10-Q 1 q12002.txt 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, 2002 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: 373,911,684 shares of Common Stock, par value $.001 per share, outstanding on May 13, 2002 In the Company's 2001 Report on Form 10-K the Company disclosed that it dismissed Arthur Andersen LLP effective March 29, 2002, as its independent public accountants and appointed Deloitte and Touche LLP as its new independent public accountants. Pursuant to Temporary Note 2T to Article 3 of Regulation S-X, this Report on Form 10-Q is being filed prior to the completion of the review by Deloitte and Touche LLP that would otherwise be required by Statement on Auditing Standards No. 71, "Interim Financial Information." CALPINE CORPORATION AND SUBSIDIARIES Report on Form 10-Q For the Quarter Ended March 31, 2002
INDEX PAGE NO. PART I - FINANCIAL INFORMATION Item 1. Financial Statements. Consolidated Condensed Balance Sheets March 31, 2002 and December 31, 2001.................. 1 Consolidated Condensed Statements of Operations For the Three Months Ended March 31, 2002 and 2001.................................................................................... 3 Consolidated Condensed Statements of Cash Flows For the Three Months Ended March 31, 2002 and 2001.................................................................................... 5 Notes to Consolidated Condensed Financial Statements March 31, 2002......................... 6 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations....... 22 Item 3. Quantitative and Qualitative Disclosures About Market Risk.................................. 38 PART II - OTHER INFORMATION Item 1. Legal Proceedings........................................................................... 38 Item 2. Changes in Securities and Use of Proceeds................................................... 39 Item 6. Exhibits and Reports on Form 8-K............................................................ 40 Signatures................................................................................................................ 42
PART I - FINANCIAL INFORMATION In the Company's 2001 Report on Form 10-K the Company disclosed that it dismissed Arthur Andersen LLP effective March 29, 2002, as its independent public accountants and appointed Deloitte and Touche LLP as its new independent public accountants. Pursuant to Temporary Note 2T to Article 3 of Regulation S-X, this Report on Form 10-Q is being filed prior to the completion of the review by Deloitte and Touche LLP that would otherwise be required by Statement on Auditing Standards No. 71, "Interim Financial Information." Item 1. Financial Statements. CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED BALANCE SHEETS March 31, 2002 and December 31, 2001 (in thousands, except share and per share amounts)
MARCH 31, DECEMBER 31, 2002 2001 ------------ ------------ ASSETS (unaudited) Current assets: Cash and cash equivalents ................................................... $ 410,772 $ 1,525,417 Accounts receivable, net..................................................... 817,936 966,080 Margin deposits and other prepaid expense ................................... 304,564 480,656 Inventories ................................................................. 90,627 78,862 Current derivative assets ................................................... 549,155 763,162 Other current assets ........................................................ 133,056 193,525 ------------ ------------ Total current assets ..................................................... 2,306,110 4,007,702 ------------ ------------ Restricted cash ................................................................ 91,070 95,833 Notes receivable, net of current portion ....................................... 160,359 158,124 Project development costs ...................................................... 185,412 179,783 Investments in power projects .................................................. 380,558 378,614 Deferred financing costs ....................................................... 223,893 210,811 Property, plant and equipment, net ............................................. 16,211,489 15,200,498 Goodwill and other intangible assets, net ...................................... 221,786 228,673 Long-term derivative assets .................................................... 554,354 564,952 Other assets ................................................................... 308,504 304,562 ------------ ------------ Total assets ............................................................. $ 20,643,535 $ 21,329,552 ============ ============ LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable ............................................................ $ 1,260,579 $ 1,283,843 Accrued payroll and related expense ......................................... 49,876 57,285 Accrued interest payable .................................................... 194,538 160,115 Notes payable and borrowings under lines of credit, current portion ......... 14,336 23,238 Capital lease obligation, current portion ................................... 2,279 2,206 Zero-Coupon Convertible Debentures Due 2021 ................................. 685,500 878,000 Current derivative liabilities .............................................. 450,865 625,339 Other current liabilities ................................................... 231,036 198,812 ------------ ------------ Total current liabilities ................................................ 2,889,009 3,228,838 ------------ ------------ Notes payable and borrowings under lines of credit, net of current portion ..... 10,000 74,750 Capital lease obligation, net of current portion ............................... 206,697 207,219 Construction/project financing ................................................. 3,424,097 3,393,410 Convertible Senior Notes Due 2006 .............................................. 1,200,000 1,100,000 Senior notes ................................................................... 7,039,516 7,049,038 Deferred income taxes, net ..................................................... 915,092 964,346 Deferred lease incentive ....................................................... 56,360 57,236 Deferred revenue ............................................................... 186,725 154,381 Long-term derivative liabilities ............................................... 497,916 822,848 Other liabilities .............................................................. 97,658 96,504 ------------ ------------ Total liabilities ........................................................ 16,523,070 17,148,570 ------------ ------------ -1- Company-obligated mandatorily redeemable convertible preferred securities of subsidiary trusts ........................................................ 1,123,275 1,123,024 Minority interests ............................................................. 39,319 47,389 ------------ ------------ Stockholders' equity: Preferred stock, $.001 par value per share; authorized 10,000,000 shares; issued and outstanding one share in 2002 and 2001 ................ -- -- Common stock, $.001 par value per share; authorized 1,000,000,000 shares in 2002 and 2001; issued and outstanding 307,604,929 shares in 2002 and 307,058,751 shares in 2001 ............................ 308 307 Additional paid-in capital .................................................. 2,043,816 2,040,836 Retained earnings ........................................................... 1,121,733 1,196,000 Accumulated other comprehensive loss ........................................ (207,986) (226,574) ------------ ------------ Total stockholders' equity ............................................... 2,957,871 3,010,569 ------------ ------------ Total liabilities and stockholders' equity ............................... $ 20,643,535 $ 21,329,552 ============ ============ The accompanying notes are an integral part of these consolidated condensed financial statements.
-2- CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS For the Three Months Ended March 31, 2002 and 2001 (in thousands, except per share amounts) (unaudited)
THREE MONTHS ENDED MARCH 31, --------------------------------- 2002 2001 ------------ ------------ Revenue: Electric generation and marketing revenue Electricity and steam revenue.............................................. $ 620,179 $ 595,159 Sales of purchased power................................................... 908,301 453,602 Electric power derivative mark-to-market gain.............................. 4,166 1,306 ------------ ------------ Total electric generation and marketing revenue............................... 1,532,646 1,050,067 Oil and gas production and marketing revenue Oil and gas sales.......................................................... 67,488 156,687 Sales of purchased gas..................................................... 132,158 129,172 ------------ ------------ Total oil and gas production and marketing revenue............................ 199,646 285,859 Income from unconsolidated investments in power projects...................... 1,444 563 Other revenue................................................................. 4,611 3,262 ------------ ------------ Total revenue............................................................ 1,738,347 1,339,751 ------------ ------------ Cost of revenue: Electric generation and marketing expense Plant operating expense.................................................... 115,157 84,460 Royalty expense............................................................ 4,155 11,009 Purchased power expense.................................................... 815,005 456,266 ------------ ------------ Total electric generation and marketing expense............................... 934,317 551,735 Oil and gas production and marketing expense Oil and gas production expense............................................. 26,940 34,283 Purchased gas expense...................................................... 123,694 118,628 ------------ ------------ Total oil and gas production and marketing expense............................ 150,634 152,911 Fuel expense Cost of oil and natural gas burned by power plants......................... 326,443 264,563 Natural gas derivative mark-to-market loss (gain).......................... 6,392 (7,549) ------------ ------------ Total fuel expense............................................................ 332,835 257,014 Depreciation, depletion and amortization expense.............................. 103,873 72,013 Operating lease expense....................................................... 36,134 28,011 Other expense................................................................. 2,590 2,499 ------------ ------------ Total cost of revenue.................................................... 1,560,383 1,064,183 ------------ ------------ Gross profit.................................................................. 177,964 275,568 Project development expense..................................................... 11,338 15,839 Equipment cancellation cost..................................................... 168,471 -- General and administrative expense.............................................. 60,261 36,085 Merger expense.................................................................. -- 6,021 ------------ ------------ Income (loss) from operations................................................. (62,106) 217,623 Interest expense................................................................ 61,311 19,925 Distributions on trust preferred securities..................................... 15,386 15,175 Interest income................................................................. (12,176) (19,358) Other income, net............................................................... (9,093) (5,727) ------------ ------------ Income (loss) before provision (benefit) for income taxes..................... (117,534) 207,608 Provision (benefit) for income taxes............................................ (41,137) 88,981 ------------ ------------ Income (loss) before extraordinary gain and cumulative effect of a change in accounting principle.......................................... (76,397) 118,627 Extraordinary gain, net of tax provision of $1,362 and $-- ..................... 2,130 -- Cumulative effect of a change in accounting principle, net of tax provision of $-- and $669.......................................... -- 1,036 ------------ ------------ Net income (loss)............................................................. $ (74,267) $ 119,663 ============ ============ Basic earnings (loss) per common share: Weighted average shares of common stock outstanding........................... 307,332 300,554 Income (loss) before extraordinary gain and cumulative effect of a change in accounting principle............................................ $ (0.25) $ 0.39 Extraordinary gain............................................................ $ 0.01 $ -- Cumulative effect of a change in accounting principle......................... $ -- $ 0.01 ------------ ------------ Net income (loss)............................................................. $ (0.24) $ 0.40 ============ ============ -3- Diluted earnings (loss) per common share: Weighted average shares of common stock outstanding before dilutive effect of certain convertible securities............................ 307,332 316,832 Income (loss) before dilutive effect of certain convertible securities, extraordinary gain and cumulative effect of a change in accounting principle............................................... $ (0.25) $ 0.37 Dilutive effect of certain convertible securities (1)......................... $ -- $ (0.02) ------------ ------------ Income (loss) before extraordinary gain and cumulative effect of a change in accounting principle.......................................... $ (0.25) $ 0.35 Extraordinary gain............................................................ $ 0.01 $ -- Cumulative effect of a change in accounting principle......................... $ -- $ 0.01 ------------ ------------ Net income (loss)............................................................. $ (0.24) $ 0.36 ============ ============
__________ (1) Includes the effect of the assumed conversion of certain convertible securities in 2001. No convertible securities were included in the 2002 amounts as the securities were antidilutive. For the three months ended March 31, 2001, the assumed conversion calculation added 44,882 shares of common stock and $9,355 to the net income results. The accompanying notes are an integral part of these consolidated condensed financial statements. -4- CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS For the Three Months Ended March 31, 2002 and 2001 (in thousands) (unaudited)
THREE MONTHS ENDED MARCH 31, --------------------------------- 2002 2001 ------------ ------------ Cash flows from operating activities: Net income (loss) ........................................................... $ (74,267) $ 119,663 Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation, depletion and amortization ................................. 114,136 77,594 Equipment cancellation cost....................... ....................... 168,471 -- Deferred income taxes, net ............................................... (94,247) 41,216 Gain on sale of assets.................................................... (9,667) (10,750) Minority interests........................................................ 1 3,604 Income from unconsolidated investments in power projects.................. (1,444) (563) Distributions from unconsolidated investments in power projects........... 9 1,213 Change in operating assets and liabilities, net of effects of acquisitions: Accounts receivable..................................................... 148,144 (10,316) Notes receivable........................................................ (5,202) (7,959) Current derivative assets............................................... 214,007 (391,291) Other current assets.................................................... 231,918 (29,969) Long-term derivative assets............................................. 10,598 (162,488) Other assets............................................................ (7,241) 3,176 Accounts payable and accrued expense ................................... 24,073 (132,685) Current derivative liabilities.......................................... (174,474) 408,781 Long-term derivative liabilities........................................ (324,906) 222,479 Other liabilities....................................................... 54,125 (9,969) Other comprehensive income (loss) relating to derivatives .............. 71,911 (86,181) ------------ ------------ Net cash provided by operating activities ............................. 345,945 35,555 ------------ ------------ Cash flows from investing activities: Purchases of property, plant and equipment .................................. (1,289,615) (795,561) Disposals of property, plant and equipment................................... 1,739 19,134 Advances to joint ventures .................................................. (23,121) (32,331) Decrease (increase) in notes receivable ..................................... 12,914 (21,588) Maturities of collateral securities ......................................... 3,325 2,885 Project development costs ................................................... (23,784) (19,210) Decrease (increase) in restricted cash ...................................... 16,929 (51,964) ------------ ------------ Net cash used in investing activities ................................. (1,301,613) (898,635) ------------ ------------ Cash flows from financing activities: Repurchase of Zero-Coupon Convertible Debentures Due 2021.................... (187,727) -- Repayments of notes payable and borrowings under lines of credit ............ (73,652) (134,493) Borrowings from project financing ........................................... 122,885 609,354 Repayments of project financing ............................................. (92,198) (403,810) Proceeds from issuance of Convertible Senior Notes Due 2006 ................. 100,000 -- Proceeds from issuance of senior notes ...................................... -- 1,150,000 Financing costs.............................................................. (31,479) (52,509) Other ....................................................................... 3,685 (31,460) ------------ ------------ Net cash provided by (used in) financing activities ................... (158,486) 1,137,082 ------------ ------------ Effect of exchange rate changes on cash and cash equivalents.................... (491) -- Net increase (decrease) in cash and cash equivalents ........................... (1,114,645) 274,002 Cash and cash equivalents, beginning of period ................................. 1,525,417 596,077 ------------ ------------ Cash and cash equivalents, end of period ....................................... $ 410,772 $ 870,079 ============ ============ Cash paid during the period for: Interest, net of amounts capitalized ........................................ $ 6,218 $ 12,599 Income taxes ................................................................ $ 12,255 $ 65,745
The accompanying notes are an integral part of these consolidated condensed financial statements. -5- CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS March 31, 2002 (unaudited) 1. Organization and Operation of the Company Calpine Corporation ("Calpine"), a Delaware corporation, and subsidiaries (collectively, "the Company") is engaged in the generation of electricity in the United States, Canada and the United Kingdom. The Company is involved in the development, acquisition, ownership and operation of power generation facilities and the sale of electricity and its by-product, thermal energy, primarily in the form of steam. The Company has ownership interests in and operates gas-fired power generation and cogeneration facilities, gas fields, gathering systems and gas pipelines, geothermal steam fields and geothermal power generation facilities in the United States. In Canada, the Company has power facilities and oil and gas operations. In the United Kingdom, the Company has a gas-fired power cogeneration facility. Each of the generation facilities produces and markets electricity for sale to utilities and other third party purchasers. Thermal energy produced by the gas-fired cogeneration facilities is primarily sold to industrial users. Gas produced and not physically delivered to the Company's generating plants is sold to third parties. 2. Summary of Significant Accounting Policies Basis of Interim Presentation -- The accompanying unaudited interim consolidated condensed financial statements of the Company have been prepared by the Company pursuant to the rules and regulations of the Securities and Exchange Commission. In the opinion of management, the consolidated condensed financial statements include the adjustments necessary to present fairly the information required to be set forth therein. The Company's historical amounts have been restated to reflect the pooling-of-interests transaction completed during the second quarter of 2001 for the acquisition of Encal Energy Ltd. ("Encal"). Certain information and note disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles in the United States of America have been condensed or omitted from these statements pursuant to such rules and regulations and, accordingly, these financial statements should be read in conjunction with the audited consolidated financial statements of the Company for the year ended December 31, 2001, included in the Company's Annual Report on Form 10-K. The results for interim periods are not necessarily indicative of the results for the entire year. Use of Estimates in Preparation of Financial Statements -- The preparation of financial statements in conformity with generally accepted accounting principles in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expense during the reporting period. Actual results could differ from those estimates. The most significant estimates with regard to these financial statements relate to future development costs, useful lives of the generation facilities, provision for income taxes, fair value calculations of derivative instruments and depletion, depreciation and impairment of natural gas and petroleum property and equipment. See the "Critical Accounting Policies" subsection in the Management's Discussion and Analysis of Financial Condition and Results of Operations in the Company's Annual Report on Form 10-K for the year ended December 31, 2001 for a further discussion of the Company's significant estimates. Revenue Recognition -- The Company is primarily an electric generation company, operating a portfolio of mostly wholly owned plants but also some plants in which its ownership interest is 50% or less and which are accounted for under the equity method. In conjunction with its electric generation business, the Company also produces, as a by-product, thermal energy for sale to customers, principally steam hosts at its cogeneration sites. In addition, the Company acquires and produces natural gas for its own consumption and sells the balance and oil produced to third parties. To protect and enhance the profit potential of its electric generation plants, the Company, through its subsidiary, Calpine Energy Services, L.P. ("CES"), enters into electric and gas hedging, balancing, optimization, and trading transactions in which purchased electricity and gas is resold to third parties. CES generally 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, "Revenue Recognition in Financial Statements" and the Emerging Issues Task Force ("EITF") Issue No. 99-19, "Reporting Revenue Gross as a Principal Versus Net as an Agent," CES recognizes revenue on a gross basis, except in the case of financial swap transactions, in which case the net gain or loss from the financial swap is recorded in income when the effects of the risks being managed are recognized. Managed risks typically include commodity price risk associated with fuel purchases and power sales. The Company, through Power Systems Mfg., LLC ("PSM"), designs and manufactures certain spare parts for gas turbines. The Company also generates small amounts of revenue by occasionally loaning funds to power projects, by providing operation and maintenance ("O&M") services to unconsolidated power projects, and by performing engineering services for data centers and other facilities requiring highly reliable power. Further details of the Company's revenue recognition policy for each type of revenue transaction are provided below: -6- Electric Generation and Marketing Revenue -- This includes electricity and steam sales, mark-to-market gains and losses from electric power derivatives and sales of purchased power. The Company actively manages the revenue stream for its portfolio of electric generating facilities. The Company markets on a system basis both power generated by its plants in excess of amounts under direct contract between the plant and a third party, and power purchased from third parties, through hedging, balancing and optimization transactions. CES performs a market-based allocation of total electric generation and marketing revenue, exclusive of mark-to-market activity, to electricity and steam sales (based on electricity delivered by the Company's electric generating facilities to serve CES contracts) and the balance is allocated to sales of purchased power. Sales of purchased power also includes revenue from the settlement of contracts that have been previously recorded in results of operations as electric power derivative mark-to-market gains or losses Oil and Gas Production and Marketing Revenue -- This includes sales to third parties of oil, gas and related products that are produced by the Company's Calpine Natural Gas and Calpine Canada Natural Gas subsidiaries and also sales of purchased gas arising from hedging, balancing and optimization transactions. Sales of purchased gas also includes revenue from the settlement of contracts that have been previously recorded in results of operations as natural gas derivative mark-to-market gains or losses. Oil and gas sales for produced products are recognized pursuant to the sales method. 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, that the Company's investment is reduced to zero, at which time equity income is generally recognized only upon receipt of cash distributions from the investee. Other Revenue -- This includes O&M contract revenue, interest income on loans to power projects, PSM revenue from sales to third parties, engineering revenue and miscellaneous revenue. Purchased Power and Purchased Gas Expense -- The cost of power purchased from third parties for hedging, balancing, and optimization activities, along with costs from the subsequent settlement of contracts that have been previously recorded in results of operations as electric power derivative mark-to-market gains or losses, is recorded as purchased power expense, a component of electric generation and marketing expense. The Company records the cost of gas consumed in its power plants as cost of oil and natural gas burned by power plants, while gas purchased from third parties for hedging, balancing, and optimization activities, along with costs from the subsequent settlement of contracts that have been previously recorded in results of operations as natural gas derivative mark-to-market gains or losses, is recorded as purchased gas expense, a component of oil and gas production and marketing expense. Derivative Instruments -- Financial Accounting Standards Board ("FASB") Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities" as amended by SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities -- Deferral of the Effective Date of FASB Statement No. 133 -- an Amendment of FASB Statement No. 133," SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities -- an Amendment of FASB Statement No. 133" and related guidance from the Derivatives Implementation Group established accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair value. The statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge criteria are met, and requires that a company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. SFAS No. 133 provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income and be reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, must be recognized currently in earnings. SFAS No. 133 provides that the changes in fair value of derivatives designated as fair value hedges and the corresponding changes in the fair value of the hedged risk attributable to a recognized asset, liability, or unrecognized firm commitment be recorded in earnings. If the fair value hedge is effective, the amounts recorded will offset in earnings. SFAS No. 133 requires that as of the date of initial adoption, the difference between the fair value of derivative instruments and the previous carrying amount of these derivatives be recorded in net income or other comprehensive income, as appropriate, as the cumulative effect of a change in accounting principle. Upon adoption of SFAS No. 133 effective January 1, 2001, the Company recorded cumulative effects of a change in accounting principle of $1.0 million (net of a $0.7 million tax provision) to net income and $39.8 million (net of a $25.7 million tax provision) to other comprehensive income. -7- New Accounting Pronouncements -- In June 2001, the Company adopted SFAS No. 141, "Business Combinations," which supersedes Accounting Principles Board ("APB") Opinion No. 16, "Business Combinations" and SFAS No. 38, "Accounting for Preacquisition Contingencies of Purchased Enterprises." SFAS No. 141 eliminated the pooling-of-interests method of accounting for business combinations and modified the recognition of intangible assets and disclosure requirements. Adoption of SFAS No. 141 did not have a material effect on the Company's consolidated financial statements. On January 1, 2002, the Company adopted SFAS No. 142, "Goodwill and Other Intangible Assets," which supersedes APB Opinion No. 17, "Intangible Assets." See Note 4 for more information. In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations," which amends SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies." SFAS No. 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. SFAS No. 143 is effective for financial statements issued for fiscal years beginning after June 15, 2002. The Company has not completed its analysis of the impact that SFAS No. 143 will have on its consolidated financial statements. On January 1, 2002, the Company adopted SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," which supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," and the accounting and reporting provisions of APB Opinion No. 30, "Reporting the Results of Operations -- Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions," for the disposal of a segment of a business (as previously defined in that APB Opinion). SFAS No. 144 establishes a single accounting model, based on the framework established in SFAS No. 121, for long-lived assets to be disposed of by sale. SFAS No. 144 also resolves several significant implementation issues related to SFAS No. 121, such as eliminating the requirement to allocate goodwill to long-lived assets to be tested for impairment and establishing criteria to define whether a long-lived asset is held for sale. Adoption of SFAS No. 144 did not have a material effect on the Company's consolidated financial statements. In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections." SFAS No. 145 rescinds SFAS No. 4, "Reporting Gains and Losses from Extinguishment of Debt" and an amendment of that statement, SFAS No. 64, "Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements." SFAS No. 145 also rescinds SFAS No. 44, "Accounting for Intangible Assets of Motor Carriers." SFAS No. 145 also amends SFAS No. 13, "Accounting for Leases," to eliminate an inconsistency between the required accounting for sale-leaseback transactions and the required accounting for certain lease modifications that have economic effects that are similar to sale-leaseback transactions. SFAS No. 145 also amends other existing authoritative pronouncements to make various technical corrections, clarify meanings, or describe their applicability under changed conditions. The provisions related to the rescission of SFAS No. 4 shall be applied in fiscal years beginning after May 15, 2002. The provisions related to SFAS No. 13 shall be effective for transactions occurring after May 15, 2002. All other provisions shall be effective for financial statements issued on or after May 15, 2002, with early application encouraged. The Company does not believe that SFAS No. 145 will have a material effect on its results of operations. Reclassifications -- Prior period amounts in the consolidated condensed financial statements have been reclassified where necessary to conform to the 2002 presentation. -8- 3. Property, Plant and Equipment, Net, and Capitalized Interest Property, plant and equipment, net, consisted of the following (in thousands):
MARCH 31, DECEMBER 31, 2002 2001 ------------ ------------ Buildings, machinery and equipment ............. $ 4,966,818 $ 4,585,139 Oil and gas properties, including pipelines .... 2,327,040 2,283,344 Geothermal properties .......................... 382,134 375,156 Other .......................................... 240,997 223,675 ------------ ------------ 7,916,989 7,467,314 Less: accumulated depreciation, depletion and amortization.................................... (935,600) (843,778) ------------ ------------ 6,981,389 6,623,536 Land ........................................... 80,680 80,506 Construction in progress ....................... 9,149,420 8,496,456 ------------ ------------ Property, plant and equipment, net ............. $ 16,211,489 $ 15,200,498 ============ ============
Construction in progress is primarily attributable to gas-fired power projects under construction including prepayments on gas turbine generators. Upon commencement of plant operation, these costs are transferred to the applicable property category, generally buildings, machinery and equipment. In March 2002, the Company announced a new turbine and construction program that will slow the growth in the Company's construction in progress. See Note 11 for a discussion of the turbine order cancellations during the quarter. Capitalized Interest -- The Company capitalizes interest on capital invested in projects during the advanced stages of development and the construction period in accordance with SFAS No. 34, "Capitalization of Interest Cost," as amended by SFAS No. 58, "Capitalization of Interest Cost in Financial Statements That Include Investments Accounted for by the Equity Method (an Amendment of FASB Statement No. 34)." The Company's qualifying assets include construction in progress, certain oil and gas properties under development, construction costs related to unconsolidated investments in power projects under construction, and advanced stage development costs. For the three months ended March 31, 2002 and 2001, the total amount of interest capitalized was $163.1 million and $104.0 million, including $35.1 million and $34.7 million, respectively, of interest incurred on funds borrowed for specific construction projects and $128.0 million and $69.3 million, respectively of interest incurred on general corporate funds used for construction. Upon commencement of plant operation, capitalized interest, as a component of the total cost of the plant, is amortized over the estimated useful life of the plant. The increase in the amount of interest capitalized during the three months ended March 31, 2002 reflects the significant increase in the Company's power plant construction program. In accordance with SFAS No. 34, the Company determines which debt instruments best represent a reasonable measure of the cost of financing construction assets in terms of interest cost incurred that otherwise could have been avoided. These debt instruments and associated interest cost are included in the calculation of the weighted average interest rate used for capitalizing interest on general funds. The primary debt instruments included in the rate calculation are the Company's senior notes and the corporate revolvers. 4. Goodwill and Other Intangible Assets On January 1, 2002, the Company adopted SFAS No. 142, "Goodwill and Other Intangible Assets," which requires that all intangible assets with finite useful lives be amortized and that goodwill and intangible assets with indefinite lives not be amortized, but rather tested upon adoption and at least annually for impairment. The Company is required to complete the initial step of a transitional impairment test within six months of adoption of SFAS No. 142 and to complete the final step of the transitional impairment test by the end of the fiscal year. Any impairment loss resulting from the transitional impairment test would be recorded as a cumulative effect of a change in accounting principle for the quarter ended March 31, 2002. Subsequent impairment losses will be reflected in operating income or loss in the consolidated statements of operations. We will complete a transitional goodwill impairment test as required prior to June 30, 2002. In accordance with the standard, the Company discontinued the amortization of its recorded goodwill as of January 1, 2002 and identified reporting units based on its current segment reporting structure and allocated all recorded goodwill, as well as other assets and liabilities, to the reporting units. A reconciliation of previously reported net income and earnings per share to the amounts adjusted for the exclusion of goodwill amortization is provided below (in thousands except per share amounts): -9-
Three Months Ended March 31, ---------------------------------------------------------------------- 2002 2001 ------------------------------ ------------------------------ Per Share Per Share ------------------ ----------------- Amount Diluted Basic Amount Diluted Basic --------- ------- ------- --------- ------- ------- Reported income (loss) before extraordinary gain and cumulative effect of a change in accounting principle........................... $(76,397) $(0.25) $(0.25) $ 118,627 $ 0.35 $ 0.39 Add: Goodwill amortization, net of tax............ -- -- -- 136 -- -- Income (loss) before extraordinary gain and cumulative effect of a change in accounting principle, as adjusted............................ (76,397) (0.25) (0.25) 118,763 0.35 0.39 Extraordinary gain and cumulative effect of a change in accounting principle, net of tax........ 2,130 0.01 0.01 1,036 0.01 0.01 -------- ------ ------ --------- ------- ------- Net income (loss), as adjusted.................... $(74,267) $(0.24) $(0.24) $ 119,799 $ 0.36 $ 0.40 ======== ====== ====== ========= ======= =======
Recorded goodwill, by segment, as of March 31, 2002 was (in thousands): Electric Generation and Marketing ............................ $29,348 Oil and Gas Production and Marketing.......................... -- Corporate, Other and Eliminations ............................ -- ------- Total ..................................................... $29,348 =======
The Company also reassessed the useful lives and the classification of its identifiable intangible assets and determined that they continue to be appropriate. The components of the amortizable intangible assets consist of the following (in thousands):
As of March 31, 2002 As of December 31, 2001 ------------------------ ------------------------ Weighted Average Useful Life/Contract Carrying Accumulated Carrying Accumulated Life Amount Amortization Amount Amortization ------------- ---------- ------------ ---------- ------------ Patents .................. 5 $ 485 $ (158) $ 485 $ (134) Power sales agreements.... 14 173,479 (93,779) 173,479 (87,823) Fuel supply and fuel management contracts..... 33 127,543 (15,477) 127,543 (14,503) Other..................... 5 381 (36) 277 (25) --------- ---------- --------- --------- Total..................... $ 301,888 $ (109,450) $ 301,784 $(102,485) ========= ========== ========= =========
Amortization expense of other intangible assets was $7.0 million and $6.9 million in the three months ended March 31, 2002 and 2001, respectively. Assuming no future impairments of these assets or additions as the result of acquisitions, annual amortization expense will be $25.0 million for the twelve months ended December 31, 2002, $8.9 million in 2003, $8.4 million in 2004, $8.3 million in 2005 and $8.2 million in 2006. 5. Investments in Power Projects On March 29, 2002, the Company sold its 11.4% interest in the Lockport Power Plant in exchange for a $27.3 million note receivable from Fortistar Tuscarora LLC, a wholly owned subsidiary of Fortistar LLC, the project's managing general partner. The note is scheduled to be repaid in the second quarter of 2002. This transaction resulted in a pre-tax other income gain of $9.7 million. -10- 6. Financing In January 2002, the Company entered into a letter of intent with ING Bank on the debt portion of a proposed California peaker sale/leaseback, including 11 California peaker facilities. This transaction is expected to generate $500 million of cash that will be received throughout 2002 as the power facilities enter commercial operation. Between January 2, 2002, and February 11, 2002, the Company repurchased an additional $192.5 million of its Zero-Coupon Convertible Debentures Due 2021 ("Zero Coupons"), bringing total repurchases to $314.5 million, and bringing the amount of Zero Coupons outstanding as of March 31, 2002 to $685.5 million. The Zero Coupons were repurchased at a discount, resulting in an extraordinary gain of $2.1 million, after the write-off of related financing costs and provision for tax. See Note 14 for additional repurchases subsequent to March 31, 2002. On January 3, 2002, the Company sold $100 million in aggregate principal amount of 4% Convertible Senior Notes Due 2006 ("Convertible Notes"), pursuant to the exercise of the initial purchaser's remaining $100 million option to purchase additional Convertible Notes. These securities will be convertible into shares of Calpine common stock at a price of $18.07. In March 2002, the Company closed a new secured credit agreement comprised of (a) a $1.0 billion revolving credit facility expiring on May 24, 2003 and (b) a two-year term loan facility for up to $600 million, which as previously reported, was only to be made available to the Company upon satisfaction of certain conditions to borrowing on or before June 8, 2002. On May 10, 2002, the Company borrowed $500 million of the term loan facility and, subject to certain conditions, may borrow the remaining $100 million in one or two remaining tranches on or before June 8, 2002. At the March 2002 closing, the Company also amended its existing $400 million revolving credit agreement to provide, among other things, security for borrowings under that agreement. The security for the revolving and term loan facilities as originally provided included (a) a pledge of the capital stock of the Company's subsidiary holding, directly or indirectly, (i) the interests in its natural gas properties, (ii) the Saltend power plant located in the United Kingdom and (iii) the Company's equity investment in nine U.S. power plants, and (b) a pledge by certain of the Company's subsidiaries of a total of 65% of the capital stock of Calpine Canada Energy Ltd. As part of the recent funding of the $500 million term loan, the Company expanded the security for the revolving credit and term loan facilities under both the $1.6 billion and the $400 million credit agreements by pledging to the lenders substantially all of the Company's remaining first tier domestic subsidiaries (excluding CES). On March 13, 2002, the Company repaid the Michael Petroleum note payable, which had a balance of $64.8 million at repayment. 7. Derivative Instruments As an independent power producer primarily focused on generation of electricity using gas-fired turbines, the Company's natural physical commodity position is "short" fuel (i.e., natural gas consumer) and "long" power (i.e., electricity seller). To manage forward exposure to price fluctuation in these and (to a lesser extent) other commodities, the Company enters into derivative commodity instruments. All transactions are subject to the Company's risk management policy which prohibits positions that exceed total portfolio generation and fuel requirements. Any hedging, balancing, or optimization activities that the Company engages in are directly related to the Company's asset-based business model of owning and operating gas-fired electric power plants and are designed to protect the Company's "spark spread" (the difference between the Company's fuel cost and the revenue it receives for its electric generation). The Company hedges exposures that arise from the ownership and operation of power plants and related sales of electricity and purchases of natural gas, and the Company utilizes derivatives to optimize the returns the Company is able to achieve from these assets for the Company's shareholders. While certain of the Company's contracts are considered energy trading contracts as defined in EITF Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," the Company's traders have low capital at risk and value at risk limits for energy trading, and its risk management policy limits, at any given time, its net sales of power to its generation capacity and limits its net purchases of gas to its fuel consumption requirements on a total portfolio basis. This model is markedly different from that of companies that engage in significant commodity trading operations that are unrelated to underlying physical assets. Derivative commodity instruments are accounted for under the requirements of SFAS No. 133. The Company enters into various foreign currency swap agreements to hedge against changes in exchange rates on certain of its senior notes denominated in currencies other than the U.S. dollar. The foreign currency swaps effectively convert floating exchange rates into fixed exchange rates so that the Company can predict with greater assurance what its U.S. dollar cost will be for purchasing foreign currencies to satisfy the interest and principal payments on these senior notes. -11- The Company also enters into various interest rate swap agreements to hedge against changes in floating interest rates on certain of its project financing facilities. The interest rate swap agreements effectively convert floating rates into fixed rates so that the Company can predict with greater assurance what its future interest costs will be and protect itself against increases in floating rates. In conjunction with its capital markets activities, the Company enters into various forward interest rate agreements to hedge against interest rate fluctuations that may occur after the Company has decided to issue long-term fixed rate debt but before the debt is actually issued. The forward interest rate agreements effectively prevent the interest rates on anticipated future long-term debt from increasing beyond a certain level, allowing the Company to predict with greater assurance what its future interest costs on fixed rate long-term debt will be. The Company enters into commodity financial instruments to convert floating or indexed electricity and gas (and to a lesser extent oil and refined product) prices to fixed prices in order to lessen its vulnerability to reductions in electric prices for the electricity it generates, to reductions in gas prices for the gas it produces, and to increases in gas prices for the fuel it consumes in its power plants. The Company seeks to "self-hedge" its gas consumption exposure to an extent with its own gas production position. The Company also routinely enters into physical commodity contracts for sales of its generated electricity and sales of its natural gas production to ensure favorable utilization of generation and production assets. Such contracts often meet the criteria of SFAS No. 133 as derivatives but are generally eligible for the normal purchase and sales exception under SFAS No. 138. Some of those that are not deemed normal purchases and sales, can be designated as hedges of the underlying consumption of gas or production of electricity. During 2001, the FASB issued SFAS No. 133 Implementation Issue No. C15, dealing with a proposed electric industry normal purchases and sales exception for capacity sales transactions ("The Eligibility of Option Contracts in Electricity for the Normal Purchases and Normal Sales Exception"). As a result of Issue No. C15, as revised, most of the Company's capacity sales contracts qualify for the normal purchases and sales exception. 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. In 2001 the FASB cleared SFAS No. 133 Implementation Issue No. C16 "Applying the Normal Purchases and Normal Sales Exception to Contracts That Combine a Forward Contract and a Purchased Option Contract" ("C16"). The guidance in C16 applies to fuel supply contracts that require delivery of a contractual minimum quantity of fuel at a fixed price and have an option that permits the holder to take specified additional amounts of fuel at the same fixed price at various times. Under C16, the volumetric optionality provided by such contracts is considered a purchased option that disqualifies the entire derivative fuel supply contract from being eligible to qualify for the normal purchases and normal sales exception in SFAS No. 133. The Company has adopted the guidance provided by C16 effective April 1, 2002, and Issue C16 is expected to increase the volatility of the Company's reported earnings in the future. The changes in fair values of derivative instruments designated as cash flow hedges are recorded in other comprehensive income ("OCI") for the effective portion and in current earnings, using the dollar offset method, for the ineffective portion. The changes in fair values of derivative instruments designated as fair value hedges are recorded in current earnings, as are the changes in fair values of the hedged risk attributable to the recognized asset, liability or unrecognized firm commitment being hedged. The changes in fair values of derivative instruments that are not designated as hedges are recorded in current earnings. -12- The table below reflects the amounts (in thousands) that are recorded as assets and liabilities at March 31, 2002 for the Company's derivative instruments:
Commodity Interest Rate Currency Derivative Total Derivative Derivative Instruments Derivative Instruments Instruments Net Instruments ------------ ----------- ----------- ------------ Current derivative assets .............. $ -- $ -- $ 549,155 $ 549,155 Long-term derivative assets ............ -- -- 554,354 554,354 -------- --------- ---------- ---------- Total assets ......................... $ -- $ -- $1,103,509 $1,103,509 ======== ========= ========== ========== Current derivative liabilities ......... $(10,927) $ (1,971) $ (437,967) $ (450,865) Long-term derivative liabilities ....... (6,136) (12,690) (479,090) (497,916) -------- --------- ---------- ---------- Total liabilities ............... $(17,063) $ (14,661) $ (917,057) $ (948,781) ======== ========= ========== ========== Net derivative assets (liabilities)..... $(17,063) $ (14,661) $ 186,452 $ 154,728 ======== ========= ========== ==========
At any point in time, it is highly unlikely that total net derivative assets and liabilities will equal accumulated OCI, net of tax from derivatives, for three primary reasons: o Tax effect of OCI -- When the values and subsequent changes in values of derivatives that qualify as effective hedges are recorded into OCI, they are initially offset by a derivative asset or liability. Once in OCI, however, these values are tax effected against a deferred tax liabiality, thereby creating an imbalance between net OCI and net derivative assets and liabilities. o Derivatives not designated as cash flow hedges and hedge ineffectiveness -- Only derivatives that qualify as effective cash flow hedges will have an offsetting amount recorded in OCI. Derivatives not designated as cash flow hedges and the ineffective portion of derivatives designated as cash flow hedges will be recorded into earnings instead of OCI, creating a difference between net derivative assets and liabilities and pre-tax OCI from derivatives. o Termination of effective cash flow hedges prior to maturity -- Following the termination of a cash flow hedge and subsequent settlement with a counterparty, the derivative asset or liability is liquidated and removed from the books. At this point, no asset or liability exists on the books for the hedge but a balance remains in OCI, which is not recognized in earnings until the forecasted transactions occur. As a result, there will be a temporary difference between OCI and derivative assets and liabilities on the books until the remaining OCI balance is recognized in earnings. Below is a reconciliation from the Company's net derivative assets to its accumulated other comprehensive loss, net of tax from derivative instruments at March 31, 2002 (in thousands): Net derivative assets ............................................. $ 154,728 Derivatives not designated as cash flow hedges and recognized hedge ineffectiveness ................................ (126,740) Terminated cash flow hedges, prior to maturity .................... (255,817) Deferred tax asset attributable to accumulated other comprehensive loss on cash flow hedges .......................... 88,210 --------- Accumulated other comprehensive loss from derivative instruments, net of tax ............................... $(139,619) =========
The asset and liability balances for the Company's commodity derivative instruments represent the net totals after offsetting certain assets against certain liabilities under the criteria of FASB Interpretation No. 39, "Offsetting of Amounts Related to Certain Contracts (an Interpretation of APB Opinion No. 10 and FASB Statement No. 105)" ("FIN 39"). For a given contract, FIN 39 will allow the offsetting of assets against liabilities so long as four criteria are met: (1) each of the two parties under contract owes the other determinable amounts; (2) the party reporting under the offset method has the right to set off the amount it owes against the amount owed to it by the other party; (3) the party reporting under the offset method intends to exercise its right to set off; and; (4) the right of set-off is enforceable by law. The table below reflects both the amounts (in thousands) recorded as assets and liabilities by the Company and the amounts that would have been recorded had the Company's commodity derivative instrument contracts not qualified for offsetting as of March 31, 2002. -13-
MARCH 31, 2002 ------------------------------ GROSS NET ----------- ------------ Current derivative assets .................. $ 1,182,400 $ 549,155 Long-term derivative assets ................ 957,666 554,354 ----------- ----------- Total derivative assets .................. $ 2,140,066 $ 1,103,509 =========== =========== Current derivative liabilities ............. $(1,071,212) $ (437,967) Long-term derivative liabilities ........... (882,402) (479,090) ----------- ----------- Total derivative liabilities ............. $(1,953,614) $ (917,057) =========== =========== Net commodity derivative assets .......... $ 186,452 $ 186,452 =========== ===========
The table above excludes the value of interest rate and currency derivative instruments. The table below reflects the impact of the Company's derivative instruments on its pre-tax earnings, both from cash flow hedge ineffectiveness and from the changes in market value of derivatives not designated as hedges of cash flows, for the three months ended March 31, 2002 and 2001, respectively (in thousands):
Three Months Ended March 31, ------------------------------------------------------------------------------------- 2002 2001 ------------------------------------------ --------------------------------------- Hedge Undesignated Hedge Undesignated Ineffectiveness Derivatives Total Ineffectiveness Derivatives Total --------------- ------------ -------- --------------- ------------ ------- Natural gas derivatives (1)................. $ (2,596) $(3,796) $(6,392) $ 526 $ 7,023 $ 7,549 Power derivatives .......................... (222) 4,388 4,166 (1,217) 2,523 1,306 Interest rate derivatives (2) .............. (152) -- (152) -- -- -- Foreign currency derivatives ............... -- -- -- -- -- -- --------- --------- --------- --------- --------- -------- Total..................................... $ (2,970) $ 592 $(2,378) $ (691) $ 9,546 $ 8,855 ========= ========= ========= ========= ========= ========
(1) Composed of gas contracts and crude oil costless collar arrangements (2) Recorded within Other Income For the three months ended March 31, 2002 and 2001, the Company's realized commodity cash flow hedge activity contributed $50.7 million and $17.0 million, respectively, to pre-tax earnings based on the reclassification adjustment from OCI to earnings. For the three months ended March 31, 2002 and 2001, power hedges contributed $86.5 million and $(9.3) million, respectively, to pre-tax earnings. For the three months ended March 31, 2002 and 2001, gas and crude oil hedges contributed $(35.8) million and $26.3 million, respectively, to pre-tax earnings. As of March 31, 2002, the maximum length of time over which the Company was hedging its exposure to the variability in future cash flows for forecasted transactions was 6, 7, and 16 1/2 years, for commodity, foreign currency and interest rate derivative instruments, respectively. The company estimates that pre-tax gains of $80.1 million would be reclassified from accumulated OCI into earnings during the twelve months ended March 31, 2003 as the hedged transactions affect earnings assuming constant gas and power prices, interest rates, and exchange rates over time; however, the actual amounts that will be reclassified will likely vary based on the probability that gas and power prices as well as interest rates and exchange rates will, in fact, change. Therefore, management is unable to predict what the actual reclassification from OCI to earnings (positive or negative) will be for the next twelve months. -14- The table below presents (in thousands) the pre-tax gains (losses) currently held in OCI that will be recognized annually into earnings, assuming constant gas and power prices, interest rates, and exchange rates over time.
2007 2002 2003 2004 2005 2006 & After Total --------- ---------- --------- ---------- --------- --------- ---------- Crude oil OCI..................... $ (129) $ -- $ -- $ -- $ -- $ -- $ (129) Gas OCI........................... (88,344) (183,131) (69,772) (63,121) (22,540) -- (426,908) Power OCI......................... 206,945 66,583 353 1,320 1,898 (652) 276,447 Interest rates OCI................ (14,119) (12,118) (8,779) (7,612) (6,951) (18,937) (68,516) Foreign currency OCI.............. (1,971) (1,831) (1,700) (1,588) (1,500) (133) (8,723) --------- ---------- --------- --------- --------- --------- ---------- Total OCI....................... $ 102,382 $ (130,497) $ (79,898) $ (71,001) $ (29,093) $ (19,722) $ (227,829) ========= ========== ========= ========= ========= ========= ==========
8. Comprehensive Income (Loss) Comprehensive income (loss) is the total of net income (loss) and all other non-owner changes in equity. Comprehensive income (loss) includes net income (loss) and unrealized gains and losses from derivative instruments that qualify as hedges. The Company reports accumulated other comprehensive loss in its consolidated balance sheet. The tables below detail the changes in the Company's accumulated OCI balance and the components of the Company's comprehensive income (loss) (in thousands):
Accumulated Other Comprehensive Loss at March 31, 2002 ------------------------------------- Comprehensive Foreign Loss for the Three Cash Flow Currency Months Ended Hedges Translation Total March 31, 2002 --------- ----------- --------- ------------------ Net loss .......................................................... $ (74,267) Accumulated other comprehensive loss at beginning of period ....... $(183,377) $ (43,197) $(226,574) -- Cash flow hedges: Comprehensive pre-tax gain on cash flow hedges before reclassification adjustment during the three months ended March 31, 2002 ........................................ 120,610 -- 120,610 120,610 Reclassification adjustment for gain included in net loss for the three months ended March 31, 2002 .............. (48,699) -- (48,699) (48,699) Income tax provision for the three months ended March 31, 2002 .............................................. (28,153) -- (28,153) (28,153) --------- --------- --------- 43,758 -- 43,758 43,758 Foreign currency translation loss for the three months ended March 31, 2002 ........................................ -- (25,170) (25,170) (25,170) --------- --------- --------- --------- Accumulated other comprehensive loss at end of period ............. $(139,619) $ (68,367) $(207,986) -- ========= ========= ========= Comprehensive loss ................................................ $ (55,679) =========
-15-
Accumulated Other Comprehensive Loss at March 31, 2001 ------------------------------------- Comprehensive Foreign Income for the Three Cash Flow Currency Months Ended Hedges Translation Total March 31, 2001 --------- ----------- --------- ------------------ Net income......................................................... $ 119,663 Accumulated other comprehensive loss at beginning of period........ $ -- $ (23,085) $ (23,085) -- Cash flow hedges: Comprehensive pre-tax loss on cash flow hedges before reclassification adjustment during the three months ended March 31, 2001......................................... (69,134) -- (69,134) (69,134) Reclassification adjustment for gain included in net income for the three months ended March 31, 2001............. (17,047) -- (17,047) (17,047) Income tax benefit for the three months ended March 31, 2001............................................... 32,611 -- 32,611 32,611 --------- --------- --------- (53,570) -- (53,570) (53,570) Foreign currency translation gain for the three months ended March 31, 2001......................................... -- 14,694 14,694 14,694 --------- --------- --------- --------- Accumulated other comprehensive loss at end of period.............. $ (53,570) $ (8,391) $ (61,961) -- ========= ========= ========= Comprehensive income .............................................. $ 80,787 =========
9. Customers Enron During 2001, the Company, primarily through its CES subsidiary, transacted a significant volume of business with units of Enron Corp. ("Enron"), mainly Enron Power Marketing, Inc. ("EPMI") and Enron North America Corp. ("ENA"). ENA is the parent corporation of EPMI. Enron is the direct parent corporation of ENA. Most of these transactions were contracts for sales and purchases of power and gas for hedging purposes, some of which extended out as far as 2009. On December 2, 2001, Enron Corp. and certain of its subsidiaries filed voluntary petitions for Chapter 11 reorganization with the U.S. Bankruptcy Court for the Southern District of New York. EPMI and ENA are among the subsidiaries of Enron that filed for reorganization on December 2, 2001. The Company conducted a limited amount of business with EPMI and ENA during December of 2001 on a collateralized or prepaid basis and has conducted no business with EPMI or ENA since December 31, 2001. The following table sets forth information regarding the Company's settled physical transactions and non-hedging mark-to-market gains with Enron for the three months ended March 31, 2002 and 2001, (in thousands of dollars and thousands of MWh's, in the case of electricity transactions, and thousands of MMBtu's, in the case of oil and gas transactions):
For the Three Months Ended For the Three Months Ended March 31, 2002 March 31, 2001 -------------------------- -------------------------- Dollar Volume Dollar Volume --------- ------ --------- ------ Electric generation and marketing revenue (electricity and steam revenue and sales of purchased power) ................... $ -- -- $ 84,175 1,293 Oil and gas production and marketing revenue (sales of purchased gas) ................................................ -- -- 53,290 4,719 Other revenue .................................................. -- -- 1,348 -- ------- --------- Total power and fuel and other revenue from Enron .............. $ -- $ 138,813 ------- --------- Electric generation and marketing expense (Purchased power expense) ...................................................... $ -- -- $ 110,886 1,283 Fuel expense (cost of oil and natural gas burned by power plants and natural gas derivative mark-to-market gain) ........ -- -- 16,930 2,417 ------- --------- Total CES power and fuel expenses related to Enron (1) ......... $ -- $ 127,816 ======= =========
__________ (1) Expenses of CES only, as other Enron expenses incurred are not material. -16- The Company has terminated all of its open forward positions with ENA and EPMI as of March 31, 2002, and will settle with ENA and EPMI based on the value of the terminated contracts at the termination or replacement date, as applicable. Accordingly, all amounts associated with terminated ENA and EPMI forward contracts have been included within the Company's accounts payable. As of March 31, 2002, unrealized pre-tax losses on derivatives designated as effective cash flow hedges recorded in OCI associated with terminated ENA and EPMI contracts were $161.6 million. These amounts will be recognized in future earnings as the original hedged forecasted transactions occur. The sales to and purchases from various Enron subsidiaries were mostly for hedging, balancing and optimization transactions, and in most cases the purchases and sales are not related and should not be netted to try to gauge the profitability of transactions with Enron subsidiaries. On November 14, 2001, CES, ENA and EPMI entered into a Master Netting, Setoff and Security Agreement (the "Netting Agreement"). The Netting Agreement permits CES, on the one hand, and ENA and EPMI, on the other hand, to set off amounts owed to each other under an ISDA Master Agreement between CES and ENA, an Enfolio Master Firm Purchase/Sale Agreement between CES and ENA and a Master Energy Purchase/Sale Agreement between CES and EPMI (in each case, after giving effect to the netting provisions contained in each of these agreements). Based on legal analysis of the Netting Agreement, the Company believes it has no net collection exposure to Enron. Following are the accounts receivable and accounts payable balances, presented on both a gross and net basis, with ENA and EPMI at March 31, 2002 (in millions):
Receivables/Payables -------------------- Gross Gross Net Receivable Receivable Payable (Payable) ---------- ---------- -------------- Enron North America ........... $ 1,125.6 $ (1,404.7) $ (279.1) Enron Power Marketing ......... 836.7 (701.1) 135.6 ---------- ---------- -------- Total ....................... $ 1,962.3 $ (2,105.8) $ (143.5) ========== ========== ========
After netting the receivables and payables from ENA and EPMI, the Company has an existing or future obligation of $143.5 million as of March 31, 2002, which obligation will be offset by CES' losses, damages, attorneys' fees and other expenses arising from the default by Enron. Although the Company had no net collection exposure to ENA and EPMI at March 31, 2002, the Company established a $13.1 million reserve in December 2001 related to unrealized mark to market gains generated by Enron's insolvency, which caused earnings recognition for contracts that had previously been exempted from SFAS No. 133 accounting and which caused cash flow hedges to cease to be effective and marked-to-market in earnings until termination. The Company's treasury department includes a credit group focused on monitoring and managing counterparty risk. The credit group monitors the net exposure with each counterparty on a daily basis. The analysis is performed on a mark-to-market basis using the forward curves audited by the Company's Risk Controls group. The net exposure is compared against a counterparty credit risk threshold which is determined based on the counterparty's credit ratings, evaluation of the financial statements and bond values. The credit department monitors these thresholds to determine the need for additional collateral or an adjustment to activity with the counterparty. Nevada Power and Sierra Pacific Resources During the first quarter of 2002, two subsidiaries of Sierra Pacific Resources Corporation, Nevada Power Company ("NPC") and Sierra Pacific Resources ("SPR"), received credit downgrades to sub-investment grades from the major credit rating agencies. The credit downgrades resulted from short-term liquidity problems created when the Public Utilities Commission of Nevada disallowed a rate adjustment requested by NPC to cover the increased cost of buying power during the 2001 energy crisis. NPC and SPR have requested that their power suppliers extend payment terms to help them overcome their short-term liquidity problems. As of March 31, 2002, the Company had net collection exposures of approximately $30.7 million and $21.3 million with NPC and SPR, respectively. The Company's exposures include open forward power position contracts that are reported at fair value in the Company's balance sheet as well as receivable and payable balances relating to settled power deliveries. Management is continuing to monitor the exposure and its effect on the Company's financial condition. The table below details the components of the Company's exposure position at March 31, 2002 (in millions of dollars). The positive net positions represent realization exposure while the negative net positions represent the Company's existing or potential obligations. -17-
Receivables/Payables Fair Values -------------------------------- -------------------------------- Net Gross Gross Net Open Gross Gross Receivable Fair Fair Positions Receivable Payable (Payable) Value(+) Value(-) Value Total ---------- ------- ---------- -------- -------- --------- ------ Nevada Power Company ................... $ 3.5 $ (4.6) $ (1.1) $ 91.0 $ (59.2) $ 31.8 $ 30.7 Sierra Pacific Resources ............... 1.0 -- 1.0 20.3 -- 20.3 21.3 ----- ------ ------ ------- ------- ------ ------ Total ................................ $ 4.5 $ (4.6) $ (0.1) $ 111.3 $ (59.2) $ 52.1 $ 52.0 ===== ====== ====== ======= ======= ====== ======
Under the terms of its contracts with NPC and SPPC, the Company believes that it has the right to offset asset and liability positions. 10. Earnings (loss) per Share Basic earnings (loss) per common share were computed by dividing net income (loss) by the weighted average number of common shares outstanding for the period. The dilutive effect of the potential exercise of outstanding options to purchase shares of common stock is calculated using the treasury stock method. The dilutive effect of the assumed conversion of certain convertible securities into the Company's common stock is based on the dilutive common share equivalents and the after tax distribution expense avoided upon conversion. The reconciliation of basic earnings (loss) per common share to diluted earnings (loss) per share is shown in the following table (in thousands except per share data).
PERIODS ENDED MARCH 31, ----------------------------------------------------------------- 2002 2001 ------------------------------- ------------------------------ NET NET INCOME INCOME (LOSS) SHARES EPS (LOSS) SHARES EPS -------- ------- ------ -------- ------- -------- THREE MONTHS: Basic earnings (loss) per common share: Income (loss) before extraordinary gain and cumulative effect of a change in accounting principle .................... $(76,397) 307,332 $(0.25) $118,627 300,554 $ 0.39 Extraordinary gain, net of tax .................................. 2,130 -- 0.01 -- -- -- Cumulative effect of a change in accounting principle, net of tax .................................................... -- -- -- 1,036 -- 0.01 -------- ------- ------ -------- ------- -------- Net income (loss) ............................................... $(74,267) 307,332 $(0.24) $119,663 300,554 $ 0.40 -------- ------- ------ -------- ------- -------- Diluted earnings (loss) per common share: Common shares issuable upon exercise of stock options using treasury stock method ................................... -- 16,278 ------- ------- Income (loss) before dilutive effect of certain convertible securities, extraordinary gain and cumulative effect of a change in accounting principle ........................... $(76,397) 307,332 $(0.25) $118,627 316,832 $ 0.37 Dilutive effect of certain convertible securities ............... -- -- -- 9,355 44,882 (0.02) -------- ------- ------ -------- ------- -------- Income (loss) before extraordinary gain and cumulative effect of a change in accounting principle .................... (76,397) 307,332 (0.25) 127,982 361,714 0.35 Extraordinary gain, net of tax .................................. 2,130 -- 0.01 -- -- -- Cumulative effect of a change in accounting principle, net of tax .................................................... -- -- -- 1,036 -- 0.01 -------- ------- ------ -------- ------- -------- Net income (loss) ............................................... $(74,267) 307,332 $ (0.24) $129,018 361,714 $ 0.36 ======== ======= ======== ======== ======= ========
The effect of 151,353,196 and 280,849 unexercised employee stock options, Company-obligated mandatorily redeemable convertible preferred securities of subsidiary trusts, Zero Coupons and Convertible Notes were not included in the computation of diluted shares outstanding for the three months ended March 31, 2002 and 2001, because such inclusion would have been antidilutive. Because of the Company's loss for the three months ended March 31, 2002, basic shares were used in the calculation of fully diluted loss per share, under the guidelines of SFAS No. 128, "Earnings per Share," as using the basic shares produced the more dilutive effect on the loss per share. -18- 11. Commitments and Contingencies Capital Expenditures -- On March 12, 2002, the Company announced a new turbine program that reduces previously forecasted capital spending by approximately $1.2 billion in 2002 and $1.8 billion in 2003. The revision includes adjusted timing of turbine delivery and related payment schedules and also turbine cancellation orders. As a result of the turbine order cancellations and the cancellation of certain other equipment, the Company recorded a pre-tax charge of $168.5 million in the first quarter of 2002, based primarily on forfeited prepayments to date and an immaterial cash payment pursuant to contract terms. Litigation -- Calpine Corporation v. Automated Credit Exchange ("ACE"). On March 5, 2002, Calpine sued ACE in the Superior Court of the State of California for the County of Alameda for negligence and breach of contract to recover reclaim trading credits, a form of emission reduction credits that should have been held in Calpine's account with U.S. Trust Company (US Trust). ACE is a broker in emission reduction credits based in Pasadena, California. Calpine had paid ACE for Nitrogen oxide (NOx) coastal credits that were to be purchased by ACE and held by US Trust. The credits were to be held by US Trust pursuant to a Credit Holding Agreement, which provided, among other things, that US Trust was to hold the credits until receiving instructions from ACE to disburse the credits. ACE had agreed that (i) upon prior written instruction from Calpine, to instruct US Trust to take such actions as may be directed by Calpine to disburse the credits held in escrow pursuant to the Credit Holding Agreement and (ii) not to take any action, or otherwise instruct US Trust to take any action, concerning the credits held in escrow pursuant to the Credit Holding Agreement without prior written instruction from Calpine. Calpine and ACE entered into a settlement agreement that resolved all issues on March 29, 2002. The settlement provided for a partial recovery of $7 million and for the rights to the emission reduction credits to be held by ACE. The Company expects to recognize the $7 million in the second quarter of 2002, after all realization uncertainties are cleared. In accordance with the settlement agreement, Calpine has dismissed its complaint against ACE. Ben Johnson v. Peter Cartwright, et al. On December 17, 2001, a shareholder filed a derivative lawsuit on behalf of Calpine against its directors and one of its senior officers. This lawsuit is styled Johnson vs. Cartwright, et al. (No. CV803872), and is pending in the California Superior Court, Santa Clara County. Calpine is a nominal defendant in this lawsuit, which alleges claims relating to purportedly misleading statements about Calpine and stock sales by certain of the director defendants and the officer defendant. Calpine has filed a demurrer asking the court to dismiss the complaint on the ground that the shareholder plaintiff lacks standing to pursue claims on behalf of Calpine. The individual defendants have filed a demurrer asking the court to dismiss the complaint on the ground that it fails to state any claims against them. Securities Class Action Lawsuits. Since March 11, 2002, fourteen shareholder lawsuits have been filed against Calpine and certain of its officers in the United States District Court, Northern District of California. The actions captioned Weisz vs. Calpine Corp., et al., filed March 11, 2002, and Labyrinth Technologies, Inc. v. Calpine Corp., et al., filed March 28, 2002 are purported class actions on behalf of purchasers of Calpine stock between March 15, 2001 and December 13, 2001. Gustaferro v. Calpine Corp., filed April 18, 2002 is a purported class action on behalf of purchasers of Calpine stock between February 6, 2001 and December 13, 2001. The eleven other actions, captioned Local 144 Nursing Home Pension Fund vs. Calpine Corp., Lukowski vs. Calpine Corp., Hart vs. Calpine Corp., Atchison vs. Calpine Corp. and Laborers Local 1298 v. Calpine Corp., Bell v. Calpine Corp., Nowicki v. Calpine Corp. Pallotta v. Calpine Corp., Knepell v. Calpine Corp., Staub v. Calpine Corp, and Rose v. Calpine Corp. were filed between March 18, 2002 and April 23, 2002. The complaints in these eleven actions are virtually identical--they were filed by three law firms, in conjunction with other law firms as co-counsel. All eleven lawsuits are purported class actions on behalf of purchasers of Calpine's securities between January 5, 2001 and December 13, 2001. The complaints in these fourteen actions allege that, during the purported class periods, certain senior executives issued false and misleading statements about Calpine's financial condition in violation of Sections 10(b) and 20(1) of the Securities Exchange Act of 1934, as well as Rule 10b-5. These actions seek an unspecified amount of damages, in addition to other forms of relief. We expect that these actions, as well as any related actions that may be filed in the future, will be consolidated by the court into a single securities class action. We consider the lawsuits to be without merit, and we intend to defend vigorously against these allegations. Public Utilities Commission of the State of California v. Sellers of Long Term Contracts to the California Department of Water Resources; California Electricity Oversight Board v. Sellers of Long Term Contracts to the California Department of Water Resources. In February 2002 both the California Public Utilities Commission ("CPUC") and the California Electric Oversight Board ("EOB") filed complaints under Section 206 of the Federal Power Act with the Federal Energy Regulatory Commission ("FERC") (EL02-60-000 and EL02-62-000, respectively) alleging that the prices and terms of the long-term contracts with the California Department of Water Resources ("DWR") are unjust and unreasonable and counter to the public interest. CES is a respondent and the four long-term -19- contracts entered into between CES and DWR are subject to the complaint (see, Risk Factors - California Long-Term Supply Agreements). As part of Calpine's successful renegotiation of its long-term power contracts with DWR announced on April 22, 2002, the Office of the Governor, the CPUC, the EOB and the California Attorney General ("AG") agreed to settle this action and drop all challenges to Calpine's long-term contracts with DWR. On May 2, 2002 each of the CPUC, the EOB, and the AG filed a Notice of Partial Withdrawal with Prejudice of Complaint as to Calpine Energy Services, L.P. with the FERC. Pursuant to its respective notice each of the CPUC and the EOB withdrew all of their respective claims against CES which had been alleged in the above-for-mentioned complaints (EL02-60-000 and ELO2-62-000) concerning the justness and reasonableness of the terms under the long-term contracts with DWR. In addition, pursuant to its notice, the AG withdrew all claims as to CES in its complaint (EL02-71-000) wherein it had alleged that public utility sellers of energy and ancillary services to DWR and into markets operated by the California Independent System Operator and the California Power Exchange were not in compliance with their disclosure obligations under Section 205 of the Federal Power Act. The Company is involved in various other claims and legal actions arising out of the normal course of business. The Company does not expect that the outcome of these proceedings will have a material adverse effect on the Company's financial position or results of operations. 12. Operating Segments The Company's primary operating segments are electric generation and marketing; oil and gas production and marketing; and corporate activities and other. Electric generation and marketing includes the development, acquisition, ownership and operation of power production facilities, the sale of electricity and steam and electricity hedging and related activity. Oil and gas production and marketing includes the ownership and operation of gas fields, gathering systems and gas pipelines for internal gas consumption, third party sales and oil and gas hedging and related activity. Corporate activities and other consists primarily of financing activities, general and administrative costs and consolidating eliminations. Certain costs related to company-wide functions are allocated to each segment. However, interest on corporate debt is maintained at corporate and is not allocated to the segments. Due to the integrated nature of the business segments, estimates and judgments have been made in allocating certain revenue and expense items. The Company evaluates performance of these operating segments based upon several criteria including profits before tax.
ELECTRIC OIL AND GAS GENERATION PRODUCTION CORPORATE, OTHER AND MARKETING AND MARKETING AND ELIMINATIONS TOTAL ----------------------- ------------------- -------------------- ----------------------- 2002 2001 2002 2001 2002 2001 2002 2001 ---------- ---------- -------- -------- -------- -------- ---------- ---------- (in thousands) For the three months ended March 31, 2002 and 2001: Revenue......................... $1,534,143 $1,050,629 $236,348 $331,828 $(32,144) $(42,706) $1,738,347 $1,339,751 Income before taxes and extraordinary charge.......... (46,186) 127,791 13,064 116,535 (84,412) (36,718) (117,534) 207,608 Merger expense.................. -- -- -- 6,021 -- -- -- 6,021 Equipment cancellation cost..... 168,471 -- -- -- -- -- 168,471 --
ELECTRIC OIL AND GAS GENERATION PRODUCTION CORPORATE, OTHER AND MARKETING AND MARKETING AND ELIMINATIONS TOTAL ------------- ------------- ---------------- ----------- (in thousands) Total assets: March 31, 2002.................. $14,010,815 $3,714,004 $2,918,716 $20,643,535 December 31, 2001............... $12,572,848 $3,503,075 $5,253,629 $21,329,552
For the three months ended March 31, 2002 and 2001, there were intersegment revenues of approximately $36.7 million and $46.0 million, respectively. The elimination of these intersegment revenues, which primarily relate to the use of internally procured gas for the Company's power plants, are included in the Corporate and Other reporting segment. 13. California Power Market On February 25, 2002, both the CPUC and the EOB filed complaints under Section 206 of the Federal Power Act with FERC (EL02-60-000 and EL02-62-000, respectively) alleging that the prices and terms of the long-term contracts with DWR are unjust and unreasonable and counter to the public interest. Calpine was a respondent and the four long-term contracts entered into by Calpine were subject to the complaint. -20- On March 6, 2002, in accordance with the state legislation that authorized DWR to enter into the long-term power contracts, the CPUC issued a Rate Agreement, which dedicates a portion of the retail rate paid by electricity customers of the California investor-owned utilities to a fund to pay bondholders of bonds to be issued by DWR and to a fund to pay electricity suppliers such as Calpine. The proceeds from those bonds will be used in part to fund the Electric Power Fund established by the state legislation authorizing DWR to enter into long-term power contracts with the power suppliers whose recourse in the event of a default by DWR is to the Electric Power Fund. Proceeds from the bonds will also be used to repay the state of California General Fund. The bonds have not been issued, but representatives of the State have indicated that the bonds should be issued in the near future. FERC Investigation into California Wholesale Markets -- On February 13, 2002, FERC initiated an investigation of potential manipulation of electric and natural gas prices in the western United States. This investigation was initiated as a result of allegations that Enron Corp. through its affiliates used its market position to distort electric and natural gas markets in the West. The scope of the investigation is to consider whether as a result of any manipulation in the short-term markets for electric energy or natural gas or other undue influence on the wholesale markets by any party since January 1, 2000, the rates of the long-term contracts subsequently entered into in the West are potentially unjust and unreasonable. In connection with its investigation, FERC has, and may in the future, issue data requests seeking information regarding trading practices in California and the western electricity markets. FERC has stated that it may use the information gathered in connection with the investigation to determine how to proceed on any existing or future complaint brought under Section 206 of the Federal Power Act involving long-term power contracts entered into in the West since January 1, 2000, or to initiate a Federal Power Act Section 206 or Natural Gas Act Section 5 proceeding on its own initiative. 14. Subsequent Events On April 22, 2002, the Company announced that it had renegotiated CES' long-term power contracts with the DWR. The Office of the Governor, the CPUC, the EOB and the AG have endorsed the renegotiated contracts and have agreed to drop all pending claims against the Company and its affiliates, including withdrawing the complaint under Section 206 of the Federal Power Act recently filed by the CPUC and EOB with FERC and the CPUC and the EOB have agreed to terminate their efforts to seek refunds from the Company and its affiliates through FERC refund proceedings. In connection with the renegotiation, the Company has agreed to pay $6 million over three years to the AG to resolve any and all possible claims against the Company and its affiliates brought by the AG. The renegotiation includes the shortening of the duration of the two ten-year, baseload energy contracts by two years and of the 20-year peaker contract by ten years. These changes reduce DWR's long-term purchase obligations. In addition, CES agreed to reduce the energy price on one baseload contract from $61.00 to $59.60 per megawatt-hour, and to convert the energy portion of the peaker contract to gas index pricing from fixed energy pricing. CES has also agreed to deliver up to 12.2 million megawatt-hours of additional energy pursuant to the baseload energy contracts in 2002 and 2003. In connection with the renegotiation, CES has also agreed with DWR that DWR will have the right to assume and complete four of our projects currently planned for California and in the advanced development stage if the Company does not meet certain milestones with respect to each project assumed, provided that DWR reimburses the Company for all construction costs and certain other costs incurred by the Company to the date DWR assumes the relevant project. The negotiation resolved the dispute with DWR concerning payment of the capacity payment on the 495-megawatt peaking contract dated February 28, 2001. The contract provides that through December 31, 2002, CES may earn a capacity payment by committing to supply electricity to DWR from a source other than the peaker units designated in the contract. DWR made certain assertions challenging CES' right to substitute units or provide replacement energy and had withheld capacity payments in the amount of approximately $15.0 million since December 2001. As part of the renegotiation, the Company has received payment in full on these withheld capacity payments and will have the right to provide replacement capacity through December 31, 2002, based on the original contract terms. On May 2, 2002, each of the CPUC and the EOB filed a Notice of Partial Withdrawal with Prejudice of Complaint as to Calpine Energy Services, L.P. with the FERC in the EL02-60-000 and EL02-62-000 dockets, respectively. In April 2002 the Company entered into letters of intent for Wisconsin Public Service to purchase its 180-megawatt De Pere Energy Center and for Wisconsin Public Service to enter into a power purchase agreement for up to 235 megawatts of capacity and energy for 10 years from Calpine's Sherry Energy Center located near Marshfield, Wisconsin. Wisconsin Public Service will pay Calpine $120 million for the De Pere facility and termination of the existing power purchase agreement. The cost of the capacity purchases from the Sherry Energy Center will be approximately $250 million over the 10-year period. Wisconsin Public Service will be responsible for supplying the fuel to produce the energy it receives from the Sherry Energy Center. -21- On April 30, 2002, the Company completed a public offering of common stock of 66 million shares and priced the offering at $11.50 per share. The proceeds from the offering, after underwriting fees, were $734.3 million. Calpine has granted the underwriters an over-allotment option for an additional 9.9 million shares of its common stock, which may be exercised for up to 30 days. As of the date of this report, this option had not been exercised. Management cannot predict whether the underwriters will exercise this option in whole or in part. On April 30, 2002, the Company repurchased the remaining $685.5 million of Zero Coupons at par pursuant to a scheduled put provided for by the terms of the securities. Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations. In addition to historical information, this report contains forward-looking statements. Such statements include those concerning Calpine Corporation's ("the Company's") expected financial performance and its strategic and operational plans, as well as all assumptions, expectations, predictions, intentions or beliefs about future events. You are cautioned that any such forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties that could cause actual results to differ materially from the forward-looking statements such as, but not limited to, (i) unseasonable weather patterns that reduce demand for power and natural gas, (ii) systemic economic slowdowns, which can adversely affect consumption of power by businesses and consumers, (iii) the timing and extent of deregulation of energy markets and the rules and regulations adopted on a transitional basis with respect thereto, (iv) the timing and extent of changes in commodity prices and derivative values for energy, particularly natural gas and electricity, (v) 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, (vi) cost estimates are preliminary and actual costs may be higher than estimated, (vii) a competitor's development of a lower-cost gas-fired power plant, (viii) risks associated with marketing and selling power from power plants in the newly-competitive energy market, or (ix) 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. All information set forth in this filing is as of May 15, 2002, and Calpine undertakes no duty to update this information. Readers should carefully review the "Risk Factors" section in documents filed with the Securities and Exchange Commission. 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, 2002, as compared to the same period in 2001, primarily due to the consolidation of acquisitions and increased production as a result of acquired plants and bringing new plants under construction on line. Electricity revenue is composed of fixed capacity payments, which are not related to production, and variable energy payments, which are related to production. Capacity revenue includes, besides traditional capacity payments, other revenues such as reliability must run and ancillary service revenues. The information set forth under thermal and other revenue consists of host thermal sales and other revenue (revenues in thousands).
Three months ended March 31, (in thousands, except ---------------------------- production and pricing data) 2002 2001 ----------- ---------- Power Plants: Electricity and steam ("E&S") revenues: Energy ............................................. $ 513,103 $ 435,382 Capacity ........................................... 75,391 117,727 Thermal and other .................................. 31,685 42,050 ----------- ---------- Subtotal ........................................... $ 620,179 $ 595,159 Spread on sales of purchased power (1) ............... 93,139 (1,348) ----------- ---------- Adjusted E&S revenues ................................ $ 713,318 $ 593,811 Megawatt hours produced .............................. 14,714,000 7,239,000 All-in electricity price per megawatt hour generated . $ 48.48 $ 82.03
_________ (1) From hedging, balancing and optimization activities related to our generating assets. The spread on trading activities is excluded. -22- Megawatt hours produced at the power plants increased 103.3% for the three months ended March 31, 2002 as compared to the same period in 2001. This was primarily due to the addition of power plants that were either acquired or commenced commercial operation subsequent to March 31, 2001. Lower average market prices caused the all-in electricity price per megawatt hour generated to decrease between periods. Results of Operations Set forth below is a table summarizing the dollar amounts and percentages of our total revenue for the three months ended March 31, 2002 and 2001 that represent purchased power and purchased gas sales and the costs we incurred to purchase the power and gas that we resold during these periods (in thousands, except for percentage data):
THREE MONTHS ENDED MARCH 31, ----------------------------- 2002 2001 ---------- ----------- Total revenue .............................. $1,738,347 $1,339,751 Sales of purchased power ................... 908,301 453,602 As a percentage of total revenue ........... 52.3% 33.9% Sale of purchased gas ...................... 132,158 129,172 As a percentage of total revenue ........... 7.6% 9.6% Total cost of revenue ("COR") .............. 1,560,383 1,064,183 Purchased power expense .................... 815,005 456,266 As a percentage of total COR ............... 52.2% 42.9% Purchased gas expense ...................... 123,694 118,628 As a percentage of total COR ............... 7.9% 11.1%
The accounting requirements under Staff Accounting Bulletin ("SAB") 101, "Revenue Recognition in Financial Statements" and EITF 99-19, "Reporting Revenue Gross as a Principal versus Net as an Agent" require us to show most of our hedging contracts on a gross basis (as opposed to netting sales and cost of revenue). The primary reason for the significant increase in these sales and cost of revenue in 2002 as compared with 2001 is the growth of our generation activity in 2002 as compared with 2001 and the corresponding increase in hedging, balancing, optimization, and trading activities. Rules in effect throughout 2002 and 2001 associated with the NEPOOL market in New England require that all power generated in NEPOOL be sold directly to the Independent System Operator ("ISO") in that market; we then buy from the ISO to serve our customer contracts. Generally accepted accounting principles in the United States of America require us to account for this activity, which applies to three of our merchant generating facilities, as the aggregate of two distinct sales and one purchase. This gross basis presentation increases revenues but not gross profit. The table below details the financial extent of our transactions with NEPOOL for the period indicated. The decrease in 2002 is primarily due to lower prices in 2002, partially offset by increased volume.
THREE MONTHS ENDED MARCH 31, ------------------ (in thousands) 2002 2001 ------- ------- Sales into NEPOOL ISO from power we generated ............ $50,581 $59,564 Sales into NEPOOL ISO from hedging and other activity .... 24,657 34,956 ------- ------- Total sales into NEPOOL ................................ $75,238 $94,520 Total purchases from NEPOOL ISO .......................... $75,834 $85,243
Three Months Ended March 31, 2002, Compared to Three Months Ended March 31, 2001. Revenue -- Total revenue increased to $1,738.3 million for the three months ended March 31, 2002, compared to $1,339.8 million for the same period in 2001. Electric generation and marketing revenue increased to $1,532.6 million in 2002 compared to $1,050.1 million in 2001. Sales of purchased power grew by $454.7 million due to increased price hedging, balancing, optimization and trading activity as a result of the growth of our subsidiary, Calpine Energy Services, LP ("CES") and our operating plant portfolio during the three months ended March 31, 2002. Approximately $25.0 million of the $482.5 million variance was due to electricity and steam sales, which increased due to our growing portfolio. Generation more than doubled but pricing dropped almost by half to moderate revenue growth. Our revenue for the period ended March 31, 2002, includes the consolidated results of additional facilities that we acquired or -23- completed construction on subsequent to March 31, 2001. We also recognized a $2.9 million increase in mark-to-market gains on power derivatives to $4.2 million in 2002. Oil and gas production and marketing revenue decreased to $199.6 million in 2002 compared to $285.9 million in 2001. The decrease is primarily due to an $89.2 million decrease in oil and gas sales to third parties because of much lower average pricing in 2002. Cost of revenue -- Cost of revenue increased to $1,560.4 million in 2002 compared to $1,064.2 million in 2001. Approximately $358.7 million of the $496.2 million increase relates to the cost of power purchased by our energy services organization due to increased price hedging, balancing, optimization and trading activities. Fuel expense increased 29.5%, from $257.0 million in 2001 to $332.8 million in 2002, due to a doubling of megawatt hours generated as offset by significantly lower gas prices in 2002. Plant operating expense increased by 36.3% from $84.5 million to $115.2 million but, expressed per mwh of generation, decreased from $11.67/mwh to $7.83/mwh as economies of scale are being realized due to the increase in the average size of our plants. Depreciation, depletion and amortization expense increased by 44.3%, from $72.0 million to $103.9 million, due primarily to additional power facilities in consolidated operations at March 31, 2002, as compared to the same period in 2001. Project development expense -- Project development expense decreased 28.4% as a result of a deceleration of our efforts in identifying new development opportunities due to overall market and liquidity issues. Equipment cancellation cost -- The pre-tax equipment cancellation charge of $168.5 million in the three months ended March 31, 2002 was as a result of the turbine order cancellations and the cancellation of certain other equipment based primarily on forfeited prepayments to date and an immaterial cash payment pursuant to contract terms. General and administrative expense -- General and administrative expense increased 67.0% to $60.3 million for the three months ended March 31, 2002, as compared to $36.1 million for the same period in 2001. The increase was attributable to continued growth in personnel and associated overhead costs necessary to support the overall growth in our operations and due to recent acquisitions, including power facilities and natural gas operations. General and administrative expense expressed per mwh of generation decreased to $4.10/mwh in 2002 from $4.98/mwh in 2001. Interest expense -- Interest expense increased 208.0% to $61.3 million for the three months ended March 31, 2002, from $19.9 million for the same period in 2001. Interest expense increased primarily due to the issuance of the Convertible Notes and additional senior notes in 2001. The associated incremental interest expense was partially offset by interest capitalized in connection with our growing construction portfolio. Interest capitalized increased from $104.0 million in the three months ended 2001 to $163.1 million in the three months ended 2002. Interest income -- Interest income decreased to $12.2 million for the three months ended March 31, 2002, compared to $19.4 million for the same period in 2001. This decrease is due to lower interest rates in 2002. Other income (expense) -- Other income (expense) increased to $9.1 million in 2002 from $5.7 million in 2001 primarily due to the $9.7 million gain on the sale of our 11.4% interest in the Lockport Power Plant. Provision for income taxes -- The effective income tax rate was approximately 35.0% and 42.9% for the three months ended March 31, 2002 and 2001, respectively. The decrease in rates was due to our expansion into Canada and the United Kingdom and our cross border financings, which reduced our effective blended tax rates. The 35% rate in 2002 was the same as the full year rate for 2001. Extraordinary charge, net -- The $2.1 million charge in 2002 (net of tax of $1.4 million) represents the repurchase of $192.5 million aggregate principal amount of our Zero Coupon Convertible Debentures Due 2021 ("Zero Coupons"), which was comprised primarily of a $4.8 million gain from the repurchase of the Zero Coupons at a discount, partially offset by a loss due to the write-off of unamortized deferred financing costs. Selected Balance Sheet Information Unconsolidated Investments in Power Projects -- Although our preference is to own 100% of the power plants we acquire or develop, there are situations when we take less than 100% ownership. Reasons why we may take less than a 100% interest in a power plant may include, but are not limited to: (a) our acquisitions of other IPP's such as Cogeneration Corporation of America in 1999 and SkyGen Energy LLC in 2000 in which minority interest projects were included in the portfolio of assets owned by the acquired entities (Grays Ferry Power Plant (40% now owned by Calpine) and Androscoggin Energy Center (32.3% now owned by Calpine) respectively); (b) opportunities to co-invest with non-regulated subsidiaries of regulated electric utilities, which under the Public Utility Regulatory Policies Act of 1978, as amended are restricted to 50% ownership of cogeneration qualifying facilities -- such as our investment in Gordonsville -24- Power Plant (50% owned by Calpine and 50% owned by Edison Mission Energy, which is wholly-owned by Edison International Company); and (c) opportunities to invest in merchant power projects with partners who bring marketing, funding, permitting or other resources that add value to a project. An example of this is Acadia Energy Center, which is under construction in Louisiana (50% owned by Calpine and 50% owned by Cleco Midstream Resources, an affiliate of Cleco Corporation). None of our equity investment projects have nominal carrying values as a result of material recurring losses. Further, there is no history of impairment in any of these investments. Accumulated other comprehensive loss -- Accumulated other comprehensive loss at March 31, 2002 decreased from $(226.6) million at December 31, 2001 to $(208.0) million at March 31, 2002. The change resulted from unrealized gains on derivatives designated as cash flow hedges of $43.8 million, net of amounts reclassified to net loss and income taxes, and foreign currency translation losses of $25.2 million. See Note 8 for further information. Liquidity and Capital Resources General -- The latter half of 2001, and particularly the fourth quarter, saw a significant contraction in the availability of capital for participants in the energy sector. This was due to a range of factors, including uncertainty arising from the collapse of Enron. While we have continued to be able to access the capital and bank credit markets, as discussed below, we recognize that terms of available financing in the future may not be attractive to us. To protect against this possibility, we have scaled back our capital expenditure program for 2002 and 2003 to enable us to conserve our available capital resources, but remain ready to access the capital markets as attractive opportunities arise. To date, we have obtained cash from our operations; borrowings under our credit facilities and other working capital lines; sale of debt, equity, trust preferred securities and convertible debentures; proceeds from sale/leaseback transactions and project financing. We have utilized this cash to fund our operations, service debt obligations, fund acquisitions, develop and construct power generation facilities, finance capital expenditures, support our hedging, balancing and optimization activities at CES, and meet our other cash and liquidity needs. Our business is capital intensive. Our ability to capitalize on growth opportunities is dependent on the availability of capital on attractive terms. Our strategy is also to reinvest our cash from operations into our business development and construction program, rather than to pay cash dividends. Cash Flow Activities -- The following table summarizes our cash flow activities for the periods indicated:
THREE MONTHS ENDED MARCH 31, ---------------------------- (in thousands) 2002 2001 ----------- ----------- Beginning cash and cash equivalents ............... $ 1,525,417 $ 596,077 Net cash provided by (used in): Operating activities ............................ 345,945 35,555 Investing activities ............................ (1,301,613) (898,635) Financing activities ............................ (158,486) 1,137,082 Effect of exchange rates changes on cash and cash equivalents................... (491) -- ----------- ----------- Net increase (decrease) in cash and cash equivalents .......................... (1,114,645) 274,002 ----------- ----------- Ending cash and cash equivalents .................. $ 410,772 $ 870,079 =========== ===========
Operating activities for the three months ended March 31, 2002 provided net cash of $345.9 million, compared to $35.6 million for the three months ended March 31, 2001. The cash provided by operating activities for the three months ended March 31, 2002 consisted primarily of a $592.2 million decrease in operating assets, mainly in derivative activity, accounts receivable and other current assets. The decrease in accounts receivable was primarily due to the collection from escrow of $222.3 million for the PG&E past due pre-petition receivables that were sold at a discount to a third party in December 2001. The decrease in other current assets is primarily due to reducing CES margin deposits and replacing them with letters of credit. This was offset by a $421.2 million decrease in operating liabilities, primarily related to derivative activity. Investing activities for the three months ended March 31, 2002 consumed net cash of $1.3 billion, primarily due to $1.3 billion for construction costs and capital expenditures including gas turbine generator costs and associated capitalized interest, $23.1 million of advances to joint ventures including associated capitalized interest for investments in power projects under construction, $23.8 million of capitalized project development costs including associated capitalized interest. This was partially offset by a $16.9 million decrease in restricted cash and a $12.9 million decrease in notes receivable. -25- Financing activities for the three months ended March 31, 2002 consumed $158.5 million of net cash consisting of $187.7 million for repurchase of Zero Coupons, $73.7 million for the repayment of notes payable and borrowings under lines of credit, $92.2 million for repayments of project financing and $31.5 million of additional financing costs. This was partially offset by $100.0 million of proceeds from the issuance of the Convertible Senior Notes Due 2006 pursuant to exercise of the initial purchasers' option and $122.9 million of proceeds from project financing. We continue to evaluate current and forecasted cash flow as a basis for financing operating requirements and capital expenditures. We believe that we will have sufficient liquidity from cash flow from operations, borrowings available under the lines of credit, access to the capital markets and working capital to satisfy all obligations under outstanding indebtedness, to finance anticipated capital expenditures and to fund working capital requirements for the next twelve months. PG&E and Enron Bankruptcies -- As stated above, in January 2002 we received the cash from escrow related to the December 2001 sale of past due pre-bankruptcy PG&E receivables to a third party. As discussed in Note 9 of the Notes to Consolidated Condensed Financial Statements, there is considerable uncertainty surrounding the Enron bankruptcy. Regardless of the resolution of the current situation, we believe, based on legal analysis, that we have no net collection exposure to Enron. Nevada Power and Sierra Pacific Resources -- During the first quarter of 2002, two subsidiaries of Sierra Pacific Resources Corporation, Nevada Power Company ("NPC") and Sierra Pacific Resources ("SPR"), received credit downgrades to sub-investment grades from the major credit rating agencies. The credit downgrades resulted from short-term liquidity problems created when the Public Utilities Commission of Nevada disallowed a rate adjustment requested by NPC to cover the increased cost of buying power during the 2001 energy crisis. NPC and SPR have requested that their power suppliers extend payment terms to help them overcome their short-term liquidity problems. As of March 31, 2002, we had net collection exposures of approximately $30.7 million and $21.3 million with NPC and SPR, respectively. Our exposures include open forward power position contracts that are reported at fair value in the Company's balance sheet as well as receivable and payable balances relating to settled power deliveries. We are continuing to monitor our exposure and its effect on our financial condition. CES Margin Deposits and Other Credit Support -- As of March 31, 2002, CES had $177.2 million in cash on deposit as margin deposits with third parties related to its business activities and letters of credit outstanding in support of CES business activities of $365.4 million. As of December 31, 2001, CES had deposited $345.5 million in cash as margin deposits with third parties related to its business activities and letters of credit outstanding in support of CES business activities of $259.4 million. The Company is evaluating various relationships with potential partners to strengthen its ability to conduct risk management activities and to support the credit requirements of its trading activities. While we believe that we have adequate liquidity to support CES' operations at this time, it is difficult to predict how these various factors will develop in 2002 and beyond. Therefore, it is difficult to predict the amount of credit support that the Company may need to provide as part of its business operations. Working Capital Position -- At March 31, 2002, working capital, defined as current assets less current liabilities, was $(582.9) million. This negative position was primarily the result of the $685.5 million of Zero Coupons, which were classified as a current liability until repaid in full on April 30, 2002. Letter of credit facilities -- At March 31, 2002, we had approximately $776.4 million in letters of credit outstanding under various credit support facilities, including facilities related to CES risk management activities. The remainder related to other operational and construction activities. Of the total letters of credit, $156.0 million was temporary coverage in excess of requirements due to transitioning certain of the letters of credit under the $400 million revolver to the new $1.0 billion revolver. At December 31, 2001, we had $642.5 million in letters of credit outstanding, including facilities relating to CES risk management activities. Revised Capital Expenditure Program -- Following a comprehensive review of our power plant development program, we announced in January 2002 the adoption of a revised capital expenditure program, which contemplates the completion of 27 power projects (representing 15,200 MW) then under construction. Three of these facilities achieved full or partial commercial operations as of March 31, 2002. Construction of an additional 34 advanced-stage development projects (representing 15,100 MW) will be placed on "hot standby" following completion of advanced development activities pending further review, reducing previously forecasted 2002 capital spending by as much as $2 billion. Construction of these advanced stage development projects is expected to proceed when there is an established market need for additional generating resources at prices that will allow us to meet our established investment criteria, and when capital is available to us on attractive terms. However, our entire development and construction program is flexible and subject to continuing review and revision based upon such criteria. -26- On March 12, 2002, we announced a new turbine program that reduces previously forecasted capital spending by approximately $1.2 billion in 2002 and $1.8 billion in 2003. The revision includes adjusted timing of turbine delivery and related payment schedules and also cancellation orders. As a result of these turbine cancellations and other equipment cancellations, we recorded a pre-tax charge of $168.5 million in the first quarter of 2002. Capital Availability -- Notwithstanding recent uncertainties in the domestic energy and capital markets, we have continued to raise substantial capital. In the first quarter of 2002, we closed a $1.6 billion secured working capital credit facility (see below for more information). We also issued in separate closings in December 2001 and January 2002 $1.2 billion in aggregate principal amount of Convertible Senior Notes due 2006. Proceeds from this offering and cash from general working capital were used to fully retire the Zero Coupons that remained outstanding at December 31, 2001. On April 30, 2002, we completed a public offering of common stock of 66 million shares and priced the offering at $11.50 per share. The proceeds after underwriting fees totaled $734.3 million. We granted the underwriters an over-allotment option for an additional 9.9 million shares of our common stock, which may be exercised for up to 30 days. As of the date of this report, this option had not been exercised. Management cannot predict whether the underwriters will exercise this option in whole or in part. The proceeds from the offering are expected to be used to repay debt and for general corporate purposes. In March 2002, we entered into a letter of intent with ING Bank on the debt portion of a proposed California peaker sale/leaseback, including 11 California peaker facilities. This transaction is expected to generate $500 million of cash that will be received throughout 2002 as the power facilities enter commercial operation. New Working Capital Credit Agreement -- In March 2002, the Company closed a new secured credit agreement comprised of (a) a $1.0 billion revolving credit facility expiring on May 24, 2003 and (b) a two-year term loan facility for up to $600 million, which as previously reported, was only to be made available to the Company upon satisfaction of certain conditions to borrowing on or before June 8, 2002. On May 10, 2002, the Company borrowed $500 million of the term loan facility and, subject to certain conditions, may borrow the remaining $100 million in one or two remaining tranches on or before June 8, 2002. At the March 2002 closing, the Company also amended its existing $400 million revolving credit agreement to provide, among other things, security for borrowings under that agreement. The security for the revolving and term loan facilities as originally provided included (a) a pledge of the capital stock of the Company's subsidiary holding, directly or indirectly, (i) the interests in its natural gas properties, (ii) the Saltend power plant located in the United Kingdom and (iii) the Company's equity investment in nine U.S. power plants, and (b) a pledge by certain of the Company's subsidiaries of a total of 65% of the capital stock of Calpine Canada Energy Ltd. As part of the recent funding of the $500 million term loan, the Company expanded the security for the revolving credit and term loan facilities under both the $1.6 billion and the $400 million credit agreements by pledging to the lenders substantially all of the Company's remaining first tier domestic subsidiaries (excluding CES). Credit Considerations -- On March 12, 2002, Fitch downgraded our senior unsecured debt to BB. On March 25, 2002, Standard & Poor's downgraded our corporate credit rating from BB+ to BB and our investor unsecured debt from BB+ to B+. Many other issuers in the power generation sector have also been downgraded by one or more of the ratings agencies during this period. Such downgrades can have a negative impact on our liquidity by reducing attractive financing opportunities and increasing the amount of collateral required by trading counterparties. Off-Balance Sheet Commitments -- In accordance with SFAS No. 13 and SFAS No. 98, "Accounting for Leases" our operating leases are not reflected on our balance sheet. We have also entered into several sale/leaseback transactions. All counterparties in these transactions are third parties that are unrelated to Calpine. The sale/leaseback transactions involving Tiverton, Rumford, South Point, Broad River, and RockGen utilize special-purpose entities formed by the equity investors with the sole purpose of owning a power generation facility. Some of the Company's operating leases contain customary restrictions on dividends, additional debt and further encumbrances similar to those typically found in project finance instruments. Calpine has no ownership or other interest in any of these special-purpose entities. In accordance with APB Opinion No. 18 "The Equity Method of Accounting For Investments in Common Stock" and FASB Interpretation No. 35, "Criteria for Applying the Equity Method of Accounting for Investments in Common Stock (An Interpretation of APB Opinion No. 18)," the debt on the books of our unconsolidated investments in power projects is not reflected on our balance sheet. At March 31, 2002, investee debt is approximately $673.0 million. Based on our pro rata ownership share of each of the investments, our share would be approximately $248.8 million. However, all such debt is non-recourse to us. For the Aries Power Plant construction debt, we and Aquila Energy, a wholly owned subsidiary of Aquila Inc, have provided support arrangements until construction is completed to cover cost overruns, if any. -27- Performance Metrics In understanding our business, we believe that certain performance metrics are particularly important. These include: o Average gross profit margin based on pro forma (non-GAAP) revenue and pro forma (non-GAAP) cost of revenue. A high percentage of our revenue consists of CES hedging, balancing, optimization, and trading activity undertaken primarily to enhance the value of our generating assets (see "Marketing, Hedging, Optimization, and Trading" subsection of the Business Section of our 2001 Form 10-K). CES's hedging, balancing, optimization, and trading activity is primarily accomplished by buying and selling electric power and buying and selling natural gas or by entering into gas financial instruments such as exchange-traded swaps or forward contracts. Under SAB No. 101 and EITF No. 99-19, we must show the purchases and sales of electricity and gas on a gross basis in our statement of operations when we act as a principal, take title to the electricity and gas we purchase for resale, and enjoy the risks and rewards of ownership. This is notwithstanding the fact that the net gain or loss on certain financial hedging instruments, such as exchange-traded forward contracts for natural gas, is shown as a net item in our GAAP financials. Because of the inflating effect on revenue of much of our hedging, balancing, optimization, and trading activity, we believe that revenue levels and trends do not reflect our performance as accurately as gross profit, and that it is analytically useful to look at our results on a pro forma, non-GAAP basis with all hedging, balancing, optimization, and trading activity netted. This analytical approach nets the sales of purchased power with purchased power expense (with the exception of net realized sales and expenses on electrical trading activity, which is shown on a net basis in sales of purchased power) and includes that net amount as an adjustment to electricity and steam ("E&S") revenue for our generation assets. Similarly, we believe that it is analytically useful to net the sales of purchased gas with purchased gas expense (with the exception of net realized sales and expenses on gas trading activity, which is shown on a net basis in sales of purchased gas) and include that net amount as an adjustment to cost of oil and natural gas burned by power plants, a component of fuel expense. This allows us to look at all hedging, balancing, optimization, and trading activity consistently (net presentation) and better understand our performance trends. It should be noted that in this non-GAAP analytical approach, total gross profit does not change from the GAAP presentation, but the gross profit margins as a percent of revenue do differ from corresponding GAAP amounts because the inflating effects on our revenue of hedging, balancing, optimization, and trading activities are removed. o Average availability and average capacity factor or operating rate. Availability represents the percent of total hours during the period that our plants were available to run after taking into account the downtime associated with both scheduled and unscheduled outages. The capacity factor, sometimes called operating rate, is calculated by dividing (a) total megawatt hours generated by our power plants (excluding peakers) by multiplying (b) the weighted average megawatts in operation during the period by (c) the total hours in the period. The capacity factor is thus a measure of total actual generation as a percent of total potential generation. If we elect not to generate during periods when electricity pricing is too low or gas prices too high to operate profitably, the capacity factor will reflect that decision as well as both scheduled and unscheduled outages due to maintenance and repair requirements. o Average heat rate for gas-fired fleet of power plants expressed in Btu's of fuel consumed per kWh generated. We calculate the average heat rate for our gas-fired power plants (excluding peakers) by dividing (a) fuel consumed in Btu's by (b) kilowatt-hours generated. The resultant heat rate is a measure of fuel efficiency, so the lower the heat rate, the better. We also calculate a "steam-adjusted" heat rate, in which we adjust the fuel consumption in Btu's down by the equivalent heat content in steam or other thermal energy exported to a third party, such as to steam hosts for our cogeneration facilities. Our goal is to have the lowest average heat rate in the industry. o Average all-in realized electric price expressed in dollars per MWh generated. We calculate the all-in realized electric price per MWh generated by dividing (a) adjusted E&S revenue, which includes capacity revenues, energy revenues, thermal revenues and the spread on sales of purchased electricity for hedging, balancing, and optimization activity, by (b) total generated MWh's in the period. o Average cost of natural gas expressed in dollars per millions of Btu's of fuel consumed. At Calpine, the fuel costs for our gas-fired power plants are a function of the price we pay for fuel purchased and the results of the fuel hedging, balancing, and optimization activities by CES. Accordingly, we calculate the cost of natural gas per millions of Btu's of fuel consumed in our power plants by dividing (a) adjusted cost of oil and natural gas burned by power plants which includes the cost of fuel consumed by our plants (adding back cost of intercompany "equity" gas from Calpine Natural Gas, which is eliminated in consolidation), and the spread on sales of purchased gas for hedging, balancing, and optimization activity by (b) the heat content in millions of Btu's of the fuel we consumed in our power plants for the period. -28- o Average spark spread expressed in dollars per MWh generated. Our risk management activities focus on managing the spark spread for our portfolio of power plants, the spread between the sales price for electricity generated and the cost of fuel. We calculate the spark spread per MWh generated by subtracting (a) adjusted cost of oil and natural gas burned by power plants from (b) adjusted E&S revenue and dividing the difference by (c) total generated MWh's in the period. The table below presents, side-by-side, both our GAAP and pro forma non-GAAP netted revenue, costs of revenue and gross profit showing the purchases and sales of electricity and gas for hedging, balancing, optimization, and trading activity on a net basis. It also shows the other performance metrics discussed above.
Non-GAAP Netted GAAP Presentation Presentation Three Months Ended March 31, Three Months Ended March 31, ---------------------------- ---------------------------- 2002 2001 2002 2001 ----------- ----------- ----------- ----------- (In thousands) Revenue, Cost of Revenue and Gross Profit Revenue: Electric generation and marketing revenue Electricity and steam revenue(1) ................................ $ 620,179 $ 595,159 $ 713,318 $ 593,811 Sales of purchased power(1) ..................................... 908,301 453,602 157 (1,316) Electric power derivative mark-to-market gain .................... 4,166 1,306 4,166 1,306 ----------- ----------- ----------- ----------- Total electric generation and marketing revenue .................... 1,532,646 1,050,067 717,641 593,801 Oil and gas production and marketing revenue Oil and gas sales ............................................... 67,488 156,687 67,488 156,687 Sales of purchased gas(1) ....................................... 132,158 129,172 6,072 3,169 ----------- ----------- ----------- ----------- Total oil and gas production and marketing revenue ................. 199,646 285,859 73,560 159,856 Income from unconsolidated investments in power projects ........... 1,444 563 1,444 563 Other revenue ...................................................... 4,611 3,262 4,611 3,262 ----------- ----------- ----------- ----------- Total revenue ................................................. 1,738,347 1,339,751 797,256 757,482 ----------- ----------- ----------- ----------- Cost of revenue: Electric generation and marketing expense Plant operating expense ......................................... 115,157 84,460 115,157 84,460 Royalty expense ................................................. 4,155 11,009 4,155 11,009 Purchased power expense(1) ...................................... 815,005 456,266 -- -- ----------- ----------- ----------- ----------- Total electric generation and marketing expense .................... 934,317 551,735 119,312 95,469 Oil and gas production and marketing expense Oil and gas production expense .................................. 26,940 34,283 26,940 34,283 Purchased gas expense(1) ........................................ 123,694 118,628 -- -- ----------- ----------- ----------- ----------- Total oil and gas production and marketing expense ................. 150,634 152,911 26,940 34,283 Fuel expense Cost of oil and natural gas burned by power plants(1) ........... 326,443 264,563 324,051 257,188 Natural gas derivative mark-to-market loss (gain) ............... 6,392 (7,549) 6,392 (7,549) ----------- ----------- ----------- ----------- Total fuel expense ................................................. 332,835 257,014 330,443 249,639 Depreciation, depletion and amortization expense ................... 103,873 72,013 103,873 72,013 Operating lease expense ............................................ 36,134 28,011 36,134 28,011 Other expense ...................................................... 2,590 2,499 2,590 2,499 ----------- ----------- ----------- ----------- Total cost of revenue ......................................... 1,560,383 1,064,183 619,292 481,914 ----------- ----------- ----------- ----------- Gross profit .................................................... $ 177,964 $ 275,568 $ 177,964 $ 275,568 =========== =========== =========== =========== Gross profit margin ............................................. 10% 21% 22% 36%
-29-
Non-GAAP Netted Presentation Three Months December 31, -------------------------- 2002 2001 -------- -------- (In thousands) Other Non-GAAP Performance Metrics Average availability and capacity factor: Average availability ........................................................................... 94% 92% Average capacity factor or operating rate based on total hours (excluding peakers) ............. 71% 69% Average heat rate for gas-fired power plants (excluding peakers) (Btu's/kWh): Not steam adjusted ............................................................................. 8,173 8,670 Steam adjusted ................................................................................. 7,374 7,506 Average all-in realized electric price: Adjusted electricity and steam revenue (in thousands) .......................................... $713,318 $593,811 MWh generated (in thousands) ................................................................... 14,714 7,239 Average all-in realized electric price per MWh ................................................. $ 48.48 $ 82.03 Average cost of natural gas: Cost of oil and natural gas burned by power plants (in thousands) .............................. $324,051 $257,188 Fuel cost elimination .......................................................................... 36,702 43,216 -------- -------- Adjusted cost of oil and natural gas burned by power plants .................................... $360,753 $300,404 MMBtu of fuel consumed by generating plants (in thousands) ..................................... 106,524 47,992 Average cost of natural gas per MMBtu .......................................................... $ 3.39 $ 6.26 MWh generated (in thousands) ................................................................... 14,714 7,239 Average cost of oil and natural gas burned by power plants per MWh ............................. $ 24.52 $ 41.50 Average spark spread: Adjusted electricity and steam revenue (in thousands) .......................................... $713,318 $593,811 Less: Adjusted cost of oil and natural gas burned by power plants (in thousands) ............... 360,753 300,404 -------- -------- Spark spread (in thousands) .................................................................... $352,565 $293,407 MWh generated (in thousands) ................................................................... 14,714 7,239 Average spark spread per MWh ................................................................... $ 23.96 $ 40.53
The non-GAAP presentation above also facilitates a look at the total "trading" activity impact on gross profit. For the three months ended March 31, 2002 and 2001, trading activity consisted of:
Three Months Ended March 31, ------------------------ 2002 2001 ------- -------- ELECTRICITY Electric generation and marketing revenue Realized gain (loss) Sales of purchased power .............................. $ 157 $ (1,316) Unrealized Electric power derivative mark-to-market gain ......... 4,166 1,306 ------- -------- Subtotal........................................................................ $ 4,323 $ (10) GAS Oil and gas production and marketing revenue Realized gain (loss) Sales of purchased gas ................................ $ 6,072 $ 3,169 Fuel Expense Unrealized Natural gas derivative mark-to-market gain (loss)...... (6,392) 7,549 ------- -------- Subtotal........................................................................ $ (320) $ 10,718
Three Months Three Months Ended Percent of Ended Percent of March 31, Gross March 31, Gross 2002 Profit 2001 Profit ------------ ---------- ------------ ---------- Total trading activity gain....................... $ 4,003 2.2% $ 10,708 3.9% Realized gain (loss).............................. $ 6,229 3.5% $ 1,853 0.7% Unrealized (mark-to-market) gain (loss)(2)........ $ (2,226) (1.3)% $ 8,855 3.2%
__________ -30- (1) Following is a reconciliation of GAAP to non-GAAP presentation further to the narrative set forth under this Performance Metrics section ($ in thousands):
To Net Hedging, Balancing & To Net Netted GAAP Optimization Trading Non-GAAP Balance Activity Activity Balance ---------- ------------ --------- ---------- Three months ended March 31, 2002 Electricity and steam revenue.......................... $ 620,179 $ 93,139 $ -- $ 713,318 Sales of purchased power............................... 908,301 (842,606) (65,538) 157 Sales of purchased gas................................. 132,158 (132,158) 6,072 6,072 Purchased power expense................................ 815,005 (749,467) (65,538) -- Purchased gas expense.................................. 123,694 (123,694) -- -- Cost of oil and natural gas burned by power plants..... 326,443 (8,464) 6,072 324,051 Three months ended March 31, 2001 Electricity and steam revenue.......................... $ 595,159 $ (1,348) $ -- $ 593,811 Sales of purchased power............................... 453,602 (443,482) (11,436) (1,316) Sales of purchased gas................................. 129,172 (129,172) 3,169 3,169 Purchased power expense................................ 456,266 (444,830) (11,436) -- Purchased gas expense.................................. 118,628 (118,628) -- -- Cost of oil and natural gas burned by power plants..... 264,563 (10,544) 3,169 257,188
(2) For the three months ended March 31, 2002, the mark-to-market gains shown above as "trading" activity include a net loss on hedge ineffectiveness of $(2,818), consisting of an ineffectiveness loss on power hedges of $(222), an ineffectiveness loss on crude oil costless collar arrangements of $(5,042) and an ineffectiveness gain on gas hedges of $2,446. For the three months ended March 31, 2001, the mark-to-market gains shown above as "trading" activity include a net loss on hedge ineffectiveness of $(691), consisting of an ineffectiveness loss on power hedges of $1,217 and an ineffectiveness gain on gas hedges of $526. Outlook At May 15, 2002, we had 22 projects under construction, representing an additional 13,412 megawatts of net capacity. We have also announced plans to develop 34 additional power generation projects, representing a net capacity of 15,100 megawatts. Our new $2 billion revolving credit and term loan facilities and April 2002 issuance of 66 million shares of common stock have ameliorated our 2002 liquidity concerns. We have made significant progress in reducing our operations and maintenance costs and general and administrative expenses per unit of electrical generation as we have doubled our generation of electricity from the first quarter of 2001 to the first quarter of 2002. Our outlook for 2002 is stable and profitable, but we recognize that the pace of pricing and spark spread improvement is dependent on the nation's economic recovery and on weather, particularly in the summer and winter periods. We remain confident in our strategy, as outlined in our 2001 Form 10-K, and optimistic about our future performance. Overview Summary of Key Activities Power Plant Development and Construction:
Date Project Description ---- ------------------------------------- ---------------------------- 1/02 Gilroy Peaking Energy Center Commercial operation 2/02 Magic Valley Generating Station Commercial operation 2/02 King City Energy Center (Peaker Unit) Commercial operation 3/02 Aries Power Project Partial commercial operation 4/02 Island Cogeneration Commercial operation 4/02 Channel Energy Center Combined-cycle operation
Finance Note Repayments:
Date Amount Description ------- ------------- ------------------------------ 3/13/02 $64.8 million Michael Petroleum Note Payable 4/1/02 $10.0 million Silverado Note Payable
-31- Repurchases of Zero-Coupon Convertible Debentures Due 2021:
Date Amount --------------------------------------- -------------- January 2, 2002, through April 30, 2002 $878.0 million
Calpine Corporation's Sale of 4% Convertible Senior Notes Due 2006 and Common Stock:
Date Offering Description Use of Proceeds ------- ------------------- --------------------------- ------------------------------- 1/3/02 $100 million Conversion price of $18.07 For general corporate purposes per common share 4/30/02 $759 million, gross 66 million shares at $11.50 For general corporate purposes, per share including debt repayment
Working Capital Credit Facility:
Date Amount Security Use of Proceeds ------- ------------ ----------------------------------- ------------------------------- 3/12/02 $2.0 billion Natural gas properties, Saltend Finance capital expenditures and Power Plant, our equity other general corporate purposes investment in 9 U.S. power plants, 65% of the capital stock of Calpine Canada Ltd., and our remaining first tier domestic subsidiaries (excluding CES)
Turbine Cancellations:
Date of Reduction in Capital Announcement Spending Earnings Effect ------------ -------------------- ------------------------------------- 3/12/02 $1.2 billion in 2002 $168.5 million pre-tax charge in 2002 $1.8 billion in 2003
Other:
Date Description ------- ------------------------------------------- 1/02 Letter of intent for sale/leaseback of 11 California peaker facilities 3/12/02 Fitch, Inc. lowered the credit rating on senior unsecured debt from BB+ to BB, and it lowered the rating on convertible trust preferred securities from BB- to B 3/25/02 Standard & Poor's downgraded corporate credit rating from BB+ to BB, and senior unsecured debt from BB+ to B+ 3/29/02 Sale of 11.4% interest in Lockport Power Plant for $27.3 million 4/2/02 Proposed sale of De Pere Energy Center for $120 million, including termination of existing power purchase agreement 4/22/02 Renegotiation of California Department of Water Resources long-term power contracts
California Power Market California Long-Term Supply Contracts -- On February 25, 2002, both the California Public Utilities Commission ("CPUC") and the California Electric Oversight Board ("EOB")filed complaints under Section 206 of the Federal Power Act with the Federal Energy Regulatory Commission ("FERC") (EL02-60-000 and EL02-62-000, respectively) alleging that the prices and terms of the long-term contracts with the California Department of Water Resources ("DWR") are unjust and unreasonable and counter to the public interest. Calpine was a respondent and the four long-term contracts entered into by Calpine were subject to the complaint. On March 6, 2002, in accordance with the state legislation that authorized DWR to enter into the long-term power contracts, the CPUC issued a Rate Agreement, which dedicates a portion of the retail rate paid by electricity customers of the California investor-owned utilities to a fund to pay bondholders of bonds to be issued by DWR and to a fund to pay electricity suppliers such as Calpine. The proceeds from those bonds will be used in part to -32- fund the Electric Power Fund established by the state legislation authorizing DWR to enter into long-term power contracts with the power suppliers whose recourse in the event of a default by DWR is to the Electric Power Fund. Proceeds from the bonds will also be used to repay the state of California General Fund. The bonds have not been issued, but representatives of the State have indicated that the bonds should be issued in the near future. On April 22, 2002, the Company announced that it had renegotiated CES' long-term power contracts with DWR. The Office of the Governor, the CPUC, the EOB and the California Attorney General ("AG") have endorsed the renegotiated contracts and have agreed to drop all pending claims against the Company and its affiliates, including withdrawing the complaint under Section 206 of the Federal Power Act recently filed by the CPUC and EOB with FERC and the CPUC and the EOB have agreed to terminate their efforts to seek refunds from the Company and its affiliates through FERC refund proceedings. In connection with the renegotiation, the Company has agreed to pay $6 million over three years to the AG to resolve any and all possible claims against the Company and its affiliates brought by the AG. The renegotiation includes the shortening of the duration of the two ten-year, baseload energy contracts by two years and of the 20-year peaker contract by ten years. These changes reduce DWR's long-term purchase obligations. In addition, CES agreed to reduce the energy price on one baseload contract from $61.00 to $59.60 per megawatt-hour, and to convert the energy portion of the peaker contract to gas index pricing from fixed energy pricing. CES has also agreed to deliver up to 12.2 million megawatt-hours of additional energy pursuant to the baseload energy contracts in 2002 and 2003. In connection with the renegotiation, CES has also agreed with DWR that DWR will have the right to assume and complete four of our projects currently planned for California and in the advanced development stage if the Company does not meet certain milestones with respect to each project assumed, provided that DWR reimburses the Company for all construction costs and certain other costs incurred by the Company to the date DWR assumes the relevant project. The negotiation resolved the dispute with DWR concerning payment of the capacity payment on the 495-megawatt peaking contract dated February 28, 2001. The contract provides that through December 31, 2002, CES may earn a capacity payment by committing to supply electricity to DWR from a source other than the peaker units designated in the contract. DWR made certain assertions challenging CES' right to substitute units or provide replacement energy and had withheld capacity payments in the amount of approximately $15.0 million since December 2001. As part of the renegotiation, the Company has received payment in full on these withheld capacity payments and will have the right to provide replacement capacity through December 31, 2002 based on the original contract terms. On May 2, 2002, each of the CPUC and the EOB filed a Notice of Partial Withdrawal with Prejudice of Complaint as to Calpine Energy Services, L.P. with the FERC in the EL02-60-000 and EL02-62-000 dockets, respectively. FERC Investigation into California Wholesale Markets -- On February 13, 2002, FERC initiated an investigation of potential manipulation of electric and natural gas prices in the western United States. This investigation was initiated as a result of allegations that Enron Corp. through its affiliates used its market position to distort electric and natural gas markets in the West. The scope of the investigation is to consider whether as a result of any manipulation in the short-term markets for electric energy or natural gas or other undue influence on the wholesale markets by any party since January 1, 2000, the rates of the long-term contracts subsequently entered into in the West are potentially unjust and unreasonable. In connection with its investigation, FERC has, and may in the future, issue data requests seeking information regarding trading practices in California and the western electricity markets. FERC has stated that it may use the information gathered in connection with the investigation to determine how to proceed on any existing or future complaint brought under Section 206 of the Federal Power Act involving long-term power contracts entered into in the West since January 1, 2000, or to initiate a Federal Power Act Section 206 or Natural Gas Act Section 5 proceeding on its own initiative. Financial Market Risks Energy price fluctuations -- As an independent power producer primarily focused on generation of electricity using gas-fired turbines, our natural physical commodity position is "short" (we require) gas and "long" (we own) power capacity. To manage forward exposure to price fluctuation in these and (to a lesser extent) other commodities, we enter into derivative commodity instruments. All transactions are subject to our risk management policy which prohibits positions that exceed production capacity and fuel requirements on a total portfolio basis. Any hedging, balancing, or optimization activities that we engage in are directly related to our asset-based business model of owning and operating gas-fired electric power plants. We hedge exposures that arise from the ownership and operation of power plants and related sales of electricity and purchases of natural gas, and we utilize derivatives to optimize the returns we are able to achieve from these assets for our shareholders. This model is markedly different from that of companies that engage in significant commodity trading operations that are unrelated to underlying physical assets. Derivative commodity instruments are accounted for under the requirements of SFAS No. 133, as amended. -33- The change in fair value of outstanding commodity derivative instruments from January 1, 2002 through March 31, 2002 is summarized in the table below (in thousands): Fair value of contracts outstanding at January 1, 2002 $ (88,123) (Gains) losses realized or otherwise settled during the period (1)............................... (56,928) Changes in fair value attributable to changes in valuation techniques and assumptions............ -- Other changes in fair value (2).................................................................. 331,503 --------- Fair value of contracts outstanding at March 31, 2002 (3)........................................ $ 186,452 =========
__________ (1) Realized cash flow hedges of $50.7 million reported in Note 7 of the financial statements and $6.2 million realized gain on trading activity reported in the performance metrics section of the management discussion and analysis, both included in this filing. (2) Includes $204.0 million for the reclassification of Enron obligations from derivative assets and liabilities to Accounts Payable as a result of the termination of Calpine's contracts with Enron. (3) Net assets reported in Note 7 of the Notes to Consolidated Financial Statements included in this filing. The fair value of outstanding derivative commodity instruments at March 31, 2002, based on price source and the period during which the instruments will mature (i.e., be realized) are summarized in the table below (in thousands):
Fair Value Source 2002 2003-2004 2005-2006 After 2006 Total ----------------- -------- -------- -------- ---------- -------- Prices actively quoted ....................................... $ 7,498 $(14,593) $(30,746) $ -- $(37,841) Prices provided by other external sources .................... 1,334 44,071 16,159 -- 61,564 Prices based on models and other valuation methods ........... 103,605 34,886 26,298 (2,060) 162,729 -------- -------- -------- -------- -------- Total fair value ............................................. $112,437 $ 64,364 $ 11,711 $ (2,060) $186,452 ======== ======== ======== ======== ========
The Company's traders maintain fair value price information derived from various sources in the Company's trading and risk management systems. The propriety of that information is validated by the Company's Risk Control function. Prices actively quoted include validation with prices sourced from commodities exchanges (e.g., New York Mercantile Exchange). Prices provided by other external sources include quotes from commodity brokers and electronic trading platforms. Prices based on models and other valuation methods are validated using quantitative methods. Validation methods have been independently reviewed for propriety. The counterparty credit quality associated with the fair value of outstanding derivative commodity instruments at March 31, 2002, and the period during which the instruments will mature (i.e., be realized) are summarized in the table below (in thousands):
Credit Quality (based on April 22, 2002 ratings) 2002 2003-2004 2005-2006 After 2006 Total ------------------------------------------------ -------- --------- --------- ---------- -------- Investment grade.............................................. $114,854 $ 73,794 $ 18,678 $ (2,078) $205,248 Non-investment grade.......................................... 40,463 (42,852) (17,819) -- (20,208) No external ratings........................................... (1,029) 2,307 116 18 1,412 -------- -------- -------- -------- -------- Total fair value.............................................. $154,288 $ 33,249 $ 975 $ (2,060) $186,452 ======== ======== ======== ======== ========
-34- 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, 2002: Crude oil ....................... $ (2,132) $ (4,746) Electricity ..................... 286,181 (29,715) Natural gas ..................... (97,597) (134,607) --------- --------- Total ....................... $ 186,452 $(169,068) ========= =========
Derivative commodity instruments included in the table are those included in Note 7 to the unaudited Consolidated Condensed Financial Statements. The fair value of derivative commodity instruments included in the table is based on present value adjusted quoted market prices of comparable contracts. The positive fair value of electricity derivative commodity instruments includes the effect of decreased power prices versus our derivative forward commitments. Conversely, the negative fair value of the natural gas derivatives reflects a general decline in gas prices versus our derivative forward commitments. Derivative commodity instruments offset physical positions exposed to the cash market. None of the offsetting physical positions are included in the table above. 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 prices, the fair value of Calpine's derivative portfolio would typically change by more than ten percent for earlier forward months and less than ten percent for later forward months because of the higher volatilities in the near term and the effects of discounting expected future cash flows. The primary factors affecting the fair value of the Company's derivatives at any point in time are (1) the volume of open derivative positions (MMBtu and Mwh), and (2) changing commodity market prices, principally for electricity and natural gas. The total volume of open gas derivative positions decreased 53% from December 31, 2001 to March 31, 2002, while the total volume of open power derivative positions decreased 12% for the same period. In that prices for electricity and natural gas are among the most volatile of all commodity prices, there may be material changes in the fair value of the Company's derivatives over time, driven both by price volatility and the increases in volume of open derivative transactions. Under SFAS No. 133, the change since the last balance sheet date in the total value of the derivatives (both assets and liabilities) is reflected either in OCI, net of tax, or in the statement of operations as an item (gain or loss) of current earnings. As of March 31, 2002, the majority of the balance in accumulated OCI represented the unrealized net loss associated with commodity cash flow hedging transactions. As noted above, there is a substantial amount of volatility inherent in accounting for the fair value of these derivatives, and the Company's results during the three months ended March 31, 2002 have reflected this. See Note 7 for additional information on derivative activity and also the 2001 Form 10-K for a further discussion of the Company's accounting policies related to derivative accounting. This treatment depends upon whether the derivative is designated as a cash flow or fair value hedge or whether the derivative is not designated in a hedge relationship. The following accounting applies: o Changes in the value of derivatives designated as cash flow hedges, net of any ineffectiveness, are recorded to OCI. o Changes in the value of derivatives designated as fair value hedges are recorded in the statement of operations with the offsetting change in value of the hedge item also recorded in the statement of operations. Any difference between these two entries to the statement of operations represents hedge ineffectiveness. o The change in value of derivatives not designated in hedge relationships is recorded to the statement of operations. In 2001 the FASB cleared SFAS No. 133 Implementation Issue No. C16 "Applying the Normal Purchases and Normal Sales Exception to Contracts That Combine a Forward Contract and a Purchased Option Contract" ("C16"). The guidance in C16 applies to fuel supply contracts that require delivery of a contractual minimum quantity of fuel at a fixed price and have an option that permits the holder to take specified additional amounts of fuel at the same fixed price at various times. Under C16, the volumetric optionality provided by such contracts is considered a purchased option that disqualifies the entire derivative fuel supply contract from being eligible to qualify for the normal -35- purchases and normal sales exception in SFAS No. 133. The Company has adopted the guidance provided by C16 effective April 1, 2002, and Issue C16 is expected to increase the volatility of the Company's reported earnings in the future. Interest rate swaps and cross currency swaps -- From time to time, we use interest rate swap and cross currency swap agreements to mitigate our exposure to interest rate and currency fluctuations associated with certain of our debt instruments. We do not use interest rate swap and currency swap agreements for speculative or trading purposes. In regards to foreign currency denominated senior notes, the swap notional amounts equal the amount of the related principal debt. The following tables summarize the fair market values of our existing interest rate swap and currency swap agreements as of March 31, 2002 (dollars in thousands):
Notional Principal Weighted Average Weighted Average Fair Market Maturity Date Amount Interest Rate Interest Rate Value ------------- ------------------ ---------------- ---------------- ----------- (Pay) (Receive) 2009 .............................. $ 14,862 6.9% 3-month US LIBOR $ (940) 2011 .............................. 53,126 6.9% 3-month US LIBOR (3,324) 2012 .............................. 118,692 6.5% 3-month US LIBOR (5,554) 2014 .............................. 67,929 6.7% 3-month US LIBOR (4,086) 2015 .............................. 22,500 7.0% 3-month US LIBOR (1,728) 2018 .............................. 17,500 7.0% 3-month US LIBOR (1,431) -------- --- -------- Total ........................... $294,609 6.7% 3-month US LIBOR $(17,063) ======== === ========
Frequency of Fixed Currency Currency Fair Market Maturity Date Notional Principal Exchange Exchange Value ------------- ----------------------------------- ------------------------------- ------------- ----------- (Pay/Receive) (Pay/Receive) 2007........... US$127,763/C$200,000 US$5,545/C$8,750 Semi-annually $ (3,929) 2008........... Pound sterling 109,550/Euro 175,000 Pound sterling 5,152/Euro 7,328 Semi-annually (10,732) -------- Total.... $(14,661) ========
Long-term senior notes and construction/project financing -- Because of the significant capital requirements within our industry, additional financing is often needed to fund our growth. We use two primary forms of debt to raise this financing -- long-term senior notes and construction/project financing. Our Senior Notes bear fixed interest rates and are generally used to fund acquisitions, replace construction financing for power plants once they achieve commercial operations, and for general corporate purposes. Our construction/project financing is funded through two separate credit agreements, Calpine Construction Finance Company L.P. and Calpine Construction Finance Company II, LLC. Borrowings under these credit agreements bear variable interest rates, and are used exclusively to fund the construction of our power plants. -36- The following table summarizes the fair market value of our existing long-term senior notes and construction/project financing as of March 31, 2002 (dollars in thousands):
Outstanding Weighted Average Fair Market Maturity Date Balance Interest Rate Value ------------- ----------- ---------------- ----------- Long-term senior notes: Senior Notes Due 2005 ........................... $ 250,000 8.3% $ 205,000 Senior Notes Due 2006 ........................... 171,750 10.5% 152,858 Senior Notes Due 2006 ........................... 250,000 7.6% 200,000 Convertible Senior Notes Due 2006 ............... 1,200,000 4.0% 924,000 Senior Notes Due 2007 ........................... 275,000 8.8% 222,750 Senior Notes Due 2007 ........................... 125,500 8.8% 100,400 Senior Notes Due 2008 ........................... 400,000 7.9% 312,000 Senior Notes Due 2008 ........................... 2,030,000 8.5% 1,745,800 Senior Notes Due 2008 ........................... 152,446 8.4% 121,957 Senior Notes Due 2009 ........................... 350,000 7.8% 269,500 Senior Notes Due 2010 ........................... 750,000 8.6% 585,000 Senior Notes Due 2011 ........................... 2,000,000 8.5% 1,570,000 Senior Notes Due 2011 ........................... 284,820 8.9% 219,311 ---------- --- ---------- Total long-term senior notes................. $8,239,516 7.8% $6,628,576 ========== === ========== Construction/project financing: Calpine Construction Finance Company L.P. ....... $ 981,400 1-month US LIBOR $ 981,400 Calpine Construction Finance Company II, LLC .... 2,442,697 1-month US LIBOR 2,442,697 ---------- ---------------- ---------- Total long-term construction/ project financing.......................... $3,424,097 1-month US LIBOR $3,424,097 ========== ================ ==========
Short-term investments -- As of March 31, 2002, we had short-term investments of $14.1 million. These short-term investments consist of highly liquid investments with maturities of less than three months. We have the ability to hold these investments to maturity, and as a result, we would not expect the value of these investments to be affected to any significant degree by the effect of a sudden change in market interest rates. New Accounting Pronouncements In June 2001, we adopted SFAS No. 141, "Business Combinations," which supersedes Accounting Principles Board ("APB") Opinion No. 16, "Business Combinations" and SFAS No. 38, "Accounting for Preacquisition Contingencies of Purchased Enterprises." SFAS No. 141 eliminated the pooling-of-interests method of accounting for business combinations and modified the recognition of intangible assets and disclosure requirements. Adoption of SFAS No. 141 did not have a material effect on the consolidated financial statements. In Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2001, the subsection entitled "SFAS No. 141" in the Impact of Recent Accounting Pronouncements section was inadvertently overwritten with an outdated draft of the SFAS No. 142 accounting pronouncement paragraph. The paragraph above discussing SFAS No. 141 supersedes the discussion in the 2001 Form 10-K. In June 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible Assets," which supersedes APB Opinion No. 17, "Intangible Assets." SFAS No. 142 eliminates the current requirement to amortize goodwill and indefinite-lived intangible assets, extends the allowable useful lives of certain intangible assets, and requires impairment testing and recognition for goodwill and intangible assets. SFAS No. 142 will apply to goodwill and other intangible assets arising from transactions completed both before and after its effective date. The provisions of SFAS No. 142 are required to be applied starting with fiscal years beginning after December 15, 2001. See Note 4 for more information. In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations," which amends SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies." SFAS No. 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. SFAS No. 143 is effective for financial statements issued for fiscal years beginning after June 15, 2002. We have not completed our analysis of the impact that SFAS No. 143 will have on our consolidated financial statements. On January 1, 2002, we adopted SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," which supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," and the accounting and reporting provisions of APB Opinion No. 30, "Reporting the Results of Operations -- Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring -37- Events and Transactions," for the disposal of a segment of a business (as previously defined in that APB Opinion). SFAS No. 144 establishes a single accounting model, based on the framework established in SFAS No. 121, for long-lived assets to be disposed of by sale. SFAS No. 144 also resolves several significant implementation issues related to SFAS No. 121, such as eliminating the requirement to allocate goodwill to long-lived assets to be tested for impairment and establishing criteria to define whether a long-lived asset is held for sale. Adoption of SFAS No. 144 did not have a material effect on the consolidated financial statements. In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections." SFAS No. 145 rescinds SFAS No. 4, "Reporting Gains and Losses from Extinguishment of Debt" and an amendment of that statement, SFAS No. 64, "Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements." SFAS No. 145 also rescinds SFAS No. 44, "Accounting for Intangible Assets of Motor Carriers." SFAS No. 145 also amends SFAS No. 13, "Accounting for Leases," to eliminate an inconsistency between the required accounting for sale-leaseback transactions and the required accounting for certain lease modifications that have economic effects that are similar to sale-leaseback transactions. SFAS No. 145 also amends other existing authoritative pronouncements to make various technical corrections, clarify meanings, or describe their applicability under changed conditions. The provisions related to the rescission of SFAS No. 4 shall be applied in fiscal years beginning after May 15, 2002. The provisions related to SFAS No. 13 shall be effective for transactions occurring after May 15, 2002. All other provisions shall be effective for financial statements issued on or after May 15, 2002, with early application encouraged. We do not believe that SFAS No. 145 will have a material effect on our results of operations. Item 3. Quantitative and Qualitative Disclosures About Market Risk. See "Financial Market Risks" in Item 2. PART II - OTHER INFORMATION Item 1. Legal Proceedings. Calpine Corporation v. Automated Credit Exchange ("ACE"). On March 5, 2002, Calpine sued ACE in the Superior Court of the State of California for the County of Alameda for negligence and breach of contract to recover reclaim trading credits, a form of emission reduction credits that should have been held in Calpine's account with U.S. Trust Company (US Trust). ACE is a broker in emission reduction credits based in Pasadena, California. Calpine had paid ACE for Nitrogen oxide (NOx) coastal credits that were to be purchased by ACE and held by US Trust. The credits were to be held by US Trust pursuant to a Credit Holding Agreement, which provided, among other things, that US Trust was to hold the credits until receiving instructions from ACE to disburse the credits. ACE had agreed that (i) upon prior written instruction from Calpine, to instruct US Trust to take such actions as may be directed by Calpine to disburse the credits held in escrow pursuant to the Credit Holding Agreement and (ii) not to take any action, or otherwise instruct US Trust to take any action, concerning the credits held in escrow pursuant to the Credit Holding Agreement without prior written instruction from Calpine. Calpine and ACE entered into a settlement agreement that resolved all issues on March 29, 2002. The settlement provided for a partial recovery of $7 million and for the rights to the emission reduction credits to be held by ACE. The Company expects to recognize the $7 million in the second quarter of 2002, after all realization uncertainties are cleared. In accordance with the settlement agreement, Calpine has dismissed its complaint against ACE. Ben Johnson v. Peter Cartwright, et al. On December 17, 2001, a shareholder filed a derivative lawsuit on behalf of Calpine against its directors and one of its senior officers. This lawsuit is styled Johnson vs. Cartwright, et al. (No. CV803872), and is pending in the California Superior Court, Santa Clara County. Calpine is a nominal defendant in this lawsuit, which alleges claims relating to purportedly misleading statements about Calpine and stock sales by certain of the director defendants and the officer defendant. Calpine has filed a demurrer asking the court to dismiss the complaint on the ground that the shareholder plaintiff lacks standing to pursue claims on behalf of Calpine. The individual defendants have filed a demurrer asking the court to dismiss the complaint on the ground that it fails to state any claims against them. Securities Class Action Lawsuits. Since March 11, 2002, fourteen shareholder lawsuits have been filed against Calpine and certain of its officers in the United States District Court, Northern District of California. The actions captioned Weisz vs. Calpine Corp., et al., filed March 11, 2002, and Labyrinth Technologies, Inc. v. Calpine Corp., et al., filed March 28, 2002 are purported class actions on behalf of purchasers of Calpine stock between March 15, 2001 and December 13, 2001. Gustaferro v. Calpine Corp., filed April 18, 2002 is a purported class action on behalf of purchasers of Calpine stock between February 6, 2001 and December 13, 2001. The eleven other actions, captioned Local 144 Nursing Home Pension Fund vs. Calpine Corp., Lukowski vs. Calpine Corp., Hart vs. Calpine Corp., Atchison vs. Calpine Corp. and Laborers Local 1298 v. Calpine Corp., Bell v. Calpine Corp., Nowicki v. Calpine Corp. Pallotta v. Calpine Corp., Knepell v. Calpine Corp., Staub v. Calpine Corp, and Rose v. Calpine Corp. were filed between March 18, 2002 and April 23, 2002. The complaints in these eleven actions are virtually identical--they were filed by -38- three law firms, in conjunction with other law firms as co-counsel. All eleven lawsuits are purported class actions on behalf of purchasers of Calpine's securities between January 5, 2001 and December 13, 2001. The complaints in these fourteen actions allege that, during the purported class periods, certain senior executives issued false and misleading statements about Calpine's financial condition in violation of Sections 10(b) and 20(1) of the Securities Exchange Act of 1934, as well as Rule 10b-5. These actions seek an unspecified amount of damages, in addition to other forms of relief. We expect that these actions, as well as any related actions that may be filed in the future, will be consolidated by the court into a single securities class action. We consider the lawsuits to be without merit, and we intend to defend vigorously against these allegations. Public Utilities Commission of the State of California v. Sellers of Long Term Contracts to the California Department of Water Resources; California Electricity Oversight Board v. Sellers of Long Term Contracts to the California Department of Water Resources. In February 2002 both the CPUC and the EOB filed complaints under Section 206 of the Federal Power Act with FERC (EL02-60-000 and EL02-62-000, respectively) alleging that the prices and terms of the long-term contracts with DWR are unjust and unreasonable and counter to the public interest. CES is a respondent and the four long-term contracts entered into between CES and DWR are subject to the complaint (see, Risk Factors - California Long-Term Supply Agreements). As part of Calpine's successful renegotiation of its long-term power contracts with DWR announced on April 22, 2002, the Office of the Governor, the CPUC, the EOB and the AG agreed to settle this action and drop all challenges to Calpine's long-term contracts with DWR. On May 2, 2002 each of the CPUC, the EOB, and the AG filed a Notice of Partial Withdrawal with Prejudice of Complaint as to Calpine Energy Services, L.P. with the FERC. Pursuant to its respective notice each of the CPUC and the EOB withdrew all of their respective claims against CES which had been alleged in the above-for-mentioned complaints (EL02-60-000 and ELO2-62-000) concerning the justness and reasonableness of the terms under the long-term contracts with DWR. In addition, pursuant to its notice, the AG withdrew all claims as to CES in its complaint (EL02-71-000) wherein it had alleged that public utility sellers of energy and ancillary services to DWR and into markets operated by the California Independent System Operator and the California Power Exchange were not in compliance with their disclosure obligations under Section 205 of the Federal Power Act. The Company is involved in various other claims and legal actions arising out of the normal course of business. The Company does not expect that the outcome of these proceedings will have a material adverse effect on the Company's financial position or results of operations. Item 2. Changes in Securities and Use of Proceeds. 4% Convertible Senior Notes due 2006. On December 26, 2001, we completed a private placement of $1,000,000,000 aggregate principal amount of 4% Convertible Senior Notes due 2006 (the "senior notes due 2006"). The initial purchaser of the senior notes due 2006 was Deutsche Bank Alex. Brown Inc. (the "initial purchaser"). The initial purchaser exercised its option to acquire an additional $200,000,000 aggregate principal amount of the senior notes due 2006 by purchasing an additional $100,000,000 aggregate principal amount of the senior notes due 2006 on each of December 31, 2001 and January 3, 2002. The offering price of the senior notes due 2006 was 100% of the principal amount of the senior notes due 2006, less an aggregate underwriting discount of $30,000,000. Each sale of the senior notes due 2006 to the initial purchaser was exempt from registration in reliance on Section 4(2) and Regulation D under the Securities Act of 1933, as amended, as a transaction not involving a public offering. The senior notes due 2006 were re-offered by the initial purchaser to qualified institutional buyers in reliance on Rule 144A under the Securities Act. The senior notes due 2006 are convertible into shares of our common stock at a conversion price of $18.07 per share. The conversion price is subject to adjustment in certain circumstances. We have reserved 66,408,411 shares of our authorized common stock for issuance upon conversion of the senior notes due 2006. The senior notes due 2006 are convertible at any time on or before the close of business on the day that is two business days prior to the maturity date, December 26, 2006, unless we have previously repurchased the senior notes due 2006. Holders of the senior notes due 2006 have the right to require us to repurchase their senior notes due 2006 on December 26, 2004. We may choose to pay the repurchase price in cash or shares of common stock, or a combination thereof. -39- Item 6. Exhibits and Reports on Form 8-K. (a) Exhibits The following exhibits are filed herewith unless otherwise indicated: EXHIBIT INDEX EXHIBIT NUMBER DESCRIPTION *3.1 Amended and Restated Certificate of Incorporation of Calpine Corporation (a) *3.2 Certificate of Correction of Calpine Corporation (b) *3.3 Certificate of Amendment of Amended and Restated Certificate of Incorporation of Calpine Corporation (c) *3.4 Certificate of Designation of Series A Participating Preferred Stock of Calpine Corporation (b) *3.5 Amended Certificate of Designation of Series A Participating Preferred Stock of Calpine Corporation (b) *3.6 Amended Certificate of Designation of Series A Participating Preferred Stock of Calpine Corporation (c) *3.7 Certificate of Designation of Special Voting Preferred Stock of Calpine Corporation(d) 3.8 Certificate of Ownership and Merger Merging Calpine Natural Gas GP, Inc. into Calpine Corporation. 3.9 Certificate of Ownership and Merger Merging Calpine Natural Gas Company into Calpine Corporation. *3.10 Amended and Restated By-laws of Calpine Corporation (f) *4.1 Indenture dated as of August 10, 2000, between Calpine Corporation and Wilmington Trust Company, as Trustee.(f) *4.2 First Supplemental Indenture dated as of September 28, 2000, between Calpine Corporation and Wilmington Trust Company, as Trustee.(b) *4.3 Amended and Restated Rights Agreement, dated as of September 19, 2001, between Calpine Corporation and EquiServe Trust Company, N.A., as Rights Agent.(g) *10.1 Second Amended and Restated Credit Agreement ("Second Amended and Restated Credit Agreement") dated as of May 23, 2000, among the Company, Bayerische Landesbank, as Co-Arranger and Syndication Agent, The Bank of Nova Scotia, as Lead Arranger and Administrative Agent, and the Lenders named therein.(h) *10.2 First Amendment and Waiver to Second Amended and Restated Credit Agreement, dated as of April 19, 2001, among the Company, The Bank of Nova Scotia, as Administrative Agent, and the Lenders named therein.(e) *10.3 Second Amendment to Second Amended and Restated Credit Agreement, dated as of March 8, 2002, among the Company, The Bank of Nova Scotia, as Administrative Agent, and the Lenders named therein.(e) 10.4 Third Amendment to Second Amended and Restated Credit Agreement, dated as of May 9, 2002, among the Company, The Bank of Nova Scotia, as Administrative Agent, and the Lenders named therein. *10.5 Credit Agreement, dated as of March 8, 2002, among the Company, the Lenders named therein, The Bank of Nova Scotia and Bayerische Landesbank Girozentrale, as lead arrangers and bookrunners, Salomon Smith Barney Inc. and Deutsche Banc Alex. Brown Inc., as lead arrangers and bookrunners, Bank of America, National Association, and Credit Suisse First Boston, Cayman Islands Branch, as lead arrangers and syndication agents, TD Securities (USA) Inc., as lead arranger, The Bank of Nova Scotia, as joint administrative agent and funding agent, and Citicorp USA, Inc., as joint administrative agent.(e) 10.6 First Amendment to Credit Agreement, dated as of May 9, 2002, among the Company, The Bank of Nova Scotia, as Joint Administrative Agent and Funding Agent, Citicorp USA, Inc., as Joint Administrative Agent, and the Lenders named therein. -40- *10.7 Assignment and Security Agreement, dated as of March 8, 2002, by the Company in favor of The Bank of Nova Scotia, as administrative agent for each of the Lender Parties named therein.(e) *10.8 Pledge Agreement, dated as of March 8, 2002, by the Company in favor of The Bank of Nova Scotia, as Agent for the Lender Parties named therein.(e) 10.9 Amendment Number One to Pledge Agreement, dated as of May 9, 2002, among the Company and The Bank of Nova Scotia, as Joint Administrative Agent and Funding Agent. *10.10 Pledge Agreement, dated as of March 8, 2002, by Quintana Minerals (USA), Inc., JOQ Canada, Inc. and Quintana Canada Holdings, LLC in favor of The Bank of Nova Scotia, as Agent for the Lender Parties named therein.(e) 10.11 First Amendment Pledge Agreement, dated as of May 9, 2002, by the Company in favor of The Bank of Nova Scotia, as Agent for each of the Lender Parties named therein. 10.12 First Amendment Pledge Agreement (Membership Interests), dated as of May 9, 2002, by the Company in favor of The Bank of Nova Scotia, as Agent for each of the Lender Parties named therein. 10.13 Note Pledge Agreement, dated of May 9, 2002, by the Company in favor of The Bank of Nova Scotia, as Agent for each of the Lender Parties named therein. ________________ * Incorporated by reference. (a) Incorporated by reference to Calpine Corporation's Registration Statement on Form S-3 (Registration No. 333-40652), filed with the SEC on June 30, 2000. (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 Registration Statement on Form S-3 (Registration No. 333-66078), filed with the SEC on July 27, 2001. (d) Incorporated by reference to Calpine Corporation's Quarterly Report on Form 10-Q dated March 31, 2001, filed with the SEC on May 15, 2001. (e) Incorporated by reference to Calpine Corporation's Annual Report on Form 10-K for the year ended December 31, 2001, filed with the SEC on March 29, 2002. (f) Incorporated by reference to Calpine Corporation's Registration Statement on Form S-3 (Registration No. 333-76880), filed with the SEC on January 17, 2002. (g) Incorporated by reference to Calpine Corporation's Registration Statement on Form 8-A/A filed with the SEC on September 28, 2001. (h) Incorporated by reference to Calpine Corporation's Current Report on Form 8-K dated July 25, 2000, filed with the SEC on August 9, 2000. (b) Reports on Form 8-K The registrant filed the following reports on Form 8-K during the quarter ended March 31, 2002:
DATE OF REPORT DATE FILED ITEM REPORTED -------------- ---------- ------------- December 24, 2001 ..................... January 16, 2002 5,7 November 14, 2001 ..................... January 17, 2002 5,7 January 31, 2002 ...................... February 8, 2002 5,7 March 12, 2002 ........................ March 13, 2002 5,7 March 13, 2002 ........................ March 13, 2002 5 March 25, 2002 ........................ March 26, 2002 4,7
-41- 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/ Robert D. Kelly Date: May 15, 2002 ------------------------------- Robert D. Kelly Executive Vice President and Chief Financial Officer (Principal Financial Officer) By: /s/ Charles B. Clark, Jr. Date: May 15, 2002 ------------------------------- Charles B. Clark, Jr. Senior Vice President and Corporate Controller (Principal Accounting Officer) -42- The following exhibits are filed herewith unless otherwise indicated: EXHIBIT INDEX EXHIBIT NUMBER DESCRIPTION *3.1 Amended and Restated Certificate of Incorporation of Calpine Corporation (a) *3.2 Certificate of Correction of Calpine Corporation (b) *3.3 Certificate of Amendment of Amended and Restated Certificate of Incorporation of Calpine Corporation (c) *3.4 Certificate of Designation of Series A Participating Preferred Stock of Calpine Corporation (b) *3.5 Amended Certificate of Designation of Series A Participating Preferred Stock of Calpine Corporation (b) *3.6 Amended Certificate of Designation of Series A Participating Preferred Stock of Calpine Corporation (c) *3.7 Certificate of Designation of Special Voting Preferred Stock of Calpine Corporation(d) 3.8 Certificate of Ownership and Merger Merging Calpine Natural Gas GP, Inc. into Calpine Corporation. 3.9 Certificate of Ownership and Merger Merging Calpine Natural Gas Company into Calpine Corporation. *3.10 Amended and Restated By-laws of Calpine Corporation (f) *4.1 Indenture dated as of August 10, 2000, between Calpine Corporation and Wilmington Trust Company, as Trustee.(f) *4.2 First Supplemental Indenture dated as of September 28, 2000, between Calpine Corporation and Wilmington Trust Company, as Trustee.(b) *4.3 Amended and Restated Rights Agreement, dated as of September 19, 2001, between Calpine Corporation and EquiServe Trust Company, N.A., as Rights Agent.(g) *10.1 Second Amended and Restated Credit Agreement ("Second Amended and Restated Credit Agreement") dated as of May 23, 2000, among the Company, Bayerische Landesbank, as Co-Arranger and Syndication Agent, The Bank of Nova Scotia, as Lead Arranger and Administrative Agent, and the Lenders named therein.(h) *10.2 First Amendment and Waiver to Second Amended and Restated Credit Agreement, dated as of April 19, 2001, among the Company, The Bank of Nova Scotia, as Administrative Agent, and the Lenders named therein.(e) *10.3 Second Amendment to Second Amended and Restated Credit Agreement, dated as of March 8, 2002, among the Company, The Bank of Nova Scotia, as Administrative Agent, and the Lenders named therein.(e) 10.4 Third Amendment to Second Amended and Restated Credit Agreement, dated as of May 9, 2002, among the Company, The Bank of Nova Scotia, as Administrative Agent, and the Lenders named therein. *10.5 Credit Agreement, dated as of March 8, 2002, among the Company, the Lenders named therein, The Bank of Nova Scotia and Bayerische Landesbank Girozentrale, as lead arrangers and bookrunners, Salomon Smith Barney Inc. and Deutsche Banc Alex. Brown Inc., as lead arrangers and bookrunners, Bank of America, National Association, and Credit Suisse First Boston, Cayman Islands Branch, as lead arrangers and syndication agents, TD Securities (USA) Inc., as lead arranger, The Bank of Nova Scotia, as joint administrative agent and funding agent, and Citicorp USA, Inc., as joint administrative agent.(e) 10.6 First Amendment to Credit Agreement, dated as of May 9, 2002, among the Company, The Bank of Nova Scotia, as Joint Administrative Agent and Funding Agent, Citicorp USA, Inc., as Joint Administrative Agent, and the Lenders named therein. *10.7 Assignment and Security Agreement, dated as of March 8, 2002, by the Company in favor of The Bank of Nova Scotia, as administrative agent for each of the Lender Parties named therein.(e) -43- *10.8 Pledge Agreement, dated as of March 8, 2002, by the Company in favor of The Bank of Nova Scotia, as Agent for the Lender Parties named therein.(e) 10.9 Amendment Number One to Pledge Agreement, dated as of May 9, 2002, among the Company and The Bank of Nova Scotia, as Joint Administrative Agent and Funding Agent. *10.10 Pledge Agreement, dated as of March 8, 2002, by Quintana Minerals (USA), Inc., JOQ Canada, Inc. and Quintana Canada Holdings, LLC in favor of The Bank of Nova Scotia, as Agent for the Lender Parties named therein.(e) 10.11 First Amendment Pledge Agreement, dated as of May 9, 2002, by the Company in favor of The Bank of Nova Scotia, as Agent for each of the Lender Parties named therein. 10.12 First Amendment Pledge Agreement (Membership Interests), dated as of May 9, 2002, by the Company in favor of The Bank of Nova Scotia, as Agent for each of the Lender Parties named therein. 10.13 Note Pledge Agreement, dated of May 9, 2002, by the Company in favor of The Bank of Nova Scotia, as Agent for each of the Lender Parties named therein. ________________ * Incorporated by reference. (a) Incorporated by reference to Calpine Corporation's Registration Statement on Form S-3 (Registration No. 333-40652), filed with the SEC on June 30, 2000. (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 Registration Statement on Form S-3 (Registration No. 333-66078), filed with the SEC on July 27, 2001. (d) Incorporated by reference to Calpine Corporation's Quarterly Report on Form 10-Q dated March 31, 2001, filed with the SEC on May 15, 2001. (e) Incorporated by reference to Calpine Corporation's Annual Report on Form 10-K for the year ended December 31, 2001, filed with the SEC on March 29, 2002. (f) Incorporated by reference to Calpine Corporation's Registration Statement on Form S-3 (Registration No. 333-76880), filed with the SEC on January 17, 2002. (g) Incorporated by reference to Calpine Corporation's Registration Statement on Form 8-A/A filed with the SEC on September 28, 2001. (h) Incorporated by reference to Calpine Corporation's Current Report on Form 8-K dated July 25, 2000, filed with the SEC on August 9, 2000. -44-