the Company does not believe that this proceeding will result in a material adverse effect on the Company's financial position or results of operations.
Other Subsequent Events
On October 2, 2001, the Company announced that Moody's Investors Service upgraded the Company's corporate and credit and senior unsecured notes to Baa3, which is investment grade rating, from Ba1.
On October 16, 2001, the Company acquired California Energy General Corporation and CE Newburry, Inc. from MidAmerican Energy Holdings Company for an undisclosed amount. The transaction includes the companies' geothermal resource assets, contracts, leases and development opportunities associated with the Glass Mountain Known Geothermal Resource Area ("Glass Mountain KGRA") located in Siskiyou County, California, approximately 30 miles south of the Oregon border. These purchases are directly related to the Company's plans to develop the 49.5-megawatt Fourmile Hill Geothermal Project located in the Glass Mountain KGRA. The Fourmile Hill project is in advanced development and is projected to be online by late 2004. Power from the project is committed to the Bonneville Power Administration ("BPA") under a 20-year contract and will be delivered within BPA's northern California service territory.
On October 16, 2001, the Company completed offerings of $530 million in aggregate principal amount of 8.500% Senior Notes Due 2008 issued by Calpine Canada Energy Finance ULC and guaranteed by the Company (a reopening of senior notes previously issued in April 2001), and $850 million in aggregate principal amount of 8.500% Senior Notes Due 2011 issued by the Company directly (a reopening of senior notes previously issued in February 2001).
On October 18, 2001, the Company completed an offering of C$200 million in aggregate principal amount of 8.750% Senior Notes Due 2007 issued by its wholly owned subsidiary Calpine Canada Energy Finance ULC and guaranteed by the Company, and completed offerings of L200 million in aggregate principal amount of 8.875% Senior Notes Due 2011 and E175 million in aggregate principal amount of 8.375% Senior Notes Due 2008 issued by its wholly owned subsidiary Calpine Canada Energy Finance II ULC and guaranteed by the Company. Proceeds from the offerings will be used to refinance existing bridge loan financings incurred to fund recently completed transactions, finance the development and construction of additional power generation facilities and for working capital and general corporate purposes.
On October 18, 2001, the Company completed sale/leaseback transactions for the Southpoint, Broad River and RockGen facilities raising $800.0 million in sale/ leaseback proceeds. In connection with these transactions, Calpine Corporation provided a guarantee for the obligations under the leases. The lessors issued lessor notes with an aggregate principal amount of $654.5 million, which was funded by the proceeds from the issuance of pass through certificates. In effect, the pass through certificates evidence the debt component of these sale/ leaseback transactions. The pass through certificates were issued in two tranches: the first, consisting of $454.5 million in aggregate principal amount of 8.4% Series A Certificates due May 30, 2012, and the second, consisting of $200 million in aggregate principal amount of 9.825% Series B Certificates due May 30, 2019. Proceeds from the sale/leasebacks will be used to refinance outstanding borrowings under the Company's construction loan facilities, certain project-specific debt and other indebtedness, and for working capital and general corporate purposes.
October 22, 2001, the Company acquired the remaining 14% of the voting stock of Michael Petroleum Corporation for approximately $41.9 million.
On November 5, 2001, the Company acquired Highland Energy Company from Entergy Power Gas Operations Corporation and Louis Morrison III for an undisclosed amount.
On November 6, 2001, the Company acquired Bechtel Enterprises Holdings, Inc.'s 50% interest in the Delta Energy Center, the Metcalf Energy Center and the Russell City Energy Center for approximately $154 million and the assumption of approximately $141 million of debt.
On November 9, 2001, Enron Corporation announced a pending acquisition by Dynegy Inc. after a series of adverse developments. See Note 11 for further discussion.
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. You 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
17
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 risks associated with 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 or (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. You are also cautioned that the California energy market remains uncertain. The Company's 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 possible that any such outcome will include changes in government regulations, business and contractual relationships or other factors that could materially affect the Company; however, the Company believes that a final resolution of the situation in the California energy market will not have a material adverse impact on the Company. For example, Pacific Gas and Electric Company ("PG&E"), which is in bankruptcy, has recently agreed with the Company to assume all of the Company's Qualifying Facility ("QF") contracts. You are also referred to the other risks identified from time to time in the Company's reports and registration statements filed with the Securities and Exchange Commission.
18
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 and nine months ended September 30, 2001, respectively, as compared to the same periods in 2000, primarily due to the consolidation of acquisitions and increased production. The results for the nine months ended September 30, 2001, as compared to the same period in 2001, benefited from favorable energy pricing. Electricity revenue is composed of fixed capacity payments, which are not related to production, and variable energy payments, which are related to production. Capacity revenue includes, 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 (revenues in thousands).

                                                          THREE MONTHS ENDED SEPTEMBER 30,    NINE MONTHS ENDED SEPTEMBER 30,
                                                          --------------------------------    -------------------------------
                                                               2001             2000              2001          2000
                                                           ------------      -----------       -----------   -----------
Adjusted electricity and steam ("E & S") revenues:
   Energy (1)....................................         $    754,674       $  400,448        $ 1,561,227   $   725,777
   Capacity......................................         $    179,482       $  154,893        $   424,805   $   299,694
   Thermal and other.............................         $     43,339       $   34,383        $   117,544   $    69,079
   Megawatt hours generated.........................        13,687,401        7,049,078         28,804,105    16,108,267
   All-in electricity price per megawatt hour generated..      $ 71.42          $ 83.66            $ 73.03       $ 67.95	

(1) Adjusted to include spread on sales of purchased power (See Note 10).
19
Megawatt hours produced at the power plants increased 94% and 79% for the three and nine months ended September 30, 2001, respectively, as compared to the same periods in 2000. This was primarily due to the addition of power plants that were either acquired or commenced commercial operation subsequent to September 30, 2000.
Results of Operations
Three Months Ended September 30, 2001, Compared to Three Months Ended September 30, 2000
Revenue -- Total revenue increased to $2,916.1 million for the three months ended September 30, 2001, compared to $744.8 million for the same period in 2000.
Electric generation and marketing revenue increased to $2,755.6 million in 2001 compared to $643.8 million in 2000. Approximately $125.5 million of the $2,111.8 million variance was due to electricity and steam sales, which increased due to our growing portfolio. Our revenue for the period ended September 30, 2001, includes the consolidated results of additional facilities that we acquired or completed construction on subsequent to September 30, 2000. Our power marketing revenue (sales of purchased power) grew by $1,972.8 million due to increased price hedging and optimization activity as a result of the growth of our subsidiary, Calpine Energy Services, LP ("CES"), and our operating plant portfolio during the three months ended September 30, 2001. We also recognized $13.6 million in mark to market gains on power derivatives. This gain resulted from entering into an undesignated derivative contract in a market area where we do not have generating assets and therefore the contract was neither a hedge nor a normal purchase or sale.
Oil and gas production and marketing revenue increased to $139.4 million in 2001 compared to $92.9 million in 2000. The increase is due to a $46.9 million increase in marketing activities relating to purchased gas sold to third parties in hedging, balancing and related transactions.
Other revenue increased to $14.3 million in 2001 compared to $1.0 million in 2000. This increase is due primarily to $4.0 million recognized in 2001 from our custom turbine parts manufacturing subsidiary, Power Systems Mfg., LLC ("PSM"), which was acquired in December 2000, $2.6 million in interest income on loans to power projects, and $4.6 million in commissioning services related to our Delta Energy Center ("Delta") joint venture.
Cost of revenue -- Cost of revenue increased to $2,380.2 million in 2001 compared to $418.6 million in 2000. Approximately $1,710.5 million of the $1,961.6 million increase relates to the cost of power purchased by our energy services organization. Similarly, oil and gas production and marketing expense grew by $41.1 million, largely due to $52.9 million of expense for the cost of gas purchased by our energy services organization, compared to $9.4 million in the third quarter of 2000, this was offset by a $2.4 million decrease in oil and gas production expense. Fuel expense increased 74%, from $185.6 million in 2000 to $322.1 million in 2001, due to a 94% increase in megawatt hours generated and increased fuel prices. Depreciation expense increased by 55%, from $59.1 million in the third quarter of 2000 to $91.5 million in the third quarter of 2001, due to additional power facilities in consolidated operations at September 30, 2001 as compared to the same period in 2000, and due to $10.4 million in higher depreciation and depletion in our oil and gas operating subsidiaries.
Project development expense -- Project development expense decreased 20% due to several projects moving from early to late stage development during the three months ended September 30, 2001.
General and administrative expense -- General and administrative expense increased 6% to $29.9 million for the three months ended September 30, 2001, as compared to $28.1 million for the same period in 2000. The increase was 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. This was offset by a decrease in cash bonus accruals to reflect a higher mix of stock options in the Company's incentive program for management.
Interest expense -- Interest expense increased 71% to $49.7 million for the three months ended September 30, 2001, from $29.1 million for the same period in 2000. Interest expense increased primarily due to the issuances of $250.0 million of Senior Notes Due 2005 in August 2000, $750.0 million of Senior Notes Due 2010 in August 2000, $1.15 billion of Senior Notes Due 2011 in February 2001 and $1.5 billion of Calpine Canada Energy Finance ULC Senior Notes Due 2008 in April 2001. The associated incremental interest expense was partially offset by interest capitalized in connection with our growing construction portfolio.
20
Distributions on trust preferred securities -- Distributions on trust preferred securities increased 21% to $15.4 million for the three months ended September 30, 2001, compared to $12.7 million for the corresponding months in 2000. The increase is attributable to a full period of distributions in 2001 on the August 2000 offering.
Interest income -- Interest income increased to $21.1 million for the three months ended September 30, 2001, compared to $15.9 million for the same period in 2000. This increase is due to interest income on the PG&E receivable.
Other income (expense)-- Other income (expense) increased to $7.9 million in 2001 from $(1.2) million in 2000 primarily due to contingent income as the result of the sale of the Bayonne Power Plant and a gain on the sale of the Cessford property in Canada.
Provision for income taxes -- The effective income tax rate was approximately 31.0% and 40.2% for the three months ended September 30, 2001 and 2000, respectively. The decrease in rates was due to a year to date true-up in accordance with APB Opinion No. 28 to reflect our expansion into Canada and the United Kingdom and our cross border financings, which reduced our statutory tax rates.
Extraordinary charge, net -- The $1.2 million charge in 2000 represents the write-off of deferred financing costs related to the repayment of bridge financing and the Bank One, Texas, N.A. borrowing base facilities.
Nine Months Ended September 30, 2001, Compared to Nine Months Ended September 30, 2000
Revenue -- Total revenue increased to $5,868.7 million for the nine months ended September 30, 2001, compared to $1,447.2 million for the same period in 2000.
Electric generation and marketing revenue increased to $5,063.0 million in 2001 compared to $1,191.5 million in 2000. Approximately $719.8 million of the $3,871.5 million variance was due to electricity and steam sales, which increased due to our growing portfolio and favorable energy pricing. Our revenue for the period ended September 30, 2001, includes the consolidated results of additional facilities that we acquired or completed construction on subsequent to September 30, 2000. Our power marketing activities contributed an additional $3,068.4 million due to increased price hedging and optimization activity as a result of the growth of CES and our operating plant portfolio during the nine months ended September 30, 2001. We also recognized $83.3 million in mark to market gains on power derivatives. Almost all of this gain resulted from entering into undesignated derivative contracts where we do not have generating assets and therefore such contracts were neither hedges nor normal purchases or sales.
Oil and gas production and marketing revenue increased to $768.3 million in 2001 compared to $229.5 million in 2000. Approximately $386.5 million of the increase is due to marketing activities relating to purchased gas sold to third parties in hedging, balancing and related transactions. Additionally, approximately $152.3 million of the variance relates to increased production and commodity prices in sales to third parties from reserves acquired in Canada and the United States.
Income from unconsolidated investments in power projects decreased to $9.0 million in 2001 compared to $21.8 million during 2000. The variance is primarily due to the contractual reduction in distributions from the Sumas Power Plant of approximately $12.3 million.
Other revenue increased to $28.4 million in 2001 compared to $4.4 million in 2000. This increase is due primarily to $10.4 million recognized in 2001 from PSM, $5.9 million in commissioning services related to Delta and a $5.4 million increase in interest income on loans to power projects.
Cost of revenue -- Cost of revenue increased to $4,753.0 million in 2001 compared to $903.1 million in 2000. Approximately $2,779.2 million of the $3,849.9 million increase relates to the cost of power purchased by our energy services organization. Similarly, oil and gas production and marketing expense grew by $384.1 million, largely due to a $365.2 million increase in expense for the cost of gas purchased and resold by our energy services organization. Fuel expense increased 122%, from $363.3 million in 2000 to $807.5 million in 2001, due to a 79% increase in megawatt hours generated and a significant increase in fuel price. Depreciation expense increased by 52%, from $154.9 million in the first nine months of 2000 to $235.7 million in the first nine months of 2001, due to additional power facilities in operation in 2001 and due to $40.6 million in higher depreciation and depletion in our oil and gas operating subsidiaries. Operating lease expense increased by $36.9 million due to leases entered into or acquired in connection with our Pasadena, Tiverton, Rumford, KIAC, West Ford Flat and Bear Canyon facilities during and subsequent to the period ended September 30, 2000.
21
Project development expense -- Project development expense increased 67% due to an increase of projects in the early stage of development.
General and administrative expense -- General and administrative expense increased 103% to $116.5 million for the nine months ended September 30, 2001, as compared to $57.3 million for the same period in 2000. The increase was 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. This increase was offset by a decrease in cash bonus accruals to reflect a higher mix of stock options in the Company's incentive program for management.
Merger Expense -- We incurred approximately $41.6 million of expense in the nine months ended September 30, 2001, in connection with the merger with Encal Energy Ltd. on April 19, 2001. The transaction was accounted for under the pooling-of-interests method and, accordingly, all transaction costs have been expensed as incurred and all periods presented have been restated to reflect the transaction.
Interest expense -- Interest expense increased 64% to $113.0 million for the nine months ended September 30, 2001, from $69.0 million for the same period in 2000. Interest expense increased primarily due to the issuances of $250.0 million of Senior Notes Due 2005 in August 2000, $750.0 million of Senior Notes Due 2010 in August 2000, $1.15 billion of Senior Notes Due 2011 in February 2001 and $1.5 billion of Energy Finance Senior Notes Due 2008 in April 2000. The associated incremental interest expense was partially offset by interest capitalized in connection with our growing construction portfolio.
Distributions on trust preferred securities -- Distributions on trust preferred securities increased 60% to $45.9 million for the first nine months in 2001 compared to $28.7 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 period of distributions in 2001 on the January 2000 offering and the subsequent exercise of the initial purchasers' option to purchase additional securities.
Interest income -- Interest income increased to $61.0 million for the nine months ended September 30, 2001, compared to $29.1 million for the same period in 2000. This increase is due primarily to the significantly higher cash balances that we have maintained as a result of our senior notes and convertible securities offerings during the first and second quarters of 2001. This increase is also due to interest income on the PG&E receivable.
Other income (expense) -- Other income (expense) increased to $16.9 million in 2001 from $(1.4) million in 2000 primarily due to a gain on the sale of our interests in the Elwood development project, the Cessford property in Canada and the Bayonne Power Plant including related contingent income recognized as earned thereafter.
Provision for income taxes -- The effective income tax rate was approximately 35.6% and 40.4% for the nine months ended September 30, 2001 and 2000, respectively. The decrease in rates was due to a year to date true-up in accordance with APB Opinion No. 28 to reflect our expansion into Canada and the United Kingdom and our cross border financings, which reduced our statutory tax rates.
Extraordinary charge, net -- The $1.3 million charge in 2001 was a result of writing off unamortized deferred financing costs related to the repayment of $105.0 million 9 1/4% Senior Notes Due 2004. The $1.2 million charge in 2000 represents the write-off of deferred financing costs related to the repayment of bridge financing and the Bank One, Texas, N.A. borrowing base facilities.
Cumulative effect of a change in accounting principle -- The $1.0 million of additional income, net of tax, is due to the adoption in 2001 of Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities," amended by SFAS No. 137 and SFAS No. 138 ("SFAS No. 133").
Liquidity and Capital Resources
To date, we have obtained cash from our operations; borrowings under our credit facilities and other working capital lines; sales of debt, equity, trust preferred securities and convertible debentures; and proceeds from project financing. We have 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. We expect that neither the California energy crisis nor the problems that Enron Corp. has experienced will have a material adverse effect on the Company's liquidity. As such, with the exception of our receivables from the California Independent System Operator Corporation and Automated Power Exchange, Inc., we have not reserved for any other California receivables. See Note 11 for further discussion. On October 2, 2001, Moody's Investors Service upgraded our corporate credit and senior unsecured notes to Baa3, which is investment grade rating, from Ba1. We expect to continue to have access to the capital markets to fund our substantial growth program.
22
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 combines our expertise in design, engineering, procurement, finance, construction management, fuel and resource acquisition, operations, risk management and power marketing, to provide 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 November 12, 2001, we had 30 projects under construction, representing an additional 17,065 megawatts of net capacity. Included in these 30 projects are 4 project expansions, representing 734 megawatts of net capacity. We have also announced plans to develop 31 additional power generation projects, representing a net capacity of 17,569 megawatts. Included in these 31 development projects are 6 expansion projects representing 592 megawatts.
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 expense and fuel cost. This will become even more significant as our portfolio of power generation facilities expands to 87 power plants with a net capacity of 28,150 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.
Overview
The Company is engaged in the development, acquisition, ownership, and operation of power generation facilities and the sale of electricity and steam in the United States, Canada and the United Kingdom. At November 12, 2001, we had interests in 61 operating power plants representing 11,085 megawatts of net capacity.

ACQUISITIONS
-----------------------------------------------------------------------------------------------------------------------------
Date           Description                                             Seller                          Price
-----------------------------------------------------------------------------------------------------------------------------
8/1/01        Announced agreement to purchase remaining 50%           Edison Mission Energy     $35 million
              equity interest in Gordonsville Power Plant

8/15/01       Acquired 86% of the voting stock of Michael             Shareholders of Michael   $273.6 million and
              Petroleum Corporation                                   Petroleum Corporation     assumption of
                                                                                                 $54.5 million of debt

8/24/01       Acquired the 1,200-megawatt Saltend Energy Centre       Entergy Corporation       US$814.4 million
                                                                                                (at exchange rates at the
                                                                                                closing of the acquisition)

9/12/01       Acquired remaining 33.3% interests in Hog Bayou         Intergen                  $9.6 million
              and Pine Bluff Energy Centers                          (North America), Inc.

9/20/01       Acquired 100% interest in the 250-megawatt Island       Westcoast Energy Inc.     US$212.1 million
              Cogeneration facility and 50% interest in the                                     (at exchange rates at the
              50-megawatt Whitby Cogeneration facility                                          closing of the acquisition)

10/16/01      Acquired California Energy General Corporation          MidAmerican Energy        undisclosed amount
              and CE Newburry, Inc.                                   Holdings Company

10/22/01      Acquired the remaining 14% of the voting stock          Shareholders of Michael   $41.9 million
              of Michael Petroleum Corporation                        Petroleum Corporation

11/5/01       Acquired Highland Energy Company                        Entergy Power Gas         undisclosed amount
                                                                      Operations Corporation
                                                                      and Louis Morrison III

11/6/01       Acquired remaining 50% interest in Delta                Bechtel Enterprises       Approximately
              Energy Center, Metcalf Energy Center and                Holdings, Inc.            $154 million and the
              Russell City Energy Center                                                        assumption of approximately
                                                                                                $141 million of debt	

FINANCE
------------------------------------------------------------------------------------------------------------------
Offerings of Senior Notes:
------------------------------------------------------------------------------------------------------------------
Date               Offering                       Rate        Due            Issuer
------------------------------------------------------------------------------------------------------------------
10/16/01           US $530 million                 8.500%      2008          Calpine Canada Energy Finance ULC
10/16/01           US $850 million                 8.500%      2011          Calpine Corporation
10/18/01           C$200 million                   8.750%      2007          Calpine Canada Energy Finance ULC
10/18/01           L200 million                    8.875%      2011          Calpine Canada Energy Finance II ULC
10/18/01           E175 million                    8.375%      2008          Calpine Canada Energy Finance II ULC	

Sale/Leaseback Transactions:
-----------------------------------------------------------------------------------------
Date               Proceeds                  Facility
-----------------------------------------------------------------------------------------

10/18/01           $800.0 million            South Point Energy Center, Broad River
                                             Energy Center and RockGen Energy Center	

Other:
------------------------------------------------------------------------------------------------------------
Date             Description
------------------------------------------------------------------------------------------------------------
9/28/01          Announced the amendment of certain provisions of the Stockholder Rights Agreement

10/2/01          Moody's Investors Service upgraded corporate credit and senior unsecured notes
                 of Calpine to Baa3 from Ba1	

POWER PLANT DEVELOPMENT AND CONSTRUCTION
-----------------------------------------------------------------------------------------------------------------------------
Date           Project                                                             Description
-----------------------------------------------------------------------------------------------------------------------------
7/2/01         Sutter Energy Center                                                Announced commercial operation

7/9/01         Los Medanos Energy Center                                           Announced initial operation

7/10/01        500-megawatt Otay Mesa Generating Project located in San            Acquired from the PG&E National Energy Group
               Diego County, California

7/11/01        600-megawatt Russell City Energy Center located in Hayward,         Application for Certification ("AFC") met the
               California                                                          California Energy Commission's ("CEC")
                                                                                   data adequacy requirements; approved for
                                                                                   expedited review

7/11/01        180-megawatt Los Esteros Critical Energy Facility located in        Announced plans for development
               San Jose, California

7/11/01        Hog Bayou Energy Center                                             Announced commercial operation

7/16/01        Aries Power Project                                                 Announced simple-cycle operation

7/17/01        900-megawatt Sherry Energy Center located in Wood County,           Announced plans for development
               Wisconsin

7/30/01        Channel Energy Center                                               Announced simple-cycle operation

8/24/01        540-megawatt Wawayanda Energy center located in the town of         Announced filing of Article X Application
               Wawayanda, New York

9/5/01         Broad River Energy Center                                           Announced commercial operation of 350-megawatt
                                                                                   expansion

9/24/01        Pine Bluff Energy Center                                            Announced commercial operation

9/24/01        Metcalf Energy Center                                               CEC voted unanimously to approve the
                                                                                   construction and operation

10/16/01       49.5-megawatt Fourmile Hill Geothermal Project in the Glass         Announced plans for development
               Mountain Known Geothermal Resource Area in California

11/1/01        905-megawatt Palmetto Energy Center located in South Carolina       Announced plans for development

11/1/01        1,100-megawatt Central Valley Energy Center located in              Announced filing of AFC with the CEC
               San Joaquin, California	

TURBINE PURCHASES
-------------------------------------------------------------------------------------------------------------------------
Date of Announcement           Turbines               Manufacturer                               Delivery Dates
-------------------------------------------------------------------------------------------------------------------------
8/9/01                         27 steam turbines      Siemens Westinghouse                       2002 through 2005
8/22/01                        19 steam turbines      Toshiba International Corporation          2002 through 2005	

MANAGEMENT DEVELOPMENTS
----------------------------------------------------------------------------------------------------------------------------
Date of Announcement           Individual                        Description
----------------------------------------------------------------------------------------------------------------------------
7/16/01                        Michael Polsky                    Resignation from the Board of Directors and as an
                                                                 officer of the Company

7/17/01                        Gerald Greenwald                  Appointment to the Board of Directors

11/5/01                        David Johnson                     Resignation as President and Chief Executive Officer
                                                                 of Calpine Canada	

Enron Corporation -- See Risk Factors for discussion of acquisition by Dynegy Inc. and recent adverse developments.
California Power Market -- The deregulation of the California power market has produced significant unanticipated results in the past year and a half. The deregulation froze the rates that utilities can charge their retail and business customers in California, until recent rate increases approved by the California Public Utilities Commission ("CPUC"), and prohibited the utilities from buying power on a forward basis, while wholesale power prices were not subjected to limits.
In the past year and a half, a series of factors have reduced the supply of power to California, which has resulted in wholesale power prices that for a period from mid 2000 to spring 2001 were 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 during 2000, 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 were subject to the retail rate freeze, including PG&E, have faced wholesale prices that far exceeded the retail prices they were permitted to charge. This led to significant under-recovery of costs by these utilities. As a consequence, these utilities defaulted under a variety of contractual obligations, including payment obligations to power generators. PG&E has defaulted on payment obligations to the Company under its long-term QF contracts, which are subject to federal regulation under the Public Utility Regulatory Policies Act of 1978, as amended ("PURPA"). The PG&E QF contracts are in place at eleven of our facilities and represent nearly 600 megawatts of electricity for Northern California customers.
PG&E Bankruptcy Proceedings -- 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 $265.6 million in accounts receivable with PG&E under our QF contracts, plus $68.7 million in notes receivable not yet due and payable. As of September 30, 2001, we had recorded $292.1 million in accounts receivable (the pre-petition amount of $265.6 and associated $6.0 million in interest income are classified as a long-term receivable) and $105.6 million in notes receivable not yet due and payable. We are currently selling power to PG&E pursuant to our long-term QF contracts, and PG&E is paying on a current basis for these purchases since its bankruptcy filing. With respect to the receivables recorded under these contracts, we announced on July 6, 2001, that we had entered into a binding agreement with PG&E to modify all of our QF contracts with PG&E and that, based upon such modification, PG&E had agreed to assume all of the QF contracts. Under the terms of this agreement, we will continue to receive our contractual capacity payments under the QF contracts, plus a five-year fixed energy price component that averages 5.37 cents per kilowatt-hour in lieu of the short run avoided cost. In addition, all past due receivables under the QF contracts will be elevated to administrative priority status in the PG&E bankruptcy proceeding and will be paid to the Company, with interest, upon the effective date of a confirmed plan of reorganization. Administrative claims enjoy priority over payments made to the general unsecured creditors in bankruptcy. The bankruptcy court approved the agreement on July 12, 2001. On September 20, 2001, PG&E filed its proposed plan of reorganization with the bankruptcy court. This plan is consistent with the agreement between the Company and PG&E described above. We cannot predict when the bankruptcy court will confirm a plan of reorganization for PG&E, but anticipate that it will be at least twelve months following September 30, 2001.
CPUC Proceedings Regarding QF Contract Pricing -- Our QF contracts with PG&E provide that the CPUC has the authority to determine the appropriate utility "avoided cost" to be used to set energy payments for certain QF contracts, including those for all of our QF plants in California which sell power to PG&E.
Section 390 of the California Public Utility Code provides 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 (R.99-11-022) to determine whether the PX Price was the appropriate price for the energy component upon which to base payments to QFs which had elected the PX-based pricing option. The CPUC has issued a proposed decision to the effect that the PX price was the appropriate price for energy payments under the California Public Utility Code. However, a final decision has not been issued to date. Therefore, 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.
On March 28, 2001, the CPUC issued an order (Decision 01-03-067) (the "March 2001 Decision") proposing to change, on a prospective basis, the composition of the short run avoided cost ("SRAC") energy price formula, which is reset monthly, used by the California utilities in QF contracts. Prior to the March 2001 Decision, CPUC regulations calculated SRAC based on 50% Topock and 50% Malin border gas indices. In the March 2001 Decision, the CPUC changed this formulation to eliminate the prices at Topock from the SRAC formula. The March 2001 Decision is subject to challenges at the CPUC and the Federal Energy Regulatory Commission ("FERC").
On June 14, 2001, however, the CPUC issued an order (Decision 01-06-015) (the "June 2001 Decision") that authorized the California utilities, including PG&E, to amend QF contracts to elect a fixed energy price component that averages 5.37 cents per kilowatt-hour for a five-year term under those contracts in lieu of using the SRAC energy price formula. By this order, the CPUC authorized the QF contract energy price amendments without further CPUC concurrence. As part of the agreement we entered into with PG&E pursuant to which PG&E, in bankruptcy, agreed to assume its QF contracts with us, PG&E agreed with us to amend these contracts to adopt the fixed price component, that averages 5.37 cents pursuant to the June 2001 Decision. This election became effective as of July 16, 2001. As a result of the June 2001 Decision and our agreement with PG&E to amend the QF contracts to adopt the fixed price energy component, the energy price component in our QF contracts is now fixed for five years and we are no longer subject to any uncertainty that may have existed with respect to this component of our QF contract pricing as a result of the March 2001 Decision. Further, the March 2001 Decision has no bearing on PG&E's agreement with us to assume the QF contracts in bankruptcy or on the amount of the receivable that was so assumed. As such, we have not reserved our PG&E receivables.
California Long-Term Supply Contracts -- 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 in a publicly announced auction. Calpine successfully bid in that auction and signed several 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, which increases to 1,000 megawatts by January 1, 2004. The electricity will be sold directly to DWR on a 24 hours-a-day, 7 days-a-week basis.
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 10-year, $5.2 billion fixed-price contract, we committed to sell up to 1,000 megawatts of generation. Initial deliveries began 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.
FERC Investigation into California Wholesale Markets -- On June 19, 2001, FERC ordered price mitigation in 11 states in the western United States in an attempt to reduce the dependence of the California market on spot markets in favor of longer-term committed energy supplies. The order provides for price mitigation in the spot market throughout the 11 state western region during "reserve deficiency hours," which is when operating reserves in California fall below seven percent. This price will be a single market clearing price based upon the marginal operating cost of the last unit dispatched by the California ISO. In addition, FERC implemented price mitigation in non-reserve deficiency hours, which will be set at 85% of the market clearing price during the last reserve deficiency period. These price mitigation procedures went into effect on June 20, 2001, and will remain in effect until September 30, 2002.
The retention by FERC of a market-based, rather than a cost-of-service-based, rate structure, will enable us to continue to realize benefits from our efficient, modern power plants. We believe that Calpine's marginal costs will continue to be below any price cap imposed by FERC, whether during reserve deficiency hours or at other times. Therefore, we believe that FERC's mitigation plan will not have a material adverse effect on Calpine's financial condition or results of operations.
FERC also ordered all sellers and buyers in wholesale power markets administered by the California ISO, as well as representatives of the State of California, to participate in a settlement conference before a FERC administrative judge. The settlement discussions were intended to resolve all issues that remain outstanding to resolve past accounts, including sellers' claims for unpaid invoices, and buyers' claims for refunds of alleged overcharges, for past periods. The settlement discussions began on June 25, 2001, and ended on July 9, 2001. The Chief Administrative Law Judge issued his report and recommendations to FERC on July 12, 2001. On July 25, 2001, FERC ordered an expedited fact-finding hearing to calculate refunds for spot market transactions in California. The hearing has been delayed pending the submission by the California ISO and the PX of data for the purpose of developing the factual basis needed to implement the refund methodology and order refunds. The FERC Administrative Law Judge presiding over this hearing recently announced that this information must be submitted not later than December 7, 2001, and the deadline for completion of the hearing is March 8, 2002. While it is not possible to predict the amount of any refunds until the hearings take place, based upon the information available at this time, we do not believe that this proceeding will result in a material adverse effect on the Company's financial condition or results of operations.
Risk Factors
Enron Corporation -- In 2001 the Company, primarily through our CES subsidiary, has transacted a significant volume of business with units of Enron Corp ("Enron"). Most of these transactions are contracts for sales and purchases of power and gas for hedging and optimization purposes, some of which extend out as far as 2009. In October and November of 2001, Enron announced a series of developments including restatement of the last four years of earnings, an investigation by the Securities and Exchange Commission relating to the adequacy of Enron's disclosures of certain off-balance sheet financial transactions or structures and dismissals of certain members of senior management. Additionally, there have been downgrades of its debt by the rating agencies and press reports about liquidity concerns. These developments have culminated in press reports on November 9, 2001 that Enron has agreed to be acquired by Dynegy Inc. ("Dynegy"), a competitor of both Enron and the Company. The acquisition is reported to involve an imminent significant infusion of cash into Enron by ChevronTexaco Corporation, which is reported to hold a 26.5% interest in Dynegy.
For the three and nine months ended September 30, 2001, $767.9 million or 26.3% and $1,329.8 million or 22.7%, of our revenue was with Enron subsidiaries, primarily Enron Power Marketing, Inc. ("EPMI") and Enron North America Corp. ("ENA"). We, primarily our subsidiary, CES, purchases significant amounts of fuel and power from ENA and EPMI, giving rise to current accounts payable and open contract fair value positions. For the three months ended September 30, 2001, CES had fuel and power purchases from ENA and EPMI of $905.3 million. For the nine months ended September 30, 2001, CES had fuel and power purchases from ENA and EPMI of $1,358.7 million. These purchases must be included in an overall understanding of our Enron exposure. The sales to and purchases from various Enron subsidiaries are mostly hedging and optimization transactions, and in most cases the purchases and sales are not related and should not be netted to try to gauge the profitability of transactions with Enron subsidiaries.
ENA is the parent corporation of EPMI. Enron is the direct or indirect parent corporation of ENA. In assessing our exposure to Enron subsidiaries and affiliates, we analyze our accounts receivable and accounts payable balances on contracts that have already settled and also the fair value (mark to market value) of the contracts that have not settled. In the event of a default by one or more of the Enron subsidiaries and affiliates, we might terminate some or all of the open contracts, in which case we would have an exposure to realize the fair value of the positive ("in the money") contracts. In managing the overall credit exposure to each other, Calpine and Enron have entered into a netting agreement in which they net or offset overall mark to market exposures from all transactions between certain Enron subsidiaries and CES to liabilities between those entities.
See Footnote 11 for our accounts receivable (payable) balances as well as the fair value of our open contracts with Enron subsidiaries and affiliates at November 12, 2001. We had no net exposure at November 12, 2001. Additionally, our Enron exposure is mitigated as we have open positions with Citrus Trading Corp., which is 50% owned by El Paso Corporation. As such, a reserve is not needed.
Our treasury department includes a credit group focused on monitoring and managing counterparty risk. The credit group monitors the net exposure with each counterparty on a daily basis. The analysis is performed on a mark to market basis using the forward curves audited by our Risk Controls group. The net exposure is compared against a counterparty credit risk threshold which is determined based on the counterparty's credit ratings, evaluation of the financial statements and bond values. The credit department monitors these thresholds to determine the need for additional collateral or an adjustment to activity with the counterparty.
We will continue to evaluate the Enron risk in the same manner as discussed above. We will adjust our threshold for Enron exposure based on factors discussed above and continue to monitor the exposure on a daily basis.
CPUC Proceedings Regarding QF Contract Pricing -- Our QF contracts with PG&E provide that the CPUC has the authority to determine the appropriate utility "avoided cost" to be used to set energy payments for certain QF contracts, including those for all of our QF plants in California which sell power to PG&E.
Section 390 of the California Public Utility Code provides QFs the option to elect to receive energy payments based on the PX market clearing price. In mid 2000, our QF facilities elected this option and were paid based upon the 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 (R.99-11-022) to determine whether the PX Price was the appropriate price for the energy component upon which to base payments to QFs which had elected the PX-based pricing option. The CPUC has issued a proposed decision to the effect that the PX price was the appropriate price for energy payments under the California Public Utility Code. However, a final decision has not been issued to date. Therefore, 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.
On March 28, 2001, the CPUC issued an order (Decision 01-03-067) (the "March 2001 Decision") proposing to change, on a prospective basis, the composition of the short run avoided cost ("SRAC") energy price formula, which is reset monthly, used by the California utilities in QF contracts. Prior to the March 2001 Decision, CPUC regulations calculated SRAC based on 50% Topock and 50% Malin border gas indices. In the March 2001 Decision, the CPUC changed this formulation to eliminate the prices at Topock from the SRAC formula. The March 2001 Decision is subject to challenges at the CPUC and the FERC.
23
On June 14, 2001, however, the CPUC issued an order (Decision 01-06-015) (the "June 2001 Decision") that authorized the California utilities, including PG&E, to amend QF contracts to elect a fixed energy price component that averages 5.37 cents per kilowatt-hour for a five-year term under those contracts in lieu of using the SRAC energy price formula. By this order, the CPUC authorized the QF contract energy price amendments without further CPUC concurrence. As part of the agreement we entered into with PG&E pursuant to which PG&E, in bankruptcy, agreed to assume its QF contracts with us, PG&E agreed with us to amend these contracts to adopt the fixed price component that averages 5.37 cents pursuant to the June 2001 Decision. This election became effective as of July 16, 2001. As a result of the June 2001 Decision and our agreement with PG&E to amend the QF contracts to adopt the fixed price energy component, the energy price component in our QF contracts is now fixed for five years and we are no longer subject to any uncertainty that may have existed with respect to this component of our QF contract pricing as a result of the March 2001 Decision. Further, the March 2001 Decision has no bearing on PG&E's agreement with us to assume the QF contracts in bankruptcy or on the amount of the receivable that was so assumed. As such, we have not reserved our PG&E receivables.
FERC Investigation into California Wholesale Markets -- On June 19, 2001, FERC ordered price mitigation in 11 states in the western United States in an attempt to reduce the dependence of the California market on spot markets in favor of longer-term committed energy supplies. The order provides for price mitigation in the spot market throughout the 11-state western region during "reserve deficiency hours," which is when operating reserves in California fall below seven percent. This price will be a single market clearing price based upon the marginal operating cost of the last unit dispatched by the California ISO. In addition, FERC implemented price mitigation in non-reserve deficiency hours, which will be set at 85% of the market clearing price during the last reserve deficiency period. These price mitigation procedures went into effect on June 20, 2001, and will remain in effect until September 30, 2002.
The retention by FERC of a market-based, rather than a cost-of-service-based, rate structure, will enable us to continue to realize benefits from our efficient, modern power plants. We believe that Calpine's marginal costs will continue to be below any price cap imposed by FERC, whether during reserve deficiency hours or at other times. Therefore, we believe that FERC's mitigation plan will not have a material adverse effect on Calpine's financial condition or results of operations.
FERC also ordered all sellers and buyers in wholesale power markets administered by the California ISO, as well as representatives of the State of California, to participate in a settlement conference before a FERC administrative judge. The settlement discussions were intended to resolve all issues that remain outstanding to resolve past accounts, including sellers' claims for unpaid invoices, and buyers' claims for refunds of alleged overcharges, for past periods. The settlement discussions began on June 25, 2001, and ended on July 9, 2001. The Chief Administrative Law Judge issued his report and recommendations to FERC on July 12, 2001. On July 25, 2001, FERC ordered an expedited fact-finding hearing to calculate refunds for spot market transactions in California. The hearing has been delayed pending the submission by the California ISO and the California Power Exchange of data for the purpose of developing the factual basis needed to implement the refund methodology and order refunds. The FERC Administrative Law Judge presiding over this hearing recently announced that this information must be submitted not later than December 7, 2001, and the deadline for completion of the hearing is March 8, 2002. While it is not possible to predict the amount of any refunds until the hearings take place, based upon the information available at this time, we do not believe that this proceeding will result in a material adverse effect on Calpine's financial condition or results of operations.
Financial Market Risks
Short-term investments -- As of September 30, 2001, we had short-term investments of $137.7 million. These short-term investments consist of highly liquid investments with maturities of 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.
Interest rate swaps and forward interest rate agreements -- From time to time, we use interest rate swap agreements to mitigate our exposure to interest rate fluctuations. We do not use interest rate swap agreements for speculative or trading purposes. The following table summarizes the fair market value of our existing interest rate swap agreements as of September 30, 2001 (dollars in thousands):

                                                 WEIGHTED
                                   NOTIONAL      AVERAGE
                                   PRINCIPAL     INTEREST          FAIR
          MATURITY DATE             AMOUNT         RATE        MARKET VALUE
          -------------            ---------     --------      ------------
2007........................        $38,103       8.0%           $(6,216)
2007........................         38,103       8.0             (6,199)
2007........................         29,757       7.9             (5,025)
2007........................         29,757       7.9             (5,009)	

24

2008........................          300,000          5.0             (9,446)
2008........................          100,000          4.9             (2,943)
2008........................           50,000          4.8             (1,094)
2009........................           15,000          6.9             (1,593)
2011........................           54,434          6.9             (5,683)
2011........................          250,000          5.1             (7,634)
2012........................          119,385          6.5            (11,743)
2014........................           70,528          6.7             (6,969)
2015........................           22,500          7.0             (3,225)
2018........................           17,500          7.0             (2,692)
                                   ----------         ----        -----------
         Total..............       $1,135,067          5.8%       $   (75,471)
                                   ==========         ====        ===========	

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 No. 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):

                                                        CHANGE IN FAIR
                                                          VALUE FROM
                                                          10% ADVERSE
                                        FAIR VALUE       PRICE CHANGE
                                      -------------     --------------
At September 30, 2001:
     Crude oil ...................    $       2,688      $      (5,797)
     Electricity..................          469,307            (75,340)
     Natural gas..................         (592,424)          (123,930)
                                      -------------      -------------
         Total....................    $    (120,429)     $    (205,067)
                                      ==============     =============	

Derivative commodity instruments included in the table are those included in Note 8 to the unaudited Consolidated Condensed Financial Statements. The fair value of derivative commodity instruments included in the table is based on present value adjusted quoted market prices of comparable contracts. During the nine months ended September 30, 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.
The primary factors affecting the fair value of the Company's derivatives at any point in time are (1) the volume of open derivative positions (MMBtu and Mwh), and (2) changing commodity market prices, principally for electricity and natural gas. The total volume of open gas derivative positions increased 29% from June 30, 2001 to September 30, 2001, while the total volume of open power derivative positions increased 175% for the same period. In that prices for electricity and natural gas are among the most volatile of all commodity prices, there may be material changes in the fair value of the Company's derivatives over time, driven both by price volatility and the increases in volume of open derivative transactions. Under SFAS No. 133, the change since the last balance sheet date in the total value of the derivatives (both assets and liabilities) is reflected either in OCI, net of tax, or in the statement of operations as an item (gain or loss) of current earnings. As of September 30, 2001, the majority of the balance in accumulated OCI represented the unrealized net loss associated with commodity cash flow hedging transactions. As noted above, there is a substantial amount of volatility inherent in accounting for the fair value of these derivatives, and the Company's results during 2001 have reflected this. See Note 8 for additional information on derivative activity and also the Form 8-K filed on September 5, 2001 for a further discussion of the Company's accounting policies related to derivative accounting.
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk.
See "Financial Market Risks" in ITEM 2.
PART II - OTHER INFORMATION
ITEM 1. Legal Proceedings.
Litigation -- An action was filed against Lockport Energy Associates, L.P. and the New York Public Service Commission ("NYPSC") in August 1997 by New York State Electricity and Gas Company ("NYSEG") in the Federal District Court for the Northern District of New York. NYSEG requested the Court to direct NYPSC and FERC to modify contract rates to be paid to the Lockport Power Plant. In October 1997, NYPSC filed a cross-claim alleging that the FERC violated the Public Utility Regulatory Policies Act of 1978, as amended ("PURPA"), and the Federal Power Act by failing to reform the NYSEG contract that was previously approved by the NYPSC. On September 29, 2000, the New York Federal District Court dismissed NYSEG's complaint and NYPSC's cross-claim. The Court stated that FERC has no authority to alter or waive its regulations or exemptions to alter the terms of the applicable power purchase agreements and that Qualifying Facilities are entitled to the benefit of their bargain, even if at the expense of NYSEG and its ratepayers. NYSEG has filed an appeal with respect to this decision. In any event, the Company retains the right to require The Brooklyn Union Gas Company to purchase its interest in the Lockport Power Plant for $18.9 million, less equity distributions received by the Company, at any time before December 19, 2001. On October 5, 2001, the United States Court of Appeals affirmed the judgment of the federal district court and dismissed all of the claims raised by NYSEG against Lockport.
The Company is involved in various other claims and legal actions arising out of the normal course of business. The Company does not expect that the outcome of these proceedings will have a material adverse effect on the Company's financial position or results of operations.
ITEM 2. Changes in Securities and Use of Proceeds.
On April 19, 2001, Calpine 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 Calpine's subsidiary, Calpine Canada Holdings Ltd. A total of 16,603,633 exchangeable shares were issued to Encal shareholders in exchange for their Encal common stock. Each exchangeable share is exchangeable for one share of Calpine common stock until April 19, 2002, at which date all remaining exchangeable shares will automatically be exchanged for shares of Calpine common stock.
The exchangeable shares and the underlying shares of Calpine common stock were issued without registration under the Securities Act of 1933 in reliance upon the exemption afforded by Section 3(a)(10) thereby. While no shares of Calpine common stock were issued to Encal shareholders as part of the closing of the acquisition on April 19, 2001, exchanges have been occurring from time to time since that date. Calpine is hereby reporting the issuance of all 16,603,633 shares of Calpine common stock underlying the exchangeable shares, although some exchangeable shares remain unconverted at this time.
ITEM 4. Submission of Matters to a Vote of Security Holders.
As previously reported, on July 16, 2001, we announced that Michael Polsky had resigned from the Board of Directors and on July 17, 2001, we announced the appointment of Gerald Greenwald to the Board of Directors.
ITEM 6. Exhibits and Reports on Form 8-K.
(a) Exhibits
25
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. (a)

  *2.2          Amending Agreement to the Combination Agreement, dated as of March
                16, 2001, between Calpine Corporation and Encal Energy Ltd. (b)

  *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 (c)

  *3.2          Certificate of Correction of Calpine Corporation (d)

  *3.3          Certificate of Amendment of Amended and Restated Certificate of
                Incorporation of Calpine Corporation (e)

  *3.4          Certificate of Designation of Series A Participating Preferred Stock of
                Calpine Corporation (d)

  *3.5          Amended Certificate of Designation of Series A Participating Preferred Stock of
                Calpine Corporation (d)

  *3.6          Amended Certificate of Designation of Series A Participating Preferred Stock of
                Calpine Corporation (e)

  *3.7          Certificate of Designation of Special Voting Preferred Stock of Calpine Corporation(m)

  *3.8          Amended and Restated By-laws of Calpine Corporation (f)

  *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(g)

  *4.4          First Supplemental Indenture dated as of September 28, 2000, between Calpine Corporation
                and Wilmington Trust Company, as Trustee(h)

  *4.5          Indenture dated as of April 25, 2001, between Calpine Canada
                Energy Finance ULC and Wilmington Trust Company, as Trustee (i)

  *4.6          Guarantee Agreement dated as of April 25, 2001, by Calpine Corporation
                as guarantor of debt securities of Calpine Canada Energy Finance ULC (j)

  *4.7          Amended and Restated Indenture dated as of October 16, 2001, between
                Calpine Canada Energy Finance ULC and Wilmington Trust Company, as Trustee (j)

  *4.8          First Amendment to Guarantee Agreement dated as of October 16, 2001, between
                Calpine Corporation and Wilmington Trust Company (j)

  *4.9          Indenture dated as of October 18, 2001, between Calpine Canada Energy
                Finance II ULC and Wilmington Trust Company, as Trustee (j)

  *4.10         First Supplemental Indenture dated as of October 18, 2001, between Calpine
                Canada Energy Finance II ULC and Wilmington Trust Company, as Trustee (j)

  *4.11         Guarantee Agreement dated as of October 18, 2001, between Calpine
                Corporation and Wilmington Trust Company (j)

  *4.12         First Amendment to Guarantee Agreement dated as of October 18, 2001,
                between Calpine Corporation and Wilmington Trust Company (j)

  *4.13         Rights Agreement, dated as of June 5, 1997, between Calpine Corporation
                and First Chicago Trust Company of New York, as Rights Agent (k)

  *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 (l)	

* Incorporated by reference.
(a) Incorporated by reference to Calpine Corporation's Quarterly Report on Form 10-Q dated June 30, 2001 and filed on August 14, 2001 (File No. 1-12079).
(b) Incorporated by reference to Calpine Corporation's Registration Statement on Form S-3/A (File No. 333-56712).
(c) Incorporated by reference to Calpine Corporation's Registration Statement on Form S-3 (File No. 333-40652).
(d) 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.
(e) Incorporated by reference to Calpine Corporation's Registration Statement on Form S-3 (File No. 333-66078).
(f) Incorporated by reference to Calpine Corporation's Registration Statement on Form S-3/A (File No. 333-67446).
(g) Incorporated by reference to Calpine Corporation's Registration Statement on Form S-3/A (File No. 333-72583).
26
(h) 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).
(i) Incorporated by reference to Calpine Corporation's Registration Statement on Form S-3/A (File No. 333-57338).
(j) Incorporated by reference to Calpine Corporation's Current Report on Form 8-K dated October 16, 2001 and filed on November 13, 2001 (File No. 001-12079).
(k) Incorporated by reference to Calpine Corporation's Registration Statement on Form 8-A/A filed with the SEC on September 28, 2001 (File No. 001-12079).
(l) 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.
(m) Incorporated by reference to Calpine Corporation's Quarterly Report on Form 10-Q dated March 31, 2001 and filed on May 15, 2001 (File No. 001-12079).
(b) Reports on Form 8-K
The registrant filed the following reports on Form 8-K during the quarter ended September 30, 2001:

DATE OF REPORT                     DATE FILED            ITEM REPORTED
--------------                     ----------          ---------------
July 6, 2001                     July 9, 2001               5, 7
July 12, 2001                    July 13, 2001              5, 7
July 16, 2001                    July 17, 2001              5, 7
July 26, 2001                    July 27, 2001              5, 7
August 14, 2001                  September 5, 2001             5
December 31, 2000                September 10, 2001         5, 7
September 19, 2001               September 28, 2001         5, 7	

27
 
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: November 14, 2001
      ------------------------------------------
      Ann B. Curtis
      Executive Vice President
      (Chief Financial Officer)

By:   /s/ Charles B. Clark, Jr.                                    Date: November 14, 2001
      ----------------------------------------------
      Charles B. Clark, Jr.
      Senior Vice President and Corporate Controller
      (Chief Accounting Officer)	

28
The following exhibits are filed herewith unless otherwise indicated:
EXHIBIT INDEX

 EXHIBIT
  NUMBER                                 DESCRIPTION
--------                                 -----------
  *2.1          Combination Agreement, dated as of February 7, 2001, by and between
                Calpine Corporation and Encal Energy Ltd. (a)

  *2.2          Amending Agreement to the Combination Agreement, dated as of March
                16, 2001, between Calpine Corporation and Encal Energy Ltd. (b)

  *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 (c)

  *3.2          Certificate of Correction of Calpine Corporation (d)

  *3.3          Certificate of Amendment of Amended and Restated Certificate of
                Incorporation of Calpine Corporation (e)

  *3.4          Certificate of Designation of Series A Participating Preferred Stock of
                Calpine Corporation (d)

  *3.5          Amended Certificate of Designation of Series A Participating Preferred Stock of
                Calpine Corporation (d)

  *3.6          Amended Certificate of Designation of Series A Participating Preferred Stock of
                Calpine Corporation (e)

  *3.7          Certificate of Designation of Special Voting Preferred Stock of
                Calpine Corporation (m)

  *3.8          Amended and Restated By-laws of Calpine Corporation (f)

  *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(g)

  *4.4          First Supplemental Indenture dated as of September 28, 2000, between Calpine Corporation
                and Wilmington Trust Company, as Trustee(h)

  *4.5          Indenture dated as of April 25, 2001, between Calpine Canada
                Energy Finance ULC and Wilmington Trust Company, as Trustee (i)

  *4.6          Guarantee Agreement dated as of April 25, 2001, by Calpine Corporation
                as guarantor of debt securities of Calpine Canada Energy
                Finance ULC (j)

  *4.7          Amended and Restated Indenture dated as of October 16, 2001, between
                Calpine Canada Energy Finance ULC and Wilmington Trust Company, as Trustee (j)

  *4.8          First Amendment to Guarantee Agreement dated as of October 16, 2001, between
                Calpine Corporation and Wilmington Trust Company (j)

  *4.9          Indenture dated as of October 18, 2001, between Calpine Canada Energy
                Finance II ULC and Wilmington Trust Company, as Trustee (j)

  *4.10         First Supplemental Indenture dated as of October 18, 2001, between Calpine
                Canada Energy Finance II ULC and Wilmington Trust Company, as Trustee (j)

  *4.11         Guarantee Agreement dated as of October 18, 2001, between Calpine
                Corporation and Wilmington Trust Company (j)

  *4.12         First Amendment to Guarantee Agreement dated as of October 18, 2001,
                between Calpine Corporation and Wilmington Trust Company (j)

  *4.13         Rights Agreement, dated as of June 5, 1997, between Calpine Corporation
                and First Chicago Trust Company of New York, as Rights Agent (k)

  *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 (l)	

* Incorporated by reference.
(a) Incorporated by reference to Calpine Corporation's Quarterly Report on Form 10-Q dated June 30, 2001 and filed on August 14, 2001 (File No. 1-12079).
(b) Incorporated by reference to Calpine Corporation's Registration Statement on Form S-3/A (File No. 333-56712).
(c) Incorporated by reference to Calpine Corporation's Registration Statement on Form S-3 (File No. 333-40652).
(d) 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.
(e) Incorporated by reference to Calpine Corporation's Registration Statement on Form S-3 (File No. 333-66078).
(f) Incorporated by reference to Calpine Corporation's Registration Statement on Form S-3/A (File No. 333-67446).
(g) Incorporated by reference to Calpine Corporation's Registration Statement on Form S-3/A (File No. 333-72583).
(h) 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).
(i) Incorporated by reference to Calpine Corporation's Registration Statement on Form S-3/A (File No. 333-57338).
(j) Incorporated by reference to Calpine Corporation's Current Report on Form 8-K dated October 16, 2001 and filed on November 13, 2001 (File No. 001-12079).
(k) Incorporated by reference to Calpine Corporation's Registration Statement on Form 8-A/A filed with the SEC on September 28, 2001 (File No. 001-12079).
(l) 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.
(m) Incorporated by reference to Calpine Corporation's Quarterly Report on Form 10-Q dated March 31, 2001 and filed on May 15, 2001 (File No. 001-12079).