10-Q 1 o81401.txt SECOND QUARTER - 2001 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 June 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: 304,986,024 shares of Common Stock, par value $.001 per share, outstanding on August 13, 2001 CALPINE CORPORATION AND SUBSIDIARIES Report on Form 10-Q For the Quarter Ended June 30, 2001
INDEX Page No. PART I - FINANCIAL INFORMATION ITEM 1. Financial Statements. Consolidated Condensed Balance Sheets June 30, 2001 and December 31, 2000.................................................... 3 Consolidated Condensed Statements of Operations For the Three and Six Months Ended June 30, 2001 and 2000.............................. 4 Consolidated Condensed Statements of Cash Flows For the Six Months Ended June 30, 2001 and 2000........................................ 5 Notes to Consolidated Condensed Financial Statements June 30, 2001.......................................................................... 6 ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations..... 14 ITEM 3. Quantitative and Qualitative Disclosures About Market Risk................................ 25 PART II - OTHER INFORMATION ITEM 2. Change 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.......................................................... 26 Signatures.................................................................................................. 28
PART I - FINANCIAL INFORMATION ITEM 1. Financial Statements. CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED BALANCE SHEETS June 30, 2001 and December 31, 2000 (in thousands, except share and per share amounts) (unaudited)
June 30, December 31, 2001 2000 ------------ ------------ ASSETS Current assets: Cash and cash equivalents .................................................... $ 1,241,520 $ 596,077 Accounts receivable, net of allowance of $17,521 and $11,555 ................. 1,046,080 727,893 Inventories .................................................................. 56,615 44,456 Prepaid expense .............................................................. 77,239 27,515 Other current assets ......................................................... 1,087,610 41,165 ------------ ------------ Total current assets ...................................................... 3,509,064 1,437,106 ------------ ------------ Property, plant and equipment, net .............................................. 10,399,454 7,979,160 Investments in power projects ................................................... 261,189 205,621 Project development costs ....................................................... 92,001 38,597 Notes receivable ................................................................ 354,301 217,927 Restricted cash ................................................................. 97,949 88,618 Deferred financing costs ........................................................ 159,949 112,049 Other assets .................................................................... 1,145,158 244,125 ------------ ------------ Total assets .............................................................. $ 16,019,065 $ 10,323,203 ============ ============ LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Notes payable and borrowings under lines of credit, current portion .......... $ 1,258 $ 1,087 Accounts payable ............................................................. 914,960 843,641 Zero-Coupon Convertible Debentures Due 2021 .................................. 1,000,000 -- Project financing, current portion ........................................... 1,396 58,486 Capital lease obligation, current portion .................................... 2,251 1,985 Income taxes payable ......................................................... -- 63,409 Accrued payroll and related expense .......................................... 57,038 53,667 Accrued interest payable ..................................................... 126,130 77,878 Other current liabilities .................................................... 897,281 149,080 ------------ ------------ Total current liabilities ................................................. 3,000,314 1,249,233 ------------ ------------ Notes payable and borrowings under lines of credit, net of current portion ...... 10,587 455,067 Project financing, net of current portion ....................................... 1,776,435 1,473,869 Senior notes .................................................................... 5,096,750 2,551,750 Capital lease obligation, net of current portion ................................ 208,839 208,876 Deferred income taxes, net ...................................................... 768,057 620,807 Deferred lease incentive ........................................................ 58,989 60,676 Deferred revenue ................................................................ 102,581 92,511 Other liabilities ............................................................... 985,287 30,529 ------------ ------------ Total liabilities ......................................................... 12,007,839 6,743,318 ------------ ------------ Company-obligated mandatorily redeemable convertible preferred securities of subsidiary trusts ........................ 1,122,706 1,122,490 Minority interests .............................................................. 40,733 37,576 Stockholders' equity: Preferred stock, $.001 par value per share; authorized 10,000,000 shares; issued and outstanding none 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 304,162,586 shares in 2001 and 300,074,078 shares in 2000 ................. 304 300 Additional paid-in capital ................................................... 1,993,849 1,896,987 Retained earnings ............................................................ 775,223 547,895 Accumulated other comprehensive income (loss) ................................ 78,411 (25,363) ------------ ------------ Total stockholders' equity ................................................ 2,847,787 2,419,819 ------------ ------------ Total liabilities and stockholders' equity ................................ $ 16,019,065 $ 10,323,203 ============ ============ The accompanying notes are an integral part of these consolidated condensed financial statements.
CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS For the Three and Six Months Ended June 30, 2001 and 2000 (in thousands, except per share amounts) (unaudited)
Three Months Ended Six Months Ended June 30, June 30, -------------------------- -------------------------- 2001 2000 2001 2000 ----------- ----------- ----------- ----------- Revenue: Electric generation and marketing revenue ........................ $ 1,257,340 $ 341,611 $ 2,307,407 $ 547,679 Oil and gas production and marketing revenue ..................... 343,012 69,652 628,871 136,627 Income from unconsolidated investments in power projects ......... 1,600 4,843 2,163 14,617 Other revenue .................................................... 10,921 1,050 14,183 3,431 ----------- ----------- ----------- ----------- Total revenue ................................................ 1,612,873 417,156 2,952,624 702,354 ----------- ----------- ----------- ----------- Cost of revenue: Electric generation and marketing expense ........................ 731,497 78,722 1,283,232 131,607 Oil and gas production and marketing expense ..................... 245,638 25,104 398,549 55,543 Fuel expense ..................................................... 228,430 104,044 485,444 177,696 Depreciation expense ............................................. 72,144 50,702 144,157 95,815 Operating lease expense .......................................... 27,449 10,672 55,460 21,130 Other expense .................................................... 3,490 1,280 5,989 2,780 ----------- ----------- ----------- ----------- Total cost of revenue ........................................ 1,308,648 270,524 2,372,831 484,571 ----------- ----------- ----------- ----------- Gross profit ................................................. 304,225 146,632 579,793 217,783 Project development expense ......................................... 4,372 5,228 20,211 9,390 General and administrative expense .................................. 50,537 18,508 86,622 28,740 Nonrecurring merger cost ............................................ 35,606 -- 41,627 -- ----------- ----------- ----------- ----------- Income from operations ....................................... 213,710 122,896 431,333 179,653 Other expense (income): Interest expense ................................................. 43,331 18,202 63,256 39,955 Distributions on trust preferred securities ...................... 15,387 9,085 30,562 16,063 Interest income .................................................. (20,531) (5,615) (39,889) (13,177) Other expense (income), net ...................................... (3,291) 178 (9,018) (380) ----------- ----------- ----------- ----------- Income before provision for income taxes ..................... 178,814 101,046 386,422 137,192 Provision for income taxes .......................................... 69,849 41,538 158,830 56,583 ----------- ----------- ----------- ----------- Income before extraordinary charge and cumulative effect of a change in accounting principle .............................. 108,965 59,508 227,592 80,609 Extraordinary charge, net of tax benefit of $834 .................... (1,300) -- (1,300) -- Cumulative effect of a change in accounting principle ............... -- -- 1,036 -- ----------- ----------- ----------- ----------- Net income ................................................... $ 107,665 $ 59,508 $ 227,328 $ 80,609 =========== =========== =========== =========== Basic earnings per common share: Weighted average shares of common stock outstanding ............ 302,729 271,505 301,641 270,516 Income before extraordinary charge and cumulative effect of a change in accounting principle .............................. $ 0.36 $ 0.22 $ 0.75 $ 0.30 Extraordinary charge ........................................... $ -- $ -- $ -- $ -- Cumulative effect of a change in accounting principle .......... $ -- $ -- $ -- $ -- ----------- ----------- ----------- ----------- Net income ..................................................... $ 0.36 $ 0.22 $ 0.75 $ 0.30 =========== =========== =========== =========== Diluted earnings per common share: Weighted average shares of common stock outstanding before dilutive effect of certain convertible securities ............. 318,255 287,271 317,544 286,439 Income before dilutive effect of certain convertible securities, extraordinary charge and change in accounting principle ....... $ 0.34 $ 0.21 $ 0.72 $ 0.28 Dilutive effect of certain convertible securities (1) .......... $ (0.02) $ (0.01) $ (0.04) $ -- ----------- ----------- ----------- ----------- Income before extraordinary charge and cumulative effect of a change in accounting principle .............................. $ 0.32 $ 0.20 $ 0.68 $ 0.28 Extraordinary charge ........................................... $ -- $ -- $ -- $ -- Cumulative effect of a change in accounting principle .......... $ -- $ -- $ -- $ -- ----------- ----------- ----------- ----------- Net income ..................................................... $ 0.32 $ 0.20 $ 0.68 $ 0.28 =========== =========== =========== =========== (1) Includes the effect of the assumed conversion of certain convertible securities. For the three and six months ended June 30, 2001, the assumed conversion calculation adds 41,964 and 49,379 shares of common stock and $7,507 and $20,838 to the net income results, representing the after tax expense on certain convertible securities avoided upon conversion. For the three and six months ended June 30, 2000, the assumed conversion calculation adds 18,912 shares of common stock and $2,439 and $4,878 to the net income results. The accompanying notes are an integral part of these consolidated condensed financial statements.
CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS For the Six Months Ended June 30, 2001 and 2000 (in thousands) (unaudited)
Six Months Ended June 30, 2001 2000 ----------- ----------- Cash flows from operating activities: Net income ........................................ $ 227,328 $ 80,609 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization .................. 148,552 102,893 Deferred income taxes, net ..................... 123,937 5,960 Income from unconsolidated investments in power projects ................................ (2,163) (14,617) Distributions from unconsolidated power projects 2,459 19,413 Minority interest .............................. 3,157 407 Change in long-term liabilities ................ 1,061,206 -- Change in operating assets and liabilities, net of effects of acquisitions: Accounts receivable ............................ (315,344) (105,688) Inventories .................................... (12,159) (953) Other current assets ........................... (1,072,306) (9,906) Notes receivable ............................... (43,624) (16,955) Other assets ................................... (901,012) 11,866 Accounts payable and accrued expense ........... 131,502 40,358 Other current liabilities and deferred revenue . 749,190 (39,944) ----------- ----------- Net cash provided by operating activities ... 100,723 73,443 ----------- ----------- Cash flows from investing activities: Purchases of property, plant and equipment ........ (2,556,789) (968,475) Acquisitions, net of cash acquired ................ (252) (201,823) Capital expenditures on joint ventures ............ (63,871) (134,561) Maturities of collateral securities ............... 2,885 3,315 Project development costs ......................... (55,314) (47,767) Decrease in notes receivable ...................... (93,723) (32,040) Increase in restricted cash ....................... (24,705) (192) Other ............................................. 8,384 -- ----------- ----------- Net cash used in investing activities ....... (2,783,385) (1,381,543) ----------- ----------- Cash flows from financing activities: Proceeds from notes payable and borrowings under lines of credit ........................... 258 443,776 Repayments of notes payable and borrowings under lines of credit ........................... (444,568) (9,159) Borrowings from project financing ................. 1,479,673 361,965 Repayments of project financing ................... (1,234,433) -- Proceeds from issuance of senior notes ............ 2,650,000 -- Repayments of senior notes ........................ (105,000) -- Proceeds from issuance of convertible securities .. 1,000,000 360,000 Proceeds from issuance of common stock ............ 49,369 6,519 Financing costs ................................... (64,534) (25,099) Other ............................................. (2,660) 8,504 ----------- ----------- Net cash provided by financing activities ... 3,328,105 1,146,506 ----------- ----------- Net increase (decrease) in cash and cash equivalents . 645,443 (161,594) Cash and cash equivalents, beginning of period ....... 596,077 349,371 ----------- ----------- Cash and cash equivalents, end of period ............. $ 1,241,520 $ 187,777 =========== =========== Cash paid during the period for: Interest .......................................... $ 208,903 $ 94,911 Income taxes ...................................... $ 114,083 $ 37,113 The accompanying notes are an integral part of these consolidated condensed financial statements.
CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS June 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 and Canada. In pursuing this single business strategy, the Company is involved in the development, acquisition, ownership and operation of power generation facilities and the sale of electricity and its by-product, thermal energy, primarily in the form of steam. The Company has ownership interests in and operates gas-fired power generation and cogeneration facilities, gas fields, gathering systems and gas pipelines, geothermal steam fields and geothermal power generation facilities in the United States and Canada. Each of the generation facilities produces and markets electricity for sale to utilities and other third party purchasers. Thermal energy produced by the gas-fired cogeneration facilities is primarily sold to governmental and industrial users. 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 (see Note 6). 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 included in the Company's annual report on Form 10-K for the year ended December 31, 2000. The results for interim periods are not necessarily indicative of the results for the entire year. Use of Estimates in Preparation of Financial Statements -- The preparation of financial statements in conformity with generally accepted accounting principles in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of 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: 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, and the Company's policy prohibits positions that exceed production capacity and fuel requirements. The Company's credit risk associated with energy contracts results from the risk-of-loss on non-performance by counterparties. The Company reviews and assesses counterparty risk to limit any material impact on its financial position and results of operations. The Company does not believe there is a significant risk of non-performance by the counterparties. New Accounting Pronouncements -- In July 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". SFAS No. 141 eliminates the pooling-of-interests method of accounting for business combinations and modifies the application of the purchase accounting method. 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 impact on its consolidated financial statements. In July 2001, the FASB issued SFAS No. 142, "Goodwill and 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 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 impact 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. Derivative Instruments On January 1, 2001, the Company adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." The Company currently holds four classes of derivative instruments that are impacted by the new pronouncement - interest rate swaps, commodity financial instruments, commodity contracts, and physical options. Additionally, one of the Company's unconsolidated investees holds two foreign exchange forward contracts. The Company 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 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. The FASB has 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"). As a result, certain capacity sales contracts currently held by the Company 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 June 30, 2001 for the Company's derivative instruments.
Commodity Total Interest Rate Derivative Derivative Swaps Instruments Instruments ------------- ----------- ----------- Current derivative asset (1) ..................................... $ -- $ 1,048,198 $ 1,048,198 Long-term derivative asset (2) ................................... -- 874,306 874,306 ----------- ----------- ----------- Total assets .................................................. $ -- $ 1,922,504 $ 1,922,504 =========== =========== =========== Current derivative liability (3) ................................. $ 12,886 $ 677,045 $ 689,931 Long-term derivative liability (4) ............................... 13,000 944,448 957,448 ----------- ----------- ----------- Total liabilities ........................................... $ 25,886 $ 1,621,493 $ 1,647,379 =========== =========== =========== Total comprehensive income (loss) ................................ $ (25,937) $ 176,933 $ 150,996 Reclassification adjustment for activity included in net income .. -- 21,792 21,792 Income tax benefit (expense) ..................................... 8,970 (78,406) (69,436) ----------- ----------- ----------- Net comprehensive income (loss) ............................. $ (16,967) $ 120,319 $ 103,352 =========== =========== =========== (1) Included in other current assets (2) Included in other assets (3) Included in other current liabilities (4) Included in other liabilities
During the three and six months ended June 30, 2001, the Company recognized gains on derivatives not designated as hedges of $67.2 million and $69.7 million, respectively, which were recorded in electric generation and marketing revenue, and $27.4 and $34.5 million, respectively, which were recorded in fuel expense. During the three and six months ended June 30, 2001, the Company recognized pretax losses of $4.0 million and $3.5 million, respectively, related to hedge ineffectiveness on gas contracts, which are included in fuel expense. For the three and six months ended June 30, 2001, the Company recognized pretax gains of $1.2 million and zero, respectively, related to hedge ineffectiveness on electricity contracts, which are included in electric generation and marketing revenue. The Company did not exclude any components of derivative instruments from the assessment of hedge effectiveness. As of June 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 17.5 years. The Company estimates that pretax gains of $358.3 million will be reclassified from accumulated OCI into earnings during the next twelve months as the hedged transactions affect earnings. 4. Property, Plant and Equipment, Net and Capitalized Interest Property, plant and equipment, net consisted of the following (in thousands):
June 30, December 31, 2001 2000 ------------ ------------ Geothermal properties ........................... $ 356,089 $ 334,585 Oil and gas properties .......................... 1,666,933 1,441,175 Buildings, machinery and equipment .............. 2,982,315 1,951,250 Power sales agreements .......................... 139,932 162,086 Gas contracts ................................... 143,619 129,999 Other ........................................... 190,065 145,877 ------------ ----------- 5,478,953 4,164,972 Less accumulated depreciation and amortization .. (828,384) (614,816) ------------ ----------- 4,650,569 3,550,156 Land ........................................... 68,630 12,578 Construction in progress ....................... 5,680,255 4,416,426 ------------ ----------- Property, plant and equipment, net ............. $ 10,399,454 $ 7,979,160 ============ ===========
Construction in progress is primarily attributable to gas-fired projects under construction. Upon commencement of plant operation, these costs are transferred to buildings, machinery and equipment. Capitalized Interest -- The Company capitalizes interest on capital invested in projects during the advanced stages of development and the construction period, in accordance with SFAS No. 34, as amended by SFAS No. 58. For the six months ended June 30, 2001 and 2000, the Company recorded net interest expense of $63.3 million and $40.0 million, respectively, after capitalizing $153.7 million and $52.0 million, respectively, of interest on general corporate funds used for construction and after recording $65.9 million and $15.3 million, respectively, of interest capitalized on funds borrowed for specific construction projects. Upon commencement of plant operation, capitalized interest, as a component of the total cost of the plant, is amortized over the estimated useful life of the plant. The increase in the amount of interest capitalized during the six months ended June 30, 2001, reflects the significant increase in the Company's power plant construction program. 5. Notes Receivable As of June 30, 2001 and December 31, 2000, the components of notes receivable were (in thousands):
June 30, December 31, 2001 2000 --------- ------------ PG&E note .................................. $ 84,208 $ 62,336 Delta note ................................. 243,402 112,050 Other ...................................... 38,237 43,724 --------- --------- Total notes receivable ............ 365,847 218,110 Less: Notes receivable, current portion .... (11,546) (183) --------- --------- Notes receivable, net of current portion.... $ 354,301 $ 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 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 a note from the project, Delta Energy Center, LLC, bearing interest at 11.37% per annum. 6. Acquisitions and Asset Purchases On April 3, 2001, the Company acquired all of the common shares of WRMS Engineering, Inc. ("WRMS"), a California-based engineering and architectural firm, through a stock-for-stock exchange in which WRMS shareholders received a total of 151,176 shares of Calpine common stock. The aggregate value of the transaction was approximately $7.8 million, including the assumed indebtedness of WRMS. On April 11, 2001, the Company acquired the development rights from Enron North America for the 750-megawatt natural gas-fired Pastoria Energy Center planned for Kern County, California. The project was licensed by the California Energy Commission in December 2000. Construction began in June 2001 and commercial operation is scheduled for the summer of 2003. On April 17, 2001, the Company acquired the development rights from Kirkland, Washington-based National Energy Systems Company for the 248-megawatt natural gas-fired Goldendale Energy Center planned for Goldendale, Washington. Energy generated from the Goldendale facility will be sold directly into the Northwest Power Pool. Construction commenced in April 2001, and energy deliveries are scheduled to begin July 1, 2002. On April 17, 2001, the Company acquired assets of The Bayless Companies and its partners with reserves located in the western portion of the San Juan Basin in New Mexico. Currently 35 wells produce approximately 6 million cubic feet equivalent per day ("mmcfe/d"), 96 percent of which is natural gas. On April 19, 2001, the Company acquired all of the common shares of Encal Energy Ltd. ("Encal") (which was thereafter merged with and into Calpine Canada Resources Ltd.), a Calgary, Alberta-based natural gas and petroleum exploration and development company, through a stock-for-stock exchange in which Encal shareholders received, in exchange for each share of Encal common stock, .1493 shares of Calpine common equivalent shares (called "exchangeable shares") of the 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. The aggregate value of the transaction was approximately U.S. $1.1 billion, including the assumed indebtedness of Encal. The transaction was accounted for under the pooling-of-interests method and, accordingly, all historical amounts reflected in the consolidated condensed financial statements have been restated to reflect the transaction. To date, the Company incurred $41.6 million in nonrecurring merger costs for this transaction. With the addition of Encal's assets, which currently produce approximately 230 mmcfe per day, net of royalties, Calpine's net production increased to 390 mmcfe per day in North America, enough to fuel approximately 2,300 megawatts of its power fleet. 7. Project Financing In connection with financings in the second quarter (see Notes 8 and 9), the Company repaid approximately $874 million of its project financing. The Company drew $870.1 million on the Calpine Construction Finance Company debt revolvers during the quarter. 8. Senior Notes On April 25, 2001, Calpine Canada Energy Finance ULC ("Energy Finance"), the Company's indirect wholly owned subsidiary, issued $1.5 billion in aggregate principal amount of its 8 1/2% Senior Notes Due 2008. The Energy Finance Senior Notes Due 2008 are fully and unconditionally guaranteed by the Company. On June 7, 2001, the Company redeemed all $105 million in aggregate outstanding principal amount of its 9 1/4% Senior Notes Due 2004 at a redemption price of 100% of the principal amount plus accrued interest to the redemption date. As a result, the Company recorded a $1.3 million extraordinary charge related to writing off the unamortized balance of deferred financing costs. 9. Zero-Coupon Convertible Debentures On April 30, 2001, the Company completed the sale of $1.0 billion of Zero-Coupon Convertible Debentures Due 2021 in a private placement under Rule 144A of the Securities Act of 1933. The securities are convertible into Calpine common shares at a price of $75.35 at the option of the holder at any time. Holders have the right to require the Company to repurchase their debentures in 2002, 2004, 2006, 2008, 2011 and 2016 at a specified price in cash or Calpine common stock at the Company's option, except in 2016 when the repurchase price must be paid in cash. The debentures are redeemable at the option of the Company after 2004 at a specified price in cash or Calpine common stock. As the holders of the debentures have the right to require the Company to repurchase the debentures within a year, the debentures are classified as current. 10. Equity In the second quarter of 2001, the Company's shareholders approved an amendment to the Articles of Incorporation, which increased the number of authorized shares of common stock to 1,000,000,000. In addition, the Board of Directors voted to increase the number of authorized shares of Series A Participating Preferred Stock to 1,000,000 shares. 11. 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 Six Months Ended June 30, June 30, --------------------- --------------------- 2001 2000 2001 2000 --------- -------- --------- -------- Net income ...................................... $ 107,665 $ 59,508 $ 227,328 $ 80,609 --------- -------- --------- -------- Other comprehensive income: Unrealized gain on cash flow hedges ........ 260,957 -- 172,788 -- Gain on foreign currency translation ....... 2,914 -- 422 -- Income tax expense ......................... (104,035) -- (69,436) -- --------- -------- --------- -------- Other comprehensive income, net of tax .. 159,836 -- 103,774 -- --------- -------- --------- -------- Total comprehensive income ...................... $ 267,501 $ 59,508 $ 331,102 $ 80,609 ========= ======== ========= ========
12. Significant Customers The Company's significant customers at June 30, 2001, were PG&E and Enron Power Marketing. Due to the increase in volume in CES transactions, Enron Power Marketing has become a significant customer, exceeding 10% of the Company's revenue for the six months ended June 30, 2001, and 10% of the accounts receivable balance at June 30, 2001. Revenues earned from Enron were $340.9 million and $1.3 million for the six months ended June 30, 2001 and 2000, respectively. Receivables were $147.5 million and $46.0 million at June 30, 2001 and December 31, 2000, respectively. The receivables at June 30, 2001, were current and continue to be paid currently. 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. See Note 16 for an update of the PG&E bankruptcy proceedings. 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. 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 agreed to assume its QF contracts with Calpine in bankruptcy, 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 six months ended June 30, 2001 and 2000 were as follows (in thousands):
Three Months Ended June 30, Six Months Ended June 30, --------------------------- ------------------------- 2001 2000 2001 2000 -------- -------- -------- -------- Revenues: PG&E ................. $119,027 $ 97,870 $289,995 $139,029
Receivables at June 30, 2001, April 6, 2001, and December 31, 2000, were as follows (in thousands):
June 30, 2001 April 6, 2001 December 31, 2000 ------------- ------------- ----------------- Receivables: PG&E accounts receivable .... $291,991 $265,588 $204,448
PG&E has paid currently for energy deliveries made after April 6, 2001, the PG&E bankruptcy filing date. The Company had a combined accounts receivable balance of $14.2 million as of June 30, 2001, from the California Independent System Operator Corporation ("CAISO") and Automated Power Exchange, Inc. ("APX"). CAISO's ability to pay the Company is directly impacted by PG&E's ability to pay CAISO. APX's ability to pay the Company is impacted by PG&E's ability to pay the California Power Exchange, which in turn pays APX for energy deliveries by the Company through APX. The Company has provided a full reserve against collection uncertainties for these receivables. See Note 16 for an update on the Federal Energy Regulatory Commission ("FERC") investigation into the California wholesale markets. The Company also had an accounts receivable balance of $26.2 million as of June 30, 2001, from the California Department of Water Resources. These receivables at June 30, 2001, were current and continue to be paid currently. 13. Purchased Power and Gas Sales and Expense The Company records the cost of gas consumed in its power plants as fuel expense, while gas purchased from third parties, for hedging, balancing and related activities, is recorded as purchased gas expense, a component of oil 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 purposes, 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. Although the Company believes it is most meaningful to review the combined total of electric generation and marketing revenue, the table below shows the relative levels and growth of power and gas hedging, balancing and related activity.
Three Months Ended Six Months Ended June 30, June 30, ----------------------- ----------------------- 2001 2000 2001 2000 ---------- ---------- ---------- ---------- Sales of purchased power ... $ 683,196 $ 28,977 $1,136,798 $ 41,121 Sales of purchased gas ..... 226,693 7,727 355,865 16,331 ---------- ---------- ---------- ---------- Total ............. $ 909,889 $ 36,704 $1,492,663 $ 57,452 ========== ========== ========== ========== Purchased power expense .... $ 655,322 $ 31,605 $1,111,588 $ 42,852 Purchased gas expense ...... 218,330 7,480 336,958 15,219 ---------- ---------- ---------- ---------- Total ............. $ 873,652 $ 39,085 $1,448,546 $ 58,071 ========== ========== ========== ==========
14. 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 June 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 .................... $ 108,965 302,729 $ 0.36 $ 59,508 271,505 $ 0.22 Extraordinary charge, net of tax benefit ........................ (1,300) -- -- -- -- -- Cumulative effect of a change in accounting principle, net of tax .................................................... -- -- -- -- -- -- --------- ------- ------ -------- ------- ------ Net income ...................................................... $ 107,665 302,729 $ 0.36 $ 59,508 271,505 $ 0.22 ========= ======= ====== ======== ======= ====== Common shares issuable upon exercise of stock options using treasury stock method ................................... 15,526 15,766 ------- ----- Diluted earnings per common share: Income before dilutive effect of certain convertible securities, extraordinary charge and cumulative effect of a change in accounting principle ........................... $ 108,965 318,255 $ 0.34 $ 59,508 287,271 $ 0.21 Dilutive effect of certain convertible securities ............... 7,507 41,964 (0.02) 2,439 18,912 (0.01) --------- ------- ------ -------- ------- ------ Income before extraordinary charge and cumulative effect of a change in accounting principle ........................... 116,472 360,219 0.32 61,947 306,183 0.20 Extraordinary charge, net of tax benefit ........................ (1,300) -- -- -- -- -- Cumulative effect of a change in accounting principle, net of tax .................................................... -- -- -- -- -- -- --------- ------- ------ -------- ------- ------ Net income ...................................................... $ 115,172 360,219 $ 0.32 $ 61,947 306,183 $ 0.20 ========= ======= ====== ======== ======= ====== SIX MONTHS: Basic earnings per common share: Income before extraordinary charge and cumulative effect of a change in accounting principle .................... $ 227,592 301,641 $ 0.75 $ 80,609 270,516 $ 0.30 Extraordinary charge, net of tax benefit ........................ (1,300) -- -- -- -- -- Cumulative effect of a change in accounting principle, net of tax .................................................... 1,036 -- -- -- -- -- --------- ------- ------ -------- -------- ------ Net income ...................................................... $ 227,328 301,641 $ 0.75 $ 80,609 270,516 $ 0.30 ========= ======= ====== ======== ======= ====== Common shares issuable upon exercise of stock options using treasury stock method ................................... 15,903 15,923 ------- ------- Diluted earnings per common share: Income before dilutive effect of certain convertible securities, extraordinary charge and cumulative effect of a change in accounting principle ........................... $ 227,592 317,544 $ 0.72 $ 80,609 286,439 $ 0.28 Dilutive effect of certain convertible securities ............... 20,838 49,379 (0.04) 4,878 18,912 -- --------- ------- ------ -------- ------- ------ Income before extraordinary charge and cumulative effect of a change in accounting principle ........................... 248,430 366,923 0.68 85,487 305,351 0.28 Extraordinary charge, net of tax benefit ........................ (1,300) -- -- -- -- -- Cumulative effect of a change in accounting principle, net of tax .................................................... 1,036 -- -- -- -- -- --------- ------- ------ -------- ------- ------ Net income ...................................................... $ 248,166 366,923 $ 0.68 $ 85,487 305,351 $ 0.28 ========= ======= ====== ======== ======= ======
Unexercised employee stock options to purchase approximately 284.8 and 36.0 thousand shares of the Company's common stock during the six months ended June 30, 2001 and 2000, respectively, were not included in the computation of diluted shares outstanding because such inclusion would have been anti-dilutive. 15. Commitments and Contingencies Capital Expenditures -- During the second quarter of 2001, the Company purchased 35 model 7FB and 11 model 7FA gas-fired turbines from GE Power Systems. The Company expects to take delivery of 5 turbines in 2002, with the remainder of the contract to be filled by the end of 2005. This brought the total number of gas-fired and steam turbines on order to 304 with an approximate value of $9 billion. 16. Subsequent Events PG&E Bankruptcy Proceedings -- 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 Capine'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. The 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 must be completed within 45 days from the date the California ISO provides certain critical data for the purpose of developing the factual basis needed to implement the refund methodology and order refunds. While it is not possible to predict the amount of any refunds until the hearing takes 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 May 15, 2001, the Company announced that Canada Power Holdings Ltd. had entered into a letter of intent to acquire and assume operations of two Canadian power generating facilities from British Columbia-based Westcoast Energy, Inc. for up to approximately US$250 million, plus the assumption of US$14.6 million of debt. The Company will gain a 100 percent interest in the 250-megawatt natural gas-fired Island Cogeneration facility located near Campbell River, British Columbia on Vancouver Island, and a 50 percent interest in the 50-megawatt Whitby Cogeneration facility located in Whitby, Ontario. The acquisition is expected to close in the third quarter of 2001 and is subject to final documentation and various third party and regulatory approvals. On July 5, 2001, the Company announced an agreement to acquire a 1,200-megawatt natural gas-fired power plant at Saltend near Hull, Yorkshire, England from Entergy Wholesale Operations for up to approximately 562.5 million pounds sterling (approximately US$800 million at current exchange rates). The Saltend facility, a cogeneration facility, provides electricity and steam for BP Chemical's Hull Works plant under a 15-year agreement. The balance of the Saltend facility's electricity output is sold into the deregulated United Kingdom power market. The acquisition is expected to close in the third quarter of this year and is subject to third party approvals. On July 10, 2001, the Company jointly announced with PG&E Corporation's PG&E National Energy Group the completion of the acquisition of the 500-megawatt natural gas-fired Otay Mesa Generating Project in San Diego County. The PG&E National Energy Group developed the combined-cycle project, which was licensed by the California Energy Commission in April. Construction is expected to begin later this summer, and with completion scheduled for mid-2003, the project will be the first new power facility built in San Diego County in 30 years. Under the terms of the sale, Calpine 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 July 10, 2001, the Company announced the acquisition of a majority interest of Michael Petroleum Corporation, a Houston, Texas-based natural gas exploration and development company. These reserves are located exclusively in South Texas. The assets include total proved reserves of 204 bcfe and currently produce 43 mmcfe/d. In addition, this transaction provides an inventory of high quality, low risk drilling locations within a 94,000 acreage position in close proximity to the Magic Valley Generating Station and the Hidalgo Energy Center. The value of the transaction is approximately $338.5 million, plus the assumption of $44.1 million of debt. The acquisition is expected to close in the third quarter of 2001. On August 1, 2001, the Company announced an agreement with Edison Mission Energy for the purchase of the remaining fifty percent equity interest in a 240-megawatt combined-cycle cogeneration facility located in Gordonsville, Virginia for $35 million. The Gordonsville facility provides electric power and steam to Virginia Electric and Power Company and the Rapidan Service Authority, respectively, under long-term contracts that expire in 2024. The acquisition is expected to close in the third quarter of 2001. 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 risks, such as a failure to obtain financing and the necessary permits to operate or the failure of third-party contractors to perform their contractual obligations, (iii) cost estimates are preliminary and actual costs may be higher than estimated, (iv) the assurance that the Company will develop additional plants, (v) a competitor's development of a lower-cost generating gas-fired power plant, (vi) the risks associated with marketing and selling power from power plants in the newly competitive energy market, (vii) the risks associated with marketing and selling combustion turbine parts and components in the competitive combustion turbine parts market, (viii) the risks associated with engineering, designing and manufacturing combustion turbine parts and components, or (ix) delivery and performance risks associated with combustion turbine parts and components attributable to production, quality control, suppliers and transportation. 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 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. Overview Calpine is engaged in the development, acquisition, ownership, and operation of power generation facilities and the sale of electricity and steam in the United States and Canada. At August 13, 2001, we had interests in 58 operating power plants representing 9,626 megawatts of net capacity. On April 3, 2001, we announced that our affiliate, Calpine Power America, L.P., was certified as a Retail Energy Provider in the Electric Reliability Council of Texas ("ERCOT"). This allows us to offer services to a full range of wholesale and retail customers in Texas. Calpine Power America will sell to large industrials, in addition to municipalities, cooperatives, and investor-owned utilities. Additionally, we received an ERCOT certification to be a Qualified Scheduling Entity ("QSE"). As a QSE, Calpine Power Management, L.P. may act on behalf of generators and consumers in the region and would be responsible for scheduling the generation of energy flowing to the electricity grid with the ERCOT Independent System Operator. On April 3, 2001, we acquired all of the common shares of WRMS Engineering, Inc. ("WRMS"), a California-based engineering and architectural firm, through a stock-for-stock exchange in which WRMS shareholders received a total of 151,176 shares of Calpine common stock. The aggregate value of the transaction is approximately $7.8 million, including the assumed indebtedness of WRMS. WRMS is expected to provide services to support our c*Power unit, which provides highly reliable, critical power to industrial and high tech customers. On April 11, 2001, we acquired the development rights from Enron North America for the 750-megawatt natural gas-fired Pastoria Energy Center planned for Kern County, California. The project was licensed by the California Energy Commission in December 2000. Construction began in June 2001 and commercial operation is scheduled for the summer of 2003. On April 17, 2001, we acquired the development rights from Kirkland, Washington-based National Energy Systems Company for the 248-megawatt natural gas-fired Goldendale Energy Center planned for Goldendale, Washington. Energy generated from the Goldendale facility will be sold directly into the Northwest Power Pool. Construction commenced in April 2001, and energy deliveries are scheduled to begin July 1, 2002. On April 17, 2001, we acquired assets of The Bayless Companies and its partners with reserves located in the western portion of the San Juan Basin in New Mexico. Currently 35 wells produce approximately 6 million cubic feet equivalent per day ("mmcfe/d"), 96 percent of which is natural gas. On April 19, 2001, we announced the purchase of 35 model 7FB and 11 model 7FA gas-fired turbines from GE Power Systems. We will take delivery of 5 turbines in 2002, with the remainder of the contract to be filled by the end of 2005. On April 19, 2001, we acquired all of the common shares of Encal Energy Ltd. ("Encal"), a Calgary, Alberta-based natural gas and petroleum exploration and development company, through a stock-for-stock exchange in which Encal shareholders received, in exchange for each share of Encal common stock, .1493 shares of Calpine common equivalent shares of our subsidiary, Calpine Canada Holdings Ltd. A total of 16,603,633 Calpine common equivalent shares were issued to Encal shareholders in exchange for their Encal common stock. Each Calpine common equivalent share is exchangeable for one share of Calpine common stock. The aggregate value of the transaction is approximately U.S. $1.1 billion, including the assumed indebtedness of Encal. This acquisition was accounted for under the pooling-of-interests method. With the addition of Encal's assets, which currently produce approximately 230 mmcfe per day, net of royalties, our net production is expected to increase to 390 mmcfe per day in North America, enough to fuel approximately 2,300 megawatts of our power fleet. On April 25, 2001, through our wholly owned financing company, Calpine Canada Energy Finance ULC ("Energy Finance"), we completed a public offering of $1.5 billion of 8 1/2% Senior Notes Due 2008 priced at 99.768%. These senior notes are fully and unconditionally guaranteed by us. On April 30, 2001, we completed the sale of $1.0 billion of Zero-Coupon Convertible Debentures Due 2021 in a private placement under Rule 144A of the Securities Act of 1933. The securities are convertible into Calpine common shares at a price of $75.35 at the option of the holder at any time. Holders have the right to require us to repurchase their debentures in 2002, 2004, 2006, 2008, 2011 and 2016 at a specified price in cash or our common stock at our option, except in 2016 when the repurchase price must be paid in cash. The debentures are redeemable at the option of Calpine after 2004 at a specified price in cash or our common stock. Proceeds from the offering were used to refinance certain debt, for working capital and for general corporate purposes. The indenture relating to these securities has not been filed with the Securities and Exchange Commission at the date of this filing. We will furnish a copy to the Securities and Exchange Commission upon request. On May 2, 2001, we jointly announced with Kinder Morgan Energy Partners, L.P. plans to develop the Sonoran Pipeline, subject to a successful open season and all other approvals. As proposed, the Sonoran Pipeline will be a 1,160-mile, high-pressure interstate natural gas pipeline from the San Juan Basin in northern New Mexico to markets in California. The interstate pipeline will be evaluated and developed in two phases, which will be subject to the jurisdiction of the Federal Energy Regulatory Commission ("FERC"). The first phase will run from the San Juan Basin to the California border with the second phase extending from the California border to the San Francisco Bay area. The first phase of the pipeline is expected to be completed in the summer of 2003. On May 9, 2001, we announced that our emergency energy proposal to the San Francisco Public Utilities Commission was approved by the San Francisco Board of Supervisors. Under the terms of this contract, we will guarantee to provide San Francisco with 50 megawatts of electricity 24 hours-a-day for the next five years starting July 1, 2001. On May 15, 2001, we announced that we plan to build, own and operate a 1,030-megawatt natural gas-fired electricity generating facility to be located in Berrien, Michigan. We entered into an agreement with Boston-based CME North American Merchant Energy, which had initiated development efforts for the project and will continue to work with us as the project moves forward. The Berrien Energy Center is our first Michigan development project and commercial operation is scheduled to begin in 2004. On May 15, 2001, we announced that our wholly owned subsidiary, Canada Power Holdings Ltd., entered into a letter of intent to acquire and assume operations of two Canadian power generating facilities from British Columbia-based Westcoast Energy, Inc. for up to approximately US$250 million, plus the assumption of US$14.6 million of debt. We will own a 100 percent interest in the 250-megawatt natural gas-fired Island Cogeneration facility located near Campbell River, British Columbia on Vancouver Island, and a 50 percent interest in the 50-megawatt Whitby Cogeneration facility located in Whitby, Ontario. The acquisition is expected to close in the third quarter of 2001 and is subject to final documentation and various third party and regulatory approvals. At the Annual Meeting of Stockholders on May 17, 2001, the stockholders elected Ann B. Curtis and Kenneth T. Derr as the Class II Directors, approved the amendment to the Company's Amended and Restated Certificate of Incorporation to increase the number of authorized shares of Common Stock from 500,000,000 to 1,000,000,000, and ratified the appointment of Arthur Andersen LLP as independent accountants for the fiscal year ending December 31, 2001. On May 23, 2001, we, together with San Francisco-based Bechtel Enterprises Holdings, Inc., filed an Application For Certification with the California Energy Commission ("CEC") for the proposed Russell City Energy Center, a 600-megawatt, natural gas-fired, combined-cycle electric generating facility located in Hayward, California. The filing marks the beginning of an extensive CEC licensing process required to build and operate an electricity generating facility in California. The filing included a request for expedited review that would reduce the licensing review process period from 12 months to 6 months. Based upon successful licensing of the project, construction could begin in the summer of 2002, with commercial operation by the summer of 2004. The Russell City Energy Center would provide electricity for Hayward, western Alameda County and the San Francisco Peninsula. On June 7, 2001, we jointly announced with Kinder Morgan Energy Partners, L.P. that we received significant interest in the proposed Sonoran Pipeline project during the open seasons that closed on June 1, 2001. More than 1 billion cubic feet ("Bcf") per day of binding precedent agreements and non-binding expressions of interest were received for Phase One of Sonoran, and another 1.5 Bcf per day of non-binding commitments and expressions of interest were received for Phase Two of the project. On June 7, 2001, we redeemed all $105 million in aggregate outstanding principal amount of our 9 1/4% Senior Notes Due 2004 at a redemption price of 100% of the principal amount plus accrued interest to the redemption date. On June 8, 2001, we announced plans to build, own and operate a 600-megawatt electric generating facility to be located in southwestern Riverside County, California. The proposed Inland Empire Energy Center will feed directly into Southern California Edison's power grid and is intended to serve the rapidly growing counties of Riverside and San Bernardino. Construction is scheduled to begin in mid-2002, with commercial operation targeted for mid-2004. On June 20, 2001, we jointly announced with Bechtel Enterprises Holdings, Inc. that the Presiding Members' Proposed Decision, released by the California Energy Commission on June 18, 2001, recommends that the full five-member CEC approve the 600-megawatt, gas-fired Metcalf Energy Center. The CEC's final decision is expected in the third quarter 2001. On June 28, 2001, we announced that Florida's Power Plant Siting Board granted final state regulatory approval for the proposed 529-megawatt Osprey Energy Center, to be located in Auburndale, Florida. We are the first independent power producer to receive approval of a Site Certification Application for a large-scale combined-cycle generating facility under Florida's complex Power Plant Siting Act. Transactions Announced or Consummated Subsequent to June 30, 2001, and Recent Developments On July 2, 2001, we announced commercial operation of our Sutter Energy Center, located near Yuba City, California. The Sutter Energy Center, the first major combined-cycle facility built in California in over a decade, is providing 540 megawatts of electricity to California on a 24 hours-a-day, seven days-a-week availability. On July 5, 2001, we announced that we had signed a binding agreement to acquire a 1,200-megawatt natural gas-fired power plant at Saltend near Hull, Yorkshire, England from Entergy Wholesale Operations for up to approximately 562.5 million pounds sterling (US$800 million). The Saltend Energy Centre entered commercial operations in November 2000 and is one of the largest natural gas-fired electric power generating facilities in England. As a cogeneration facility, Saltend Energy Centre provides electricity and steam for BP Chemical's 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. The facility incorporates natural gas-fired combustion turbines in combination with steam turbines to optimize fuel efficiency. On July 9, 2001, we announced initial operation of our Los Medanos Energy Center in Pittsburg, California. This 555-megawatt facility is the second major combined-cycle facility to be licensed and built in California in over a decade and will provide electricity on a 24 hours-a-day, 7 days-a-week availability. As a cogeneration facility, the project also delivers electricity and steam to USS POSCO for use in industrial processing. On July 10, 2001, we jointly announced with PG&E Corporation's PG&E National Energy Group that we had completed the acquisition of the 500-megawatt natural gas-fired Otay Mesa Generating Project in San Diego County. The PG&E National Energy Group developed the combined-cycle project, which was licensed by the California Energy Commission in April. Construction is expected to begin later this summer, and with completion scheduled for mid-2003, the project will be the first new power facility built in San Diego County in 30 years. Under the terms of the sale, we 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 our subsidiary, Calpine Energy Services, LP ("CES"). On July 10, 2001, we announced the acquisition of a majority interest of Michael Petroleum Corporation, a Houston, Texas-based natural gas exploration and development company. These reserves are located exclusively in South Texas. The assets include total proved reserves of 204 bcfe and currently produce 43 mmcfe/d. In addition, this transaction provides an inventory of high quality, low risk drilling locations within a 94,000 acreage position in close proximity to the Magic Valley Generating Station and the Hidalgo Energy Center. The value of the transaction is approximately $338.5 million plus the assumption of $44.1 million of debt. The acquisition is expected to close in the third quarter of 2001. On July 11, 2001, we jointly announced with Bechtel Enterprises Holdings, Inc. that the Application for Certification of the Russell City Energy Center met the California Energy Commission's data adequacy requirements. The project was also approved for expedited review, making the 600-megawatt Russell City Energy Center the first combined-cycle California energy project to meet the CEC's stringent qualifications for a six-month review. On July 11, 2001, we announced plans for the 180-megawatt Los Esteros Critical Energy Facility. Located in San Jose, California, our c*Power program will supply U.S. Data Port's planned San Jose Internet Campus with highly reliable critical power and ancillary services. Construction of the facility will be accelerated so that in advance of the initiation and completion of the U.S. Data Port project we will be able to provide 180 megawatts of peaking capacity and energy to the California Department of Water Resources under a power contract beginning May 1, 2002 and continuing through April 30, 2005. On July 16, 2001, we announced that Michael Polsky had resigned from the Board of Directors and as an officer of the Company. On July 17, 2001, we announced the appointment of Gerald Greenwald to the Board of Directors. On July 17, 2001, we announced plans to build a 900-megawatt natural gas-fired facility called the Sherry Energy Center in Wood County, Wisconsin. We entered into two separate 10-year agreements to supply 225 megawatts and 141 megawatts of electric capacity and energy from the plant to the Wisconsin Electric Power Company and the Wisconsin Public Service Corporation, respectively. The remaining output will be sold to other Wisconsin utilities and wholesale power purchasers. Construction is expected to begin during the second quarter of 2002, with commercial operation of the simple-cycle units slated for the second quarter of 2003, and commercial operation of the combined-cycle plant expected in the second quarter of 2004. On July 17, 2001, we signed two 5-year agreements to deliver 1,000 megawatts of power to Reliant Energy Services, Inc., a unit of Reliant Resources, Inc. The contracts will begin with the official start date of deregulation in ERCOT, which is expected to be January 1, 2002. We will serve Reliant's load from our ERCOT system of natural gas-fired power plants totaling approximately 2,700 megawatts of capacity. On July 18, 2001, we jointly announced with Shell Energy Services Company L.L.C., a wholly owned subsidiary of Shell Oil Company, the signing of an exclusive energy agreement. We will be the exclusive provider of up to 3,000 megawatts of electricity to Shell Energy, a retail electricity provider participating in the Texas Electric Choice pilot program in the ERCOT. Beginning January 1, 2002, we will provide capacity, energy, and ancillary services to Shell for the ERCOT market in accordance with the 5-year full requirements contract. On July 19, 2001, we announced a ten-year agreement for the sale of 100 megawatts of power to Excelon Generation's Power Team. This power will be produced by the Morris Power Plant located just southwest of Chicago, Illinois. On August 1, 2001, we announced an agreement with Edison Mission Energy for the purchase of the remaining fifty percent equity interest in a 240-megawatt combined-cycle cogeneration facility located in Gordonsville, Virginia for $35 million. The Gordonsville facility provides electric power and steam to Virginia Electric and Power Company and the Rapidan Service Authority, respectively, under long-term contracts that expire in 2024. On August 9, 2001, we announced plans to purchase 27 steam turbine generators from Siemens Westinghouse. We expect turbine deliveries to begin in September 2002, with full inventory in place by February 2005. Combined, the turbines represent up to 5,400 megawatts of generating capacity. 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 have been significantly higher than historical levels. Several factors contributed to this increase. These included: - significantly increased volatility in prices and supplies of natural gas; - an unusually dry fall and winter in the Pacific Northwest, which reduced the amount of available hydroelectric power from that region (typically, California imports a portion of its power from this source); - the large number of power generating facilities in California nearing the end of their useful lives, resulting in increased downtime (either for repairs or because they have exhausted their air pollution credits and replacement credits have become too costly to acquire on the secondary market); and - continued obstacles to new power plant construction in California, which deprived the market of new power sources that could have, in part, ameliorated the adverse effects of the foregoing factors. As a result of this situation, two major California utilities that are subject to the retail rate freeze, including PG&E, have faced wholesale prices that far exceed the retail prices they are permitted to charge. This has led to significant under-recovery of costs by these utilities. As a consequence, these utilities have defaulted under a variety of contractual obligations, including payment obligations to power generators. PG&E has defaulted on payment obligations to Calpine under Calpine's 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 $266 million in accounts receivable with PG&E under our QF contracts, plus $69 million in notes receivable not yet due and payable. As of June 30, 2001, we had recorded $292 million in accounts receivable and $84 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 Calpine, 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. We cannot predict when the bankruptcy court will confirm a plan of reorganization for PG&E. 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. 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 agreed to assume its QF contracts with us in bankruptcy, 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. 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. This contract is contingent upon our satisfaction, in our sole discretion, that adequate provisions have been made by DWR to assure us of full payment under the terms of the contract (including, but not limited to, the terms and conditions of any bonds issued by DWR to provide funds for payment of its obligations under the contract). On February 28, 2001, we announced the signing of two long-term power sales contracts with DWR. Under the terms of the first contract, a 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. Each of these contracts is also contingent upon our satisfaction, in our sole discretion, that adequate provisions have been made by DWR to assure us of full payment under the terms of that contract (including, but not limited to, the terms and conditions of any bonds issued by DWR to provide funds for payment of its obligations under that contract). 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. 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 must be completed within 45 days from the date the California ISO provides certain critical data for the purpose of developing the factual basis needed to implement the refund methodology and order refunds. While it is not possible to predict the amount of any refunds until the hearing takes 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. 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 six months ended June 30, 2001, respectively, as compared to the same periods in 2000, primarily due to the consolidation of acquisitions, favorable energy pricing, and increased production. Electricity revenue is composed of fixed capacity payments, which are not related to production, and variable energy payments, which are related to production. Capacity 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.
Three Months Ended June 30, Six Months Ended June 30, --------------------------- ------------------------- 2001 2000 2001 2000 ---------- ---------- ----------- ---------- Electricity and steam ("E & S") revenues: Energy (1) ............................... $ 354,366 $ 199,950 $ 806,552 $ 325,329 Capacity ................................. $ 147,064 $ 89,318 $ 245,323 $ 144,802 Thermal and other ........................ $ 32,157 $ 20,738 $ 74,205 $ 34,696 Megawatt hours produced ..................... 7,877,505 4,678,000 15,116,704 9,059,189 Average energy price per megawatt hour ...... $ 44.98 $ 42.74 $ 53.36 $ 35.91 (1) Includes spread on sales of purchased power.
Megawatt hours produced at the power plants increased 68% and 67% for the three and six months ended June 30, 2001, 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 June 30, 2000. Results of Operations Three Months Ended June 30, 2001, Compared to Three Months Ended June 30, 2000 Revenue -- Total revenue increased to $1,612.9 million for the three months ended June 30, 2001, compared to $417.2 million for the same period in 2000. Electric generation and marketing revenue increased 268% to $1,257.3 million in 2001 compared to $341.6 million in 2000. Approximately $192.9 million of the $915.7 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 June 30, 2001, includes the consolidated results of fourteen additional facilities that we acquired or completed construction on subsequent to June 30, 2000. Our power marketing revenue (sales of purchased power) grew by $654.2 million due to increased price hedging and optimization activity during the three months ended June 30, 2001. We also recognized $68.4 million in mark-to-market gains on power derivatives. Oil and gas production and marketing revenue increased to $343.0 million in 2001 compared to $69.7 million in 2000. The majority of the increase is due to marketing activities relating to purchased gas sold to third parties in hedging, balancing and related transactions. Additionally, approximately $54.4 million of the variance relates to increased production and commodity prices from sales to third parties from our reserves in Canada and in the United States. Income from unconsolidated investments in power projects decreased to $1.6 million in 2001 compared to $4.8 million during 2000. The variance is primarily due to the contractual reduction in distributions from the Sumas Power Plant of approximately $2.6 million. Other revenue increased to $10.9 million in 2001 compared to $1.1 million in 2000. This increase is due primarily to $4.8 million recognized in 2001 from our custom turbine parts manufacturing subsidiary, Power Systems Mfg., LLC, which was acquired in December 2000, and $2.8 million in interest income on loans to power projects. Cost of revenue -- Cost of revenue increased to $1,308.6 million in 2001 compared to $270.5 million in 2000. Approximately $623.7 million of the $1,038.1 million increase relates to the cost of power purchased by our energy services organization. Similarly, oil and gas production and marketing expense grew by $220.5 million, largely due to $218.3 million of expense for the cost of gas purchased by the energy services organization, compared to $7.5 million in the second quarter of 2000. Fuel expense increased 120%, from $104.0 million in 2000 to $228.4 million in 2001, due to a 68% increase in megawatt hours generated and increased fuel price. Depreciation expense increased by 42%, from $50.7 million in the second quarter of 2000 to $72.1 million in the second quarter of 2001, due to fourteen additional power facilities in consolidated operations at June 30, 2001, as compared to the same period in 2000, and due to $14.4 million in higher depreciation and depletion in our oil and gas operating subsidiaries. Operating lease expense increased by $16.8 million due to leases entered into or acquired in connection with our Pasadena, Tiverton, Rumford, and KIAC facilities, all of which were either entered into during or after the second quarter of 2000. General and administrative expense -- General and administrative expense increased 173% to $50.5 million for the three months ended June 30, 2001, as compared to $18.5 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. Nonrecurring merger costs -- We incurred approximately $35.6 million in the three months ended June 30, 2001, in connection with the merger with Encal Energy Limited 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 138% to $43.3 million for the three months ended June 30, 2001, from $18.2 million for the same period in 2000. Interest expense increased primarily due to the issuances of $1.15 billion of Senior Notes Due 2011 in February 2001 and of $1.5 billion of Energy Finance 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. Distributions on trust preferred securities -- Distributions on trust preferred securities increased 69% to $15.4 million for the three months ended June 30, 2001, compared to $9.1 million for the corresponding months in 2000. The increase is attributable to the issuance of additional trust preferred securities in August 2000. Interest income -- Interest income increased to $20.5 million for the three months ended June 30, 2001, compared to $5.6 million for the same period in 2000. This increase is due to the significantly higher cash balances that we have maintained, primarily from senior notes issuances and the issuance of our convertible securities in April 2001. Other income -- Other income increased to $3.3 million in 2001 from $(0.2) million in 2000 primarily due to foreign currency gains relating to Encal debt that was repaid during the quarter. Provision for income taxes -- The effective income tax rate was approximately 39.1% and 41.1% for the three months ended June 30, 2001 and 2000, respectively. The decrease in rates was due to the lower contribution of Canadian operations (which are subject to higher statutory tax rates) due partially to the recognition of nonrecurring merger costs. Extraordinary charge, net -- The $1.3 million charge relating to write off of unamortized deferred financing costs was a result of the repayment of $105 million 9 1/4% Senior Notes Due 2004. Six Months Ended June 30, 2001, Compared to Six Months Ended June 30, 2000 Revenue -- Total revenue increased to $2,952.6 million for the six months ended June 30, 2001, compared to $702.4 million for the same period in 2000. Electric generation and marketing revenue increased to $2,307.4 million in 2001 compared to $547.7 million in 2000. Approximately $594.3 million of the $1,759.7 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 June 30, 2001, includes the consolidated results of fourteen additional facilities that we acquired or completed construction on subsequent to June 30, 2000. Our power marketing activities contributed an additional $1,095.7 million due to increased price hedging and optimization activity during the six months ended June 30, 2001. We also recognized $69.7 million in mark-to-market gains on power derivatives. Oil and gas production and marketing revenue increased to $628.9 million in 2001 compared to $136.6 million in 2000. Approximately $339.5 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 $152.7 million of the variance relates to increased production and commodity prices in sales to third parties from reserves acquired in Canada and in the United States. Income from unconsolidated investments in power projects decreased to $2.2 million in 2001 compared to $14.6 million during 2000. The variance is primarily due to the contractual reduction in distributions from the Sumas Power Plant of approximately $9.7 million. Other revenue increased to $14.2 million in 2001 compared to $3.4 million in 2000. This increase is due primarily to $6.4 million recognized in 2001 from our custom turbine parts manufacturing subsidiary, Power Systems Mfg., LLC, and a $2.8 million increase in interest income on loans to power projects. Cost of revenue -- Cost of revenue increased to $2,372.8 million in 2001 compared to $484.6 million in 2000. Approximately $1,068.7 million of the $1,888.2 million increase relates to the cost of power purchased by our energy services organization. Similarly, oil and gas production and marketing expense grew by $343.0 million, largely due to a $321.7 million increase in expense for the cost of gas purchased and resold by the energy services organization. Fuel expense increased 173%, from $177.7 million in 2000 to $485.4 million in 2001, due to a 67% increase in megawatt hours generated and a significant increase in fuel price. Depreciation expense increased by 51%, from $95.8 million in the first six months of 2000 to $144.2 million in the first six months of 2001, due to additional power facilities in operation in 2001 and due to $30.2 million in higher depreciation and depletion in our oil and gas operating subsidiaries. Operating lease expense increased by $34.3 million due to leases entered into or acquired in connection with our Pasadena, Tiverton, Rumford, and KIAC facilities during and subsequent to the period ended June 30, 2000. General and administrative expense -- General and administrative expense increased 202% to $86.6 million for the six months ended June 30, 2001, as compared to $28.7 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. Nonrecurring merger costs -- We incurred approximately $41.6 million in the six months ended June 30, 2001, in connection with the merger with Encal Energy Limited 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 58% to $63.3 million for the six months ended June 30, 2001, from $40.0 million for the same period in 2000. Interest expense increased primarily due to the issuances of $1.15 billion of Senior Notes Due 2011 in February 2001 and of $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 90% to $30.6 million for the first six months in 2001 compared to $16.1 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 on the January 2000 offering and the subsequent exercise of the purchasers' option to purchase additional securities. Interest income -- Interest income increased to $39.9 million for the six months ended June 30, 2001, compared to $13.2 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 second quarter of 2001. Other income -- Other income increased to $9.0 million in 2001 from $0.4 million in 2000 primarily due to a gain on the sale of our interests in the Elwood development project and the Bayonne facility and related contingent income recognized as earned thereafter. Provision for income taxes -- The effective income tax rate was approximately 41.1% and 41.2% for the six months ended June 30, 2001 and 2000, respectively. Extraordinary charge, net -- The $1.3 million charge was a result of writing off unamortized deferred financing costs related to the repayment of $105 million 9 1/4% Senior Notes Due 2004. Cumulative effect of a change in accounting principle -- The $1.0 million of additional income, net of tax, is due to the adoption of Statement of Financial Accounting Standards ("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 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. Outlook Our strategy is to continue our rapid growth by capitalizing on the significant opportunities in the power industry, primarily through our active development and acquisition programs. In pursuing our proven growth strategy, we utilize our extensive management and technical expertise to implement a fully integrated approach to the acquisition, development and operation of power generation facilities. This approach uses our expertise in design, engineering, procurement, finance, construction management, fuel and resource acquisition, operations, risk management and power marketing, which we believe provides us with a competitive advantage. The key elements of our strategy are as follows: Development of new and expansion of existing power plants -- We are actively pursuing the development of new and expansion of both baseload and peaking capacity at our existing highly efficient, low-cost, gas-fired power plants that replace old and inefficient generating facilities and meet the demand for new generation. Our strategy is to develop power plants in strategic geographic locations that enable us to leverage existing power generation assets and operate the power plants as integrated electric generation systems. This allows us to achieve significant operating synergies and efficiencies in fuel procurement, power marketing and operation and maintenance. At August 13, 2001, we had 27 projects under construction, representing an additional 14,932 megawatts of net capacity. Included in these 27 projects are 4 project expansions, representing 735 megawatts of net capacity. We have also announced plans to develop 29 additional power generation projects, representing a net capacity of 16,618 megawatts. Included in these 29 development projects are 5 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 81 power plants with a net capacity of 24,558 megawatts, after completion of our projects currently under construction. We focus on operating our plants as an integrated system of power generation, which enables us to minimize costs and maximize operating efficiencies. We believe that achieving and maintaining a low cost of production will be increasingly important to compete effectively in the power generation industry. Risk Factors 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 Federal Energy Regulatory Commission. 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 agreed to assume its QF contracts with us in bankruptcy, 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. 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. 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 must be completed within 45 days from the date the California ISO provides certain critical data for the purpose of developing the factual basis needed to implement the refund methodology and order refunds. While it is not possible to predict the amount of any refunds until the hearing takes 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 June 30, 2001, we had short-term investments of $740.8 million. These short-term investments consist of highly liquid investments with maturities less than three months. We have the ability to hold these investments to maturity, and as a result, we would not expect the value of these investments to be affected to any significant degree by the effect of a sudden change in market interest rates. Interest rate swaps -- 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 June 30, 2001 (dollars in thousands):
Notional Weighted Principal Average Fair Maturity Date Amount Interest Rate Market Value ------------- --------- ------------- ------------ 2001................... $ 71,000 7.4% $ (72) 2007................... 38,150 8.0 (3,907) 2007................... 38,150 8.0 (3,889) 2007................... 29,757 7.9 (3,146) 2007................... 29,757 7.9 (3,131) 2009................... 15,000 6.9 (709) 2011................... 55,742 6.9 (2,611) 2012................... 120,078 6.5 (3,273) 2014................... 72,334 6.7 (2,815) 2015................... 22,500 7.0 (1,278) 2018................... 17,500 7.0 (1,055) --------- ---- --------- Total......... $ 509,968 7.1% $ (25,886) ========= ==== =========
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 June 30, 2001 Electricity................. $ 595,850 $ (204,773) Natural gas................. (294,840) (105,763) ---------- ---------- Total................... $ 301,010 $ (310,536) =========== ==========
Derivative commodity instruments included in the table are those included in Note 3 to the 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 six months ended June 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. ITEM 3. Quantitative and Qualitative Disclosures About Market Risk. See "Financial Market Risks" in ITEM 2. PART II. OTHER INFORMATION ITEM 2. Change in Securities and Use of Proceeds. On April 30, 2001, we completed the sale of $1.0 billion of Zero-Coupon Convertible Debentures Due 2021 in a private placement under Rule 144A of the Securities Act of 1933. The securities are convertible into Calpine common shares at a price of $75.35 at the option of the holder at any time. Holders have the right to require us to repurchase their debentures in 2002, 2004, 2006, 2008, 2011 and 2016 at a specified price in cash or Calpine common stock at our option, except in 2016 when the repurchase price must be paid in cash. The debentures are redeemable at the option of Calpine after 2004 at a specified price in cash or Calpine common stock. ITEM 4. Submission of Matters to a Vote of Security Holders. Our Annual Meeting of Stockholders was held on May 17, 2001, (the "Annual Meeting") in Boston, Massachusetts. At the Annual Meeting, the stockholders voted on the following matters: (i) the proposal to elect two Class II Directors to the Board of Directors for a term of three years expiring in 2004, (ii) the proposal to amend the Company's Amended and Restated Certificate of Incorporation to increase the number of authorized shares of Common Stock, par value $.001 per share ("Common Stock"), from 500,000,000 to 1,000,000,000; and (iii) the proposal to ratify the appointment of Arthur Andersen LLP as independent accountants for the Company for the fiscal year ending December 31, 2001. The stockholders elected management's nominees as the Class II Directors in an uncontested election, approved the amendment to the Company's Amended and Restated Certificate of Incorporation to increase the number of authorized shares of Common Stock from 500,000,000 to 1,000,000,000, and ratified the appointment of independent accountants by the following votes, respectively: (i) Election of Ann B. Curtis and Kenneth T. Derr as Class II Directors for a three-year term expiring 2004, 250,888,564 FOR and 2,555,356 ABSTAIN, (ii) Amendment to the Company's Amended and Restated Certificate of Incorporation to increase the authorized shares of Common Stock from 500,000,000 to 1,000,000,000, 226,837,920 FOR, 25,790,692 AGAINST, and 815,308 ABSTAIN, and (iii)Ratification of the appointment of Arthur Andersen LLP as independent accountants for the fiscal year ending December 31, 2001, 240,859,017 FOR, 11,784,745 AGAINST, and 800,158 ABSTAIN. The three-year terms of Class III and Class I Directors continued after the Annual Meeting and will expire in 2002 and 2003, respectively. The Class III Directors include Peter Cartwright, Michael P. Polsky, and Susan C. Schwab. The Class I Directors are Jeffrey E. Garten, George J. Stathakis, and John O. Wilson. Subsequent to the Annual Meeting, on July 16, 2001, we announced that Michael Polsky had resigned from the Board of Directors. 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 The following exhibits are filed herewith unless otherwise indicated:
Exhibit Number Description ------- ----------- 2.1 Combination Agreement, dated as of February 7, 2001, by and between Calpine Corporation and Encal Energy Ltd. *2.2 Amending Agreement to the Combination Agreement, dated as of March 16, 2001, between Calpine Corporation and Encal Energy Ltd. (a) 2.3 Form of Plan of Arrangement Under Section 186 of the Business Corporations Act (Alberta) (included as Exhibit A to Exhibit 2.1) Involving and Affecting Encal Energy Ltd. and the Holders of its Common Shares and Options *3.1 Amended and Restated Certificate of Incorporation of Calpine Corporation (b) *3.2 Certificate of Correction of Calpine Corporation (c) *3.3 Certificate of Amendment of Amended and Restated Certificate of Incorporation of Calpine Corporation (d) *3.4 Certificate of Designation of Series A Participating Preferred Stock of Calpine Corporation (c) *3.5 Amended Certificate of Designation of Series A Participating Preferred Stock of Calpine Corporation (c) *3.6 Amended Certificate of Designation of Series A Participating Preferred Stock of Calpine Corporation (d) 3.7 Certificate of Designation of Special Voting Preferred Stock of Calpine Corporation *3.8 Amended and Restated By-laws of Calpine Corporation (e) 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 (f) *4.4 First Supplemental Indenture dated as of September 28, 2000, between Calpine Corporation and Wilmington Trust Company, as Trustee (g) *4.5 Indenture dated as of April 25, 2001, between Calpine Canada Energy Finance ULC and Wilmington Trust Company, as Trustee (h) *4.6 Guarantee Agreement dated as of April 25, 2001, by Calpine Corporation as guarantor of debt securities of Calpine Canada Energy Finance ULC (h) 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 (i)
------------ * Incorporated by reference. (a) Incorporated by reference to Calpine Corporation's Registration Statement on Form S-3/A (File No. 333-56712). (b) Incorporated by reference to Calpine Corporation's Registration Statement on Form S-3 (File No. 333-40652). (c) 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. (d) Incorporated by reference to Calpine Corporation's Registration Statement on Form S-3 (File No. 333-66078). (e) Incorporated by reference to Calpine Corporation's Registration Statement on Form S-1 (File No. 333-07497). (f) Incorporated by reference to Calpine Corporation's Registration Statement on Form S-3/A (File No. 333-72583). (g) 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). (h) Incorporated by reference to Calpine Corporation's Registration Statement on Form S-3/A (File No. 333-57338). (i) Approximately 24 pages of this exhibit have been omitted pursuant to a request for confidential treatment. The omitted language has been filed separately with the Securities and Exchange Commission. (b) Reports on Form 8-K The registrant filed the following reports on Form 8-K during the quarter ended June 30, 2001:
Date of Report Date Filed Item Reported -------------- -------------- ------------- April 9, 2001 April 10, 2001 5 April 19, 2001 April 19, 2001 2, 7 April 26, 2001 April 30, 2001 5, 7 June 26, 2001 June 26, 2001 5
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: August 14, 2001 --------------------------------- Ann B. Curtis Executive Vice President (Chief Financial Officer) By: /s/ Charles B. Clark, Jr. Date: August 14, 2001 --------------------------------- Charles B. Clark, Jr. Vice President and Corporate Controller (Chief Accounting Officer)