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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Form 10-Q

Commission file number: 1-12079

Calpine Corporation

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

50 West San Fernando Street

      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.

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

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

      381,260,990 shares of Common Stock, par value $.001 per share, outstanding on June 27, 2003

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CALPINE CORPORATION AND SUBSIDIARIES

REPORT ON FORM 10-Q

INDEX

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PART I — FINANCIAL INFORMATION

CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED BALANCE SHEETS

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

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CALPINE CORPORATION AND SUBSIDIARIES

(1)	See Note 2 to Consolidated Condensed Financial Statements regarding the restatement of financial statements.

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

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CALPINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(1)	See Note 2 to Consolidated Condensed Financial Statements regarding the restatement of financial statements.

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

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CALPINE CORPORATION AND SUBSIDIARIES

      Calpine Corporation (“Calpine”), a Delaware corporation, and subsidiaries (collectively, the “Company”) is engaged in the generation of electricity in the United States of America, Canada and the United Kingdom. The Company is involved in the development, construction, ownership and operation of power generation facilities and the sale of electricity and its by-product, thermal energy, primarily in the form of steam. 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 of America. In Canada, the Company owns oil and gas operations and has ownership interests in, and operates, power facilities. In the United Kingdom, the Company owns and operates a gas-fired power cogeneration facility. 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 power cogeneration facilities is primarily sold to industrial users. Gas produced, and not physically delivered to the Company’s generating plants, is sold to third parties.

      Restatement of Prior Period Financial Statements — The accompanying financial statements reflect certain restatements of first quarter 2002 amounts, which were included in and described in the Company’s Annual Report on Form 10-K (“Annual Report” or “Form 10-K”) for the year ended December 31, 2002. Subsequent to the issuance of the Company’s Consolidated Condensed Financial Statements as of March 31, 2002, the Company determined that the sale/leaseback transactions for its Pasadena and Broad River facilities should have been accounted for as financing transactions, rather than as sales with operating leases as had been the accounting previously afforded such transactions. Accordingly, these two transactions were restated as financing transactions and the proceeds were classified as debt and the operating lease payments were recharacterized as debt service payments in the accompanying Consolidated Condensed Financial Statements. The Company is therefore now accounting for the assets as if they had not been sold. The assets were added back to the Company’s property, plant and equipment, and depreciation has been recorded thereon.

      In addition the Company has reclassified certain amounts in the accompanying Consolidated Condensed Financial Statements for the three months ended March 31, 2002, to reflect the adoption of new accounting standards. The reclassifications include (a) treatment as discontinued operations pursuant to SFAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets” of the 2002 sales of certain oil and gas properties and the DePere Energy Center, (b) the reclassification of revenues and costs associated with certain energy trading contracts to trading revenues, net, pursuant to Emerging Issues Task Force (“EITF”) Issue No. 02-3, “Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities” and (c) the adoption of SFAS No. 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections” to reclassify gains or losses from extinguishment of debt from extraordinary gain or loss to other income or loss.

      In October 2002 the EITF released EITF Issue No. 02-3, which precludes mark-to-market accounting for all energy trading contracts not within the scope of SFAS No. 133 and mandates that gains and losses on derivative instruments within the scope of SFAS No. 133 should be shown net in the income statement if the derivative instruments are held for trading purposes. EITF Issue No. 02-3 has had no impact on the Company’s net income but did affect the presentation of the prior period Consolidated Financial Statements. Accordingly, the Company reclassified certain prior period revenue amounts and cost of revenue in its Consolidated Statements of Operations. The reclassification of the financial information in accordance with

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SFAS No. 144, SFAS No. 145 and EITF Issue No. 02-3 discussed above relates exclusively to the presentation and classification of such amounts and has no effect on net income.

      To properly account for the two sale/leaseback transactions as financing transactions, to record certain other adjustments, and to reflect the adoption of new accounting standards as described above, the accompanying Consolidated Condensed Financial Statements for the three months ended March 31, 2002, have been restated and differ from amounts previously reported in the Company’s Quarterly Report on Form 10Q for the quarter ended March 31, 2002.

      A summary of the significant effects of restatement, along with certain reclassification adjustments, to the consolidated condensed statement of operations for the three months ended March 31, 2002 is as follows:

      For further information on prior period restatement items, please see Note 2 to the Consolidated Financial Statements included in the Company’s Annual report on Form 10-K for the year ended December 31, 2002.

      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. Certain information and note disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles in the United States of America have been condensed or omitted from these statements pursuant to such rules and regulations and, accordingly, these financial statements should be read in conjunction with the audited Consolidated Financial Statements of the Company for the year ended December 31, 2002, included in the Company’s Annual Report on Form 10-K. 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 of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expense during the reporting period. Actual results could differ from those estimates. The most significant estimates with regard to these financial statements relate to useful lives and carrying values of assets (including the carrying value of projects in development, construction and operation), provision for income taxes, fair value calculations of derivative instruments and associated reserves, capitalization of interest and depletion, depreciation and impairment of natural gas and petroleum property and equipment.

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      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 the Company’s cogeneration sites. In addition, the Company acquires and produces natural gas for its own consumption and sells the balance and oil produced to third parties. Where applicable, revenues are recognized under EITF No. 91-6, “Revenue Recognition of Long Term Power Sales Contracts,” ratably over the terms of the related contracts. To protect and enhance the profit potential of its electric generation plants, the Company, through its subsidiary, Calpine Energy Services (“CES”), enters into electric and gas hedging, balancing, and optimization transactions, subject to market conditions, and CES has also, from time to time, entered into contracts considered energy trading contracts under EITF Issue No. 02-3. CES executes these transactions primarily through the use of physical forward commodity purchases and sales and financial commodity swaps and options. With respect to its physical forward contracts, CES generally acts as a principal, takes title to the commodities, and assumes the risks and rewards of ownership. Therefore, when CES does not hold these contracts for trading purposes and, in accordance with SAB No. 101 and EITF Issue No. 99-19, the Company records settlement of its non-trading physical forward contracts on a gross basis. Effective July 1, 2002, the Company changed its method of reporting gains and losses from derivatives held for trading purposes to a net basis. Prior to July 1, 2002, physical trading contracts were recorded on a gross basis but have been reclassified to a net basis to conform to the current presentation. The Company settles its financial swap and option transactions net and does not take title to the underlying commodity. Accordingly, the Company records gains and losses from settlement of financial swaps and options net within net income. Managed risks typically include commodity price risk associated with fuel purchases and power sales.

      The Company, through its wholly owned subsidiary, Power Systems Mfg., LLC (“PSM”), designs and manufactures certain spare parts for gas turbines, and through its Thomassen Turbine Systems (“TTS”) subsidiary provides turbine maintenance services to third parties. The Company also generates revenue by occasionally loaning funds to power projects, by providing operation and maintenance (“O&M”) services to third parties and to certain unconsolidated power projects, and by performing engineering services for data centers and other facilities requiring highly reliable power. The Company also has begun to sell engineering and construction services to third parties for power projects. Further details of the Company’s revenue recognition policy for each type of revenue transaction are provided below:

      Electric Generation and Marketing Revenue — This includes electricity and steam sales and sales of purchased power for hedging, balancing and optimization. Subject to market and other conditions, the Company manages the revenue stream for its portfolio of electric generating facilities. 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, through hedging, balancing and optimization transactions. The Company records revenues from generation sold under long-term contracts and generation liquidated into the market as electricity and steam sales. The Company records revenues from sales of power not sourced from the Company’s generation as sales of purchased power.

      Oil and Gas Production and Marketing Revenue — This includes sales to third parties of oil, gas and related products that are produced by the Company’s Calpine Natural Gas and Calpine Canada Natural Gas subsidiaries and, subject to market and other conditions, sales of purchased gas arising from hedging, balancing and optimization transactions. Oil and gas sales for produced products are recognized pursuant to the sales method, net of royalties. If the Company has recorded gas sales on a particular well or field in excess of its share of remaining estimated reserves, then the excessive gas sale imbalance is recognized as a liability. If the Company is under-produced on a particular well or field, and it is determined that an over-produced partner’s share of remaining reserves is insufficient to settle the gas imbalance, the Company will recognize a receivable, to the extent collectible, from the over-produced partner.

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      Trading Revenue, Net — This includes realized settlements of, and unrealized mark-to-market gains and losses on, both power and gas derivative instruments held for trading purposes or not designated as a hedge related to the Company’s generating assets in accordance with EITF 02-03, “Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities.” Gains and losses due to ineffectiveness on hedging instruments are also included in unrealized mark-to-market gains and losses.

      Other Revenue — This includes O&M contract revenue, PSM and TTS revenue from sales to third parties, engineering revenue and miscellaneous revenue.

      Purchased Power and Purchased Gas Expense — The cost of power purchased from third parties for hedging, balancing and optimization activities is recorded as purchased power expense, a component of electric generation and marketing expense. The Company records the cost of gas purchased from third parties for the purposes of consumption in its power plants as fuel expense, while gas purchased from third parties for hedging, balancing, and optimization activities is recorded as purchased gas expense for hedging and optimization, a component of oil and gas production and marketing expense.

      Derivative Instruments — SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” as amended and interpreted by other related accounting literature, establishes accounting and reporting standards for derivative instruments (including certain derivative instruments embedded in other contracts). SFAS No. 133 requires companies to record derivatives on their balance sheets as either assets or liabilities measured at their fair value unless exempted from derivative treatment as a normal purchase and sale. All changes in the fair value of derivatives are recognized currently in earnings unless specific hedge criteria are met, which requires that a company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting.

      SFAS No. 133 sets forth the accounting requirements for cash flow and fair value hedges. SFAS No. 133 provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of Other Comprehensive Income (“OCI”) and be reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, must be recognized currently in earnings. SFAS No. 133 provides that the changes in fair value of both derivatives designated as fair value hedges and the corresponding changes in the fair value of the hedged risk attributable to a recognized asset, liability, or unrecognized firm commitment be recorded in earnings. If the fair value hedge is effective, the amounts recorded will offset in earnings.

      Where the Company’s derivative instruments are subject to a master netting agreement and the criteria of FASB Interpretation (“FIN”) 39 “Offsetting of Amounts Related to Certain Contracts (An Interpretation of APB Opinion No. 10 and SFAS No. 105)” are met, the Company presents its derivative assets and liabilities on a net basis in its balance sheet. The Company has chosen this method of presentation because it is consistent with the way related mark-to-market gains and losses on derivatives are recorded in its Consolidated Condensed Statements of Operations and within OCI.

      In June 2001 the Financial Accounting Standards Board (“FASB”) issued SFAS No. 143, “Accounting for Asset Retirement Obligations”. SFAS No. 143 applies to fiscal years beginning after June 15, 2002, and amends SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies.” This standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development or normal use of the assets and requires that a liability for an asset retirement obligation be recognized when incurred, recorded at fair value and classified as a liability in the balance sheet. When the liability is initially recorded, the entity will capitalize the cost and increase the

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carrying value of the related long-lived asset. Asset retirement obligations represent future liabilities, and, as a result, accretion expense will be accrued on this liability until the obligation is satisfied. At the same time, the capitalized cost will be depreciated over the estimated useful life of the related asset. At the settlement date, the entity will settle the obligation for its recorded amount or recognize a gain or loss upon settlement.

      The Company adopted the new rules on asset retirement obligations on January 1, 2003. As required by the new rules, the Company recorded liabilities equal to the present value of expected future asset retirement obligations at January 1, 2003. The Company identified obligations related to operating gas-fired power plants, geothermal power plants and oil and gas properties. The liabilities are partially offset by increases in net assets, net of accumulated depreciation, recorded as if the provisions of SFAS 143 had been in effect at the date the obligation was incurred, which for power plants is generally the start of commercial operations for the facility.

      Based on current information and assumptions, the Company recorded, as of January 1, 2003, an additional long-term liability of $25.9 million, an additional asset within Property, plant and equipment, net of accumulated depreciation, of $26.9 million, and a pre-tax gain to income due to the cumulative effect of a change in accounting principle of $1.0 million. These entries include the effects of the reversal of site dismantlement and restoration costs previously expensed in accordance with SFAS No. 19.

      In June 2002 the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities,” which addresses accounting for restructuring and similar costs. SFAS No. 146 supersedes previous accounting guidance, principally EITF Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (Including Certain Costs Incurred in a Restructuring).” The Company has adopted, effective January 1, 2003, the provisions of SFAS No. 146 for restructuring activities initiated after December 31, 2002. SFAS No. 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. Under EITF No. 94-3, a liability for an exit cost was recognized at the date of commitment to an exit plan. SFAS No. 146 also establishes that the liability should initially be measured and recorded at fair value. Accordingly, SFAS No. 146 may affect the timing of recognizing future restructuring costs as well as the amounts recognized. SFAS No. 146 has not had a material impact on the Company’s Consolidated Condensed Financial Statements.

      In November 2002 the FASB issued Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others (“FIN 45”)”. This Interpretation addresses the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees. In addition, the Interpretation clarifies the requirements related to the recognition of a liability by a guarantor at the inception of a guarantee for the obligations that the guarantor has undertaken in issuing the guarantee. The Company adopted the disclosure requirements of FIN 45 for the fiscal year ended December 31, 2002, and the recognition provisions on January 1, 2003. Adoption of this Interpretation did not have a material impact on the Company’s Consolidated Condensed Financial Statements.

      On January 1, 2003, the Company prospectively adopted the fair value method of accounting for stock-based employee compensation pursuant to SFAS No. 123, “Accounting for Stock-Based Compensation” as amended by SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure.” SFAS No. 148 amends SFAS No. 123 to provide alternative methods of transition for companies that voluntarily change their accounting for stock-based compensation from the less preferred intrinsic value based method to the more preferred fair value based method. Prior to its amendment, SFAS No. 123 required that companies enacting a voluntary change in accounting principle from the intrinsic value methodology provided by Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees” could only do so on a prospective basis; no adoption or transition provisions were established to allow for a restatement of prior period financial statements. SFAS No. 148 provides two additional transition options to report the change in accounting principle — the modified prospective method and the retroactive restatement method. Additionally, SFAS No. 148 amends the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for

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stock-based employee compensation and the effect of the method used on reported results. The Company has elected to adopt the provisions of SFAS No. 123 on a prospective basis; consequently, the Company is required to provide a pro-forma disclosure of net income and earnings per share as if SFAS No. 123 accounting had been applied to all prior periods presented within its financial statements. As shown below, the adoption of SFAS No. 123 has had a material impact on the Company’s financial statements. The table below reflects the pro forma impact of stock-based compensation on the Company’s net income and earnings per share for the three months ended for March 31, 2003 and 2002, had the Company applied the accounting provisions of SFAS No. 123 to its prior years’ financial statements.

      The range of fair values of the Company’s stock options granted for the three months ended March 31, 2003 and 2002, respectively, was as follows, based on varying historical stock option exercise patterns by different levels of Calpine employees: $1.60-$3.43 in 2003, $3.83-$13.85 in 2002, on the date of grant using the Black-Scholes option pricing model with the following weighted-average assumptions: expected dividend yields of 0%, expected volatility of 70.44%-97.19% and 59.30%-65.09% for the three months ended March 31, 2003 and 2002, respectively, risk-free interest rates of 1.76%-4.04% and 4.61%-5.42% for the three months ended March 31, 2003 and 2002, respectively, and expected option terms of 2 1/2-9 1/2 years and 4-9 1/2 years for the three months ended March 31, 2003 and 2002, respectively.

      In January 2003 the FASB issued FIN 46, “Consolidation of Variable Interest Entities — an Interpretation of ARB No. 51”. FIN 46 establishes accounting, reporting and disclosure requirements for companies that currently hold unconsolidated investments in Variable Interest Entities (“VIEs”). FIN 46 defines VIEs as entities that meet one or both of two criteria: 1. the entity’s total equity at risk is deemed to be insufficient to finance its ongoing business activities without additional subordinated financial support from other parties, and/or, 2. as a collective group, the entity’s owners do not have a controlling financial interest in the entity, which effectively occurs if the voting rights to, or the entitlement to future returns or risk of future losses from the investment for each of the entity’s owners is inconsistent with the ownership percentages assigned to each owner within the underlying partnership agreement. If an investment is determined to be a VIE, further analysis must be performed to determine which of the VIE’s owners qualifies as the primary beneficiary. The primary beneficiary is the owner of the VIE that is entitled or at risk to earn or absorb the majority of the entity’s expected future returns or losses. An owner that is determined to be the primary beneficiary of a VIE is required to consolidate the VIE into its financial statements, as well as to provide certain disclosures regarding the size and nature of the VIE, the purpose for the investment, and information about the assets

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being held as collateral on behalf of the VIE. Additionally, the remaining owners of a VIE that do not qualify as the primary beneficiary must determine whether or not they hold significant variable interests within the VIE. An owner with a significant variable interest in a VIE that is not the primary beneficiary is not required to consolidate the VIE but must provide certain disclosures regarding the size and nature of the VIE, the purpose for the investment, its potential exposure to the VIE’s losses, and the date it first acquired ownership in the VIE. FIN 46 applies immediately to VIEs created or acquired after January 31, 2003. It applies in the first fiscal year or interim period beginning after June 15, 2003, to VIEs that were previously created or acquired before February 1, 2003. FIN 46 has not had a material impact on the Company’s Consolidated Condensed Financial Statements, as no VIEs were created during the first quarter of 2003. The Company has not completed its assessment of the impact of FIN 46 for VIE relationships prior to December 31, 2002.

      In April 2003 the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” SFAS No. 149 amends and clarifies financial reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities under SFAS No. 133. SFAS No. 149 clarifies under what circumstances a contract with an initial net investment meets the characteristic of a derivative, clarifies when a derivative contains a financing component, amends the definition of an underlying to conform it to language used in FIN 45, and amends certain other existing pronouncements. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003, and should be applied prospectively, with the exception of certain SFAS No. 133 implementation issues that were effective for all fiscal quarters prior to June 15, 2003. Any such implementation issues should continue to be applied in accordance with their respective effective dates. The Company does not believe that SFAS No. 149 will have a material impact on its financial statements.

      In May 2003 the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity”. SFAS No. 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. SFAS No. 150 applies specifically to a number of financial instruments that companies have historically presented within their financial statements either as equity or between the liabilities section and the equity section, rather than as liabilities. SFAS 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The Company has not completed its assessment of the impact of SFAS No. 150.

      In June 2003, the FASB issued Derivatives Implementation Group (“DIG”) Issue No. C20, “Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature.” DIG Issue No. C20 superseded DIG Issue No. C11 “Interpretation of Clearly and Closely Related in Contracts That Qualify for the Normal Purchases and Normal Sales Exception,” and specified additional circumstances in which a price adjustment feature in a derivative contract would not be an impediment to qualifying for the normal purchases and normal sales scope exception under SFAS No. 133. DIG Issue No. C20 is effective as of the first day of the fiscal quarter beginning after July 10, 2003, (i.e. October 1, 2003, for the Company) with early application permitted. It should be applied prospectively for all existing contracts as of the effective date and for all future transactions. In conjunction with initially applying the implementation guidance, DIG Issue No. C20 requires the recognition of a special transition adjustment for certain contracts containing a price adjustment feature based on a broad market index for which the normal purchases and normal sales scope exception had been previously elected. In those circumstances, the derivative contract should be recognized at fair value as of the date of the initial application with a corresponding adjustment of net income as the cumulative effect of a change in accounting principle.

      Certain of the Company’s power sales contracts, which meet the definition of a derivative and for which it previously elected the normal purchases and normal sales scope exception, use a CPI or similar index to escalate the O&M charges. Accordingly, DIG Issue No. C20 will require the Company to record a special transition accounting adjustment upon adoption of the new guidance to record these contracts at fair value

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with a corresponding adjustment to net income as the effect of a change in accounting principle. The fair value of these contracts will be based in large part on the nature and extent of the key price adjustment features of the contracts and market conditions on the date of adoption, such as the forward price of power and natural gas and the expected future rate of inflation. Although the final amount of the adjustment, if any, will not be known until actual adoption of DIG Issue No. C20, based upon contract values as of June 26, 2003, the Company estimates that it will recognize derivative assets of approximately $360 million, derivative liabilities of approximately $90 million and a cumulative effect adjustment to net income of approximately $200 million, net of tax. Assuming the contracts meet the new conditions for qualifying for the normal purchases and normal sales exception and the Company makes that election, the recorded balance for these contracts would reverse through charges to income over the life of the long term contracts, which extend out as far as the year 2020, as deliveries of power are made. To the extent any contract fails to meet the new requirements in DIG Issue No. C20 or the Company does not elect the scope exception, it would be required to recognize subsequent changes in the fair value of those contracts in earnings each period. The Company anticipates that it will adopt DIG Issue No. C20 on October 1, 2003. Upon adoption of DIG Issue No. C20, the Company expects, subject to further analysis, that most of its structured power sales contracts will meet the criteria for the normal purchases and sales exception under SFAS No. 133 and that it will make that election.

      Reclassifications — Prior period amounts in the Consolidated Condensed Financial Statements have been reclassified where necessary to conform to the 2003 presentation.

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

      Construction in Progress — Construction in progress (“CIP”) is primarily attributable to gas-fired power projects under construction including prepayments on gas and steam turbine generators and other long lead-time items of equipment for certain development projects not yet in construction. Upon commencement of plant operation, these costs are transferred to the applicable property category, generally buildings, machinery and equipment. Further detail of CIP is presented below under Capital Spending — Development and Construction.

      Capitalized Interest — The Company capitalizes interest on capital invested in projects during the advanced stages of development and the construction period in accordance with SFAS No. 34, “Capitalization

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of Interest Cost,” as amended by SFAS No. 58, “Capitalization of Interest Cost in Financial Statements That Include Investments Accounted for by the Equity Method (an Amendment of FASB Statement No. 34).” The Company’s qualifying assets include construction in progress, certain oil and gas properties under development, construction costs related to unconsolidated investments in power projects under construction, and advanced stage development costs. For the three months ended March 31, 2003 and 2002, the total amount of interest capitalized was $118.5 million and $163.1 million, respectively, including $19.6 million and $35.1 million, respectively, of interest incurred on funds borrowed for specific construction projects and $98.9 million and $128.0 million, respectively, of interest incurred on general corporate funds used for construction. Upon commencement of plant operation, capitalized interest, as a component of the total cost of the plant, is amortized over the estimated useful life of the plant. The decrease in the amount of interest capitalized during the three months ended March 31, 2003 reflects the completion of construction for several power plants and the result of the current suspension of certain of the Company’s development projects.

      In accordance with SFAS No. 34, the Company determines which debt instruments best represent a reasonable measure of the cost of financing construction assets in terms of interest cost incurred that otherwise could have been avoided. These debt instruments and associated interest cost are included in the calculation of the weighted average interest rate used for capitalizing interest on general funds. The primary debt instruments included in the rate calculation of interest incurred on general corporate funds, are the Company’s Senior Notes, the Company’s term loan facility and the $950 million secured working capital revolving credit facilities.

      Projects in Active Construction — The 21 projects in active construction are estimated to come on line from April 2003 to December 2005. These projects will bring on line approximately 8,900 and 10,700 MW of base load and base load with peaking capacity, respectively. Interest and other costs related to the construction activities necessary to bring these projects to their intended use are being capitalized. The estimated cost to complete these projects, net of expected project financing proceeds, is approximately $2.0 billion.

      Projects in Advanced Development — There are 11 projects in advanced development. Of the total amount capitalized approximately $642.3 million relates to equipment, primarily turbine progress payments. These projects will bring on line approximately 5,816 and 7,014 MW of base load and base load with peaking capacity, respectively. Interest and other costs related to the development activities necessary to bring these projects to their intended use are being capitalized. However, the capitalization of interest has been suspended on one project for which development activities are complete but construction will not commence until a power purchase agreement and financing are obtained. The estimated cost to complete these projects is approximately $3.5 billion. The Company’s current plan is to project finance these costs as power purchase agreements are arranged.

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      Suspended Development Projects — Due to current electric market conditions, the Company has ceased capitalization of additional development costs and interest expense on certain development projects on which work has been suspended. Capitalization of costs may recommence as work on these projects resumes, if certain milestones and criteria are met indicating that it is again highly probable that the costs will be recovered through future operations. As is true for all projects, the suspended projects are reviewed for impairment whenever there is an indication of potential reduction in a project’s fair value. Further, if it is determined that it is no longer probable that the projects will be completed and all capitalized costs recovered through future operations, the carrying values of the projects would be written down to the recoverable value. These projects would bring on line approximately 2,858 and 3,338 MW of base load and base load with peaking capacity, respectively. The estimated cost to complete these projects is approximately $1.4 billion. Of the amount capitalized approximately $308.6 million relates to equipment cost, primarily turbine progress payments.

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

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

      Unassigned Equipment — As of March 31, 2003, the Company had made progress payments on 9 turbines, 14 heat recovery steam generators, and other equipment with an aggregate carrying value of $147.9 million, that are not assigned to specific development and construction projects and which the Company is holding for potential use on future projects. It is possible that some of this unassigned equipment may eventually be sold, potentially in combination with the Company’s engineering and construction services. For equipment that is not assigned to development or construction projects, interest is not capitalized. The Company reviews the equipment for potential impairment by allocating a factor based on the probability that it will utilize it for future projects versus selling it. Then the Company reviews for impairment in the context of the equipment’s use in a future power facility. Utilizing this methodology, the Company does not believe that the equipment is impaired. However, during the second quarter of 2003, the Company recorded approximately $17.2 million in losses in connection with the sale of two turbines, and it may incur further losses should it decide to sell more equipment in the future.

      Impairment Evaluation — All active, construction and development projects, including unassigned turbines are reviewed for impairment whenever there is an indication of potential reduction in a project’s fair value. Equipment assigned to such projects is not evaluated for impairment separately, as it is integral to the assumed future operations of the project to which it is assigned. If it is determined that it is no longer probable that the projects will be completed and all capitalized costs recovered through future operations, the carrying values of the projects would be written down to the recoverable value in accordance with the provisions of FASB 144 “Accounting for Impairment or Disposal of Long-Lived Assets.”

4.     Acquisitions

      On February 26, 2003, the Company, through its wholly owned subsidiary, Calpine European Finance, purchased 100% of the outstanding stock of Babcock Borsig Power Turbine Services (“BBPTS”) from its parent company, Babcock Borsig. Immediately following the acquisition, the BBPTS name was changed to Thomassen Turbine Systems (“TTS”). The Company’s total cost of the acquisition was $12.0 million and was comprised of two pieces. The first was a $7.0 million cash payment to Babcock Borsig to acquire the outstanding stock of TTS. Included in this payment was the right to a note receivable valued at 11.9 million Euro (approximately US$12.9 million on the acquisition date) due from TTS, which the Company acquired

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from Babcock Borsig for $1. Additionally, as of the date of the acquisition, TTS owed $5.0 million in payments to another of the Company’s wholly owned subsidiaries, PSM, under a pre-existing license agreement. Because of the acquisition, TTS ceased to exist as a third party debtor to the Company, thereby resulting in a reduction of third party receivables of $5.0 million from the Company’s consolidated perspective.

5.     Goodwill and Other Intangible Assets

      On January 1, 2002, the Company adopted SFAS No. 142, “Goodwill and Other Intangible Assets,” which requires that all intangible assets with finite useful lives be amortized and that goodwill and intangible assets with indefinite lives not be amortized, but rather tested upon adoption and at least annually for impairment. The Company was required to complete the initial step of a transitional impairment test within six months of adoption of SFAS No. 142 and to complete the final step of the transitional impairment test by the end of the fiscal year. The Company completed both the transitional goodwill impairment test and the first annual goodwill impairment test as required during 2002 and determined that the fair value of the reporting units with goodwill exceeded their net carrying values. Therefore, the Company did not record any impairment expense during 2002. Consistent with the requirements of SFAS No. 142, the Company will perform an annual impairment test for 2003 during December, in conjunction with its annual reporting process.

      In accordance with the standard, the Company discontinued the amortization of its recorded goodwill as of January 1, 2002, and identified reporting units based on its current segment reporting structure and allocated all recorded goodwill, as well as other assets and liabilities, to the reporting units.

      Recorded goodwill, by segment, was (in thousands):

      The Company also reassessed the useful lives and the classification of its identifiable intangible assets and determined that they continue to be appropriate. The components of the amortizable intangible assets consist of the following (in thousands):

      Amortization expense of other intangible assets was $1.7 million and $6.0 million in the three months ended March 31, 2003 and 2002, respectively. Assuming no future impairments of these assets or additions as

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the result of acquisitions, amortization expense for the twelve months ended December 31 will be $5.4 million in 2003, $5.0 million in 2004, $4.9 million in 2005, $4.8 million in 2006 and $4.8 million in 2007.

6.     Financing

      On February 13, 2003, the Company completed a secondary offering of 17,034,234 Warranted Units of the Calpine Power Income Fund for gross proceeds of Cdn$153.3 million (US$100.9 million). The Warranted Units were sold to a syndicate of underwriters at a price of Cdn$9.00. Each Warranted Unit consists of one Trust Unit and one-half of one Trust Unit purchase warrant. Each Warrant entitles the holder to purchase one Trust Unit at a price of Cdn$9.00 per Trust Unit at any time on or prior to December 30, 2003, after which time the Warrant will be null and void. Assuming the exercise in full of the Warrants, Calpine will not own or control any of the outstanding Trust Units. However, Calpine will retain its 30% subordinated interest in the Canadian power generating assets and will continue to operate and manage the Calpine Power Income Fund and the Fund assets.

7.     Discontinued Operations

      As a result of the significant contraction in the availability of capital for participants in the energy sector, the Company has adopted a strategy of conserving its core strategic assets and selectively disposing of certain less strategically important assets, which serves primarily to raise cash for general corporate purposes and strengthen the Company’s balance sheet through repayment of debt. Set forth below are all of the Company’s asset disposals by reportable segment that impacted the Company’s Consolidated Condensed Financial Statements for the three months ended March 31, 2003:

      On August 29, 2002, the Company completed the sale of certain oil and gas properties (“Medicine River properties”) located in central Alberta to NAL Oil and Gas Trust and another institutional investor for Cdn$125.0 million (US$80.1 million). As a result of the sale, the Company recorded a pre-tax gain of $21.9 million in the third quarter 2002.

      On October 1, 2002, the Company completed the sale of substantially all of its British Columbia oil and gas properties to Calgary, Alberta-based Pengrowth Corporation for gross proceeds of approximately Cdn$387.5 million (US$244.3 million). Of the total consideration, the Company received US$155.9 million in cash. The remaining US$88.4 million of consideration was paid by Pengrowth Corporation’s purchase in the open market of US$203.2 million in aggregate principal amount of the Company’s debt securities. As a result of the transaction, the Company recorded a US$37.4 million pre-tax gain on the sale of the properties and a gain on the extinguishment of debt of US$114.8 million in the third quarter 2002. The Company used approximately US$50.4 million of cash proceeds to repay amounts outstanding under its US$1.0 billion term loan.

      On October 31, 2002, the Company sold all of its oil and gas properties in Drake Bay Field located in Plaquemines Parish, Louisiana for approximately $3 million to Goldking Energy Corporation. As a result of the sale, the Company recognized a pre-tax loss of $0.02 million in the third quarter 2002.

      On December 16, 2002, the Company completed the sale of the 180-megawatt DePere Energy Center in DePere, Wisconsin. The facility was sold to Wisconsin Public Service for $120.4 million, which included $72.0 million in cash at closing and a $48.4 million payment due in December 2003. As a result of the sale, the Company recognized a pre-tax gain of $35.8 million. On December 17, 2002, the Company sold its right to the December 2003 payment to a third party for $46.3 million, and recognized a pre-tax loss of $2.1 million.

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      All of the asset disposals above were completed by December 31, 2002, and the Company did not have any additional material disposals during the three months ended March 31, 2003. As a result, the Company did not have any assets designated as “held for sale” on its Consolidated Condensed Balance Sheet at March 31, 2003, and December 31, 2002, respectively, and the Company did not record any income from discontinued operations for the three months ended March 31, 2003.

      The table below presents significant components of the Company’s income from discontinued operations for the three months ended March 31, 2002 (in thousands):

      The Company allocates interest expense associated with consolidated non-specific debt to its discontinued operations based on a ratio of the net assets of its discontinued operations to the Company’s total consolidated net assets, in accordance with EITF Issue No. 87-24, “Allocation of Interest to Discontinued Operations” (“EITF Issue No. 87-24”). Also in accordance with EITF Issue No. 87-24, the Company allocated interest expense to its British Columbia oil and gas properties for approximately $50.4 million of debt the Company was required to repay under the terms of its $1.0 billion term loan. For the three months ended March 31, 2002, the Company allocated interest expense of $1.2 million to its discontinued operations.

      As an independent power producer primarily focused on generation of electricity using gas-fired turbines, the Company’s natural physical commodity position is “short” fuel (i.e., natural gas consumer) and “long” power (i.e., electricity seller). To manage forward exposure to price fluctuation in these and (to a lesser extent) other commodities, the Company enters into derivative commodity instruments. The Company enters into commodity 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 an extent with its own gas production position. Any hedging, balancing, or optimization activities that the Company engages in are directly related to the Company’s asset-based business model of owning and operating gas-fired electric power plants and are designed to protect the Company’s “spark spread” (the difference between the Company’s fuel cost and the revenue it receives for its electric generation). The Company hedges exposures that arise from the ownership and operation of power plants and related sales of electricity and purchases of natural gas, and the Company utilizes derivatives to optimize the returns it is able to achieve from these assets. From time to time the Company has entered into contracts considered energy trading contracts under EITF Issue No. 02-3. However, the Company’s traders have low capital at risk and value at risk limits for energy trading, and its risk management policy limits, at any given time, its net sales of power to its generation capacity and limits its net purchases of gas to its fuel consumption requirements on a total portfolio basis. This model is markedly different from that of companies that engage in significant commodity trading operations that are unrelated to underlying physical assets. Derivative commodity instruments are accounted for under the requirements of SFAS No. 133.

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      The Company also routinely enters into physical 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 purchases and sales exception. Some of those contracts that are not deemed normal purchases and sales can be designated as hedges of the underlying consumption of gas or production of electricity.

      The Company also enters into various interest rate swap agreements to hedge against changes in floating interest rates on certain of its 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.

      In conjunction with its capital markets activities, 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 various foreign currency swap agreements to hedge against changes in exchange rates on certain of its senior notes denominated in currencies other than the U.S. dollar. The foreign currency swaps effectively convert floating exchange rates into fixed exchange rates so that the Company can predict with greater assurance what its U.S. dollar cost will be for purchasing foreign currencies to satisfy the interest and principal payments on these senior notes.

      The table below reflects the amounts (in thousands) that are recorded as assets and liabilities at March 31, 2003, for the Company’s derivative instruments: