10-Q 1 q1-2001q.txt FIRST QUARTER UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-Q [ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended March 31, 2001 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ______________ to _________________ Commission file number: 1-12079 CALPINE CORPORATION A Delaware Corporation I.R.S. Employer Identification No. 77-0212977 50 West San Fernando Street San Jose, California 95113 Telephone: (408) 995-5115 Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: $.001 par value Common Stock 298,652,450 shares outstanding on May 14, 2001 CALPINE CORPORATION AND SUBSIDIARIES Report on Form 10-Q For the Quarter Ended March 31, 2001
INDEX PART I. FINANCIAL INFORMATION Page No. ITEM 1. Financial Statements Consolidated Condensed Balance Sheets March 31, 2001 and December 31, 2000.......................3 Consolidated Condensed Statements of Operations For the Three Months Ended March 31, 2001 and 2000.........4 Consolidated Condensed Statements of Cash Flows For the Three Months Ended March 31, 2001 and 2000.........5 Notes to Consolidated Condensed Financial Statements March 31, 2001.............................................6 ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.......................14 ITEM 3. Quantitative and Qualitative Disclosures About Market Risk...............................................22 PART II. OTHER INFORMATION ITEM 6. Exhibits and Reports on Form 8-K............................22
Signatures....................................................................24 PART I. FINANCIAL INFORMATION ITEM 1. Financial Statements CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED BALANCE SHEETS March 31, 2001 and December 31, 2000 (in thousands, except share and per share amounts)
March 31, December 31, 2001 2000 ------------ ------------ (unaudited) ASSETS Current assets: Cash and cash equivalents ........................................... $ 870,079 $ 588,698 Accounts receivable, net of allowance of $16,808 and $11,078 ........ 683,514 649,422 Inventories ......................................................... 40,880 36,883 Prepaid expenses .................................................... 65,226 27,515 Other current assets ................................................ 436,517 41,165 ------------ ------------ Total current assets ........................................ 2,096,216 1,343,683 ------------ ------------ Property, plant and equipment, net .................................... 8,204,452 7,459,055 Investments in power projects ......................................... 229,106 205,621 Project development costs ............................................. 57,807 38,597 Notes receivable ...................................................... 249,835 217,927 Restricted cash ....................................................... 125,208 88,618 Deferred financing costs .............................................. 155,930 139,631 Other assets .......................................................... 400,252 244,125 ------------ ------------ Total assets ................................................ $ 11,518,806 $ 9,737,257 ============ ============ LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Notes payable and borrowings under lines of credit, current portion ................................................... $ 851 $ 1,087 Accounts payable .................................................... 631,738 765,613 Project financing, current portion .................................. 91,571 58,486 Capital lease obligation, current portion ........................... 2,050 1,985 Income taxes payable ................................................ 47,172 63,409 Accrued payroll and related expenses ................................ 42,216 53,667 Accrued interest payable ............................................ 75,600 75,865 Other current liabilities ........................................... 532,243 149,080 ------------ ------------ Total current liabilities ................................... 1,423,441 1,169,192 ------------ ------------ Notes payable and borrowings under lines of credit, net of current portion .............................................. 133,955 195,862 Project financing, net of current portion ............................. 1,646,564 1,473,869 Senior notes .......................................................... 3,701,750 2,551,750 Capital lease obligation, net of current portion ...................... 208,840 208,876 Deferred income taxes, net ............................................ 524,851 567,292 Deferred lease incentive .............................................. 59,800 60,676 Deferred revenue ...................................................... 105,366 92,511 Other liabilities ..................................................... 241,186 20,389 ------------ ------------ Total liabilities ........................................... 8,045,753 6,340,417 ------------ ------------ Company-obligated mandatorily redeemable convertible preferred securities of subsidiary trusts ........................... 1,122,686 1,122,490 Minority interests .................................................... 41,180 37,576 Stockholders' equity: Preferred stock, $.001 par value per share; authorized 10,000,000 shares; none issued and outstanding in 2001 and 2000 .................................. -- -- Common stock, $.001 par value per share; authorized 500,000,000 shares in 2001 and 2000; issued and outstanding 285,113,768 shares in 2001 and 283,715,058 shares in 2000 .................................... 285 284 Additional paid-in capital .......................................... 1,734,202 1,700,505 Retained earnings ................................................... 631,394 536,617 Accumulated other comprehensive loss ................................ (56,694) (632) ------------ ------------ Total stockholders' equity .................................. 2,309,187 2,236,774 ------------ ------------ Total liabilities and stockholders' equity .................. $ 11,518,806 $ 9,737,257 ============ ============ The accompanying notes are an integral part of these consolidated condensed financial statements.
CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS For the Three Months Ended March 31, 2001 and 2000 (in thousands, except per share amounts) (unaudited)
Three Months Ended March 31, -------------------------- 2001 2000 Revenue: Electric generation and marketing revenue ............. $ 1,050,067 $ 206,068 Oil and gas production and marketing revenue .......... 175,957 17,179 Income from unconsolidated investments in power projects ....................... 563 9,774 Other revenue ......................................... 3,262 2,381 ----------- ----------- Total revenue ....................................... 1,229,849 235,402 ----------- ----------- Cost of revenue: Power plant generating and marketing expense .......... 551,735 52,885 Oil and gas production and marketing expense .......... 131,711 10,413 Fuel expenses ......................................... 257,014 73,652 Depreciation expenses ................................. 52,910 27,818 Operating lease expenses .............................. 28,011 10,458 Other expenses ........................................ 2,499 1,501 ----------- ----------- Total cost of revenue ............................... 1,023,880 176,727 ----------- ----------- Gross profit ............................................ 205,969 58,675 Project development expenses ............................ 15,839 3,755 General and administrative expenses ..................... 32,712 8,619 ----------- ----------- Income from operations .............................. 157,418 46,301 Interest expense ........................................ 15,705 17,907 Distributions on trust preferred securities ............. 15,175 6,978 Interest income ......................................... (19,359) (7,562) Other income ............................................ (10,787) (836) ----------- ----------- Income before provision for income taxes ............ 156,684 29,814 Provision for income taxes .............................. 62,943 11,687 ----------- ----------- Income before cumulative effect of a change in accounting principle .............................. 93,741 18,127 Cumulative effect of a change in accounting principle, net of tax of $668 and $-- ............. 1,036 -- ----------- ----------- Net income .......................................... $ 94,777 $ 18,127 =========== =========== Basic earnings per common share: Weighted average shares of common stock outstanding ... 284,160 253,347 Income before cumulative effect of a change in accounting principle ................................ $ 0.33 $ 0.07 Cumulative effect of a change in accounting principle $ -- $ -- ----------- ----------- Net income ............................................ $ 0.33 $ 0.07 =========== =========== Diluted earnings per common share: Weighted average shares of common stock outstanding before dilutive effect of certain trust preferred securities .......................................... 299,927 269,255 Income before dilutive effect of certain trust preferred securities and cumulative effect of a change in accounting principle ...................... $ 0.31 $ 0.07 Dilutive effect of certain trust preferred securities (1) ...................................... $ 0.01 $ -- ----------- ----------- Income before cumulative effect of a change in accounting principle ................................ $ 0.30 $ 0.07 Cumulative effect of a change in accounting principle.. $ -- $ -- ----------- ----------- Net Income ............................................ $ 0.30 $ 0.07 =========== =========== (1) Includes the dilutive effect of the assumed conversion of certain trust preferred securities. For the three months ended March 31, 2001, the assumed conversion calculation adds 32,969 shares of common stock and $5,423 to the net income results, representing the after tax distribution expense on certain trust preferred securities avoided upon conversion. These securities were not dilutive for the three months ended March 31, 2000, and were therefore excluded from the calculation for that period. The accompanying notes are an integral part of these consolidated condensed financial statements.
CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS For the Three Months Ended March 31, 2001 and 2000 (in thousands) (unaudited)
Three Months Ended March 31, -------------------------- 2001 2000 ----------- ----------- Cash flows from operating activities: Net income ........................................... $ 94,777 $ 18,127 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization ...................... 58,491 29,264 Deferred income taxes, net ......................... (37,229) (8,862) Income from unconsolidated investments in power projects ................................ (563) (9,774) Distributions from unconsolidated power projects ... 1,213 10,260 Minority interest .................................. 3,604 (224) Change in derivative value ......................... 162,172 -- Change in operating assets and liabilities, net of effects of acquisitions: Accounts receivable .............................. (34,092) 3,143 Inventories ...................................... (3,997) 594 Other current assets ............................. (420,756) (6,734) Notes receivable ................................. (7,959) (4,794) Other assets ..................................... (156,127) 7,317 Accounts payable and accrued expenses ............ (145,215) (15,032) Other current liabilities ........................ 395,642 681 ----------- ----------- Net cash provided by (used in) operating activities ......................... (90,039) 23,966 ----------- ----------- Cash flows from investing activities: Purchases of property, plant and equipment ........... (798,307) (280,085) Acquisitions, net of cash acquired ................... -- (148,709) Capital expenditures on joint ventures ............... (32,331) (94,263) Maturities of collateral securities .................. 2,885 1,630 Project development costs ............................ (19,210) (43,181) Decrease (increase) in restricted cash ............... (51,964) 231 Increase in notes receivable ......................... (21,588) -- Other ................................................ 8,384 (236) ----------- ----------- Net cash used in investing activities ........ (912,131) (564,613) ----------- ----------- Cash flows from financing activities: Borrowings from project financing .................... 609,354 99,877 Repayments of notes payable and borrowings under lines of credit .................................... (61,907) (5,503) Repayments of project financing ...................... (403,810) -- Proceeds from issuance of Senior Notes ............... 1,150,000 -- Proceeds from issuance of trust preferred securities . -- 360,000 Proceeds from issuance of common stock ............... 12,249 2,826 Financing costs ...................................... (24,927) (15,333) Other ................................................ 2,592 -- ----------- ----------- Net cash provided by financing activities .... 1,283,551 441,867 ----------- ----------- Net increase (decrease) in cash and cash equivalents ... 281,381 (98,780) Cash and cash equivalents, beginning of period ......... 588,698 349,371 ----------- ----------- Cash and cash equivalents, end of period ............... $ 870,079 $ 250,591 =========== =========== Cash paid during the period for: Interest ............................................. $ 119,992 $ 19,726 Income taxes ......................................... $ 65,657 $ 13,621 The accompanying notes are an integral part of these consolidated condensed financial statements.
CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS March 31, 2001 (unaudited) 1. Organization and Operation of the Company Calpine Corporation ("Calpine" or "the Company"), a Delaware corporation, and subsidiaries (collectively, the "Company") is engaged in the generation of electricity in the United States and Canada. In pursuing this single business strategy, the Company is involved in the development, acquisition, ownership and operation of power generation facilities and the sale of electricity and its by-product, thermal energy, primarily in the form of steam. The Company has ownership interests in and operates gas-fired cogeneration facilities, gas fields, gathering systems and gas pipelines, geothermal steam fields and geothermal power generation facilities in the United States and Canada. Each of the generation facilities produces and markets electricity for sale to utilities and other third party purchasers. Thermal energy produced by the gas-fired cogeneration facilities is primarily sold to governmental and industrial users. 2. Summary of Significant Accounting Policies Basis of Interim Presentation -- The accompanying interim consolidated condensed financial statements of the Company have been prepared by the Company, without audit by independent public accountants, pursuant to the rules and regulations of the Securities and Exchange Commission. In the opinion of management, the consolidated condensed financial statements include the adjustments necessary to present fairly the information required to be set forth therein. Certain information and note disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted from these statements pursuant to such rules and regulations and, accordingly, should be read in conjunction with the audited consolidated financial statements of the Company included in the Company's annual report on Form 10-K for the year ended December 31, 2000. The results for interim periods are not necessarily indicative of the results for the entire year. Use of Estimates in Preparation of Financial Statements -- The preparation of financial statements in conformity with generally accepted accounting principles in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The most significant estimates with regard to these financial statements relate to future development costs and useful lives of the generation facilities. Revenue Recognition -- The Company is first and foremost an electric generation company, operating a portfolio of mostly wholly-owned plants but also some plants in which its ownership interest is 50% or less and which are accounted for under the equity method. In conjunction with its electric generation business, the Company also produces, as a by-product, thermal energy for sale to customers, principally steam hosts at its cogeneration sites. In addition the Company acquires and produces natural gas for its own consumption and sells the balance and small amounts of oil to third parties. To protect and enhance the profit potential of its electric generation plants, the Company's subsidiary, Calpine Energy Services, LP ("CES"), enters into electric and gas hedging, balancing and related transactions in which purchased electricity and gas is resold to third parties. CES acts as a principal, takes title to the commodities purchased for resale and assumes the risks and rewards of ownership. Therefore, in accordance with Staff Accounting Bulletin No. 101 and the Emerging Issues Task Force ("EITF") Issue No. 99-19, CES recognizes revenue on a gross basis, except in the case of qualifying hedge transactions, in which case the net gain or loss from the hedging instrument is recorded in income against the underlying hedged item when the effects of the hedged item are recognized. Hedged items typically include sales to third parties of natural gas produced, purchases of natural gas to fuel power plants, and sales of generated electricity. Finally, the Company, through Power Systems Mfg., LLC ("PSM"), designs and manufactures spare parts for gas turbines. PSM also generates small amounts of revenue by occasionally loaning to power projects and by providing operation and maintenance ("O&M") services to unconsolidated power plants. Further details of the Company's revenue recognition policy for each type of revenue transaction are provided below: Electric Generation and Marketing Revenue - This category of revenue includes electricity and steam sales, Statement of Financial Accounting Standards No. 133 ("SFAS 133"), "Accounting for Derivative Instruments and Hedging Activities," gains and losses from electric power derivatives (see "New Accounting Pronouncements") and sales of purchased power. The Company actively manages the revenue stream for its portfolio of electric generating facilities through its wholly-owned subsidiary, CES. CES performs a market-based allocation of electric generation and marketing revenue to electricity and steam sales. That allocation is based on electricity delivered by the Company's electric generating facilities to serve CES contracts. As the Company actively manages the revenue stream for its portfolio of electric generating facilities, it is appropriate to review the Company's financial performance using all electric generation and marketing revenue. Electricity and Steam Sales - For electricity sales by plants under direct contracts with third parties, electrical energy revenue is recognized upon transmission to the customer, and capacity and ancillary revenue is recognized when contractually earned. In accordance with EITF Issue No. 91-6, revenues from contracts entered into or acquired since May 1992, such as those relating to Calpine Geysers Company, are recognized at the lesser of amounts billable under the contract or amounts recognizable at an average rate over the term of the contract. For electricity sales by plants not under contracts with third parties, revenue is recognized as described in Note 8. Net gains or losses from qualified hedges of electricity positions are included in electricity and steam sales. Calpine Gilroy Cogen, LP ("Gilroy") had a long-term power purchase agreement ("PPA") with Pacific Gas and Electric Company ("PG&E") for the sale of energy through 2018. The terms of the PPA provided for 120 megawatts of firm capacity and up to 10 megawatts of as-delivered capacity. On December 2, 1999, the California Public Utilities Commission approved the restructuring of the PPA between Gilroy and PG&E. Under the terms of the restructuring, PG&E and Gilroy are each released from performance under the PPA effective November 1, 2002. Under the restructured contract, in addition to the normal capacity revenue for the period, Gilroy will earn from September 1999 to October 2002 restructured capacity revenue it would have earned over the November 2002 through March 2018 time period, for which PG&E will issue notes to the Company. At March 31, 2001, Gilroy had $68.3 million of such notes receivable from PG&E. These notes are scheduled to be paid by PG&E during the period from February 2003 to September 2014 (See Note 7). SFAS 133 Gains or Losses from Electric Power Derivatives - Certain power derivatives are not eligible for hedge accounting under SFAS 133, and the change in fair value of such derivatives is recorded as revenue (see New Accounting Pronouncements). The ineffective portion of power derivatives designated as hedges is recorded to revenue using the dollar offset method. Sales of Purchased Power - The Company recognizes revenue from power hedging, balancing and related activities through its wholly-owned subsidiary, CES. Revenue generated from CES through sales of purchased power to third parties is recorded as described in Note 8. Oil and Gas Production and Marketing Revenue - This category of revenue includes sales to third parties of gas, oil and related products that are produced by our Calpine Natural Gas and Calpine Canada Natural Gas subsidiaries and also sales of purchased gas. Sales to Third Parties of Gas, Oil and Related Products That Are Produced by the Company - Revenue from the sale of crude oil is recognized upon the passage of title, net of royalties and net of gains or losses from qualified hedges. Revenue from natural gas production is recognized using the sales method, net of royalties and net of gains or losses from qualified hedges. Sales of Purchased Gas - The Company recognizes revenue from gas hedging, balancing and related activities through its wholly-owned subsidiary, CES. Revenue generated from CES through sales of purchased gas to third parties is recorded as described in Note 8. Income from Unconsolidated Investments in Power Projects - The Company uses the equity method to recognize as revenue its pro rata share of the net income or loss of the unconsolidated investment until such time, if applicable, as the Company's investment is reduced to zero, at which time equity income is generally recognized only upon receipt of cash distributions from the investee. Other Revenues - This category of revenue includes O&M contract revenue, interest income on loans to power projects, PSM revenue from sales to third parties and miscellaneous revenue. O&M Contract Revenue - The Company performs operations and maintenance services for some of the projects in which it has an interest. Revenue from investees on these contracts is recognized when the services are performed. Interest Income on Loans to Power Projects - The Company recognizes as revenue interest income on loans to power projects in which it invests as the interest is earned and realizable. PSM Revenue - The Company recognizes revenue from its PSM subsidiary as products are delivered to the customer for smaller orders and on the percentage of completion method for certain special large orders under which work is performed over an extended time period. Energy Marketing Operations -- The Company, through its wholly-owned subsidiary CES, markets energy services to utilities, wholesalers, and end users. CES provides these services by entering into contracts to purchase or supply energy, primarily, at specified delivery points and specified future dates. CES also utilizes financial instruments to manage its exposure to electricity and natural gas price fluctuations, and to a lesser degree, price fluctuations of crude oil and refined products. The Company actively manages its positions, and the Company's policy prohibits positions that exceed production capacity and fuel requirements. The Company's credit risk associated with energy contracts results from the risk-of-loss on non-performance by counterparties. The Company reviews and assesses counterparty risk to limit any material impact on its financial position and results of operations. The Company does not anticipate non-performance by the counterparties. New Accounting Pronouncements -- On January 1, 2001, the Company adopted SFAS 133. The Company currently holds four classes of derivative instruments that are impacted by the new pronouncement - interest rate swaps, commodity financial instruments, commodity contracts, and physical options. Additionally, one of the Company's unconsolidated investees holds two foreign exchange forward contracts. The Company holds various interest rate swap agreements to hedge against changes in floating interest rates on certain of its project financing facilities (see Note 8 to the Company's Year 2000 Form 10-K report). The interest rate swap agreements effectively convert floating rates into fixed rates so that the Company can predict with greater assurance what its future interest costs will be and protect itself against increases in floating rates. The Company enters into commodity financial instruments to convert floating or indexed electricity and gas (and to a lesser extent oil and refined product) prices to fixed prices, thus, lessening the Company's vulnerability to reductions in electric prices for the electricity it generates, to reductions in gas prices for the gas it produces and to increases in gas prices for the fuel it consumes in its power plants. The Company seeks to "self-hedge" its gas consumption exposure to the maximum extent with its gas production position. The Company routinely negotiates commodity contracts for sales of its generated electricity and sales of its natural gas production to ensure favorable utilization of generation and production assets. Under SFAS 133 such contracts are often considered derivatives but are generally eligible for the normal purchase and sales exception. However, certain contracts, such as capacity sales contracts, are currently considered ineligible for hedge accounting. Nonetheless, they are an important means of selling generated electricity to customers who need the flexibility to match their purchases with their electric loads, since electricity cannot be stored. The Company also enters into physical options for short-term periods (typically one month) to balance its short-term generating position. The options, which the Company may write or purchase, typically provide for a premium component and firm price for energy when exercised. Upon adoption of SFAS 133, the fair values of all derivative instruments were recorded on the balance sheet as assets or liabilities. The fair value of derivative instruments is estimated based on present value adjusted quoted market prices of comparable contracts. For derivative instruments that were designated as hedges, the difference between the carrying values of the derivatives and their fair values at the date of adoption was recorded as a transition adjustment. All such derivatives were designated as cash flow hedges and were highly effective. Accordingly, a transition adjustment was recorded as a cumulative-effect-type adjustment to accumulated other comprehensive income ("OCI"). Certain of the Company's capacity sales contracts are considered derivatives not eligible for hedge accounting under the Financial Accounting Standards Board's ("FASB") tentative conclusion on SFAS 133 Implementation Issue No. C15. For such capacity contracts, their respective fair values were recorded on the income statement as a cumulative effect of a change in accounting principle. At the end of each quarter, the changes in fair values of derivative instruments designated as cash flow hedges are recorded on the balance sheet as an asset or liability. In the case of the effective portion of a hedge, an adjustment is recorded to OCI. In the case of the ineffective portion of a hedge, an adjustment is calculated using the dollar offset method and charged to income or expense on the income statement. The changes in fair values of derivative instruments that are not designated as effective hedges, or for which hedge accounting is not allowable, such as certain of the Company's capacity sales contracts, are recorded on the balance sheet as assets or liabilities and an offset is charged to income or expense on the income statement. At March 31, 2001, the FASB had not resolved SFAS 133 Implementation Issue No. C15 dealing with a proposed electric industry normal purchases and sales exception for capacity sales transactions ("The Eligibility of Option Contracts on Electricity for the Normal Purchases and Normal Sales Exception"). The Company does not assume the FASB will permit use of this exception for capacity sales contracts. Certain capacity sales contracts currently held by the Company meet the criteria of SFAS 133 Implementation Issue No. C15 and are therefore subject to the FASB's final decision expected in June 2001. Pending the FASB's final decision, the Company assumes that these contracts will not be exempt from derivative accounting treatment under the normal purchases and sales exemption unless they meet "requirements contract" guidelines under SFAS 133. The table below reflects the amounts (in thousands) that are recorded as assets, liabilities, income, expense, and OCI on March 31, 2001 for the Company's derivative instruments.
Interest Commodity Rate Derivative Swaps Instruments --------- ----------- Current derivative asset (1)........................................ $ -- $ 391,291 Long-term derivative asset (2)...................................... -- 162,488 --------- --------- Total assets ..................................................... $ -- $ 553,779 ========= ========= Current derivative liability (3).................................... 484 408,297 Long-term derivative liability (4).................................. 36,086 186,393 --------- --------- Total liabilities ................................................ $ 36,570 $ 594,690 ========= ========= Total comprehensive loss ........................................... (35,898) (67,330) Reclassification adjustment for activity included in net income ............................................................. -- 17,047 Income tax benefit ................................................. 12,875 19,736 --------- --------- Net comprehensive loss ........................................... $ (23,023) $ (30,547) ========= ========= Income on electricity contracts (5)................................. -- 1,306 Income on natural gas contracts (6)................................. -- 7,550 Income tax expense ................................................. -- (3,476) --------- --------- Income included in income from operations ........................ $ -- $ 5,380 ========= ========= Cumulative effect of a change in accounting principle (net of tax).. $ -- $ 1,036 (1) Included in other current assets (2) Included in other assets (3) Included in other current liabilities (4) Included in other liabilities (5) Included in electric generation and marketing revenue. (6) Included in fuel expense in cost of revenue.
During the three months ended March 31, 2001, the Company recognized a net gain of $6.4 million in earnings representing the amount of hedge ineffectiveness and changes in fair value of derivatives for which hedge accounting was not available. Of this amount, $1.0 million was recorded on January 1, 2001 as the cumulative effect of a change in accounting principle and the balance of $5.4 million was recorded in current earnings. A $0.4 million loss associated with hedge ineffectiveness is offset by a $5.8 million gain associated with derivative instruments excluded from the assessment of hedge effectiveness. The Company did not exclude any components of the derivative instruments' gain or loss from the assessment of hedge effectiveness and there were no reclassifications into earnings as a result of the discontinuance of hedges. As of March 31, 2001, the maximum length of time over which the Company is hedging its exposure to the variability in future cash flows for forecasted transactions is 17.5 years. The Company estimates that losses of $20.2 million will be reclassified from accumulated OCI into earnings during 2001 as the hedged transactions affect earnings. Reclassifications -- Prior period amounts in the consolidated financial statements have been reclassified where necessary to conform to the 2001 presentation. 3. Property, Plant and Equipment, Net and Capitalized Interest Property, plant and equipment, net consisted of the following (in thousands):
March 31, December 31, 2001 2000 ------------ ------------ Geothermal properties .......................... $ 341,086 $ 334,585 Oil and gas properties ......................... 647,962 658,547 Buildings, machinery and equipment ............. 1,981,838 1,927,642 Power sales agreements ......................... 132,121 159,337 Gas contracts .................................. 152,353 132,748 Other .......................................... 155,416 145,653 ----------- ----------- 3,410,776 3,358,512 Less accumulated depreciation and amortization.. (385,657) (328,461) ----------- ----------- 3,025,119 3,030,051 Land ........................................... 13,932 12,578 Construction in progress ....................... 5,165,401 4,416,426 ----------- ----------- Property, plant and equipment, net ............. $ 8,204,452 $ 7,459,055 =========== ===========
Construction in progress is primarily attributable to gas-fired projects under construction. Upon commencement of plant operation, these costs are transferred to buildings, machinery and equipment. Capitalized Interest -- The Company capitalizes interest on capital invested in projects during the advanced stages of development and the construction period. For the three months ended March 31, 2001 and 2000, the Company recorded net interest expense of $15.7 million and $17.9 million, respectively, after capitalizing $69.3 million and $22.7 million of interest on general corporate funds used for construction in the first quarter of 2001 and 2000, respectively, and after recording $34.7 million and $7.2 million of interest capitalized on funds borrowed for specific construction projects in the first quarter of 2001 and 2000, respectively. The cash paid for interest during the three months ended March 31, 2001 was $16.0 million, net of capitalized interest. For the three months ended March 31, 2000 capitalized interest exceeded cash paid for interest by $10.2 million due to timing differences. Upon commencement of plant operation, capitalized interest, as a component of the total cost of the plant, is amortized over the estimated useful life of the plant. The increase in the amount of interest capitalized during the three months ended March 31, 2001 reflects the significant increase in the Company's power plant construction program. 4. Investments in Power Projects The following details the Company's income and distributions from investments in power projects (in thousands):
Ownership Income (Loss) Distributions Interest at For the three months ended March 31, March 31, 2001 2001 2000 2001 2000 -------------- -------- -------- -------- -------- Lockport Power Plant ........ 11.4% $ 1,732 $ 1,038 $ 1,058 $ 910 Gordonsville Power Plant .... 50.0% 1,674 1,965 -- -- Bayonne Power Plant ......... (1) 154 672 155 748 Sumas Power Plant ........... (2) -- 7,089 -- 7,089 Stony Brook Power Plant ..... 100.0% -- (399) -- 1,364 Kennedy International Airport Power Plant ....... 100.0% -- (1,267) -- -- Androscoggin Energy Center .. 32.3% (1,154) -- -- -- Grays Ferry Power Plant ..... 40.0% (1,368) 481 -- -- Other ....................... -- (475) 195 -- 149 ------- ------- ------- ------- Total ............... $ 563 $ 9,774 $ 1,213 $10,260 ======= ======= ======= =======
(1) The Company sold its 7.5% interest in this facility on March 12, 2001. (2) From January 1, 1998 through December, 2000, the Company recorded income equal to the amount of cash received from partnership distributions. The Company received distributions at a rate of 70% of project cash flow until December 2000 when, in accordance with the partnership agreement, a cumulative 24.5% pre-tax rate of return was earned on its original investment. As a result, the Company's equity interest in the partnership has been reduced to 0.1%, and the Company received no distributions and recorded no income in the three months ended March 31, 2001. The Company provides for deferred taxes to the extent that distributions exceed earnings. 5. Senior Notes On February 15, 2001, the Company completed a public offering of $1.15 billion of its 8 1/2% Senior Notes Due 2011 ("Senior Notes due 2011"). The Senior Notes due 2011 bear interest at 8 1/2% per year, payable semi-annually on February 15 and August 15 and mature on February 15, 2011. The Senior Notes due 2011 may be redeemed at any time prior to maturity at a redemption price equal to 100% of their principal amount plus accrued and unpaid interest plus a make-whole premium. 6. Comprehensive Income Statement of Accounting Standards No. 130, "Reporting Comprehensive Income," requires the reporting of comprehensive income in addition to net income. Comprehensive income is the total of net income and all other non-owner changes in equity. Comprehensive income includes net income and unrealized gains and losses from derivative instruments that qualify as hedges per SFAS No. 133. The Company reports accumulated other comprehensive loss in its consolidated balance sheet. The transition adjustment from SFAS No. 133 is discussed in Note 2, "Summary of Significant Accounting Policies". Total comprehensive income is summarized as follows (in thousands):
Three Months Ended March 31, 2001 2000 -------- -------- Net income .............................................. $ 94,777 $ 18,127 Other comprehensive income: Unrecognized loss on cash flow hedges ................. (86,181) -- Loss on foreign currency translation .................. (3,124) -- Income tax benefit .................................... 32,611 -- -------- -------- Accumulated other comprehensive loss, net of tax .... (56,694) -- -------- -------- Total comprehensive income .............................. $ 38,083 $ 18,127 ======== ========
7. Significant Customers The Company's Qualifying Facility ("QF") subsidiaries sell power to PG&E under the terms of long-term QF contracts at eleven facilities. On April 6, 2001, PG&E filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. PG&E is the regulated subsidiary of PG&E Corporation, and the information on PG&E disclosed below excludes PG&E Corporation's non-regulated subsidiary activity. The Company has transactions with certain of the non-regulated subsidiaries, which have not been affected by PG&E's bankruptcy. Revenues earned from PG&E for the quarters ended March 31, 2001 and 2000 were as follows (in thousands):
March 31, 2001 March 31, 2000 -------------- -------------- Revenues: PG&E ..................... $170,968 $ 41,159
Receivables at April 6, 2001, March 31, 2001, and December 31, 2000 were as follows (in thousands):
April 6, 2001 March 31, 2001 December 31, 2000 (estimate) -------------------- -------------- ----------------- Receivables: PG&E accounts receivable (1)... $270,108 $265,969 $204,448 PG&E notes receivable (2)...... 68,664 68,300 62,336 -------- -------- -------- PG&E total ........ $338,772 $334,269 $266,784 ======== ======== ======== (1) See Note 10 for further discussion of the California power market. (2) Payments of the notes receivable are scheduled from February 2003 until September 2014 (See Note 2 for further discussion).
The Company believes that the economic attractiveness of the QF contract rates makes it probable that the contracts will be assumed by PG&E in its bankruptcy proceedings. Assumption requires that PG&E cure defaults in payments to the QF facilities. Further, as noted above, PG&E has various legal remedies it may pursue to recover its excess costs of power purchases from rate payers. SFAS 5 requires two conditions to be met to establish a reserve relating to the PG&E receivables. The loss has to be both probable and able to be reasonably estimated. Based on the above, the Company does not believe a loss is probable and, in addition, it does not have a reasonable basis for estimating the amount of loss, if any. Accordingly, the Company has not established a reserve against these QF contract receivables. The Company also had a combined accounts receivable balance of $12.6 million as of March 31, 2001 from the California Independent System Operator Corporation ("CAISO") and Automated Power Exchange, Inc. ("APX"). CAISO's ability to pay the Company is directly impacted by PG&E's ability to pay CAISO. APX's ability to pay the Company is impacted by PG&E's ability to pay the California Power Exchange, which in turn pays APX for energy deliveries by the Company through APX. The Company has provided a complete reserve against collection uncertainties for these receivable balances. 8. Purchased Power and Gas Sales and Expense The Company records the cost of gas consumed in its power plants as fuel expense, while gas purchased from third parties, for hedging, balancing and related activities, is recorded as purchased gas expense, a component of oil & gas production and marketing expense. CES records the actual revenues received from third parties as sales of purchased gas, a component of oil & gas production and marketing revenue. The cost of power purchased from third parties, for hedging, balancing and related purposes, is recorded as purchased power expense, a component of electric generation and marketing expense. The Company, through its wholly-owned subsidiary, CES, markets on a system basis both power generated by its plants in excess of amounts under direct contract between the plant and a third party, and power purchased from third parties. Total revenue realized from CES marketing activity is allocated first to electricity and steam sales, a component of electricity generation and marketing revenue, based on actual production, and on market-based prices established annually, for each of the Company's power plants. The residual revenue realized is allocated to sales of purchased power, also a component of electricity generation and marketing revenue. Although the Company believes it is most meaningful to review the combined total of electric generation and marketing revenue, the table below shows the relative levels and growth of power and gas hedging, balancing and related activity based on the revenue allocation methodology described above.
Three months ended March 31, 2001 2000 -------- -------- Sales of purchased power.......... $453,602 $ 12,144 Sales of purchased gas............ 129,172 8,604 -------- -------- Total ................... $582,774 $ 20,748 ======== ======== Purchased power expense........... $456,266 $ 11,247 Purchased gas expense............. 118,628 7,739 -------- -------- Total.................... $574,894 $ 18,986 ======== ========
9. Earnings per Share Basic earnings per common share were computed by dividing net income by the weighted average number of common shares outstanding for the period. The dilutive effect of the potential exercise of outstanding options to purchase shares of common stock is calculated using the treasury stock method. The dilutive effect of the assumed conversion of certain trust preferred securities into the Company's common stock is based on the dilutive common share equivalents and the after tax distribution expense avoided upon conversion. The reconciliation of basic earnings per common share to diluted earnings per share is shown in the following table (in thousands except per share data). All share data has been adjusted to reflect the two-for-one stock splits effective June 8, 2000 and November 14, 2000.
Periods Ended March 31, 2001 2000 --------------------------- --------------------------- Net Net Income Shares EPS Income Shares EPS --------------------------------------------------------- Basic earnings per common share: Income before cumulative effect of a change in accounting principle ............ $ 93,741 284,160 $0.33 $ 18,127 253,347 $0.07 Cumulative effect of a change in accounting principle, net of tax ........... 1,036 -- -- -- -- -- -------- -------- ----- -------- -------- ----- Net income ....................... $ 94,777 284,160 $0.33 $ 18,127 253,347 $0.07 ======== ======== ===== ======== ======== ===== Common shares issuable upon exercise of stock options using treasury stock method ..... 15,767 15,908 -------- -------- Diluted earnings per common share: Income before dilutive effect of certain trust preferred securities and cumulative effect of a change in accounting principle ....................... $ 93,741 299,927 $0.31 $ 18,127 269,255 $0.07 Dilutive effect of certain trust preferred securities ...... 5,423 32,969 (0.01) -- -- -- -------- -------- ----- -------- -------- ----- Income before cumulative effect of a change in accounting principle ............ 99,164 332,896 0.30 18,127 269,255 0.07 Cumulative effect of a change in accounting principle, net of tax............ 1,036 -- -- -- -- -- -------- -------- ----- -------- -------- ----- Net income ....................... $100,200 332,896 $0.30 $ 18,127 269,255 $0.07 ======== ======== ===== ======== ======== =====
Unexercised employee stock options to purchase 280,849 and 275,380 shares of the Company's common stock during the three months ended March 31, 2001 and 2000, respectively, were not included in the computation of diluted shares outstanding because such inclusion would be anti-dilutive. 10. Subsequent Events California Power Market On April 6, 2001, PG&E filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. As of April 6, 2001, the Company had recorded approximately $270.1 million in accounts receivable with PG&E, plus a $68.7 million note receivable not yet due and payable. The Company is currently selling power to PG&E pursuant to long-term QF contracts, and PG&E is paying on a current basis for these purchases since its bankruptcy filing. The Company has discussed the PG&E situation with its external advisors. Based upon public statements made by PG&E since its bankruptcy filing, and the favorable pricing under Calpine's QF contracts, the Company is confident that PG&E will pay it for all past due power sales. However, the timing of any such payments cannot be predicted. The Company recognizes that uncertainty exists with respect to the outcome of the PG&E bankruptcy, but we have no reasonable basis at this time to estimate any potential loss with respect to these receivables. Therefore, the Company has not provided for a reserve against collection uncertainties for these receivables at this time. However, the Company continues to monitor this situation and will consider any additional facts as they arise. Other Subsequent Events On April 3, 2001, the Company acquired all of the common shares of WRMS Engineering, Inc. ("WRMS"), a San Jose, California-based engineering and architectural firm specializing in critical use facilities for the commercial, industrial and governmental sectors, including hospitals, bio-research facilities, telecommunication and data centers, fossil fuel plants and waste treatment facilities, through a stock-for-stock exchange in which WRMS shareholders received a total of 151,176 shares of Calpine common stock. The aggregate value of the transaction is approximately $7.5 million, excluding the assumed indebtedness of WRMS. On April 11, 2001, the Company acquired the development rights from Enron North America for the 750-megawatt natural gas-fired Pastoria Energy Center planned for Kern County, California. The project was licensed by the California Energy Commission in December 2000. Construction is expected to begin during the summer of 2001 with commercial operation scheduled for the summer of 2003. On April 19, 2001, we announced the purchase of 35 model 7FB and 11 model 7FA gas-fired turbines from GE Power Systems. We will take delivery of 5 turbines in 2002, with the remainder of the contract to be filled by the end of 2005. With this purchase, we have firm orders in place for the delivery of 203 turbines which, when operated in a combined-cycle configuration, will produce approximately 50,000 megawatts of baseload capacity. On April 19, 2001, the Company closed the acquisition of all of the common shares of Encal Energy Ltd., a Calgary, Alberta-based natural gas and petroleum exploration and development company, through a stock-for-stock exchange in which Encal shareholders received, in exchange for each share of Encal common stock, .1493 shares of Calpine common equivalent shares (called "exchangeable shares") of the Company's subsidiary, Calpine Canada Holdings Ltd. A total of 16,603,633 exchangeable shares, valued at $851.2 million, were issued to Encal shareholders in exchange for their Encal common stock. Each exchangeable share is exchangeable for one share of Calpine common stock. The aggregate value of the transaction is approximately U.S. $1.1 billion, including the assumed indebtedness of Encal. The acquisition will be accounted for under the pooling of interests method. With the addition of Encal's assets, which currently produce approximately 230 million cubic feet of gas equivalent ("mmcfe") per day, net of royalties, the Company's net production is expected to increase to 390 mmcfe per day in North America, enough to fuel approximately 2,300 megawatts of its power fleet. For the three months ended March 31, 2001, the pro forma combined results of the merger would have resulted in revenues of approximately $1.4 billion, net income of $119.7 million, basic earning per share of $0.40, and diluted earning per share of $0.36. These results exclude one-time pooling expenses, the majority of which will be reported in the second quarter 2001 results. On April 25, 2001, the Company's wholly-owned financing company, Calpine Canada Energy Finance ULC, completed a public offering of $1.5 billion of 8 1/2% Senior Notes Due 2008 priced at 99.768%. These senior notes are fully and unconditionally guaranteed by the Company. On April 30, 2001, Calpine completed the sale of $1.0 billion of zero coupon convertible debentures due 2021 in a private placement under Rule 144A of the Securities Act of 1933. The securities are convertible into Calpine common shares at a price of $75.35 at the option of the holder at any time. Holders also have the right to require Calpine to repurchase their debentures in 2002, 2004, 2006, 2008, 2011 and 2016 at a specified price in cash or our common stock at the option of Calpine, except on 2016 when the repurchase price must be paid in cash. The debentures are redeemable at the option of Calpine after 2004 at a specified price in cash or our common stock. Proceeds from the offering will be used to refinance certain debt, for working capital and for general corporate purposes. The indenture relating to these securities has not been filed with the Securities and Exchange Commission at the date of this filing. The Company will furnish a copy to the Securities and Exchange Commission upon request. ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations Except for historical financial information contained herein, the matters discussed in this quarterly report may be considered "forward-looking" statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, including statements regarding the intent, belief or current expectations of Calpine Corporation ("the Company") and its management. Prospective investors are cautioned that any such forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties that could materially affect actual results such as, but not limited to, (i) changes in government regulations, including pending changes in California, and anticipated deregulation of the electric energy industry, (ii) commercial operations of new plants that may be delayed or prevented because of various development and construction risks, such as a failure to obtain financing and the necessary permits to operate or the failure of third-party contractors to perform their contractual obligations, (iii) cost estimates are preliminary and actual costs may be higher than estimated, (iv) the assurance that the Company will develop additional plants, (v) a competitor's development of a lower-cost generating gas-fired power plant, (vi) the risks associated with marketing and selling power from power plants in the newly competitive energy market, (vii) the risks associated with marketing and selling combustion turbine parts and components in the competitive combustion turbine parts market, (viii) the risks associated with engineering, designing and manufacturing combustion turbine parts and components, (ix) delivery and performance risks associated with combustion turbine parts and components attributable to production, quality control, suppliers and transportation, (x) the successful exploitation of an oil or gas resource that ultimately depends upon the geology of the resource, the total amount and cost to develop recoverable reserves, and operational factors relating to the extraction of natural gas, and (xi) other risks identified from time to time in our reports and registration statements filed with the SEC, including the risk factors identified in our Annual Report on Form 10-K for the year ended December 31, 2000, which is incorporated by reference in this offering circular. The California energy market remains uncertain. Management is working closely with a number of parties to resolve the current uncertainty. This is an ongoing process and, therefore, the outcome cannot be predicted. It is possile that any such outcome will include changes in government regulations, business and contractual relationships or other factors that could materially affect the Company. For example, although we believe it is in PG&E's best interest to assume its QF contracts with Calpine in bankruptcy, it is possible that PG&E will elect not to do so. Nothwithstanding these uncertainties, we believe that a final resolution of the situation in the California energy market will not have a material adverse impact on the Company. Overview Calpine is engaged in the development, acquisition, ownership, and operation of power generation facilities and the sale of electricity and steam principally in the United States. At May 9, 2001, we had interests in 50 operating power plants representing 6,362 megawatts of net capacity. On January 11, 2001, we jointly announced with Western Hub Properties LLC ("WHP") that WHP's wholly-owned subsidiary, Lodi Gas Storage, LLC, entered into a long-term firm agreement to supply Calpine with storage services at WHP's Lodi Gas Storage facility near Lodi, California. The storage arrangement can provide up to 4 billion cubic feet of working gas inventory and daily deliverability equal to approximately 20 percent of our western region peak day gas requirements in 2002. The Lodi Gas Storage Project, located approximately 50 miles east of San Francisco, began construction in April of 2001 and operation is scheduled to begin in late 2001. On January 17, 2001, our wholly-owned subsidiary, SkyGen Energy LLC ("SkyGen") announced plans to build, own and operate an 850-megawatt natural gas-fired cogeneration facility in Augusta, Georgia. The proposed Augusta Energy Center will be fueled by clean natural gas and will supply energy to DSM Chemicals North America, Inc. for use in its production processes. Construction is expected to begin in the third quarter of 2001. On January 26, 2001, we announced the acquisition of the development rights from Cogentrix, an independent power company based in North Carolina, for the 577- megawatt Washington Parish Energy Center, located near Bogalusa, Louisiana. We are managing construction of the facility, which began in January 2001. On February 12, 2001, we announced that the Florida Public Service Commission approved a joint application filed by Calpine and Seminole Electric Cooperative, Inc., under which we will build a 590-megawatt combined-cycle power generating facility, the Osprey Energy Center, to supply electric power to help meet Seminole's members' power needs. On February 13, 2001, we announced that our wholly-owned subsidiary, SkyGen, entered into an agreement to supply Alliant Energy's Wisconsin Power & Light Co. ("WP&L") 453 megawatts of electric capacity and energy from the proposed 600- megawatt RiverGen Energy Center, which will be located next to WP&L's existing power plant near Beloit, Wisconsin. The power sales agreement is for a term of ten years. Construction of the RiverGen Energy Center is expected to begin during the fourth quarter of 2001, with commercial operation scheduled for late 2003. On February 15, 2001, we completed a public offering of $1.15 billion of our 8 1/2% Senior Notes due 2011. The Senior Notes due 2011 bear interest at 8 1/2% per year, payable semi-annually and mature on February 15, 2011. On March 16, 2001, we announced that our wholly-owned subsidiary, SkyGen, entered into a 10-year agreement to supply Xcel Energy, formerly Public Service Co. of Colorado, with 336 megawatts of peaking capacity. Power will be delivered from the proposed Colorado Energy Center, a $100 million electric generating facility to be located east of Denver in the City of Aurora. Construction of the Colorado Energy Center is expected to begin during the summer of 2002, with commercial operation scheduled for 2003. On March 22, 2001, we announced plans to build, own and operate a 600-megawatt electric generating facility to be located near the town of Hudson in Weld County, Colorado. The proposed Rocky Mountain Energy Center will supply Xcel Energy, formerly Public Service Co. of Colorado, with up to 600 megawatts of electricity for a period of ten years. Construction of the $360 million facility is expected to begin in 2002 with commercial operation scheduled for May 2004. On March 27, 2001, we announced plans to build, own and operate a 1,000-megawatt natural gas-fired power facility in Deer Park, Texas. The proposed Deer Park Energy Center will supply steam to Shell Chemical Company and electric power to the wholesale market. Construction for the Deer Park Energy Center is expected to begin in July 2001, with the first phase of the project operational by January 2003 and the second, larger phase operational by June 2004. Transactions Announced or Consummated Subsequent to March 31, 2001, and Recent Developments On April 3, 2001, we announced that our affiliate, Calpine Power America, L.P., was certified as a Retail Energy Provider in the Electric Reliability Council of Texas ("ERCOT"). This allows us to offer services to a full range of wholesale and retail customers in Texas. Calpine Power America will sell to large industrials, in addition to municipalities, cooperatives, and investor-owned utilities. Additionally, we received an ERCOT certification to be a Qualified Scheduling Entity ("QSE"). As a QSE, Calpine Power Management, L.P. may act on behalf of generators and consumers in the region and would be responsible for scheduling the generation of energy flowing to the electricity grid with the ERCOT Independent System Operator. On April 3, 2001, we acquired all of the common shares of WRMS Engineering, Inc. ("WRMS"), a San Jose, California-based engineering and architectural firm specializing in critical use facilities for the commercial, industrial and governmental sectors, including hospitals, bio-research facilities, telecommunication and data centers, fossil fuel plants and waste treatment facilities, through a stock-for-stock exchange in which WRMS shareholders received a total of 151,176 shares of Calpine common stock. The aggregate value of the transaction is approximately $7.5 million, excluding the assumed indebtedness of WRMS. On April 11, 2001, we acquired the development rights from Enron North America for the 750-megawatt natural gas-fired Pastoria Energy Center planned for Kern County, California. The $500 million project was licensed by the California Energy Commission in December 2000. Construction is expected to begin during the summer of 2001 with commercial operation scheduled for the summer of 2003. On April 17, 2001, we acquired the development rights from Kirkland, Washington-based National Energy Systems Company for the 248-megawatt natural gas-fired Goldendale Energy Center planned for Goldendale, Washington. Energy generated from the Goldendale facility will be sold directly into the Northwest Power Pool. Construction commenced in April 2001, and energy deliveries are scheduled to begin July 1, 2002. On April 19, 2001, we announced the purchase of 35 model 7FB and 11 model 7FA gas-fired turbines from GE Power Systems. We will take delivery of 5 turbines in 2002, with the remainder of the contract to be filled by the end of 2005. With this purchase, we have firm orders in place for the delivery of 203 turbines, which, when operated in a combined-cycle configuration, will produce approximately 50,000 megawatts of baseload capacity. On April 19, 2001, we closed the acquisition of all of the common shares of Encal Energy Ltd., a Calgary, Alberta-based natural gas and petroleum exploration and development company, through a stock-for-stock exchange in which Encal shareholders received, in exchange for each share of Encal common stock, .1493 shares of Calpine common equivalent shares of our subsidiary, Calpine Canada Holdings Ltd. A total of 16,603,633 Calpine common equivalent shares were issued to Encal shareholders in exchange for their Encal common stock. Each Calpine common equivalent share is exchangeable for one share of Calpine common stock. The aggregate value of the transaction is approximately U.S. $1.1 billion, including the assumed indebtedness of Encal. This acquisition will be accounted for under the pooling of interests method. With the addition of Encal's assets, which currently produce approximately 230 million cubic feet of gas equivalent ("mmcfe") per day, net of royalties, our net production is expected to increase to 390 mmcfe per day in North America, enough to fuel approximately 2,300 megawatts of our power fleet. On April 25, 2001, through our wholly-owned financing company, Calpine Canada Energy Finance ULC, we completed a public offering of $1.5 billion of 8 1/2% Senior Notes Due 2008 priced at 99.768%. These senior notes are fully and unconditionally guaranteed by us. On April 30, 2001, we completed the sale of $1.0 billion of zero coupon convertible debentures due 2021 in a private placement under Rule 144A of the Securities Act of 1933. The securities are convertible into Calpine common shares at a price of $75.35 at the option of the holder at any time. Holders have the right to require us to repurchase their debentures in 2002, 2004, 2006, 2008, 2011 and 2016 at a specified price in cash or our common stock at our option, except on 2016 when the repurchase price must be paid in cash. The debentures are redeemable at the option of Calpine after 2004 at a specified price in cash or our common stock. Proceeds from the offering will be used to refinance certain debt, for working capital and for general corporate purposes. The indenture relating to these securities has not been filed with the Securities and Exchange Commission at the date of this filing. We will furnish a copy to the Securities and Exchange Commission upon request. On May 2, 2001, we jointly announced with Kinder Morgan Energy Partners, L.P. plans to develop the Sonoran Pipeline, subject to a successful open season and all other approvals. As proposed, the Sonoran Pipeline will be a 1,160-mile, high-pressure interstate natural gas pipeline from the San Juan Basin in northern New Mexico to markets in California. The interstate pipeline will be evaluated and developed in two phases, which will be subject to the jurisdiction of the Federal Energy Regulatory Commission ("FERC"). The first phase will run from the San Juan Basin to the California border with the second phase extending from the California border to the San Francisco Bay area. The first phase of the pipeline is expected to be completed in the summer of 2003. On May 9, 2001, we announced that our emergency energy proposal to the San Francisco Public Utilies Commission was approved by the San Francisco Board of Supervisors. Under the terms of this contract, we will guarantee to provide San Francisco with 50 megawatts of electricity 24 hours-a-day for the next five years starting July 1, 2001. Recent Developments in the California Power Market. The deregulation of the California power market has produced significant unanticipated results in the past year. The deregulation froze the rates that utilities can charge their retail and business customers in California and prohibited the utilities from buying power on a forward basis, while wholesale power prices were not subjected to limits. In the past year, a series of factors have reduced the supply of power to California, which has resulted in wholesale power prices that have been significantly higher than historical levels. Several factors contributed to this increase. These included: - significantly increased volatility in prices and supplies of natural gas; - an unusually dry fall and winter in the Pacific Northwest, which reduced the amount of available hydroelectric power from that region (typically, California imports a portion of its power from this source); - the large number of power generating facilities in California nearing the end of their useful lives, resulting in increased downtime (either for repairs or because they have exhausted their air pollution credits and replacement credits have become too costly to acquire on the secondary market); and - continued obstacles to new power plant construction in California, which deprived the market of new power sources that could have, in part, ameliorated the adverse effects of the foregoing factors. As a result of this situation, two major California utilities that are subject to the retail rate freeze, including Pacific Gas & Electric Company ("PG&E"), have faced wholesale prices that far exceed the retail prices they are permitted to charge. This has led to significant under-recovery of costs by these utilities. As a consequence, these utilities have defaulted under a variety of contractual obligations, including payment obligations to power generators. PG&E has defaulted on payment obligations to us under our long-term qualifying facility ("QF") contracts, which are subject to federal regulation under the Public Utility Regulatory Policies Act of 1978, as amended ("PURPA"). On April 6, 2001, PG&E filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. As of April 6, 2001, we had recorded approximately $270 million in accounts receivable with PG&E, plus a $68.7 million note receivable not yet due and payable. We are currently selling power to PG&E pursuant to long-term QF contracts, and PG&E is paying on a current basis for these purchases since its bankruptcy filing. We have discussed the PG&E situation with our external advisors. Based upon public statements made by PG&E since its bankruptcy filing, and the favorable pricing under our QF contracts, we are confident that PG&E will pay us for all past due power sales. However, the timing of any such payments cannot be predicted. We recognize that uncertainty exists with respect to the outcome of the PG&E bankruptcy, but we have no reasonable basis at this time to estimate any potential loss with respect to these receivables. Therefore, we have not provided for a reserve against collection uncertainties for these receivables at this time. However, we continue to monitor this situation and will consider any additional facts as they arise. The QF contracts are in place at eleven of our facilities and represent nearly 600 megawatts of electricity for Northern California customers. The QF contracts provide that the California Public Utilities Commission ("CPUC") has the authority to determine the appropriate utility "avoided cost" to be used to set energy payments for certain QF contracts, including those for all of our QF plants in California which sell power to PG&E. Section 390 of the California Public Utility Code provided QFs the option to elect to receive energy payments based on the California Power Exchange ("PX") market clearing price. In mid-2000, our QF facilities elected this option and were paid based upon the PX zonal day ahead clearing price ("PX Price") from summer 2000 until January 19, 2001, when the PX ceased operating a day ahead market. Since that time, the CPUC has ordered that the price to be paid for energy deliveries by QFs electing the PX Price shall be based on a natural gas cost-based "transition formula." The CPUC has conducted proceedings to determine whether the PX Price was the appropriate price for the energy component upon which to base payments to QFs which had elected the PX based pricing option. It is possible that the CPUC could order a payment adjustment based on a different energy price determination. We believe that the PX Price was the appropriate price for energy payments but there can be no assurance that this will be the outcome of the CPUC proceedings. California has adopted legislation permitting it to issue long-term revenue bonds to provide funding for wholesale purchases of power. The bonds will be repaid with the proceeds of payments by retail customers over time. The California Department of Water Resources ("DWR") sought bids for long-term power supply contracts. We successfully bid in that auction, and recently announced, as indicated below, that we have signed three long-term power supply contracts with DWR. On February 7, 2001, we announced the signing of a 10-year, $4.6 billion fixed-price contract with DWR to provide electricity to the State of California. We committed to sell up to 1,000 megawatts of electricity, with initial deliveries of 200 megawatts starting October 1, 2001, and increasing to 1,000 megawatts by January 1, 2004. This contract will continue through 2011. The electricity will be sold directly to DWR on a 24-hour, 7-day-a-week basis. This contract is contingent upon the Company's satisfaction, in its sole discretion, that adequate provisions have been made by DWR to assure the Company of full payment under the terms of the contract (including, but not limited to, the terms and conditions of any bonds issued by DWR to provide funds for payment of its obligations under the contract). On February 28, 2001, we announced the signing of two long-term power sales contracts with DWR. Under the terms of the first contract, a $5.2 billion, 10-year, fixed-price contract, we committed to sell up to 1,000 megawatts of generation. Initial deliveries are scheduled to begin July 1, 2001 with 200 megawatts and increase to 1,000 megawatts by as early as July 2002. Under the terms of the second contract, a 20-year contract totaling up to $3.1 billion, we will supply DWR with up to 495 megawatts of peaking generation, beginning with 90 megawatts as early as August 2001, and increasing up to 495 megawatts as early as August 2002. This contract is contingent upon the Company's satisfaction, in its sole discretion, that adequate provisions have been made by DWR to assure the Company of full payment under the terms of the contract (including, but not limited to, the terms and conditions of any bonds issued by DWR to provide funds for payment of its obligations under the contract). On March 13, 2001, we announced the signing of a two-month deal to provide 555 megawatts of electricity to DWR from our new South Point Energy Center during plant testing, effective immediately through May 15, 2001. FERC Investigation into California Wholesale Markets. Beginning in May 2000, wholesale energy prices in the California markets increased to levels well above 1999 levels. In response, on June 28, 2000, the Independent System Operator ("ISO") Board of Governors reduced the price cap applicable to the ISO's wholesale energy and ancillary services markets from $750/MWh to $500/MWh. The ISO subsequently reduced the price cap to $250/MWh on August 1, 2000. During this period, however, the PX maintained a separate price cap set at a much higher level applicable to the "day-ahead" and "day-of" markets administered by the PX. On August 23, 2000, the FERC denied a complaint filed August 2, 2000 by San Diego Gas & Electric Company ("SDG&E") that sought to extend the ISO's $250 price cap to all California energy and ancillary service markets, not just the markets administered by the ISO. However, in its order denying the relief sought by SDG&E, the FERC instructed its staff to initiate an investigation of the California power markets and to report its findings to the FERC and held further hearing procedures in abeyance pending the outcome of this investigation. On November 1, 2000, the FERC released a Staff Report detailing the results of the Staff investigation, together with an "Order Proposing Remedies for California Wholesale Markets" ("November 1 Order"). In the November 1 Order, the FERC found that the California power market structure and market rules were seriously flawed and that these flaws, together with short supply relative to demand, resulted in unusually high energy prices. The November 1 Order proposed specific remedies to the identified market flaws, including: (a) imposition of a so-called "soft" price cap at $150/MWh to be applied to both the PX and ISO markets, which would allow bids above $150/MWh to be accepted, but will subject such bids to certain reporting obligations requiring sellers to provide cost data and/or identify applicable opportunity costs and specifying that such bids may not set the overall market clearing price, (b) elimination of the requirement that the California utilities sell into and buy from the PX, (c) establishment of independent non-stakeholder governing boards for the ISO and the PX, and (d) establishment of penalty charges for scheduling deviations outside of a prescribed range. In the November 1 Order the FERC established October 2, 2000, the date 60 days after the filing of the SDG&E complaint, as the "refund effective date." Under the November 1 Order, rates charged for service after that date through December 31, 2002 will remain subject to refund if determined by the FERC not to be just and reasonable. While the FERC concluded that the Federal Power Act and prior court decisions interpreting that act strongly suggested that refunds would not be permissible for charges in the period prior to October 2, 2000, it noted that it was willing to explore proposals for equitable relief with respect to charges made in that period. All of our receivables from PG&E relate to energy generated by QF facilities. Under FERC regulations, QF contracts are exempt from regulation under the Federal Power Act, which is the legislation that provides the authority for the FERC to compel refunds or frame other equitable relief with respect to the California wholesale markets. See "Government Regulation -- Federal Energy Regulation -- Federal Power Act Regulation" set forth in our Annual Report on Form 10-K for the year ended December 31, 2000. Therefore, we believe that any refund or other equitable remedy that the FERC may impose with respect to the California wholesale markets will not affect our ability to pursue payment by PG&E of all past due amounts as described above. On December 15, 2000, the FERC issued a subsequent order that affirmed in large measure the November 1 Order (the "December 15 Order"). Various parties have filed requests for administrative rehearing and for judicial review of aspects of the FERC's December 15 Order. The outcome of these proceedings, and the extent to which the FERC or a reviewing court may revise aspects of the December 15 Order or the extent to which these proceedings may result in a refund of or reduction in the amounts charged by our subsidiaries for power sold in the ISO and PX markets, cannot be determined at this time. In its Decision 01-03-067 mailed on March 28, 2001 (the "March Decision"), the CPUC changed the formulation of the short run avoided cost ("SRAC") calculation. The March Decision is subject to pending challenges filed at the CPUC and the Federal Energy Regulatory Commission. If the March Decision withstands these challenges, this change in the SRAC formula will reduce the energy payments to us under our QF contracts. It is difficult at this time to predict the magnitude of any such reduction given the recent date of the March Decision and its uncertain status due to the challenges noted above. However, we believe that it is unlikely that the March Decision could have a material adverse impact on our results of operations or financial condition. Selected Operating Information Set forth below is certain selected operating information for our power plants and steam fields, for which results are consolidated in our statements of operations. Results vary for the three months ended March 31, 2001, as compared to the same period in 2000, primarily due to the consolidation of acquisitions, favorable energy pricing, and increased production. Electricity revenue is composed of fixed capacity payments, which are not related to production, and variable energy payments, which are related to production. Capacity revenues include, besides traditional capacity payments, other revenues such as reliability must run and ancillary service revenues. The information set forth under thermal and other revenue consists of host thermal sales and other revenue.
Three Months Ended March 31, ----------------------------- 2001 2000 ---------- ---------- (in thousands, except production and pricing data) (unaudited) Electricity and steam revenue: Energy ............................. $ 454,851 $ 124,483 Capacity ........................... $ 98,258 $ 55,483 Thermal and other .................. $ 42,050 $ 13,958 Megawatt hours produced ................... 7,239,199 4,381,189 Average energy price per megawatt hour..... $ 62.83 $ 28.41
Megawatt hours produced at the power plants increased 65% for the three months ended March 31, 2001 as compared with the same period in 2000, primarily due to 1,848,658 megawatt hours of production generated by power plants that were either acquired or commenced commercial operation subsequent to March 31, 2000, 648,666 megawatt hours of production as a result of the expansion of the Pasadena facility completed during July 2000, and 360,686 megawatt hours of production due to higher operation at certain of the Company's other facilities. Results of Operations Three Months Ended March 31, 2001 Compared to Three Months Ended March 31, 2000 Revenue -- Total revenue increased 422% to $1,229.8 million for the three months ended March 31, 2001 compared to $235.4 million for the same period in 2000. Electric generation and marketing revenue increased 410% to $1,050.1 million in 2001 compared to $206.1 million in 2000. Approximately $401.2 million of the $844.0 million variance was due to electricity and steam sales, which increased due to our growing portfolio and favorable energy pricing. Our revenues for the period ended March 31, 2001 include the consolidated results of eleven additional facilities that we acquired or completed construction on subsequent to March 31, 2000. Our power marketing activities contributed an additional $441.5 million during the three months ended March 31, 2001. This is due to the marketing of power generated by us in 2001 in addition to increased price hedging activity to protect against market volatility. Oil and gas production and marketing revenue increased to $176.0 million in 2001 compared to $17.2 million in 2000. The majority of the increase is due to marketing activities relating to purchased gas sold to third parties in hedging, balancing and related transactions. Additionally, approximately $38.2 million of the variance relates to increased commodity prices and sales to third parties from production of reserves acquired in Canada and in the United States. Income from unconsolidated investments in power projects decreased 94% to $0.6 million in 2001 compared to $9.8 million during 2000. The variance is primarily due to the contractual reduction in distributions from the Sumas Power Plant. Other revenue increased 38% to $3.3 million in 2001 compared to $2.4 million in 2000. This increase is due primarily to $1.6 million recognized in 2001 from our custom turbine parts manufacturing subsidiary, Power Systems Mfg., LLC, and is partially offset by a decrease in interest income on loans to power projects. Cost of revenue -- Cost of revenue increased 479% to $1,023.9 million in 2001 compared to $176.7 million in 2000. Approximately $445.0 million of the $847.2 million increase relates to the cost of power purchased by our energy services organization. Similarly, oil and gas production and marketing expense grew by $110.9 million, largely due to $118.6 million of expense for the cost of gas purchased by the energy services organization, compared to $7.7 million in the first quarter of 2000. Fuel expenses increased 249%, from $73.7 million in 2000 to $257.0 million in 2001, due to a 65% increase in megawatt hours generated and a significant increase in fuel price. Depreciation expenses increased by 90%, from $27.8 million in the first quarter of 2000 to $52.9 million in the first quarter of 2001, due to eleven additional power facilities in operation at March 31, 2001 as compared to the same period in 2000, and due to $14.0 million in higher depreciation and depletion in our oil and gas operating subsidiaries. Operating lease expenses increased by $17.6 million due to leases entered into or acquired in connection with our Pasadena, Tiverton, Rumford, and KIAC facilities subsequent to March 31, 2000. General and administrative expenses -- General and administrative expenses increased 280% to $32.7 million for the three months ended March 31, 2001 as compared to $8.6 million for the same period in 2000. The increases were attributable to continued growth in personnel and associated overhead costs necessary to support the overall growth in our operations and due to recent acquisitions, including power facilities and natural gas operations. Interest expense -- Interest expense decreased 12% to $15.7 million for the three months ended March 31, 2001, from $17.9 million for the same period in 2000. The decrease was primarily due to the capitalization of $69.3 million of interest on general corporate funds invested in construction projects for the three months ended March 31, 2001, as compared to $22.7 million capitalized on general corporate funds for the same period in 2000. The increase in the amount of interest capitalized reflects the significant increase in our power plant construction program. Distributions on trust preferred securities -- Distributions on trust preferred securities increased 117% to $15.2 million for the first three months in 2001 compared to $7.0 million for the corresponding months in 2000. The increase is attributable to the issuance of additional trust preferred securities in August 2000, as well as a full quarter of distributions on the January 2000 offering and the subsequent exercise of the purchasers' option. Interest income -- Interest income increased 155% to $19.4 million for the three months ended March 31, 2001 compared to $7.6 million for the same period in 2000. This increase is due primarily to the significantly higher cash balances that we have maintained. Other income -- Other income increased to $10.8 million in 2001 from $0.8 million in 2000 primarily due to a gain on the sale of our interests in the Elwood development project and the Bayonne facility. Provision for income taxes -- The effective income tax rate was approximately 40.2% and 39.2% for the three months ended March 31, 2001 and 2000, respectively. The increase in the rate is primarily due to our expansion into Canadian natural gas production markets subsequent to March 31, 2000. Cumulative effect of a change in accounting principle -- The $1.0 million of additional income, net of tax, is due to the adoption of Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities," amended by SFAS No. 137 and SFAS No. 138 ("SFAS 133") and represents a mark-to-market value of certain capacity sales contracts as of January 1, 2001. Liquidity and Capital Resources To date, we have obtained cash from our operations, borrowings under our credit facilities and other working capital lines, sale of debt, equity, and trust preferred securities, and proceeds from non-recourse project financing. We utilized this cash to fund our operations, service debt obligations, fund acquisitions, develop and construct power generation facilities, finance capital expenditures and meet our other cash and liquidity needs. For the three months ended March 31, 2001 our cash used in operating activities was $90.0 million primarily due to a decrease in accounts payable and accrued expenses, implementation of SFAS 133 and the aging of our California receivables. Outlook Our strategy is to continue our rapid growth by capitalizing on the significant opportunities in the power industry, primarily through our active development and acquisition programs. In pursuing our proven growth strategy, we utilize our extensive management and technical expertise to implement a fully integrated approach to the acquisition, development and operation of power generation facilities. This approach uses our expertise in design, engineering, procurement, finance, construction management, fuel and resource acquisition, operations and power marketing, which we believe provides us with a competitive advantage. The key elements of our strategy are as follows: - Development of new and expansion of existing power plants. We are actively pursuing the development of new and expansion of both baseload and peaking capacity at our existing highly efficient, low-cost, gas-fired power plants that replace old and inefficient generating facilities and meet the demand for new generation. Our strategy is to develop power plants in strategic geographic locations that enable us to leverage existing power generation assets and operate the power plants as integrated electric generation systems. This allows us to achieve significant operating synergies and efficiencies in fuel procurement, power marketing and operation and maintenance. At May 9, 2001, we had twenty-seven projects under construction, representing an additional 14,841 megawatts of net capacity. Included in these twenty-seven projects is an expansion of our Broad River Energy Center, which represents 360 megawatts. We have also announced plans to develop thirty additional power generation projects, representing a net capacity of 16,835 megawatts. Included in these thirty development projects are seven expansion projects representing 917 megawatts: Pine Bluff Energy Center, DePere Energy Center, Auburndale and the California Peakers (which encompass expansions of the Gilroy Power Plant, the Watsonville Power Plant, the Greenleaf 2 Power Plant and the King City Power Plant.) - Acquisition of power plants. Our strategy is to acquire power generating facilities that meet our stringent acquisition criteria and provide significant potential for revenue, cash flow and earnings growth, and that provide the opportunity to enhance the operating efficiencies of the plants. We have significantly expanded and diversified our project portfolio through numerous acquisitions of power generation facilities. - Enhance the performance and efficiency of existing power projects. We continually seek to maximize the power generation potential of our operating assets and minimize our operation and maintenance expenses and fuel costs. This will become even more significant as our portfolio of power generation facilities expands to 76 power plants with a net capacity of 21,203 megawatts, after completion of our projects currently under construction. We focus on operating our plants as an integrated system of power generation, which enables us to minimize costs and maximize operating efficiencies. We believe that achieving and maintaining a low cost of production will be increasingly important to compete effectively in the power generation industry. Risk Factors As a result of the California Power Market situation, as described in the Recent Developments section, two major California utilities that are subject to the retail rate freeze, including PG&E, have faced wholesale prices that far exceed the retail prices they are permitted to charge. This has led to significant under-recovery of costs by these utilities. As a consequence, these utilities have defaulted under a variety of contractual obligations, including payment obligations to power generators. PG&E has defaulted on payment obligations to us under our long-term QF contracts, which are subject to federal regulation under PURPA. On April 6, 2001, PG&E filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. As of April 6, 2001, we had recorded approximately $270.1 million in accounts receivable with PG&E, plus a $68.7 million note receivable not yet due and payable. We are currently selling power to PG&E pursuant to long-term QF contracts, and PG&E is paying on a current basis for these purchases since its bankruptcy filing. We have discussed the PG&E situation with our external advisors. Based upon public statements made by PG&E since its bankruptcy filing, and the favorable pricing under our QF contracts, we are confident that PG&E will pay us for all past due power sales. However, the timing of any such payments cannot be predicted. Although we believe there are compelling economic reasons for PG&E to assume our QF contracts, there is no assurance that it will do so. Failure of PG&E to assume these contracts would enable Calpine to sell in the open market at prices currently well in excess of the QF contract rates. We recognize that uncertainty exists with respect to the outcome of the PG&E bankruptcy, but we have no reasonable basis at this time to estimate any potential loss with respect to these receivables. Therefore, we have not provided for a reserve against collection uncertainties for these receivables at this time. However, we continue to monitor this situation and will continue to consider any additional facts as they arise. Financial Market Risks From time to time, we use interest rate swap agreements to mitigate our exposure to interest rate fluctuations. We do not use derivative financial instruments for speculative or trading purposes. The following table summarizes the fair market value of our existing interest rate swap agreements as of March 31, 2001 (dollars in thousands):
Notional Weighted Principal Average Fair Maturity Date Amount Interest Rate Market Value ------------- -------- ------------- ------------ 2001 .............. $ 67,281 7.4% $ (484) 2007 .............. 38,150 8.0 (4,428) 2007 .............. 38,150 8.0 (4,411) 2007 .............. 29,757 7.9 (3,901) 2007 .............. 29,757 7.9 (3,885) 2009 .............. 15,000 6.9 (929) 2011 .............. 57,050 6.9 (3,749) 2012 .............. 120,771 6.5 (6,548) 2014 .............. 72,334 6.7 (4,306) 2015 .............. 22,500 7.0 (1,997) 2017 .............. 49,771 5.9 (206) 2018 .............. 17,500 7.0 (1,724) -------- --- -------- Total ..... $558,021 7.0% $(36,568) ======== === ========
Short-term investments. As of March 31, 2001, we had short-term investments of $492.9 million. These short-term investments consist of highly liquid investments with maturities less than three months. We have the ability to hold these investments to maturity, and as a result, we would not expect the value of these investments to be affected to any significant degree by the effect of a sudden change in market interest rates. Energy price fluctuations. We enter into derivative commodity instruments to reduce our exposure to the impact of price fluctuations, primarily electricity and natural gas prices. All transactions are subject to our risk management policy which prohibits positions that exceed production capacity and fuel requirements. Derivative commodity instruments are accounted for under the requirements of SFAS 133. The fair value of outstanding derivative commodity instruments and the change in fair value that would be expected from a ten percent adverse price change are shown in the table below (in thousands):
Change in Fair Value From 10% Adverse Fair Value Price Change ---------- -------------- At March 31, 2001 Crude oil ....................... $ -- $ -- Refined products ................ -- -- Electricity ..................... (159,597) (84,806) Natural gas ..................... 118,685 (253,303) --------- --------- Total ................... $ (40,912) $(338,109) ========= =========
Derivative commodity instruments included in the table are those included in Note 2 to the Consolidated Condensed Condensed Financial Statements. The fair value of derivative commodity instruments included in the table is estimated based on present value adjusted quoted market prices of comparable contracts. During the three months ended March 31, 2001, significant electricity price volatility occurred in the western United States. The fair value of derivative commodity instruments includes the effect of increased power prices versus our forward sales commitments. Derivative commodity instruments offset physical positions exposed to the cash market. None of the offsetting physical positions are included in the above table. Price changes were calculated by assuming an across-the-board ten percent adverse price change regardless of term or historical relationship between the contract price of an instrument and the underlying commodity price. In the event of an actual ten percent change in prompt month prices, the fair value of Calpine's derivative portfolio would typically change less than that shown in the table due to lower volatility in out-month prices. ITEM 3. Quantitative and Qualitative Disclosures About Market Risk See "Financial Market Risks" in ITEM 2. PART II. OTHER INFORMATION ITEM 6. Exhibits and Reports on Form 8-K (a) Exhibits The following exhibits are filed herewith unless otherwise indicated: Exhibit Number Description ------- ----------- 2.1 Combination Agreement, dated as of February 7, 2001, by and between Calpine Corporation and Encal Energy Ltd. *2.2 Amending Agreement to the Combination Agreement, dated as of March 16, 2001, between Calpine Corporation and Encal Energy Ltd. (a) 2.3 Form of Plan of Arrangement Under Section 186 of the Business Corporations Act (Alberta) (included as Exhibit A to Exhibit 2.1) Involving and Affecting Encal Energy Ltd. and the Holders of its Common Shares and Options *3.1 Amended and Restated Certificate of Incorporation of Calpine Corporation (b) *3.2 Certificate of Correction of Calpine Corporation(b) *3.3 Certificate of Designation of Series A Participating Preferred Stock of Calpine Corporation (b) *3.4 Amended Certificate of Designation of Series A Participating Preferred Stock of Calpine Corporation (b) 3.5 Certificate of Designation of Special Voting Preferred Stock of Calpine Corporation *3.5 Amended and Restated By-laws of Calpine Corporation (c) 4.1 Form of Exchangeable Share Provisions and Other Provisions to Be Included in the Articles of Calpine Canada Holdings Ltd. (included as Exhibit B to Exhibit 2.1) 4.2 Form of Support Agreement between Calpine Corporation and Calpine Canada Holdings Ltd. (included as Exhibit C to Exhibit 2.1) *4.3 Indenture dated as of August 10, 2000, between Calpine Corporation and Wilmington Trust Company, as Trustee (d) *4.4 First Supplemental Indenture dated as of September 28, 2000, between Calpine Corporation and Wilmington Trust Company, as Trustee (e) *4.5 Indenture dated as of April 25, 2001, between Calpine Canada Energy Finance ULC and Wilmington Trust Company, as Trustee (f) *4.6 Guarantee Agreement dated as of April 25, 2001, by Calpine Corporation as guarantor of debt securities of Calpine Canada Energy Finance ULC (f) 9.1 Form of Voting and Exchange Trust Agreement between Calpine Corporation, Calpine Canada Holdings Ltd. and CIBC Mellon Trust Company, as Trustee (included as Exhibit D to Exhibit 2.1) 10.1 Amended and Restated Credit Agreement, dated as of February 15, 2001, among Calpine Construction Finance Company, L.P., The Bank of Nova Scotia, as Administrative Agent, and the Banks party thereto (g) ---------- * Incorporated by reference. (a) Incorporated by reference to Calpine Corporation's Registration Statement on Form S-3/A (File No. 333-56712). (b) Incorporated by reference to Calpine Corporation's Annual Report on Form 10-K for the year ended December 31, 2000, filed with the SEC on March 15, 2001. (c) Incorporated by reference to Calpine Corporation's Annual Report on Form 10-K dated December 31, 1999 and filed on February 29, 2000 (File No. 001-12079). (d) Incorporated by reference to Calpine Corporation's Registration Statement on Form S-3/A (File No. 333-72583). (e) Incorporated by reference to Calpine Corporation's Annual Report on Form 10-K dated December 31, 2000 and filed on March 15, 2001 (File No. 001-12079). (f) Incorporated by reference to Calpine Corporation's Registration Statement on Form S-3/A (File No. 333-57338). (g) Approximately 24 pages of this exhibit have been omitted pursuant to a request for confidential treatment. The omitted language has been filed separately with the Securities and Exchange Commission. (b) Reports on Form 8-K The registrant filed the following reports on Form 8-K during the quarter ended March 31, 2001:
Date of Report Date Filed Item Reported ---------------- ---------------- ------------- February 8, 2001 February 9, 2001 5, 7
Signatures Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. CALPINE CORPORATION By: /s/ Ann B. Curtis Date: May 15, 2001 --------------------------- Ann B. Curtis Executive Vice President (Chief Financial Officer) By: /s/ Charles B. Clark, Jr. Date: May 15, 2001 --------------------------- Charles B. Clark, Jr. Vice President and Corporate Controller (Chief Accounting Officer)