10-Q 1 q2-2002.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 June 30, 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: 376,699,769 shares of Common Stock, par value $.001 per share, outstanding on August 8, 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, the quarterly report on Form 10-Q for the three months ended March 31, 2002, has subsequently been reviewed by Deloitte and Touche LLP in accordance with Statement on Auditing Standards No. 71, "Interim Financial Information." ================================================================================ CALPINE CORPORATION AND SUBSIDIARIES Report on Form 10-Q For the Quarter Ended June 30, 2002
INDEX Page No. PART I - FINANCIAL INFORMATION Item 1. Financial Statements. Consolidated Condensed Balance Sheets June 30, 2002 and December 31, 2001........................... 3 Consolidated Condensed Statements of Operations For the Three and Six Months Ended June 30, 2002 and 2001...................................................................... 4 Consolidated Condensed Statements of Cash Flows For the Six Months Ended June 30, 2002 and 2001...................................................................... 6 Notes to Consolidated Condensed Financial Statements June 30, 2002.................................. 7 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.................. 25 Item 3. Quantitative and Qualitative Disclosures About Market Risk............................................. 45 PART II - OTHER INFORMATION Item 1. Legal Proceedings...................................................................................... 46 Item 4. Submission of Matters to a Vote of Security Holders.................................................... 47 Item 6. Exhibits and Reports on Form 8-K....................................................................... 48 Signatures........................................................................................................ 51
-2- PART I - FINANCIAL INFORMATION Item 1. Financial Statements. CALPINE CORPORATION AND SUBSIDIARIES Consolidated Condensed Balance Sheets June 30, 2002 and December 31, 2001 (In thousands, except share and per share amounts)
June 30, December 31, 2002 2001 ------------ ------------- (unaudited) ASSETS Current assets: Cash and cash equivalents.................................................................... $ 528,767 $ 1,525,417 Accounts receivable, net..................................................................... 1,009,552 966,080 Margin deposits and other prepaid expense.................................................... 244,454 480,656 Inventories.................................................................................. 96,662 78,862 Current derivative assets.................................................................... 583,943 763,162 Other current assets......................................................................... 227,948 193,525 ------------ ------------ Total current assets...................................................................... 2,691,326 4,007,702 ------------ ------------ Restricted cash................................................................................. 107,298 95,833 Notes receivable, net of current portion........................................................ 173,155 158,124 Project development costs....................................................................... 187,372 179,783 Investments in power projects................................................................... 431,046 378,614 Deferred financing costs........................................................................ 229,739 210,811 Property, plant and equipment, net.............................................................. 17,118,306 15,276,056 Goodwill and other intangible assets, net....................................................... 140,984 153,115 Long-term derivative assets..................................................................... 665,787 564,952 Other assets.................................................................................... 484,723 304,562 ------------ ------------ Total assets............................................................................ $ 22,229,736 $ 21,329,552 ============ ============ LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable............................................................................. $ 1,250,424 $ 1,283,843 Accrued payroll and related expense.......................................................... 49,899 57,285 Accrued interest payable..................................................................... 186,302 160,115 Notes payable and borrowings under lines of credit, current portion.......................... 10,523 23,238 Capital lease obligation, current portion.................................................... 2,277 2,206 Construction/project financing, current portion.............................................. 147,363 -- Zero-Coupon Convertible Debentures Due 2021.................................................. -- 878,000 Current derivative liabilities............................................................... 473,140 625,339 Other current liabilities.................................................................... 202,377 198,812 ------------ ------------ Total current liabilities................................................................. 2,322,305 3,228,838 ------------ ------------ Term loan....................................................................................... 1,000,000 -- Notes payable and borrowings under lines of credit, net of current portion...................... 77,453 74,750 Capital lease obligation, net of current portion................................................ 206,700 207,219 Construction/project financing, net of current portion.......................................... 3,434,097 3,393,410 Convertible Senior Notes Due 2006............................................................... 1,200,000 1,100,000 Senior notes.................................................................................... 7,085,886 7,049,038 Deferred income taxes, net...................................................................... 938,566 964,346 Deferred lease incentive........................................................................ 55,484 57,236 Deferred revenue................................................................................ 201,766 154,381 Long-term derivative liabilities................................................................ 580,919 822,848 Other liabilities............................................................................... 95,163 96,504 ------------ ------------ Total liabilities....................................................................... 17,198,339 17,148,570 ------------ ------------ Company-obligated mandatorily redeemable convertible preferred securities of subsidiary trusts.. 1,123,537 1,123,024 Minority interests.............................................................................. 40,000 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 375,602,307 shares in 2002 and 307,058,751 shares in 2001............ 376 307 Additional paid-in capital...................................................................... 2,791,942 2,040,836 Retained earnings............................................................................... 1,194,249 1,196,000 Accumulated other comprehensive loss............................................................ (118,707) (226,574) ------------ ------------ Total stockholders' equity................................................................... 3,867,860 3,010,569 ------------ ------------ Total liabilities and stockholders' equity................................................ $ 22,229,736 $ 21,329,552 ============ ============
The accompanying notes are an integral part of these consolidated condensed financial statements. -3- CALPINE CORPORATION AND SUBSIDIARIES Consolidated Condensed Statements of Operations For the Three and Six Months Ended June 30, 2002 and 2001 (In thousands, except per share amounts) (unaudited)
Three Months Ended Six Months Ended June 30, June 30, ----------------------------- ------------------------------ 2002 2001 2002 2001 ------------ ------------ ------------ ------------ Revenue: Electric generation and marketing revenue Electricity and steam revenue.......................... $ 708,752 $ 505,711 $ 1,328,931 $ 1,100,870 Sales of purchased power............................... 868,606 683,196 1,776,907 1,136,798 Electric power derivative mark-to-market gain.......... 6,104 68,433 10,270 69,739 ------------ ------------ ------------ ------------ Total electric generation and marketing revenue...... 1,583,462 1,257,340 3,116,108 2,307,407 Oil and gas production and marketing revenue Oil and gas sales...................................... 52,163 116,319 119,651 273,006 Sales of purchased gas................................. 302,044 226,693 434,202 355,865 ------------ ------------ ------------ ------------ Total oil and gas production and marketing revenue... 354,207 343,012 553,853 628,871 Income (loss) from unconsolidated investments in power projects........................................... (1,121) 1,600 323 2,163 Other revenue............................................. 5,258 10,921 9,869 14,183 ------------ ------------ ------------ ------------ Total revenue..................................... 1,941,806 1,612,873 3,680,153 2,952,624 ------------ ------------ ------------ ------------ Cost of revenue: Electric generation and marketing expense Plant operating expense................................ 118,930 69,259 234,087 153,719 Royalty expense........................................ 4,194 6,916 8,349 17,925 Purchased power expense................................ 698,176 655,322 1,513,181 1,111,588 ------------ ------------ ------------ ------------ Total electric generation and marketing expense...... 821,300 731,497 1,755,617 1,283,232 Oil and gas production and marketing expense Oil and gas production expense......................... 27,836 27,308 54,776 61,591 Purchased gas expense.................................. 333,724 218,330 457,418 336,958 ------------ ------------ ------------ ------------ Total oil and gas production and marketing expense... 361,560 245,638 512,194 398,549 Fuel expense Cost of oil and natural gas burned by power plants..... 350,848 251,876 677,291 516,439 Natural gas derivative mark-to-market loss (gain)...... 3,203 (23,446) 9,595 (30,995) ------------ ------------ ------------ ------------ Total fuel expense................................... 354,051 228,430 686,886 485,444 Depreciation, depletion and amortization expense.......... 110,122 72,144 213,995 144,157 Operating lease expense................................... 36,263 27,449 72,397 55,460 Other expense............................................. 2,204 3,490 4,794 5,989 ------------ ------------ ------------ ------------ Total cost of revenue............................. 1,685,500 1,308,648 3,245,883 2,372,831 ------------ ------------ ------------ ------------ Gross profit................................... 256,306 304,225 434,270 579,793 Project development expense.................................. 24,713 4,372 36,051 20,211 Equipment cancellation cost.................................. -- -- 168,471 -- General and administrative expense........................... 53,601 50,537 113,862 86,622 Merger expense............................................... -- 35,606 -- 41,627 ------------ ------------ ------------ ------------ Income from operations.................................... 177,992 213,710 115,886 431,333 Interest expense............................................. 67,058 43,331 128,369 63,256 Distributions on trust preferred securities.................. 15,387 15,387 30,773 30,562 Interest income.............................................. (9,762) (20,531) (21,938) (39,889) Other income, net............................................ (2,766) (3,291) (11,859) (9,018) ------------ ------------ ------------ ------------ Income (loss) before provision (benefit) for income taxes. 108,075 178,814 (9,459) 386,422 Provision (benefit) for income taxes......................... 35,559 69,849 (5,578) 158,830 ------------ ------------ ------------ ------------ Income (loss) before extraordinary gain (loss) and cumulative effect of a change in accounting principle.... 72,516 108,965 (3,881) 227,592 Extraordinary gain (loss), net of tax provision of $--, $834, $1,362 and $834............................................. -- (1,300) 2,130 (1,300) Cumulative effect of a change in accounting principle, net of tax provision of $--, $--, $--and $669............... -- -- -- 1,036 ------------ ------------ ------------ ------------ Net income (loss).............................. $ 72,516 $ 107,665 $ (1,751) $ 227,328 ============ ============ ============ ============
-4- CALPINE CORPORATION AND SUBSIDIARIES Consolidated Condensed Statements of Operations For the Three and Six Months Ended June 30, 2002 and 2001 (In thousands, except per share amounts) (unaudited) (continued)
Three Months Ended Six Months Ended June 30, June 30, ----------------------------- ------------------------------ 2002 2001 2002 2001 ------------ ------------ ------------ ------------ Basic earnings (loss) per common share: Weighted average shares of common stock outstanding....... 356,158 302,729 331,745 301,641 Income (loss) before extraordinary gain (loss) and cumulative effect of a change in accounting principle.... $ 0.20 $ 0.36 $ (0.01) $ 0.75 Extraordinary gain (loss)................................. $ -- $ -- $ -- $ -- Cumulative effect of a change in accounting principle..... $ -- $ -- $ -- $ -- ------------ ------------ ------------ ------------ Net income (loss).............................. $ 0.20 $ 0.36 $ (0.01) $ 0.75 ============ ============ ============ ============ Diluted earnings (loss) per common share: Weighted average shares of common stock outstanding before dilutive effect of certain convertible securities........ 365,606 318,255 331,745 317,544 Income (loss) before dilutive effect of certain convertible securities, extraordinary gain (loss) and cumulative effect of a change in accounting principle.... $ 0.20 $ 0.34 $ (0.01) $ 0.72 Dilutive effect of certain convertible securities (1)..... $ (0.01) $ (0.02) $ -- $ (0.04) ------------ ------------ ------------ ------------ Income (loss) before extraordinary gain (loss) and cumulative effect of a change in accounting principle.... $ 0.19 $ 0.32 $ (0.01) $ 0.68 Extraordinary gain (loss)................................. $ -- $ -- $ -- $ -- Cumulative effect of a change in accounting principle..... $ -- $ -- $ -- $ -- ------------ ------------ ------------ ------------ Net income (loss).............................. $ 0.19 $ 0.32 $ (0.01) $ 0.68 ============ ============ ============ ============ ---------- (1) Includes the effect of the assumed conversion of certain dilutive convertible securities. No convertible securities were included in the six months ended 2002 amounts as the securities were antidilutive. For the three months ended June 30, 2002, and for the three and six months ended June 30, 2001, the assumed conversion calculation added 85,320, 41,964 and 49,379 shares of common stock and $11,306, $7,507 and $20,838 to the net income results, respectively.
The accompanying notes are an integral part of these consolidated condensed financial statements. -5- CALPINE CORPORATION AND SUBSIDIARIES Consolidated Condensed Statements of Cash Flows For the Six Months Ended June 30, 2002 and 2001 (In thousands) (unaudited)
Six Months Ended June 30, ------------------------------- 2002 2001 ------------- ------------- Cash flows from operating activities: Net income (loss)............................................................................ $ (1,751) $ 227,328 Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation, depletion and amortization.................................................. 244,540 148,552 Equipment cancellation cost............................................................... 168,471 -- Development cost write-off................................................................ 22,300 -- Deferred income taxes, net................................................................ 115,953 123,937 Gain on sale of assets.................................................................... (11,513) (10,750) Minority interests........................................................................ (948) 3,157 Income from unconsolidated investments in power projects.................................. (323) (2,163) Distributions from unconsolidated investments in power projects........................... 18 2,459 Change in operating assets and liabilities, net of effects of acquisitions: Accounts receivable..................................................................... (43,472) (315,344) Notes receivable........................................................................ (10,404) (43,624) Current derivative assets............................................................... 179,219 (1,048,198) Other current assets.................................................................... 197,001 (36,253) Long-term derivative assets............................................................. (100,835) (874,306) Other assets............................................................................ 6,025 (9,918) Accounts payable and accrued expense.................................................... (17,000) 131,502 Current derivative liabilities.......................................................... (152,199) 689,931 Long-term derivative liabilities........................................................ (241,903) 957,448 Other liabilities....................................................................... 56,006 42,471 Other comprehensive income relating to derivatives...................................... 54,260 103,744 ------------ ------------ Net cash provided by operating activities............................................ 463,445 89,973 ------------ ------------ Cash flows from investing activities: Purchases of property, plant and equipment................................................... (2,479,037) (2,557,041) Disposals of property, plant and equipment and investments in power projects................. 49,822 19,134 Advances to joint ventures................................................................... (43,823) (63,871) Decrease (increase) in notes receivable...................................................... 2,859 (93,723) Maturities of collateral securities.......................................................... 3,325 2,885 Project development costs.................................................................... (63,654) (55,314) Increase in restricted cash.................................................................. (27,814) (24,705) ------------ ------------ Net cash used in investing activities................................................ (2,558,322) (2,772,635) ------------ ------------ Cash flows from financing activities: Proceeds from issuance of Zero-Coupon Convertible Debentures Due 2021........................ -- 1,000,000 Repurchase of Zero-Coupon Convertible Debentures Due 2021.................................... (873,227) -- Borrowings from term loan notes payable and lines of credit.................................. 1,077,453 258 Repayments of notes payable and repayments under lines of credit............................. (87,465) (444,568) Borrowings from project financing............................................................ 280,248 1,479,673 Repayments of project financing.............................................................. (92,198) (1,234,433) Proceeds from issuance of Convertible Senior Notes Due 2006.................................. 100,000 -- Proceeds from issuance of senior notes....................................................... -- 2,650,000 Repayments of senior notes................................................................... -- (105,000) Proceeds from issuance of common stock....................................................... 751,172 49,369 Financing costs.............................................................................. (59,925) (64,534) Other........................................................................................ (1,789) (2,660) ------------ ------------ Net cash provided by financing activities............................................ 1,094,269 3,328,105 ------------ ------------ Effect of exchange rate changes on cash and cash equivalents.................................... 3,958 -- Net increase (decrease) in cash and cash equivalents............................................ (996,650) 645,443 Cash and cash equivalents, beginning of period.................................................. 1,525,417 596,077 ------------ ------------ Cash and cash equivalents, end of period........................................................ $ 528,767 $ 1,241,520 ============ ============ Cash paid during the period for: Interest, net of amounts capitalized......................................................... $ 59,809 $ (7,351) Income taxes................................................................................. $ 13,043 $ 114,083 The accompanying notes are an integral part of these consolidated condensed financial statements.
-6- CALPINE CORPORATION AND SUBSIDIARIES Notes to Consolidated Condensed Financial Statements June 30, 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 owns power facilities and oil and gas operations. In the United Kingdom, the Company owns a gas-fired power cogeneration facility. Each of the generation facilities produces and markets electricity for sale to utilities and other third party purchasers. Thermal energy produced by the gas-fired power cogeneration facilities is primarily sold to industrial users. Gas produced and not physically delivered to the Company's generating plants is sold to third parties. 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. 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. 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"). Use of Estimates in Preparation of Financial Statements -- The preparation of financial statements in conformity with generally accepted accounting principles in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expense during the reporting period. Actual results could differ from those estimates. The most significant estimates with regard to these financial statements relate to useful lives and carrying values of assets (including the carrying value of projects in development, construction and operation), provision for income taxes, fair value calculations of derivative instruments and 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 the Company's cogeneration sites. In addition, the Company acquires and produces natural gas for its own consumption and sells the balance and oil produced to third parties. 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, and optimization transactions, subject to market conditions, and CES has also, from time to time, entered into contracts considered energy trading contracts under Emerging Issues Task Force ("EITF") Issue No. 98-10 "Accounting for Contracts Involved in Energy Trading and Risk Management Activities." CES executes these transactions primarily through the use of physical forward commodity purchases and sales and financial commodity swaps and options. With respect to its physical forward contracts, CES generally acts as a principal, takes title to the commodities, and assumes the risks and rewards of ownership. Therefore, in accordance with Staff Accounting Bulletin No. 101, "Revenue Recognition in Financial Statements" and EITF Issue No. 99-19, "Reporting Revenue Gross as a Principal Versus Net as an Agent," CES recognizes revenue from settlement of its physical forward contracts on a gross basis. CES settles its financial swap and option transactions net and does not take title to the underlying commodity. Accordingly, CES records gains and losses from settlement of financial swaps and options net in income. Managed risks typically include commodity price risk associated with fuel purchases and power sales. -7- It is our policy not to engage in "roundtrip" trades. We have conducted a detailed analysis of our records looking for instances of transactions that may have the characteristics of "roundtrip" trades (i.e., trades with the same counterparty at the same time, price and location) for the period from January 1, 2000 through June 30, 2002, and have determined that while there were a very small number of transactions with such characteristics, there was no material impact on our financial statements from any such trades and none were conducted for the purpose of increasing trading volume, revenue, or market prices or for any other improper purpose. The Company, through its wholly owned subsidiary, 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: 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. Subject to market and other conditions, the Company manages the revenue stream for its portfolio of electric generating facilities. The Company markets on a system basis both power generated by its plants in excess of amounts under direct contract between the plant and a third party, and power purchased from third parties, through hedging, balancing, optimization and trading 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 include revenue from the settlement of contracts that had been previously recorded in results of operations as electric power derivative mark-to-market gains or losses prior to realization. Oil and Gas Production and Marketing Revenue -- This includes sales to third parties of oil, gas and related products that are produced by the Company's Calpine Natural Gas and Calpine Canada Natural Gas subsidiaries and, subject to market and other conditions, sales of purchased gas arising from hedging, balancing, optimization and trading transactions. Sales of purchased gas also include revenue from the settlement of contracts that had been previously recorded in results of operations as natural gas derivative mark-to-market gains or losses, prior to realization. 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, optimization and trading activities, along with costs from the subsequent settlement of contracts that had been previously recorded in results of operations as electric power derivative mark-to-market gains or losses, prior to realization, are 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, optimization and trading activities, along with costs from the subsequent settlement of contracts that had been previously recorded in results of operations as natural gas derivative mark-to-market gains or losses, prior to realization, are 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," and as further amended by SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities -- an Amendment of FASB Statement No. 133," together with 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 unless exempted from derivative treatment as a normal purchase and sale. 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. -8- SFAS No. 133 provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income ("OCI") and be reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, must be recognized currently in earnings. SFAS No. 133 provides that the changes in fair value of 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 perfectly effective, such amounts recorded in earnings will be equal and offsetting. 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 OCI, 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 the cumulative effect 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 OCI. 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. The 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 does not believe that SFAS No. 143 will have a material impact 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 has not had 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" stating that gains or losses from extinguishment of debt that fall outside of the scope of APB Opinion No. 30 should not be classified as extraordinary. 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 adoption encouraged. The Company has not completed its analysis but believes that SFAS No. 145 may have a material effect on the presentation of its financial statements but no impact on net income. -9- In June 2002 the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities," which addresses accounting for restructuring and similar costs. SFAS No. 146 supersedes previous accounting guidance, principally EITF Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (Including Certain Costs Incurred in a Restructuring)." The Company will adopt the provisions of SFAS No. 146 for restructuring activities initiated after December 31, 2002. SFAS No. 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. Under Issue No. 94-3, a liability for an exit cost was recognized at the date of commitment to an exit plan. SFAS No. 146 also establishes that the liability should initially be measured and recorded at fair value. Accordingly, SFAS No. 146 may affect the timing of recognizing future restructuring costs as well as the amounts recognized. The Company does not believe that SFAS No. 146 will have a material effect on its consolidated financial statements. In June 2002 the EITF reached a consensus on two of the three issues considered in EITF 02-03, "Recognition and Reporting of Gains and Losses on Energy Trading Contracts under EITF Issues No. 98-10, `Accounting for Contracts Involved in Energy Trading and Risk Management Activities' and No. 00-17, `Measuring the Fair Value of Energy-Related Contracts in applying Issue No. 98-10.'" The issues upon which the EITF reached a consensus required net presentation of energy trading contracts in a company's financial statements and required that companies make certain disclosures regarding their energy trading contracts. The net presentation requirement is effective for financial statements issued for periods ending after July 15, 2002, and the disclosure requirements are effective for financial statements issued for fiscal years ending after July 15, 2002. The Company is still assessing the impacts of adopting this standard on its financial statements, but believes that, at a minimum, all energy trading contracts will be reported net, rather than gross, upon adoption of this standard. The standard is expected to have a material impact on total revenues and expenses, but no impact on net income. Reclassifications -- Prior period amounts in the consolidated condensed financial statements have been reclassified where necessary to conform to the 2002 presentation. 3. Property, Plant and Equipment, and Capitalized Interest Property, plant and equipment, net, consisted of the following (in thousands):
June 30, December 31, 2002 2001 ------------- ------------- Buildings, machinery and equipment......................................... $ 7,382,378 $ 4,690,484 Oil and gas properties, including pipelines................................ 2,420,500 2,283,344 Geothermal properties...................................................... 393,472 371,156 Other...................................................................... 326,404 223,675 ------------ ------------ 10,522,754 7,568,659 Less: Accumulated depreciation, depletion and amortization............. (1,088,505) (855,065) ------------ ------------ 9,434,249 6,713,594 Land....................................................................... 90,794 80,506 Construction in progress................................................... 7,593,263 8,481,956 ------------ ------------ Property, plant and equipment, net......................................... $ 17,118,306 $ 15,276,056 ============ ============
Construction in progress is primarily attributable to gas-fired power projects under construction including prepayments on gas turbine generators and other long lead-time items of equipment for certain development projects not yet in construction. Upon commencement of plant operation, these costs are transferred to the applicable property category, generally buildings, machinery and equipment. In March 2002 the Company announced a change in its turbine and construction program that will slow the growth in the Company's construction in progress. See Note 13 for a discussion of the turbine order cancellations during the first quarter. During the second quarter of 2002, the Company reclassified $203.7 million of turbine costs from construction in progress to other assets, as the turbines will not be used for the Company's current power plant development program. The Company recorded a $14.2 million charge to project development expense to effect a reduction in the carrying value of such turbines. The Company currently anticipates that some of the turbines will be used for future power plants and others may be sold to third parties. The Company is now in negotiations to cancel or restructure the contracts for up to 89 units. The Company expects to complete these negotiations in the fourth quarter of 2002. The Company may also, subject to market conditions, take steps to further adjust or restructure turbine orders, including canceling additional turbine orders, consistent with the Company's power plant construction and development programs. -10- 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. During the three months ended June 30, 2002 and 2001, the total amount of interest capitalized was $171.0 million and $115.6 million, including $37.0 million and $31.2 million, respectively, of interest incurred on funds borrowed for specific construction projects and $134.0 million and $84.4 million, respectively, of interest incurred on general corporate funds used for construction. During the six months ended June 30, 2002 and 2001, the total amount of interest capitalized was $334.1 million and $219.6 million, including $72.1 million and $65.9 million, respectively, of interest incurred on funds borrowed for specific construction projects and $262.0 million and $153.7 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 2002, compared to 2001, reflects the significant increase in the Company's power plant construction program. However, the Company expects that the amount of interest capitalized will decrease in future periods as the power plants in construction are completed and as a result of the current suspension of certain of the Company's development projects. In accordance with SFAS No. 34, the Company determines which debt instruments best represent a reasonable measure of the cost of financing construction assets in terms of interest cost incurred that otherwise could have been avoided. These debt instruments and associated interest cost are included in the calculation of the weighted average interest rate used for capitalizing interest on general funds. The primary debt instruments included in the rate calculation are the Company's senior notes, the Company's term loan facility and the Company's revolving credit facilities. 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 was required to complete the initial step of a transitional impairment test within six months of adoption of SFAS No. 142 and to complete the final step of the transitional impairment test by the end of the fiscal year. Any future impairment losses will be reflected in operating income or loss in the consolidated statements of operations. The Company completed the transitional goodwill impairment test as required and determined that the fair value of the reporting units holding goodwill exceeded their net carrying values. Therefore, the Company did not record any impairment expense. 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):
Three Months Ended June 30, -------------------------------------------------------------------- 2002 2001 -------------------------------- -------------------------------- Per Share Per Share ------------------ ------------------ Amount Diluted Basic Amount Diluted Basic ---------- ------- ------ ---------- ------- ------ Reported income before extraordinary items and cumulative effect of accounting changes.... $ 72,516 $ 0.19 $ 0.20 $ 108,965 $ 0.32 $ 0.36 Add: Goodwill amortization...................... -- -- -- 205 -- -- Pro forma income before extraordinary items and cumulative effect of accounting changes.............. 72,516 0.19 0.20 109,170 0.32 0.36 Extraordinary items and cumulative effect of accounting changes, net of tax....................... -- -- -- (1,300) -- -- ---------- ------ ------ ---------- ------ ------ Pro forma net income............................ $ 72,516 $ 0.19 $ 0.20 $ 107,870 $ 0.32 $ 0.36 ========== ====== ====== ========== ====== ======
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Six Months Ended June 30, -------------------------------------------------------------------- 2002 2001 -------------------------------- -------------------------------- Per Share Per Share ------------------ ------------------ Amount Diluted Basic Amount Diluted Basic ---------- ------- ------ ---------- ------- ------ Reported income (loss) before extraordinary items and cumulative effect of accounting changes. $ (3,881) $(0.01) $(0.01) $ 227,592 $ 0.68 $ 0.75 Add: Goodwill amortization...................... -- -- -- 341 -- 0.01 Pro forma income (loss) before extraordinary items and cumulative effect of accounting changes.......... (3,881) (0.01) (0.01) 227,933 0.68 0.76 Extraordinary items and cumulative effect of accounting changes, net of tax....................... 2,130 -- -- (264) -- -- ---------- ------ ------ ---------- ------ ------ Pro forma net income (loss)..................... $ (1,751) $(0.01) $(0.01) $ 227,669 $ 0.68 $ 0.76 ========== ====== ====== ========== ====== ======
Recorded goodwill, by segment, as of June 30, 2002, was (in thousands): Electric Generation and Marketing........................ $ 29,348 Oil and Gas Production and Marketing..................... -- Corporate, Other and Eliminations........................ -- --------- Total................................................. $ 29,348 ========= Subsequent goodwill impairment tests will be performed, at a minimum, in the fourth quarter of each year, in conjunction with the Company's annual reporting process. 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 June 30, 2002 As of December 31, 2001 -------------------------- -------------------------- Weighted Average Useful Life/Contract Carrying Accumulated Carrying Accumulated Life Amount Amortization Amount Amortization ------------- ---------- ------------ ---------- ------------ Patents...................................... 5 $ 485 $ (182) $ 485 $ (134) Power sales agreements....................... 14 173,090 (100,103) 173,090 (88,178) Fuel supply and fuel management contracts.... 26 22,198 (3,660) 22,198 (3,216) Geothermal lease rights...................... 20 19,493 (300) 19,493 (250) Other........................................ 5 662 (47) 277 (25) ---------- ---------- ---------- ---------- Total..................................... $ 215,928 $ (104,292) $ 215,543 $ (91,803) ========== ========== ========== ==========
Amortization expense of other intangible assets was $6.2 million and $1.0 million in the three months ended June 30, 2002 and 2001, respectively, and $12.4 million and $2.0 million in the six months ended June 30, 2002 and 2001, respectively. Assuming no future impairments of these assets or additions as the result of acquisitions, annual amortization expense will be $22.0 million for the twelve months ended December 31, 2002, $5.9 million in 2003, $5.4 million in 2004, $5.3 million in 2005 and $5.2 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. This transaction resulted in a pre-tax other income gain of $9.7 million. The note was repaid in the second quarter of 2002. 6. Financing On January 31, 2002, the Company's subsidiary, Calpine Construction Management Company, Inc., entered into an agreement with Siemens Westinghouse Power Corporation to reschedule the production and delivery of gas and steam turbine generators and related equipment. Under the agreement, the Company obtained vendor financing of up to $232.0 million bearing variable interest for other gas and steam turbine generators and related equipment. The financing is -12- due prior to the earliest of the equipment site delivery date specified in the agreement, the Company's requested date of turbine site delivery or June 25, 2003. At March 31, 2002 and June 30, 2002, there were $0 and $47.4 million, respectively, in borrowings outstanding under this agreement. On April 30, 2002, the Company completed a registered offering of 66 million shares of its common stock at $11.50 per share. The proceeds from this offering, after underwriting fees, were $734.3 million. On April 30, 2002, the Company repurchased the remaining $685.5 million in aggregate principal amount of its Zero Coupon Convertible Debentures due 2021 ("Zero Coupons") at par pursuant to a scheduled put provided for by the terms of the Zero Coupons. On May 14, 2002, the Company's subsidiary, Calpine California Energy Finance, LLC, entered into an amended and restated credit agreement with ING Capital LLC for the funding of 9 California peaker facilities, of which $100.0 million was drawn on May 24, 2002. The total $100.0 million funding is classified as current project financing, of which $50.0 million was repaid on August 7, 2002, and $50.0 million will be payable on September 30, 2002. This peaker funding is part of the Company's expected long-term financing of its California peaker facilities which is anticipated to be $500.0 million. On May 31, 2002, the Company increased its two-year secured bank term loan to $1.0 billion from $600.0 million, and reduced the size of its secured corporate revolving credit facilities to $1.0 billion from $1.4 billion. At June 30, 2002, the Company has $1.0 billion in funded borrowings outstanding under the term loan facility, and $75.0 million in funded borrowings and $723.2 million outstanding in letters of credit under the revolving credit facility. In 2003 and 2004, $981.4 million and $2,452.7 million, respectively, under the Company's secured revolving construction financing facilities will mature, requiring the Company to refinance this indebtedness. 7. DePere Transaction On June 28, 2002, the Company executed a definitive agreement with Wisconsin Public Service for the sale of its 180-megawatt DePere Energy Center. This agreement is subject to certain conditions, including the receipt of regulatory approval by the State of Wisconsin, which is expected to be decided in September 2002. If the agreement is approved by regulatory authorities, Wisconsin Public Service would pay the Company $120.4 million for the DePere facility and the existing power purchase agreement would be terminated. 8. Derivative Instruments Commodity 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. 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. 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. From time to time the Company has entered into contracts considered energy trading contracts under EITF Issue No. 98-10. However, the Company's traders have low capital at risk and value at risk limits for energy trading, and its risk management policy limits, at any given time, its net sales of power to its generation capacity and limits its net purchases of gas to its fuel consumption requirements on a total portfolio basis. This model is markedly different from that of companies that engage in significant commodity trading operations that are unrelated to underlying physical assets. Derivative commodity instruments are accounted for under the requirements of SFAS No. 133 and EITF Issue No. 98-10. The Company also routinely enters into physical commodity contracts for sales of its generated electricity and sales of its natural gas production to ensure favorable utilization of generation and production assets. Such contracts often meet the criteria of SFAS No. 133 as derivatives but are generally eligible for the normal purchases and sales exception. Some of those that are not deemed normal purchases and sales can be designated as hedges of the underlying consumption of gas or production of electricity. -13- 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. On April 1, 2002, the Company adopted C16. At June 30, 2002, the Company had no fuel supply contracts to which C16 applies. However, one of the Company's equity method investees has fuel supply contracts subject to C16. The equity investee also adopted C16 on April 1, 2002. The contracts qualified as highly effective hedges of the equity method investee's forecasted purchase of gas. Accordingly, the Company has recorded $7.8 million net of tax as a cumulative effect of change in accounting principle to other comprehensive income for its share of the equity method investee's other comprehensive income from accounting change. Interest Rate and Currency Derivative Instruments 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 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. Summary of Derivative Values The table below reflects the amounts (in thousands) that are recorded as assets and liabilities at June 30, 2002, for the Company's derivative instruments:
Commodity Interest Rate Currency Derivative Total Derivative Derivative Instruments Derivative Instruments Instruments Net Instruments ------------- ----------- ----------- ----------- Current derivative assets............................... $ -- $ 199 $ 583,744 $ 583,943 Long-term derivative assets............................. -- 4,167 661,620 665,787 ----------- ----------- ----------- ----------- Total assets......................................... $ -- $ 4,366 $ 1,245,364 $ 1,249,730 =========== =========== =========== =========== Current derivative liabilities.......................... $ 10,178 $ 609 $ 462,353 $ 473,140 Long-term derivative liabilities........................ 12,483 -- 568,436 580,919 ----------- ----------- ----------- ----------- Total liabilities.................................... $ 22,661 $ 609 $ 1,030,789 $ 1,054,059 =========== =========== =========== =========== Net derivative assets (liabilities)............... $ (22,661) $ 3,757 $ 214,575 $ 195,671 =========== =========== =========== ===========
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 liability, thereby creating an imbalance between net OCI and net derivative assets and liabilities. -14- 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 instrument 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 of the Company's net derivative assets to its accumulated other comprehensive loss, net of tax from derivative instruments at June 30, 2002 (in thousands):
Net derivative assets......................................................................... $ 195,671 Derivatives not designated as cash flow hedges and recognized hedge ineffectiveness........... (165,955) Cash flow hedges terminated prior to maturity................................................. (277,804) Deferred tax asset attributable to accumulated other comprehensive loss on cash flow hedges... 81,474 Accumulated OCI from unconsolidated investees (1)............................................. 31,743 Other reconciling items....................................................................... 5,754 ---------- Accumulated other comprehensive loss from derivative instruments, net of tax.................. $ (129,117) ========== (1) Includes $12.8 million (pre-tax) relating to the cumulative effect of accounting change from unconsolidated investee. See discussion of New Accounting Pronouncements in Note 2 of the financial statements.
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 June 30, 2002. June 30, 2002 ------------------------------ Gross Net ------------ ------------ Current derivative assets..................... $ 1,733,012 $ 583,744 Long-term derivative assets................... 835,937 661,620 ------------ ------------ Total derivative assets.................... $ 2,568,949 $ 1,245,364 ============ ============ Current derivative liabilities................ $ 1,611,620 $ 462,353 Long-term derivative liabilities 742,754 568,436 ------------ ------------ Total derivative liabilities............... $ 2,354,374 $ 1,030,789 ============ ============ Net commodity derivative assets......... $ 214,575 $ 214,575 ============ ============ The table above excludes the value of interest rate and currency derivative instruments. The tables below reflect 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 and six months ended June 30, 2002 and 2001, respectively (in thousands): -15-
Three Months Ended June 30, ------------------------------------------------------------------------------------------- 2002 2001 ------------------------------------------ -------------------------------------------- Hedge Undesignated Hedge Undesignated Ineffectiveness Derivatives Total Ineffectiveness Derivatives Total --------------- ------------ ------- --------------- ----------- --------- Natural gas and crude oil derivatives....................... $ 990 $(4,193) $(3,203) $(3,998) $ 27,444 $ 23,446 Power derivatives.................. (1,002) 7,106 6,104 1,217 67,216 68,433 Interest rate derivatives (1)...... (188) -- (188) (17) -- (17) Foreign currency derivatives....... -- -- -- -- -- -- ------- ------- ------- ------- -------- --------- Total........................... $ (200) $ 2,913 $ 2,713 $(2,798) $ 94,660 $ 91,862 ======= ======= ======= ======== ======== ========= Six Months Ended June 30, ------------------------------------------------------------------------------------------- 2002 2001 ------------------------------------------ -------------------------------------------- Hedge Undesignated Hedge Undesignated Ineffectiveness Derivatives Total Ineffectiveness Derivatives Total --------------- ------------ ------- --------------- ----------- --------- Natural gas and crude oil derivatives....................... $(1,605) $(7,990) $(9,595) $(3,472) $ 34,467 $ 30,995 Power derivatives.................. (1,224) 11,494 10,270 -- 69,739 69,739 Interest rate derivatives (1)...... (340) -- (340) (17) -- (17) Foreign currency derivatives....... -- -- -- -- -- -- ------- ------- ------- ------- -------- --------- Total........................... $(3,169) $ 3,504 $ 335 $(3,489) $104,206 $ 100,717 ======= ======= ======= ======= ======== ========= (1) Recorded within Other Income
For the three and six months ended June 30, 2002 and 2001, the Company's realized commodity cash flow hedge activity contributed $36.0 million and $86.8 million, respectively, and $4.8 million and $21.8 million, respectively, to pre-tax earnings based on the reclassification adjustment from OCI to earnings. For the three and six months ended June 30, 2002 and 2001, power hedges contributed $75.3 million and $161.8 million, respectively, and $3.1 million and $(6.2) million, respectively, to pre-tax earnings. For the three and six months ended June 30, 2002 and 2001, gas and crude oil hedges contributed $(39.3) million and $(75.0) million, respectively, and $1.7 million and $28.0 million, respectively, to pre-tax earnings. For the three and six months ended June 30, 2002, interest rate hedges contributed $(2.6) million and $(4.6) million, respectively, to pre-tax earnings. For the three and six months ended June 30, 2002, currency hedges contributed $(2.8) million and $(2.8) million, respectively, to pre-tax earnings. For the three and six months ended June 30, 2001, interest rate hedges and currency hedges did not impact the Company's pre-tax earnings. As of June 30, 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, 6 1/2, and 12 years, for commodity, foreign currency and interest rate derivative instruments, respectively. The Company estimates that pre-tax gains of $13.8 million would be reclassified from accumulated OCI into earnings during the twelve months ended June 30, 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. -16- 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................. $ (1,024) $ -- $ -- $ -- $ -- $ -- $ (1,024) Gas OCI....................... (48,633) (188,244) (56,318) (56,760) (11,607) 13,092 (348,470) Power OCI..................... 141,834 67,361 6,318 1,908 6,586 (818) 223,189 Interest rate OCI............. (9,273) (14,763) (11,112) (9,435) (8,607) (25,698) (78,888) Foreign currency OCI.......... (238) (781) (554) (589) (553) (2,683) (5,398) --------- --------- --------- -------- -------- -------- --------- Total OCI.................. $ 82,666 $(136,427) $(61,666) $(64,876) $(14,181) $(16,107) $(210,591) ========= ========= ======== ======== ======== ======== =========
9. 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 cash flow 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 Income (Loss) At June 30, 2002 ------------------------------------------------------------------- Foreign Cash Flow Currency Comprehensive Hedges Translation Total Income / (Loss) ----------- ----------- ----------- --------------- Net loss for the three months ended March 31, 2002............ $ (74,267) Accumulated other comprehensive loss at December 31, 2001............................................ $ (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 Reclassification adjustment for gain included in net loss for the three months ended March 31, 2002......... (48,699) Income tax provision for the three months ended March 31, 2002......................................... (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) ---------- ---------- ---------- Total comprehensive loss for the three months ended March 31, 2002............................................... $ (55,679) ========== Accumulated other comprehensive loss at March 31, 2002........ $ (139,619) $ (68,367) $ (207,986) ========== ========== ========== Net income for the three months ended June 30, 2002........... $ 72,516 Accumulated other comprehensive loss at March 31, 2002........ $ (139,619) $ (68,367) $ (207,986) Cash flow hedges: Comprehensive pre-tax gain on cash flow hedges before reclassification adjustment during the three months ended June 30, 2002............................. 47,855 Reclassification adjustment for gain included in net income for the three months ended June 30, 2002....... (30,617) Income tax provision for the three months ended June 30, 2002.......................................... (6,736) ---------- 10,502 10,502 10,502 Foreign currency translation gain for the three months ended June 30, 2002....................................... 78,777 78,777 78,777 ---------- ---------- ---------- ---------- Total comprehensive income for the three months ended June 30, 2002................................................ 161,795 ---------- Total comprehensive income for the six months ended June 30, 2002................................................ $ 106,116 ========== Accumulated other comprehensive income/(loss) at June 30, 2002................................................ $ (129,117) $ 10,410 $ (118,707) ========== ========== ==========
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Accumulated Other Comprehensive Income (Loss) At June 30, 2001 ------------------------------------------------------------------- Foreign Cash Flow Currency Comprehensive Hedges Translation Total Income / (Loss) ----------- ----------- ----------- --------------- Net income for the three months ended March 31, 2001 $ 119,663 Accumulated other comprehensive loss at December 31, 2000............................................ $ -- $ (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) Reclassification adjustment for gain included in net loss for the three months ended March 31, 2001......... (17,047) Income tax provision for the three months ended March 31, 2001......................................... 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 ---------- ---------- ---------- ---------- Total comprehensive income for the three months ended March 31, 2001............................................... $ 80,787 ========== Accumulated other comprehensive loss at March 31, 2001........ $ (53,570) $ (8,391) $ (61,961) ========== ========== ========== Net income for the three months ended June 30, 2001........... $ 107,665 Accumulated other comprehensive loss at March 31, 2001........ $ (53,570) $ (8,391) $ (61,961) Cash flow hedges: Comprehensive pre-tax gain on cash flow hedges before reclassification adjustment during the three months ended June 30, 2001............................. 263,714 Reclassification adjustment for gain included in net income for the three months ended June 30, 2001........ (4,745) Income tax provision for the three months ended June 30, 2001.......................................... (102,047) ---------- 156,922 156,922 156,922 Foreign currency translation loss for the three months ended June 30, 2001....................................... (16,550) (16,550) (16,550) ---------- ---------- ---------- ---------- Total comprehensive income for the three months ended June 30, 2001................................................ 248,037 ---------- Total comprehensive income for the six months ended June 30, 2001................................................ $ 328,824 ========== Accumulated other comprehensive income (loss) at June 30, 2001................................................ $ 103,352 $ (24,941) $ 78,411 ========== ========== ==========
10. 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, the terms of which extended out as far as 2009. On December 2, 2001, Enron Corp. and certain of its subsidiaries, including EPMI and ENA, filed voluntary petitions for Chapter 11 reorganization with the U.S. Bankruptcy Court for the Southern District of New York. The Company 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 and six months ended June 30, 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): -18-
For the Three Months Ended For the Six Months Ended June 30, 2001 June 30, 2001 -------------------------- -------------------------- Dollar Volume Dollar Volume --------- ---------- --------- ---------- Electric generation and marketing revenue (electricity and steam revenue and sales of purchased power)................. $ 264,716 2,869 $ 348,891 4,162 Oil and gas production and marketing revenue (sales of purchased gas).............................................. 92,969 9,315 146,259 11,369 Other revenue................................................ 676 -- 2,050 -- --------- --------- Total power and fuel and other revenue from Enron......... $ 358,361 $ 497,200 --------- --------- Electric generation and marketing expense (purchased power expense).............................................. $ 254,340 2,119 $ 365,226 3,401 Fuel expense (cost of oil and natural gas burned by power plants and natural gas derivative mark-to-market gain)...... 70,475 10,626 87,405 13,043 --------- --------- Total CES power and fuel expenses related to Enron (1)..... $ 324,815 $ 452,631 ========= ========= ---------- (1) Expenses of CES only, as other Enron expenses incurred are not material.
The Company has terminated all of its open forward positions with ENA and EPMI, 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 net amounts associated with terminated ENA and EPMI forward contracts have been included within the Company's accounts payable. During 2001 and prior to the termination of its forward contracts with ENA and EPMI, certain of the Company's ENA and EPMI contracts had been designated as cash flow hedges. Accordingly, prior to termination of these positions, balances had accumulated in OCI. As of June 30, 2002, the Company had remaining unrealized pre-tax losses of $183.4 million on derivatives previously designated as effective cash flow hedges. 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, optimization and trading 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. After netting the receivables from and payables to ENA and EPMI, based on certain assumptions, the Company has calculated an existing or future obligation to Enron of approximately $143.5 million as of June 30, 2002, which obligation the Company expects will be offset by CES' losses, damages, attorneys' fees and other expenses arising from the default by Enron, and which amount is included in the Company's accounts payable balance at June 30, 2002. Nevada Power and Sierra Pacific Power Company During the first quarter of 2002, two subsidiaries of Sierra Pacific Resources Company, Nevada Power Company ("NPC") and Sierra Pacific Power Company ("SPPC"), received credit downgrades to sub-investment grades from the major credit rating agencies. Additionally, NPC acknowledged 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 has requested that its power suppliers extend payment terms to help it overcome its short-term liquidity problems. During the second quarter of 2002, NPC indicated to its power suppliers that it was experiencing cash flow difficulties. In June and July 2002 NPC underpaid the Company by approximately $4.2 million, and the Company expects that NPC will underpay the Company by approximately an additional $18.4 million this summer and early fall, with repayments of deferred amounts beginning at some point thereafter once NPC's cash flow stabilizes. In consideration of the uncertainty surrounding NPC's ability to make timely payments, the Company is maintaining a bad debt reserve of approximately $2.7 million against NPC receivables, which will be closely monitored. In addition, NPC and SPPC filed with the Federal Energy Regulatory Commission ("FERC") under Section 206 of the Federal Power Act - see Note 13 for further discussion. -19- As of June 30, 2002, the Company had net collection exposures of approximately $34.8 million and $20.2 million with NPC and SPPC, respectively. However, SPPC is paying the Company currently. The Company's exposures include open forward power contracts that are reported at fair value on the Company's balance sheet as well as receivable and payable balances relating to prior 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 June 30, 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.
Receivables/Payables Fair Values -------------------------------------- ----------------------------------------------------- Net Gross Gross Net Open Gross Gross Receivable Fair Value Fair Value Positions Receivable Payable (Payable) (+) (-) Value Total ---------- --------- ---------- ---------- ----------- --------- ------- NPC........................... $ 23.6 $ (18.7) $ 4.9 $ 74.6 $ (44.7) $ 29.9 $ 34.8 SPPC.......................... 1.4 -- 1.4 18.8 -- 18.8 20.2 ------- ------- ------- ------- ------- ------- ------- Total...................... $ 25.0 $ (18.7) $ 6.3 $ 93.4 $ (44.7) $ 48.7 $ 55.0 ======= ======= ======= ======= ======= ======= =======
Under the terms of its contracts with NPC and SPPC, the Company believes that it has the right to offset asset and liability positions. PSM License Receivable In December 2001 PSM and a Dutch power services company entered into a perpetual world-wide license agreement for certain PSM proprietary reverse-flow venturi technology. The license fee, while earned upfront, is payable over the period from January 2002 through March 2004. The Company recognized the license fee of $11 million (less imputed interest on the receivable) as income in December 2001. As of the date of this filing, the Company has a receivable of $7 million, with no payments currently past due. The indirect parent of the Dutch company, a German holding company, filed for insolvency in Germany in July 2002 and the direct parent of the Dutch company is expected to also file for insolvency. However, the Dutch company has assured the Company that it has not and currently does not expect to file for insolvency in the near term. The Company has been further assured in a letter from the German holding company dated July 11, 2002, that the Dutch company expects to continue the license arrangement and to meet its obligations thereunder. Based on the Company's evaluation of these and other factors, a loss does not seem probable at this time. Accordingly, the Company has not established a reserve against the related receivable but will continue to closely monitor the situation. Credit Evaluations 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 analyzed 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. 11. 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 interest expense and 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). -20-
Periods Ended June 30, --------------------------------------------------------------------------- 2002 2001 ---------------------------------- ------------------------------------ Net Net Income Shares EPS Income Shares EPS --------- -------- ------ --------- -------- ------- THREE MONTHS: Basic earnings per common share: Income before extraordinary loss and cumulative effect of a change in accounting principle......................................... $ 72,516 356,158 $ 0.20 $ 108,965 302,729 $ 0.36 Extraordinary loss, net of tax..................... -- -- -- (1,300) -- -- Cumulative effect of a change in accounting principle, net of tax............................. -- -- -- -- -- -- --------- ------- ------ --------- ------- ------ Net income ................................... $ 72,516 356,158 $ 0.20 $ 107,665 302,729 $ 0.36 ========= ------- ====== ========= ------- ====== Diluted earnings per common share: Common shares issuable upon exercise of stock options using treasury stock method............... 9,448 15,526 ------- ------- Income before dilutive effect of certain convertible securities, extraordinary loss and cumulative effect of a change in accounting principle......................................... $ 72,516 365,606 0.20 $ 108,965 318,255 $ 0.34 Dilutive effect of certain convertible securities.. 11,306 85,320 (0.01) 7,507 41,964 (0.02) --------- ------- ------ --------- ------- ------ Income before extraordinary loss and cumulative effect of a change in accounting principle......................................... 83,822 450,926 0.19 116,472 360,219 0.32 Extraordinary loss, net of tax..................... -- -- -- (1,300) -- -- Cumulative effect of a change in accounting principle, net of tax............................. -- -- -- -- -- -- --------- ------- ------ --------- ------- ------ Net income ................................... $ 83,822 450,926 $ 0.19 $ 115,172 360,219 $ 0.32 ========= ======= ====== ========= ======= ====== Periods Ended June 30, --------------------------------------------------------------------------- 2002 2001 ---------------------------------- ------------------------------------ Net Net Income Income (Loss) Shares EPS (Loss) Shares EPS --------- -------- ------ --------- -------- ------- SIX MONTHS: Basic earnings (loss) per common share: Income (loss) before extraordinary gain (loss) and cumulative effect of a change in accounting principle......................................... $ (3,881) 331,745 $(0.01) $ 227,592 301,641 $ 0.75 Extraordinary gain (loss), net of tax.............. 2,130 -- -- (1,300) -- -- Cumulative effect of a change in accounting principle, net of tax............................. -- -- -- 1,036 -- -- --------- ------- ------ --------- ------- ------ Net income (loss)............................. $ (1,751) 331,745 $(0.01) $ 227,328 301,641 $ 0.75 ========= ------- ====== ========= ------- ====== Diluted earnings (loss) per common share: Common shares issuable upon exercise of stock options using treasury stock method............... -- 15,903 ------- ------- Income (loss) before dilutive effect of certain convertible securities, extraordinary gain (loss) and cumulative effect of a change in accounting principle......................................... $ (3,881) 331,745 $(0.01) $ 227,592 317,544 $ 0.72 Dilutive effect of certain convertible securities.. -- -- -- 20,838 49,379 (0.04) --------- ------- ------ --------- ------- ------ Income (loss) before extraordinary gain (loss) and cumulative effect of a change in accounting principle......................................... (3,881) 331,745 (0.01) 248,430 366,923 0.68 Extraordinary gain (loss), net of tax.............. 2,130 -- -- (1,300) -- -- Cumulative effect of a change in accounting principle, net of tax............................. -- -- -- 1,036 -- -- --------- ------- ------ --------- ------- ------ Net income (loss)............................. $ (1,751) 331,745 $(0.01) $ 248,166 366,923 $ 0.68 ========= ======= ====== ========= ======= ======
-21- For the three and six months ended June 30, 2002 and for the three and six months ended June 30, 2001, respectively, the effect of 38,237, 145,819, 25,886 and 13,597 thousand unexercised employee stock options, Company-obligated mandatorily redeemable convertible preferred securities of subsidiary trusts, Zero Coupons and Convertible Senior Notes Due 2006, were not included in the computation of diluted shares outstanding because such inclusion would have been antidilutive. 12. Stock Compensation The Company accounts for qualified stock compensation under APB Opinion No. 25, "Accounting for Stock Issued to Employees." Had compensation cost been determined consistent with the methodology of SFAS No. 123, "Accounting for Stock-Based Compensation," which provides for the accounting of options as compensation expense, the Company's net income (loss) and earnings (loss) per share would have been changed to the following pro forma amounts (in thousands, except per share amounts):
Three Months Ended Six Months Ended June 30, June 30, ------------------------- --------------------------- 2002 2001 2002 2001 -------- --------- --------- --------- Net income (loss) As reported............................................ $ 72,516 $ 107,665 $ (1,751) $ 227,328 Pro Forma.............................................. 67,543 99,650 (15,585) 212,020 Earnings (loss) per share data: Basic earnings (loss) per share As reported............................................ $ 0.20 $ 0.36 $ (0.01) $ 0.75 Pro Forma.............................................. 0.19 0.33 (0.05) 0.70 Diluted earnings (loss) per share As reported............................................ $ 0.19 $ 0.32 $ (0.01) $ 0.68 Pro Forma.............................................. 0.17 0.30 (0.05) 0.64
For the three and six months ended June 30, 2002 and 2001, respectively, the fair value of options granted was $9.76 and $7.74, and $39.01 and $35.36 on the dates of grant using the Black-Scholes option pricing model with the following weighted-average assumptions: expected dividend yields of 0%, expected volatility of 97% for the three and six months ended June 30, 2002, and 64% for the three and six months ended June 30, 2001, risk-free interest rates of 4.86% for the three and six months ended June 30, 2002, and 5.42% for the three and six months ended June 30, 2001, and expected lives of 10 years for the three and six months ended June 30, 2002 and 2001, respectively. 13. 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 order cancellations. 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-- Securities Derivative Lawsuit. On December 17, 2001, a shareholder filed a derivative lawsuit on behalf of the Company against its directors and one of its senior officers. This lawsuit is captioned Johnson v. Cartwright, et al. (No. CV803872), and is pending in the California Superior Court, Santa Clara County. The Company is a nominal defendant in this lawsuit, which alleges claims relating to purportedly misleading statements about the Company and stock sales by certain of the director defendants and the officer defendant. The Company 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 the Company. 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. The Company considers this lawsuit to be without merit and intends to vigorously defend against it. Securities Class Action Lawsuits. Fourteen shareholder lawsuits have been filed against the Company and certain of its officers in the United States District Court, Northern District of California. The actions captioned Weisz v. 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 -22- December 13, 2001. The eleven other actions, captioned Local 144 Nursing Home Pension Fund v. Calpine Corp., Lukowski v. Calpine Corp., Hart v. Calpine Corp., Atchison v. Calpine Corp., 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 the Company'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 Calpine executives issued false and misleading statements about the Company'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. The Company expects 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. In addition, a fifteenth securities class action, Ser v. Calpine, et al., was filed on May 13, 2002. The underlying allegations in the Ser action are substantially the same to those in the above-referenced actions. However, the Ser action is brought on behalf of a purported class of purchasers of the Company's 8.5% Senior Notes due February 15, 2011 ("2011 Notes"), and the alleged class period is October 15, 2001, through December 13, 2001. The Ser complaint alleges that, in violation of Sections 11 and 15 of the Securities Act of 1933, the Prospectus Supplement dated October 11, 2001, for the 2011 Notes contained false and misleading statements regarding the Company's financial condition. This action names the Company, certain of its officers and directors, and the underwriters of the 2011 Notes offering as defendants, and seeks an unspecified amount of damages, in addition to other forms of relief. The Company expects that this action will either be consolidated with the above-referenced actions or will proceed as a parallel related action before the same judge presiding over the other actions. The Company considers the allegations against Calpine in each of these lawsuits to be without merit, and intends to defend vigorously against them. California Business & Professions Code Section 17200 Cases. The lead case, T&E Pastorino Nursery v. Duke Energy Trading and Marketing, L.L.C., et al., was served on May 2, 2002, by T&E Pastorino Nursery, on behalf of itself and all others similarly situated. This purported class action complaint against twenty energy traders and energy companies including CES, alleges that defendants exercised market power and manipulated prices in violation of California Business & Professions Code Section 17200 et seq., and seeks injunctive relief, restitution and attorneys' fees. The Company also has been named in five other similar complaints for violations of Section 17200 captioned Bronco Don Holdings, LLP. v. Duke Energy Marketing and Trading, et al.; Century Theatres, Inc. v. Allegheny Energy Supply Company, LLC; RDJ Farms, Inc. v. Allegheny Energy Supply Company, LLC; J&M Karsant Family Limited Partnership v. Duke Energy Trading and Marketing, LLC; and Leo's Day and Night Pharmacy v. Duke Energy Trading and Marketing, LLC. All six of these cases have been removed in a multidistrict litigation proceeding from the various state courts in which they were originally filed to federal court, where a motion is now pending to transfer and consolidate these cases for pretrial proceedings with other cases in which the Company is not named as a defendant. In addition, plaintiffs in the T&E Pastorino Nursery case have filed a motion to remand that matter to California state court. The Company considers the allegations against Calpine in each of these lawsuits to be without merit, and intends to vigorously defend against them. California Department of Water Resources Case. On May 1, 2002, California State Senator Tom McClintock and others filed a complaint against Vikram Budhraja, a consultant to the California Department of Water Resources ("DWR"), DWR itself, and more than twenty-nine energy providers and other interested parties, including the Company. The complaint alleges that the long-term power contracts that DWR entered into with these energy providers, including the Company, are rendered void because Budhraja, who negotiated the contracts on behalf of DWR, allegedly had an undisclosed financial interest in the contracts due to his connection to one of the energy providers, Edison International. Among other things, the complaint seeks an injunction prohibiting further performance of the long-term contracts and restitution of any funds paid to energy providers by the State of California under the contracts. The Company considers the allegations against Calpine in this lawsuit to be without merit, and intends to vigorously defend against them. Nevada Section 206 Complaint. On December 4, 2001, NPC and SPPC filed a complaint with the FERC under Section 206 of the Federal Power Act against a number of parties to their power sales agreements, including the Company. NPC and SPPC allege in their complaint, which seeks a refund, that the prices they -23- agreed to pay in certain of the power sales agreements, including those signed with the Company, were negotiated during a time when the power market was dysfunctional and that they are unjust and unreasonable. The Company considers the complaint to be without merit and is vigorously defending against it. Emissions Credits Lawsuit. As described in previous reports, on March 5, 2002, the Company sued Automated Credit Exchange ("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 the Company's account with U.S. Trust Company ("US Trust"). the Company and ACE entered into a settlement agreement on March 29, 2002, pursuant to which ACE made a payment to the Company of $7 million and transferred to the Company the rights to the emission reduction credits to be held by ACE. The Company dismissed its complaint against ACE. The Company recognized the $7 million in the second quarter of 2002. In June 2002 a complaint was filed by InterGen North America, L.P. ("InterGen"), against Anne M. Sholtz, the owner of ACE, and EonXchange, another Sholtz-controlled entity, which filed for bankruptcy protection on May 6, 2002. InterGen alleges it suffered a loss of emission reduction credits from EonXchange in a manner similar to the the Company's loss from ACE. InterGen's complaint alleges that Anne Sholtz co-mingled assets among ACE, EonXchange and other Sholtz entities and that ACE and other Sholtz entities should be deemed to be one economic enterprise and all retroactively included in the EonXchange bankruptcy filing as of May 6, 2002. InterGen's complaint refers to the payment by ACE of $7 million to the Company, alleging that InterGen's ability to recover from EonXchange has been undermined thereby. The Company is unable to assess the likelihood of InterGen's complaint being upheld at this time. The Company is involved in various other claims and legal actions arising out of the normal course of its business. The Company does not expect that the outcome of these proceedings will have a material adverse effect on the Company's financial position or results of operations. 14. Operating Segments 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, balancing, optimization and trading 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, balancing, optimization and trading 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 June 30, 2002 and 2001: Revenue............................ $1,582,351 $1,261,705 $494,831 $381,983 $(135,376) $(30,815) $1,941,806 $1,612,873 Income (loss) before taxes and extraordinary charge.............. 77,263 167,518 59,801 55,278 (28,989) (43,982) 108,075 178,814 Merger expense..................... -- -- -- 35,606 -- -- -- 35,606 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 six months ended June 30, 2002 and 2001: Revenue............................ $3,116,494 $2,312,334 $731,179 $713,811 $(167,520) $(73,521) $3,680,153 $2,952,624 Income (loss) before taxes and extraordinary charge.............. 31,077 295,309 72,865 171,813 (113,401) (80,700) (9,459) 386,422 Merger expense..................... -- -- -- 41,627 -- -- -- 41,627 Equipment cancellation cost........ 168,471 -- -- -- -- -- 168,471 --
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Electric Oil and Gas Generation Production Corporate, Other and Marketing and Marketing and Eliminations Total ------------- ------------- ---------------- ----------- (in thousands) Total assets: June 30, 2002.................................... $14,040,562 $3,706,453 $4,482,721 $22,229,736 December 31, 2001................................ $12,572,848 $3,503,075 $5,253,629 $21,329,552
For the three months ended June 30, 2002 and 2001, there were intersegment revenues of approximately $140.6 million and $39.0 million, respectively. For the six months ended June 30, 2002 and 2001, there were intersegment revenues of approximately $177.3 million and $84.9 million, respectively. The elimination of these intersegment revenues, which primarily relate to the use of internally procured gas for the Company's power plants, are included in the Corporate and Other reporting segment. 15. California Power Market On April 22, 2002, the Company announced that it had renegotiated CES' long-term power contracts with DWR. The Office of the Governor of California, the California Public Utilities Commission (the "CPUC"), the California Electricity Oversight Board (the "EOB") and the California Attorney General (the "AG") endorsed the renegotiated contracts and agreed to drop all pending claims against the Company and its affiliates, including withdrawing the complaint under Section 206 of the Federal Power Act that had been filed by the CPUC and EOB with FERC, and the termination by the CPUC and the EOB of 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. CES had signed three long-term contracts with DWR in February 2001, comprising two 10-year baseload energy contracts and one 20-year peaking contract. The renegotiation provided for the shortening of the duration of each of the two 10-year, baseload energy contracts by two years and of the 20-year peaker contract by ten years. These changes reduced 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 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 also agreed with DWR that DWR will have the right to assume and complete four of the Company's 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. In addition, the negotiation resolved the dispute with DWR concerning payment of the capacity payment on the peaking contract. 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 had 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, 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. 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) the timing and extent of deregulation of energy markets and the rules and regulations adopted on a transitional basis with respect thereto (ii) the timing and extent of changes in commodity prices for energy, particularly natural gas and electricity (iii) commercial operations of new plants that may be delayed or prevented because of various development and construction risks, such as a failure to obtain the necessary permits to operate, failure of third-party -25- contractors to perform their contractual obligations or failure to obtain financing on acceptable terms (iv) unscheduled outages of operating plants (v) unseasonable weather patterns that produce reduced demand for power (vi) systemic economic slowdowns, which can adversely affect consumption of power by businesses and consumers (vii) cost estimates are preliminary and actual costs may be higher than estimated (viii) a competitor's development of lower-cost generating gas-fired power plants (ix) risks associated with marketing and selling power from power plants in the newly-competitive energy market (x) the successful exploitation of an oil or gas resource that ultimately depends upon the geology of the resource, the total amount and costs to develop recoverable reserves and operations factors relating to the extraction of natural gas (xi) the effects on the Company's business resulting from reduced liquidity in the trading and power industry (xii) the Company's ability to access the capital markets on attractive terms (xiii) sources and uses of cash are estimates based on current expectations; actual sources may be lower and actual uses may be higher than estimated (xiv) the direct or indirect effects on the Company's business of a lowering of its credit rating (or actions it may take in response to changing credit rating criteria), including, increased collateral requirements, refusal by the Company's current or potential counterparties to enter into transactions with it and its inability to obtain credit or capital in desired amounts or on favorable terms. All information set forth in this filing is as of August 9, 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. We file annual, quarterly and special reports, proxy statements and other information with the SEC. You may obtain and copy any document we file with the SEC at the SEC's public reference rooms in Washington, D.C., Chicago, Illinois and New York, New York. You may obtain information on the operation of the SEC's public reference facilities by calling the SEC at 1-800-SEC-0330. You can request copies of these documents, upon payment of a duplicating fee, by writing to the SEC at its principal office at 450 Fifth Street, N.W., Washington, D.C. 20549-1004. Our SEC filings are also accessible through the Internet at the SEC's website at http://www.sec.gov. Our reports on Forms 10-K, 10-Q and 8-K are available for download, free of charge, as soon as reasonably practicable, at our website at www. calpine.com. The content of our website is not a part of this report. You may request a copy of these filings, at no cost to you, by writing or telephoning us at: Calpine Corporation, 50 West San Fernando Street, San Jose, California 95113, attention: Lisa M. Bodensteiner, Assistant Secretary, telephone: (408) 995-5115. We will not send exhibits to the documents, unless the exhibits are specifically requested and you pay our fee for duplication and delivery. Selected Operating Information Set forth below is certain selected operating information for our power plants and steam fields, for which results are consolidated in our statements of operations. Results vary for the three and six months ended June 30, 2002, as compared to the same periods in 2001, for the reasons discussed more fully throughout this Management's Discussion and Analysis of Financial Condition and Results of Operations. 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 Six Months Ended June 30, June 30, ----------------------------- ------------------------------ 2002 2001 2002 2001 ------------ ------------ ------------ ------------ (in thousands, except production and pricing data) Power Plants: Electricity and steam ("E&S") revenue: Energy................................................. $ 409,415 $ 345,960 $ 922,519 $ 781,341 Capacity............................................... 257,107 127,595 332,497 245,323 Thermal and other...................................... 42,230 32,156 73,915 74,206 ------------ ------------ ------------ ------------ Subtotal............................................. $ 708,752 $ 505,711 $ 1,328,931 $ 1,100,870 Spread on sales of purchased power (1).................... 169,611 26,801 262,750 25,453 ------------ ------------ ------------ ------------ Adjusted E&S revenues..................................... $ 878,363 $ 532,512 $ 1,591,681 $ 1,126,323 Megawatt hours produced................................... 15,720,000 7,878,000 30,434,000 15,117,000 All-in electricity price per megawatt hour generated...... $ 55.88 $ 67.59 $ 52.30 $ 74.51 --------- (1) From hedging, balancing and optimization activities related to our generating assets. The spread on trading activities is excluded.
-26- Credit restrictions on certain Calpine Energy Services, L.P. ("CES") activities in 2002 could negatively impact the volume of hedging, balancing and optimization activities in the future. Megawatt hours produced at the power plants increased 100% and 101% for the three and six months ended June 30, 2002, as compared to the same periods in 2001. This was primarily due to the addition of power plants that were either acquired or commenced commercial operation subsequent to June 30, 2001. The decrease in average all-in electricity price per megawatt hour generated in 2002 reflects the softening market conditions in 2002 for power. The information above is related to our generating assets and excludes trading activities which are discussed in the Results of Operations and Performance Metrics below. The increase in electricity and steam revenues due to the addition of power plants was moderated by the reduction in CES's trading activities due to current market conditions. However, we will evaluate alternatives as they are identified for relationships with potential partners to strengthen our ability to conduct risk management activities and to support the credit requirements of its trading activities, but will proceed only if any such arrangement adds value to us. Results of Operations Set forth below is a table summarizing the dollar amounts and percentages of our total revenue for the three and six months ended June 30, 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 percentage data):
Three Months Ended Six Months Ended June 30, June 30, ----------------------------- ------------------------------ 2002 2001 2002 2001 ------------ ------------ ------------ ------------ Total revenue................................................. $ 1,941,806 $ 1,612,873 $ 3,680,153 $ 2,952,624 Sales of purchased power...................................... 868,606 683,196 1,776,907 1,136,798 As a percentage of total revenue.............................. 44.7% 42.4% 48.3% 38.5% Sales of purchased gas........................................ 302,044 226,693 434,202 355,865 As a percentage of total revenue.............................. 15.6% 14.1% 11.8% 12.1% Total cost of revenue ("COR")................................. 1,685,500 1,308,648 3,245,883 2,372,831 Purchased power expense....................................... 698,176 655,322 1,513,181 1,111,588 As a percentage of total COR.................................. 41.4% 50.1% 46.6% 46.8% Purchased gas expense......................................... 333,724 218,330 457,418 336,958 As a percentage of total COR.................................. 19.8% 16.7% 14.1% 14.2%
The accounting requirements under Staff Accounting Bulletin ("SAB") 101, "Revenue Recognition in Financial Statements" and Emerging Issues Task Force ("EITF") Issue No. 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 Six Months Ended June 30, June 30, ----------------------------- ------------------------------ 2002 2001 2002 2001 ------------ ------------ ------------ ------------ (in thousands) Sales into NEPOOL ISO from power we generated................ $ 63,455 $ 61,892 $ 114,036 $ 121,456 Sales into NEPOOL ISO from hedging and other activity........ 20,148 21,688 44,805 56,644 --------- --------- ---------- ---------- Total sales into NEPOOL ISO............................... $ 83,603 $ 83,580 $ 158,841 $ 178,100 Total purchases from NEPOOL ISO........................... $ 85,344 $ 81,317 $ 161,178 $ 166,560
-27- Three Months Ended June 30, 2002, Compared to Three Months Ended June 30, 2001. Revenue -- Total revenue increased to $1,941.8 million for the three months ended June 30, 2002, compared to $1,612.9 million for the same period in 2001. Electric generation and marketing revenue increased to $1,583.5 million in 2002 compared to $1,257.3 million in 2001. Approximately $203.0 million of the $326.1 million variance was due to electricity and steam sales, which increased due to our growing portfolio of power plants. Generation almost doubled but average pricing dropped by 17%, moderating revenue growth. Our revenue for the period ended June 30, 2002, includes the consolidated results of additional facilities that we acquired or completed construction on subsequent to June 30, 2001. Sales of purchased power grew by $185.4 million due to increased price hedging, balancing and optimization activity around our operating plant portfolio during the three months ended June 30, 2002. This was offset by a $62.3 million decrease in electric power derivative mark-to-market gain. In the three months ended June 30, 2001, we recognized a significant mark-to-market gain from power contracts in a market area where we did not have generation assets. Due to industry-wide credit restrictions on risk management and trading activities in 2002, such opportunities and other trading activities have been greatly restricted. Oil and gas production and marketing revenue increased to $354.2 million in 2002 compared to $343.0 million in 2001. The increase is due to a $75.4 million increase in sales of purchased gas, offset by a $64.2 million decrease in oil and gas sales to third parties primarily because of much lower average natural gas pricing in 2002. Cost of revenue -- Cost of revenue increased to $1,685.5 million in 2002 compared to $1,308.6 million in 2001. Approximately $42.9 million and $115.4 million of the $376.9 million increase relates to the cost of power and gas purchased by our energy services organization, respectively, due to increased price hedging, balancing, optimization and trading activities. Fuel expense increased 55%, from $228.4 million in 2001 to $354.1 million in 2002, due to an increase of 122% in gas-fired megawatt hours generated as offset by significantly lower gas prices in 2002 and an improvement in average heat rate of our generation portfolio. Plant operating expense increased by 71.7% from $69.3 million to $118.9 million but, expressed per MWh of generation, decreased from $8.79/MWh to $7.57/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 52.6%, from $72.1 million to $110.1 million, due primarily to additional power facilities in consolidated operations at June 30, 2002, as compared to the same period in 2001. Project development expense -- Project development expense increased $20.3 million as we expensed $18.1 million in costs related to the cancellation or indefinite suspension of certain development projects. Merger expense -- The merger expense of $35.6 million in the three months ended June 30, 2001 was a result of the pooling-of-interests transaction with Encal Energy Ltd. Interest expense -- Interest expense increased 54.8% to $67.1 million for the three months ended June 30, 2002, from $43.3 million for the same period in 2001. Interest expense increased primarily due to the issuance of the Convertible Senior Notes Due 2006 and additional senior notes in the second half of 2001 and due to the fact that interest expense on construction projects stops being capitalized once the project goes into commercial operations and a greater number of projects went into commercial operation in the three months ended June 30, 2002, than in the three months ended June 30, 2001. Interest capitalized increased from $115.6 million in the three months ended June 30, 2001 to $171.0 million in the three months ended June 30, 2002, as a consequence of a larger construction portfolio in 2002. We expect that interest expense will increase and the amount of interest capitalized will decrease in the future as our plants in construction are completed, and also as a result of the current suspension of our development projects. Interest income -- Interest income decreased to $9.8 million for the three months ended June 30, 2002, compared to $20.5 million for the same period in 2001. This decrease is due primarily to lower cash balances and interest rates in 2002. Other income -- Other income declined by $0.5 million in the three months ended June 30, 2002, compared to the same period in 2001. In the 2002 period we recognized $7.0 million of recovery from ACE for losses incurred on reclaim trading credit transactions (see Note 13 to the financial statements), and additionally, we recognized gains from asset sales of $7.6 million. However, these gains were partially offset by letter of credit fees of $6.2 million, $3.4 million for cost of a forfeited deposit on an asset purchase that did not close, foreign exchange translation losses of $2.0 million, due primarily to weakening in the Canadian dollar, and minority interest expense of $0.9 million. In the corresponding period in 2001, we had a foreign exchange translation gain of $3.0 million. -28- Provision for income taxes -- The effective income tax rate was approximately 32.9% and 39.1% for the three months ended June 30, 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 and due to the reversal of $2.6 million of a specific tax reserve in 2002. Extraordinary loss, net -- The $1.3 million charge (net of tax of $0.8 million) in the three months ended June 30, 2001 related to the write off of unamortized deferred financing costs as a result of the repayment of the $105 million 9 1/4% Senior Notes Due 2004. Six Months Ended June 30, 2002, Compared to Six Months Ended June 30, 2001. Revenue -- Total revenue increased to $3,680.2 million for the six months ended June 30, 2002, compared to $2,952.6 million for the same period in 2001. Electric generation and marketing revenue increased to $3,116.1 million in 2002 compared to $2,307.4 million in 2001. Sales of purchased power grew by $640.1 million due to increased price hedging, balancing and optimization activity around our operating plant portfolio during the six months ended June 30, 2002. Approximately $228.1 million of the variance was due to electricity and steam sales, which increased due to our growing portfolio of power plants. Generation more than doubled, but average pricing dropped by 30% to moderate revenue growth. Our revenue for the period ended June 30, 2002, includes the consolidated results of additional facilities that we acquired or completed construction on subsequent to June 30, 2001. The increase in electric generation and marketing revenue was offset by a $59.5 million decrease in electric power derivative mark-to-market gain. In the six months ended June 30, 2001, we recognized a significant mark-to-market gain from power contracts in a market area where we did not have generation assets. Due to industry-wide credit restrictions on risk management and trading activities in 2002, such opportunities and other trading activities have been greatly restricted. Oil and gas production and marketing revenue decreased to $553.9 million in 2002 compared to $628.9 million in 2001. The decrease is primarily due to a $153.4 million decrease in oil and gas sales to third parties because of much lower average natural gas pricing in 2002, offset by a $78.3 million increase in the sales of purchased gas. Cost of revenue -- Cost of revenue increased to $3,245.9 million in 2002 compared to $2,372.8 million in 2001. Approximately $401.6 million and $120.5 million of the $873.1 million increase relates to the cost of power and gas purchased by our energy services organization, respectively due to increased price hedging, balancing, optimization and trading activities. Fuel expense increased 41.5%, from $485.4 million in 2001 to $686.9 million in 2002, due to a 127% increase in gas-fired megawatt hours generated as offset by significantly lower gas prices and an improved average heat rate of our generation portfolio in 2002. Plant operating expense increased by 52.3% from $153.7 million to $234.1 million but, expressed per MWh of generation, decreased from $10.17/MWh to $7.69/MWh as economies of scale are being realized due to the increase in the average size of our plants. Royalty expense decreased $9.6 million between periods due to a decrease in revenue for The Geysers geothermal plants. Depreciation, depletion and amortization expense increased by 48.4%, from $144.2 million to $214.0 million, due primarily to additional power facilities in consolidated operations at June 30, 2002, as compared to the same period in 2001. Operating lease expense increased 30.5% between periods due to sale/leaseback transactions subsequent to June 30, 2001. Project development expense -- Project development expense increased 78.4% as we expensed $22.3 million in costs related to the cancellation or indefinite suspension of certain development projects. Equipment cancellation cost -- The pre-tax equipment cancellation charge of $168.5 million in the six months ended June 30, 2002, was as a result of the turbine order cancellations and the cancellation of certain other equipment based primarily on forfeited prepayments to date. General and administrative expense -- General and administrative expense increased 31.4% to $113.9 million for the six months ended June 30, 2002, as compared to $86.6 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 $3.74/MWh in 2002 from $5.73/MWh in 2001. Merger expense -- The merger expense of $41.6 million in the six months ended June 30, 2001 was a result of the pooling-of-interests transaction with Encal Energy Ltd. Interest expense -- Interest expense increased 102.9% to $128.4 million for the six months ended June 30, 2002, from $63.3 million for the same period in 2001. Interest expense increased primarily due to the issuance of the -29- Convertible Senior Notes Due 2006 and additional senior notes in the second half of 2001 and due to the new plants going into commercial operations at which point capitalization of interest expense ceases. Interest capitalized increased from $219.6 million in the six months ended June 30, 2001 to $334.1 million in the six months ended June 30, 2002, due to a larger construction portfolio in 2002. We expect that interest expense will continue to increase and the amount of interest capitalized will decrease in future periods as our plants in construction are completed, and also as a result of the current suspension of our development projects. Interest income -- Interest income decreased to $21.9 million for the six months ended June 30, 2002, compared to $39.9 million for the same period in 2001. This decrease is due primarily to lower cash balances and interest rates in 2002. Other income -- Other income increased by $2.8 million in the six months ended June 30, 2002, compared to the same period in 2001. In the 2002 period we recognized $7.0 million of recovery from ACE for losses incurred on reclaim trading credit transactions (see Note 13 to the financial statements), and additionally, we recognized net gains from asset sales of $18.8 million, which was primarily due to a gain of $9.7 million from the sale of our interests in the Lockport project, gains of $4.3 million from sales of non-strategic Canadian properties, and a gain of $2.7 million from the sale of our 7.5% interest in the Bayonne project. However, these gains were partially offset by letter of credit fees of $6.2 million, $3.4 million for cost of a forfeited deposit on an asset purchase that did not close, foreign exchange translation losses of $2.2 million and minority interest expense of $0.9 million. In the corresponding period in 2001, we had gains on sales of assets of $12.7 million, primarily from a $7.2 million gain on the sale of our development interests in the Elwood project and a gain of $4.9 million from the sale of our 7.5% interest in the Bayonne project, which was partially offset by a foreign exchange translation loss of $2.4 million, due primarily to weakening in the Canadian dollar. Provision for income taxes -- The effective income tax rate was approximately 59.0% and 41.1% for the six months ended June 30, 2002 and 2001, respectively. The increase is not meaningful since the 2002 effective rate reflects the reversal of $2.6 million of specific tax reserve in 2002 and is applied to a small net loss. Extraordinary gain (loss), net -- The $2.1 million gain (net of tax of $1.4 million) in 2002 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. The $1.3 million charge (net of tax of $0.8 million) in 2001 related to the write off of unamortized deferred financing costs as a result of the repayment of the $105 million 9 1/4% Senior Notes Due 2004. Cumulative effect of a change in accounting principle - In 2001 the $1.0 million of additional income (net of tax of $0.7 million), is due to the adoption of 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," and as further amended by SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities - an Amendment of FASB Statement No. 133." 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 IPPs 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); (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 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. -30- Accumulated other comprehensive loss -- The amount of the accumulated other comprehensive loss decreased from $(226.6) million at December 31, 2001, to $(118.7) million at June 30, 2002. The change resulted from unrealized gains on derivatives designated as cash flow hedges of $54.3 million, net of amounts reclassified to net loss and income taxes, and foreign currency translation gain of $53.6 million. See Note 9 for further information. Liquidity and Capital Resources General -- The latter half of 2001, and particularly the fourth quarter, saw the beginning of 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 and a perceived near term surplus supply of electric generating capacity. While we have been able to access the capital and bank credit markets, as discussed below, we recognize that terms of financing available to us now and 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 facilities and other working capital lines; sale of debt, equity, trust preferred securities and convertible debentures; proceeds from sale/leaseback transactions, sale of non-strategic assets 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, optimization and trading 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; the timing of the availability of such capital in today's environment is uncertain. Our strategy is also to reinvest our cash from operations into our business development and construction program, rather than to pay cash dividends. Factors that could affect our liquidity and capital resources are also discussed in the "Risk Factors" section of our Annual Report on Form 10-K for the year ended December 31, 2001. Cash Flow Activities -- The following table summarizes our cash flow activities for the periods indicated:
Six Months Ended June 30, ------------------------------ 2002 2001 ------------ ------------ (in thousands) Beginning cash and cash equivalents........................................... $ 1,525,417 $ 596,077 Net cash provided by (used in): Operating activities....................................................... 463,445 89,973 Investing activities....................................................... (2,558,322) (2,772,635) Financing activities....................................................... 1,094,269 3,328,105 Effect of exchange rates changes on cash and cash equivalents.............. 3,958 -- ------------ ------------ Net increase (decrease) in cash and cash equivalents....................... (996,650) 645,443 ------------ ------------ Ending cash and cash equivalents........................................ $ 528,767 $ 1,241,520 ============ ============
Operating activities for the six months ended June 30, 2002, provided net cash of $463.4 million, compared to $90.0 million for the six months ended June 30, 2001. The cash provided by operating activities for the six months ended June 30, 2002, consisted of a $227.5 million decrease in operating assets, primarily relating to a $236.2 million decrease in margin deposits and other prepaid expenses. This was offset by a $355.1 million decrease in operating liabilities, primarily related to derivative activity. A primary factor causing the significant increase in cash flow from operations in the six months ended June 30, 2002, in comparison to the same period in 2001, is the realization of over $200 million of pre-bankruptcy petition PG&E receivables in the first quarter of 2002, which helped our operating cash flow performance and, similarly, the failure to collect those receivables in the first half of 2001, which reduced operating cash flow in that period. Investing activities for the six months ended June 30, 2002, consumed net cash of $2.6 billion, primarily due to $2.5 billion for construction costs and capital expenditures including gas turbine generator costs and associated capitalized interest, $43.8 million of advances to joint ventures including associated capitalized interest for investments in power projects under construction, $63.7 million of capitalized project development costs including associated capitalized interest, and a $27.8 million increase in restricted cash. This was partially offset by a $49.8 million of proceeds on sales of property, plant and equipment and investments in power projects. -31- Financing activities for the six months ended June 30, 2002, provided $1.1 billion of net cash consisting of $751.2 million of proceeds from the offering of common stock, $100.0 million of proceeds from the issuance of additional Convertible Senior Notes Due 2006 pursuant to exercise of the initial purchasers' remaining purchase option, $1.1 billion of proceeds from drawings on our term loan and revolving lines of credit, and $280.2 million of proceeds from project financing. This was partially offset by $873.2 million for the repurchase of the outstanding Zero Coupons, $87.5 million for the repayment of notes payable and borrowings under our lines of credit, $92.2 million for repayments of project financing and $59.9 million of additional financing costs. 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 sale/leaseback and other markets, sale of non-strategic assets and cash balances to satisfy all obligations under outstanding indebtedness, to finance anticipated capital expenditures and to fund working capital requirements for the next twelve months. Enron Bankruptcy -- We believe, based on legal analysis, that we have no net collection exposure to Enron. See Note 10 to the Consolidated Condensed Financial Statements. Nevada Power and Sierra Pacific Power Company -- During the first quarter of 2002, two subsidiaries of Sierra Pacific Resources Company, Nevada Power Company ("NPC") and Sierra Pacific Power Company ("SPPC"), received credit downgrades to sub-investment grades from the major credit rating agencies. Additionally, NPC acknowledged 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 has requested that its power suppliers extend payment terms to help it overcome its short-term liquidity problems. During the second quarter of 2002, NPC indicated to its power suppliers that it was experiencing cash flow difficulties. In June and July 2002 NPC underpaid us by approximately $4.2 million, and we expect that NPC will underpay us by approximately an additional $18.4 million this summer and early fall. In consideration of the uncertainty surrounding NPC's ability to make timely payments, we are maintaining a bad debt reserve of approximately $2.7 million against NPC receivables. See Part II -- Other Information - Item 1 for further discussion. As of June 30, 2002, we had net collection exposures of approximately $34.8 million and $20.2 million with NPC and SPPC, respectively. However, SPPC is paying us currently. Our exposures include open forward power contracts that are reported at fair value on our balance sheet as well as receivable and payable balances relating to prior power deliveries. We are continuing to monitor our exposure and its effect on our financial condition. PSM License Receivable -- In December 2001 PSM and a Dutch power services company entered into a perpetual world-wide license agreement for certain PSM proprietary reverse-flow venturi technology. The license fee, while earned upfront, is payable over the period from January 2002 through March 2004. The Company recognized the license fee of $11 million (less imputed interest on the receivable) as income in December 2001. As of the date of this filing, we have a receivable of $7 million, with no payments currently past due. The indirect parent of the Dutch company, a German holding company, filed for insolvency in Germany in July 2002 and the direct parent of the Dutch company is expected to also file for insolvency. However, the Dutch company has assured us that it has not and currently does not expect to file for insolvency in the near term. We have been further assured in a letter from the German holding company dated July 11, 2002, that the Dutch company expects to continue the license arrangement and to meet its obligations thereunder. Based on our evaluation of these and other factors, a loss does not seem probable at this time. Accordingly, we have not established a reserve against the related receivable but will continue to closely monitor the situation. CES Margin Deposits and Other Credit Support -- As of June 30, 2002, CES had $67.3 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 $315.0 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. While we believe that we have adequate liquidity to support CES' operations at this time, it is difficult to predict future developments and the amount of credit support that we may need to provide as part of our business operations. 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 contemplated the completion of 27 power projects (representing 15,200 MW) then under construction. Nine of these facilities have subsequently achieved full or partial commercial operation as of June 30, 2002. Construction of advanced stage development projects is -32- expected to proceed only 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 may again become available to us on attractive terms. Further, our entire development and construction program is flexible and subject to continuing review and revision based upon such criteria. 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 of some 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. Uses and Sources of Funding -- As of August 1, 2002, our estimated uses of funds for 2002 are as follows: construction costs of $2.6 billion, cost to repurchase the remaining Zero Coupons of $0.9 billion, other debt repayment costs of $0.1 billion, maintenance and gas capital expenditures of $0.3 billion, cash lease payments of $0.3 billion, estimated Enron contract settlement payments of $0.1 billion and $0.7 billion for turbines for financeable and future projects. These uses of funds will be funded primarily through an estimated $0.8 billion of operating cash flow for 2002, $0.3 billion of CES cash collateral replaced with letters of credit and cash on hand of $1.8 billion (consists of cash on hand of $1.5 billion at December 31, 2001, $0.2 billion from the sale of the PG&E receivables, $0.1 billion from the sale of Convertible Senior Notes Due 2006 in early January 2002). The other sources of funding include $1.0 billion from the two-year term loan, $0.7 billion from the April equity offering, $0.6 billion from our construction revolvers and our proposed California peaker leases, as well as $0.3 billion from our secured revolving credit facilities. We are also negotiating the sale of non-strategic assets for approximately $0.3 billion. Other potential sources of cash include monetizing our Canadian power generation assets for approximately $0.3 billion, entering into a sale/leaseback transaction for our Zion facility for cash proceeds of $0.2 billion, selling our Gilroy note receivable for $0.2 billion, selling certain additional assets, including oil and gas properties, for proceeds net of debt repayment of $0.4 billion, and financing for our future turbines of $0.3 billion. Actual costs for the projected uses of funds identified above, and net proceeds from the projected sources of funds identified above could vary from those estimates, potentially in material respects. Factors that could affect the accuracy of these estimates are discussed in our Annual Report on Form 10-K for the year ended December 31, 2001, in the "Risk Factors" section. Capital Availability -- Notwithstanding recent uncertainties in the domestic energy and capital markets, we raised substantial capital earlier in 2002. 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. The proceeds from the offering were used to repay debt and for general corporate purposes. On May 14, 2002, our subsidiary, Calpine California Energy Finance, LLC, entered into an amended and restated credit agreement with ING Capital LLC for the funding of 9 California peaker facilities, of which $100.0 million was drawn on May 24, 2002. The total $100.0 million funding is classified as current project financing, of which $50.0 million was repaid on August 7, 2002, and $50.0 million will be payable on September 30, 2002. This peaker funding is part of our expected long-term financing of our California peaker facilities which is anticipated to be $500.0 million. During the second quarter of 2002, we increased our two-year secured bank term loan to $1.0 billion from $600 million, and reduced the size of our secured corporate revolving credit facilities to $1.0 billion from $1.4 billion. At June 30, 2002, we had $1.0 billion in borrowings outstanding under the term loan facility and $75.0 million in borrowings outstanding under the revolving credit facility. Letter of credit facilities -- At June 30, 2002, we had approximately $874.6 million in letters of credit outstanding under various credit support facilities, including facilities related to CES risk management activities, and other operational and construction activities. Of the total letters of credit outstanding, $723.2 million were issued under the corporate revolving credit facilities. At December 31, 2001, we had $642.5 million in letters of credit outstanding, including facilities relating to CES risk management activities. 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 sale/leaseback transactions involving our Tiverton, Rumford, South Point, Broad River, and RockGen projects. All counterparties in these transactions are third parties that are unrelated to us. The sale/leaseback transactions utilize special-purpose entities formed by the equity investors with the sole purpose of owning a power generation facility. We have no ownership or other interest in any of these special-purpose entities. Some of our operating leases contain customary restrictions on dividends, additional debt and further encumbrances similar to those typically found in project finance debt instruments. -33- 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 June 30, 2002, investee debt totaled $660.6 million. Based on our pro rata ownership share of each of the investments, our share would be $244.8 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. Additionally, one of our projects with an operating lease has $237.8 million of debt outstanding at June 30, 2002. 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 recent revenue has consisted 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 natural gas price swaps, 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 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) KWh 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. -34- 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. 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 June 30, Three Months Ended June 30, ---------------------------- ---------------------------- 2002 2001 2002 2001 ----------- ----------- ----------- ----------- (In thousands) Revenue, Cost of Revenue and Gross Profit Revenue: Electric generation and marketing revenue Electricity and steam revenue(1)....................... $ 708,752 $ 505,711 $ 878,363 $ 532,512 Sales of purchased power(1)............................ 868,606 683,196 819 1,073 Electric power derivative mark-to-market gain.......... 6,104 68,433 6,104 68,433 ----------- ----------- ----------- ----------- Total electric generation and marketing revenue...... 1,583,462 1,257,340 885,286 602,018 Oil and gas production and marketing revenue Oil and gas sales...................................... 52,163 116,319 52,163 116,319 Sales of purchased gas(1).............................. 302,044 226,693 1,383 1,715 ----------- ----------- ----------- ----------- Total oil and gas production and marketing revenue... 354,207 343,012 53,546 118,034 Income (loss) from unconsolidated investments in power projects........................................... (1,121) 1,600 (1,121) 1,600 Other revenue............................................. 5,258 10,921 5,258 10,921 ----------- ----------- ----------- ----------- Total revenue..................................... 1,941,806 1,612,873 942,969 732,573 ----------- ----------- ----------- -----------
(table continues) -35- (table continued)
Non-GAAP Netted GAAP Presentation Presentation Three Months Ended June 30, Three Months Ended June 30, ---------------------------- ---------------------------- 2002 2001 2002 2001 ----------- ----------- ----------- ----------- (In thousands) Cost of revenue: Electric generation and marketing expense Plant operating expense................................ 118,930 69,259 118,930 69,259 Royalty expense........................................ 4,194 6,916 4,194 6,916 Purchased power expense(1)............................. 698,176 655,322 -- -- ----------- ----------- ----------- ----------- Total electric generation and marketing expense...... 821,300 731,497 123,124 76,175 Oil and gas production and marketing expense Oil and gas production expense......................... 27,836 27,308 27,836 27,308 Purchased gas expense(1)............................... 333,724 218,330 -- -- ----------- ----------- ----------- ----------- Total oil and gas production and marketing expense... 361,560 245,638 27,836 27,308 Fuel expense Cost of oil and natural gas burned by power plants(1).. 350,848 251,876 383,911 245,228 Natural gas derivative mark-to-market loss (gain)...... 3,203 (23,446) 3,203 (23,446) ----------- ----------- ----------- ----------- Total fuel expense................................... 354,051 228,430 387,114 221,782 Depreciation, depletion and amortization expense.......... 110,122 72,144 110,122 72,144 Operating lease expense................................... 36,263 27,449 36,263 27,449 Other expense............................................. 2,204 3,490 2,204 3,490 ----------- ----------- ----------- ----------- Total cost of revenue............................. 1,685,500 1,308,648 686,663 428,348 ----------- ----------- ----------- ----------- Gross profit................................................. $ 256,306 $ 304,225 $ 256,306 $ 304,225 =========== =========== =========== =========== Gross profit margin.......................................... 13% 19% 27% 42% Non-GAAP Netted GAAP Presentation Presentation Six Months Ended June 30, Six Months Ended June 30, ---------------------------- ---------------------------- 2002 2001 2002 2001 ----------- ----------- ----------- ----------- (In thousands) Revenue, Cost of Revenue and Gross Profit Revenue: Electric generation and marketing revenue Electricity and steam revenue(1)....................... $ 1,328,931 $ 1,100,870 $ 1,591,681 $ 1,126,323 Sales of purchased power(1)............................ 1,776,907 1,136,798 976 (243) Electric power derivative mark-to-market gain.......... 10,270 69,739 10,270 69,739 ----------- ----------- ----------- ----------- Total electric generation and marketing revenue...... 3,116,108 2,307,407 1,602,927 1,195,819 Oil and gas production and marketing revenue Oil and gas sales...................................... 119,651 273,006 119,651 273,006 Sales of purchased gas(1).............................. 434,202 355,865 7,455 4,884 ----------- ----------- ----------- ----------- Total oil and gas production and marketing revenue... 553,853 628,871 127,106 277,890 Income from unconsolidated investments in power projects........................................... 323 2,163 323 2,163 Other revenue............................................. 9,869 14,183 9,869 14,183 ----------- ----------- ----------- ----------- Total revenue..................................... 3,680,153 2,952,624 1,740,225 1,490,055 ----------- ----------- ----------- -----------
(table continues) -36- (table continued)
Non-GAAP Netted GAAP Presentation Presentation Six Months Ended June 30, Six Months Ended June 30, ---------------------------- ---------------------------- 2002 2001 2002 2001 ----------- ----------- ----------- ----------- (In thousands) Cost of revenue: Electric generation and marketing expense Plant operating expense................................ 234,087 153,719 234,087 153,719 Royalty expense........................................ 8,349 17,925 8,349 17,925 Purchased power expense(1)............................. 1,513,181 1,111,588 -- -- ----------- ----------- ----------- ----------- Total electric generation and marketing expense...... 1,755,617 1,283,232 242,436 171,644 Oil and gas production and marketing expense Oil and gas production expense......................... 54,776 61,591 54,776 61,591 Purchased gas expense(1)............................... 457,418 336,958 -- -- ----------- ----------- ----------- ----------- Total oil and gas production and marketing expense... 512,194 398,549 54,776 61,591 Fuel expense Cost of oil and natural gas burned by power plants(1).. 677,291 516,439 707,962 502,416 Natural gas derivative mark-to-market loss (gain)...... 9,595 (30,995) 9,595 (30,995) ----------- ----------- ----------- ----------- Total fuel expense................................... 686,886 485,444 717,557 471,421 Depreciation, depletion and amortization expense.......... 213,995 144,157 213,995 144,157 Operating lease expense................................... 72,397 55,460 72,397 55,460 Other expense............................................. 4,794 5,989 4,794 5,989 ----------- ----------- ----------- ----------- Total cost of revenue............................. 3,245,883 2,372,831 1,305,955 910,262 ----------- ----------- ----------- ----------- Gross profit................................................. $ 434,270 $ 579,793 $ 434,270 $ 579,793 =========== =========== =========== =========== Gross profit margin.......................................... 12% 20% 25% 39% Non-GAAP Netted Non-GAAP Netted Presentation Presentation Three Months Ended June 30, Six Months Ended June 30, ---------------------------- ---------------------------- 2002 2001 2002 2001 ----------- ----------- ----------- ----------- (In thousands) Other Non-GAAP Performance Metrics Average availability and capacity factor: Average availability...................................... 95% 91% 95% 91% Average capacity factor or operating rate based on total hours (excluding peakers).......................... 66% 65% 68% 67% Average heat rate for gas-fired power plants (excluding peakers) (Btu's/kWh): Not steam adjusted........................................ 8,158 8,504 8,165 8,582 Steam adjusted............................................ 7,455 7,612 7,416 7,562 Average all-in realized electric price: Adjusted electricity and steam revenue (in thousands)..... $ 878,363 $ 532,512 $ 1,591,681 $ 1,126,323 MWh generated (in thousands).............................. 15,720 7,878 30,434 15,117 Average all-in realized electric price per MWh............ $ 55.88 $ 67.59 $ 52.30 $ 74.51 Average cost of natural gas: Cost of oil and natural gas burned by power plants (in thousands)........................................... $ 383,911 $ 245,228 $ 707,962 $ 502,416 Fuel cost elimination..................................... 61,357 35,455 69,954 78,671 ----------- ----------- ----------- ----------- Adjusted cost of oil and natural gas burned by power plants............................................. $ 445,268 $ 280,683 $ 777,916 $ 581,087 MMBtu of fuel consumed by generating plants (in thousands)........................................... 112,750 53,151 219,274 101,144 Average cost of natural gas per MMBtu..................... $ 3.95 $ 5.28 $ 3.55 $ 5.75 MWh generated (in thousands).............................. 15,720 7,878 30,434 15,117 Average cost of oil and natural gas burned by power plants per MWh..................................... $ 28.32 $ 35.63 $ 25.56 $ 38.44 Average spark spread: Adjusted electricity and steam revenue (in thousands)..... $ 878,363 $ 532,512 $ 1,591,681 $ 1,126,323 Less: Adjusted cost of oil and natural gas burned by power plants (in thousands)........................... 445,268 280,683 777,916 581,087 ----------- ----------- ----------- ----------- Spark spread (in thousands)............................... $ 433,095 $ 251,829 $ 813,765 $ 545,236 MWh generated (in thousands).............................. 15,720 7,878 30,434 15,117 Average spark spread per MWh.............................. $ 27.56 $ 31.97 $ 26.74 $ 36.07
The non-GAAP presentation above also facilitates a look at the total "trading" activity impact on gross profit. For the three and six months ended June 30, 2002 and 2001, trading activity consisted of (dollars in thousands): -37-
Three Months Ended Six Months Ended June 30, June 30, ----------------------- ----------------------- 2002 2001 2002 2001 -------- -------- -------- -------- ELECTRICITY Electric generation and marketing revenue Realized gain (loss) Sales of purchased power............................. $ 819 $ 1,073 $ 976 $ (243) Unrealized Electric power derivative mark-to-market gain........ 6,104 68,433 10,270 69,739 -------- -------- -------- -------- Subtotal.................................................................. $ 6,923 $ 69,506 $ 11,246 $ 69,496 GAS Oil and gas production and marketing revenue Realized gain (loss) Sales of purchased gas............................... $ 1,383 $ 1,715 $ 7,455 $ 4,884 Fuel Expense Unrealized Natural gas derivative mark-to-market gain (loss).... (3,203) 23,446 (9,595) 30,995 -------- -------- -------- -------- Subtotal.................................................................. $ (1,820) $ 25,161 $ (2,140) $ 35,879
Three Months Three Months Ended Percent of Ended Percent of June 30, Gross June 30, Gross 2002 Profit 2001 Profit ------------ ---------- ------------ ---------- Total trading activity gain.................................................. $ 5,103 2.0% $ 94,667 31.1% Realized gain (loss)......................................................... $ 2,202 0.9% $ 2,788 0.9% Unrealized (mark-to-market) gain (loss)(2)................................... $ 2,901 1.1% $ 91,879 30.2% Six Months Six Months Ended Percent of Ended Percent of June 30, Gross June 30, Gross 2002 Profit 2001 Profit ------------ ---------- ----------- ---------- Total trading activity gain.................................................. $ 9,106 2.1% $ 105,375 18.2% Realized gain (loss)......................................................... $ 8,431 1.9% $ 4,641 0.8% Unrealized (mark-to-market) gain (loss)(2)................................... $ 675 0.2% $ 100,734 17.4% (1) Following is a reconciliation of GAAP to non-GAAP presentation further to the narrative set forth under this Performance Metrics section ($ in thousands): (2) For the three and six months ended June 30, 2002, the mark-to-market gains shown above as "trading" activity include a net loss on hedge ineffectiveness of $(12) and $(2,829), consisting of an ineffectiveness loss on power hedges of $(1,002) and $(1,224), an ineffectiveness gain (loss) on crude oil costless collar arrangements of $711 and $(4,330) and an ineffectiveness gain on gas hedges of $279 and $2,725. For the three and six months ended June 30, 2001, the mark-to-market gains shown above as "trading" activity include a net loss on hedge ineffectiveness of $(2,781) and $(3,472), consisting of an ineffectiveness gain on power hedges of $1,217 and $0 and an ineffectiveness loss on gas hedges of $(3,998) and $(3,472).
To Net Hedging, Balancing & To Net Netted GAAP Optimization Trading Non-GAAP Balance Activity Activity Balance ----------- ------------ ---------- ----------- Three months ended June 30, 2002 Electricity and steam revenue............................. $ 708,752 $ 169,611 $ -- $ 878,363 Sales of purchased power.................................. 868,606 (856,876) (10,911) 819 Sales of purchased gas.................................... 302,044 (302,044) 1,383 1,383 Purchased power expense................................... 698,176 (687,265) (10,911) -- Purchased gas expense..................................... 333,724 (333,724) -- -- Cost of oil and natural gas burned by power plants........ 350,848 31,680 1,383 383,911 Three months ended June 30, 2001 Electricity and steam revenue............................. $ 505,711 $ 26,801 $ -- $ 532,512 Sales of purchased power.................................. 683,196 (578,230) (103,893) 1,073 Sales of purchased gas.................................... 226,693 (226,693) 1,715 1,715 Purchased power expense................................... 655,322 (551,429) (103,893) -- Purchased gas expense..................................... 218,330 (218,330) -- -- Cost of oil and natural gas burned by power plants........ 251,876 (8,363) 1,715 245,228
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To Net Hedging, Balancing & To Net Netted GAAP Optimization Trading Non-GAAP Balance Activity Activity Balance ----------- ------------ ---------- ----------- Six months ended June 30, 2002 Electricity and steam revenue............................. $ 1,328,931 $ 262,750 $ -- $ 1,591,681 Sales of purchased power.................................. 1,776,907 (1,699,482) (76,449) 976 Sales of purchased gas.................................... 434,202 (434,202) 7,455 7,455 Purchased power expense................................... 1,513,181 (1,436,732) (76,449) -- Purchased gas expense..................................... 457,418 (457,418) -- -- Cost of oil and natural gas burned by power plants........ 677,291 23,216 7,455 707,962 Six months ended June 30, 2001 Electricity and steam revenue............................. $ 1,100,870 $ 25,453 $ -- $ 1,126,323 Sales of purchased power.................................. 1,136,798 (1,021,713) (115,328) (243) Sales of purchased gas.................................... 355,865 (355,865) 4,884 4,884 Purchased power expense................................... 1,111,588 (996,260) (115,328) -- Purchased gas expense..................................... 336,958 (336,958) -- -- Cost of oil and natural gas burned by power plants........ 516,439 (18,907) 4,884 502,416
Outlook At August 9, 2002, we had 25 projects under construction, representing an additional 11,650 megawatts of net capacity. The completion of our projects currently under construction, which we expect to occur in the later half of 2004, would give us interests in 96 power plants totaling 28,539 megawatts. Our new $2 billion revolving credit and term loan facilities and April 2002 issuance of 66 million shares of common stock together with our ongoing financing programs and sales of non-strategic assets have helped to improve our 2002 liquidity position. For 2003 to 2004, our secured construction financing revolving facilities will mature, requiring us to restructure or refinance this indebtedness. We remain confident that we will have the ability to refinance this indebtedness as it matures, but recognize that this is dependent, in part, on market conditions that are difficult to predict and are outside of our control. 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 second quarter of 2001 to the second quarter of 2002 and, as a result of the suspension of certain of our development projects and the restructuring of our turbine contracts completed to date, our capital expenditure requirements have been reduced. 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 Annual Report on Form 10-K for the year ended December 31, 2001, and optimistic about our future performance. However, market conditions make it more difficult to predict future results than in prior periods. Additional factors that can affect our future performance are described in the "Risk Factors" section of our Annual Report on Form 10-K for the year ended December 31, 2001. Overview Summary of Key Activities Power Plant Development and Construction: Date Project Description -------- ------------------------------ -------------------------------- 4/02 Island Cogeneration Commercial operation 4/02 Channel Energy Center Combined-cycle operation 5/02 Aries Power Peaker Plant Combined-cycle operation 5/02 Baytown Energy Center Commercial operation 6/02 Metcalf Energy Center Construction commenced 6/02 Decatur Energy Center Partial commercial operation 6/02 Freestone Energy Center Partial commercial operation 6/02 Zion Energy Center Commercial operation 6/02 Delta Energy Center Commercial operation 7/02 Freestone Energy Center Combined-cycle operation 7/02 Bethpage Energy Peaker Center Commercial operation 7/02 Yuba City Energy Center Commercial operation 8/02 Acadia Energy Center Commercial operation -39- Finance Note Repayments and New Funding: Date Amount Description -------- ----------------------------- -------------------------------- 5/10/02 $500.0 million Funding under two-year term loan 5/24/02 $100.0 million Funding for Gilroy and King City Peaker Projects 5/31/02 $500.0 million Funding under two-year term loan 8/7/02 $50.0 million Repayment of peaker funding Repurchases of Zero-Coupon Convertible Debentures Due 2021: Date Amount ------- -------------- 4/30/02 $685.5 million Sale of Common Stock: Date Offering Description Use of Proceeds --------- ------------------- ---------------------- --------------------- 4/30/02 $759 million, gross 66 million shares For general corporate at $11.50 per share purposes, including debt repayment Other: Date Description --------- ----------------------------------------------------------------- 4/22/02 Renegotiation of California Department of Water Resources long-term power contracts 6/28/02 Execution of definitive agreements with Wisconsin Public Service for the sale of DePere Energy Center, including termination of existing power purchase agreement California Power Market On April 22, 2002, we announced that we had renegotiated CES' long-term power contracts with the California Department of Water Resources (the "DWR"). The Office of the Governor of California, the California Public Utilities Commission (the "CPUC"), the California Electricity Oversight Board (the "EOB") and the California Attorney General (the "AG") endorsed the renegotiated contracts and agreed to drop all pending claims against us and our affiliates, including withdrawing the complaint under Section 206 of the Federal Power Act that had been filed by the CPUC and EOB with FERC, and the termination by the CPUC and the EOB of their efforts to seek refunds from us and our affiliates through FERC refund proceedings. In connection with the renegotiation, we have agreed to pay $6 million over three years to the AG to resolve any and all possible claims against us and our affiliates brought by the AG. CES had signed three long-term contracts with DWR in February 2001, comprising two 10-year baseload energy contracts and one 20-year peaking contract. The renegotiation provided for the shortening of the duration of each of the two 10-year, baseload energy contracts by two years and of the 20-year peaker contract by ten years. These changes reduced 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 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 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 we do not meet certain milestones with respect to each project assumed, provided that DWR reimburses us for all construction costs and certain other costs incurred by us to the date DWR assumes the relevant project. The Company will generate over $8.7 billion in revenue between 2002 and 2011 from the DWR contracts. In addition, the negotiation resolved the dispute with DWR concerning payment of the capacity payment on the peaking contract. 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 had 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, we have received payment in full on these withheld capacity payments and will have the right to provide replacement capacity through December 31, 2002, 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. -40- Financial Market Risks As an independent power producer primarily focused on generation of electricity using gas-fired turbines, our 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, we enter into derivative commodity instruments. We enter 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 our vulnerability to reductions in electric prices for the electricity we generate, to reductions in gas prices for the gas we produce, and to increases in gas prices for the fuel we consume in our power plants. We seek to "self-hedge" our gas consumption exposure to an extent with our own gas production position. 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 and are designed to protect our "spark spread" (the difference between our fuel cost and the revenue we receive for our electric generation). 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. From time to time we have entered into contracts considered energy trading contracts under EITF Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities." However, our traders have low capital at risk and value at risk limits for energy trading, and our risk management policy limits, at any given time, our net sales of power to our generation capacity and limits our net purchases of gas to our 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 and EITF Issue No. 98-10. The change in fair value of outstanding commodity derivative instruments from January 1, 2002, through June 30, 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)......................... (95,167) Changes in fair value attributable to changes in valuation techniques and assumptions...... -- Change in fair value attributable to new contracts and price movements..................... 176,748 Reclassification of Enron obligations from derivative assets and liabilities to accounts payable (2)...................................................................... 221,117 --------- Fair value of contracts outstanding at June 30, 2002 (3)................................ $ 214,575 ========= ---------- (1) Realized gains from commodity cash flow hedges of $86.8 million reported in Note 8 of the financial statements and $8.4 million realized gain on trading activity reported in the performance metrics section of the management discussion and analysis, both included in this filing. (2) At termination the Enron contracts ceased to be derivatives as defined by SFAS 133; however, we are required to pay Enron for the contractual value at termination. See Note 10 to the financial statements. (3) Net assets reported in Note 8 of the Notes to Consolidated Financial Statements included in this filing. The fair value of outstanding derivative commodity instruments at June 30, 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................................ $ (22,541) $ 35,225 $ (9,143) $ -- $ 3,541 Prices provided by other external sources............. 81,796 88,434 35,119 24 205,373 Prices based on models and other valuation methods.... (2,273) (5,749) 16,334 (2,651) 5,661 ---------- --------- --------- ---------- --------- Total fair value................................... $ 56,982 $ 117,910 $ 42,310 $ (2,627) 214,575 ========== ========= ========= ========== =========
-41- Our risk managers maintain fair value price information derived from various sources in our risk management systems. The propriety of that information is validated by our 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. The counterparty credit quality associated with the fair value of outstanding derivative commodity instruments at June 30, 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 July 23, 2002, ratings) 2002 2003-2004 2005-2006 After 2006 Total ------------------------------------------------- ---------- --------- --------- ---------- --------- Investment grade...................................... $ 10,457 $ 127,214 $ 51,990 $ (2,661) $ 187,000 Non-investment grade.................................. 48,945 (8,523) (9,680) 34 30,776 No external ratings................................... (2,420) (781) -- -- (3,201) ---------- --------- --------- ---------- --------- Total fair value................................... $ 56,982 $ 117,910 $ 42,310 $ (2,627) $ 214,575 ========== ========= ========= ========== =========
The fair value of outstanding derivative commodity instruments and the change in fair value that would be expected from a ten percent adverse price change are shown in the table below (in thousands): Change in Fair Value From 10% Adverse Fair Value Price Change ---------- -------------- At June 30, 2002: Crude oil............................. $ (2,315) $ 4,108 Electricity........................... 255,322 (43,196) Natural gas........................... (38,432) (135,118) ---------- ---------- Total.............................. $ 214,575 $ (174,206) ========== ========== Derivative commodity instruments included in the table are those included in Note 8 to the unaudited Consolidated Condensed Financial Statements. The fair value of derivative commodity instruments included in the table is based on present value adjusted quoted market prices of comparable contracts. 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 our 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 58% from December 31, 2001, to June 30, 2002, while the total volume of open power derivative positions decreased 10% 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 our derivatives over time, driven both by price volatility and the changes 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 other comprehensive income ("OCI"), net of tax, or in the statement of operations as an item (gain or loss) of current earnings. As of June 30, 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 our results during the six months ended June 30, 2002, have reflected this. See Note 8 for additional information on derivative activity and also the 2001 Form 10-K for a further discussion of our accounting policies related to derivative accounting. How we account for our derivatives depends upon whether we have designated the derivative as a cash flow or fair value hedge or not designated the derivative in a hedge relationship. The following accounting applies: -42- 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 purchases and normal sales exception in SFAS No. 133. On April 1, 2002, we adopted C16. We have no fuel supply contracts to which C16 applies. However, one of our equity method investees has fuel supply contracts subject to C16. The equity investee also adopted C16 on April 1, 2002. Because the contracts qualified as highly effective hedges of the equity method investee's forecasted purchase of gas, the equity method investee designated the contracts as cash flow hedges. Accordingly, we have recorded $7.8 million net of tax as a cumulative effect of change in accounting principle to OCI for its share of the equity method investee's OCI from accounting change. 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 June 30, 2002, (dollars in thousands):
Notional Principal Weighted Average Weighted Average Fair Market Maturity Date Amount Interest Rate Interest Rate Value ------------- ------------------ ---------------- ---------------- ----------- (Pay) (Receive) 2011......... 51,760 6.9% 3-month US LIBOR $ (5,120) 2012......... 117,936 6.5% 3-month US LIBOR (10,943) 2014......... 67,929 6.7% 3-month US LIBOR (6,598) ---------- --- --------- Total..... $ 237,625 6.7% 3-month US LIBOR $ (22,661) ========== === =========
Frequency of Currency Fair Market Maturity Date Notional Principal Fixed Currency Exchange Exchange Value ------------- ----------------------------------- ------------------------------- ------------- ----------- (Pay/Receive) (Pay/Receive) 2007......... US$127,763/C$200,000 US$5,545/C$8,750 Semi-annually $ 1,889 2008......... Pound sterling 109,550/Euro 175,000 Pound sterling 5,152/Euro 7,328 Semi-annually 1,868 --------- Total..... $ 3,757 =========
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 related instruments including Convertible Senior Notes Due 2006 and construction/project financing. Our senior notes and related instruments 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. -43- The following table summarizes the fair market value of our existing long-term senior notes and construction/project financing as of June 30, 2002, (dollars in thousands):
Outstanding Weighted Average Fair Market Instrument Balance Interest Rate Value ----------------------------------------------------------------- ----------- ---------------- ----------- Long-term senior notes: Senior Notes Due 2005......................................... $ 250,000 8.3% $ 145,000 Senior Notes Due 2006......................................... 171,750 10.5% 108,203 Senior Notes Due 2006......................................... 250,000 7.6% 140,000 Convertible Senior Notes Due 2006............................. 1,200,000 4.0% 924,000 Senior Notes Due 2007......................................... 275,000 8.8% 154,000 Senior Notes Due 2007......................................... 131,700 8.8% 84,288 Senior Notes Due 2008......................................... 400,000 7.9% 208,000 Senior Notes Due 2008......................................... 2,030,000 8.5% 1,096,200 Senior Notes Due 2008......................................... 172,516 8.4% 115,586 Senior Notes Due 2009......................................... 350,000 7.8% 182,000 Senior Notes Due 2010......................................... 750,000 8.6% 397,500 Senior Notes Due 2011......................................... 2,000,000 8.5% 1,060,000 Senior Notes Due 2011......................................... 304,920 8.9% 198,198 ----------- ----- ----------- Total long-term senior notes............................... $ 8,285,886 7.8% $ 4,812,975 =========== ===== =========== Construction/project financing: Peaker financing (1).......................................... $ 100,000 4.4% (2) $ 100,000 Term loan due (due 2004)...................................... 1,000,000 3-month US LIBOR 1,000,000 Calpine Construction Finance Company L.P. (due 2003).......... 981,400 1-month US LIBOR 981,400 Calpine Construction Finance Company II, LLC (due 2004)....... 2,452,697 1-month US LIBOR 2,452,697 ----------- ----------- Total long-term construction/project financing............. $ 4,534,097 $ 4,534,097 =========== =========== (1) $50 million repaid August 2002, $50 million due September 30,2002. (2) Blended rate of two tranches.
Short-term investments -- As of June 30, 2002, we had short-term investments of $190.0 million. These short-term investments consist of highly liquid investments with original 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. Construction/project financing facilities -- In 2003 and 2004, $981.4 million and $2,452.7 million, respectively, under our secured construction financing revolving facilities will mature, requiring us to refinance this indebtedness. We remain confident that we will have the ability to refinance this indebtedness as it matures, but recognize that this is dependent, in part, on market conditions that are difficult to predict. 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 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 -44- fair value can be made. SFAS No. 143 is effective for financial statements issued for fiscal years beginning after June 15, 2002. We do not believe that SFAS No. 143 will have a material impact 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 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 has not had 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" stating that gains or losses from extinguishment of debt that fall outside the scope of APB Opinion No. 30 should not be classified as extraordinary. 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 adoption encouraged. We have not completed our analysis but believe that SFAS No. 145 may have a material effect on the presentation of our financial statements, but no impact on net income. In June 2002 the FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities," which addresses accounting for restructuring and similar costs. SFAS No. 146 supersedes previous accounting guidance, principally EITF Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (Including Certain Costs Incurred in a Restructuring)." We will adopt the provisions of SFAS No. 146 for restructuring activities initiated after December 31, 2002. SFAS No. 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. Under Issue No. 94-3, a liability for an exit cost was recognized at the date of commitment to an exit plan. SFAS No. 146 also establishes that the liability should initially be measured and recorded at fair value. Accordingly, SFAS No. 146 may affect the timing of recognizing future restructuring costs as well as the amounts recognized. We do not believe that SFAS No. 146 will have a material effect on our consolidated financial statements. In June 2002 the EITF reached a consensus on two of the three issues considered in EITF 02-03, "Recognition and Reporting of Gains and Losses on Energy Trading Contracts under EITF Issues No. 98-10, `Accounting for Contracts Involved in Energy Trading and Risk Management Activities' and No. 00-17, `Measuring the Fair Value of Energy-Related Contracts in applying Issue No. 98-10.'" The issues upon which the EITF reached a consensus required net presentation, both prospective and retroactive, of energy trading contracts in a company's financial statements and required that companies make certain disclosures regarding their energy trading contracts. The net presentation requirement is effective for financial statements issued for periods ending after July 15, 2002, and the disclosure requirements are effective for financial statements issued for fiscal years ending after July 15, 2002. We are still assessing the impacts of adopting this standard on our financial statements, but we believe, as a minimum, all energy trading contracts will be reported net, rather than gross, upon adoption of this standard. The standard is expected to have a material impact on total revenues and expenses, but no impact on net income. Item 3. Quantitative and Qualitative Disclosures About Market Risk. See "Financial Market Risks" in Item 2. -45- PART II - OTHER INFORMATION Item 1. Legal Proceedings. Securities Derivative Lawsuit. On December 17, 2001, a shareholder filed a derivative lawsuit on behalf of Calpine against our directors and one of our senior officers. This lawsuit is captioned Johnson v. 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. We have 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. We consider this lawsuit to be without merit and intend to vigorously defend against it. Securities Class Action Lawsuits. 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 v. 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 v. Calpine Corp., Lukowski v. Calpine Corp., Hart v. Calpine Corp., Atchison v. Calpine Corp., 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 our securities between January 5, 2001, and December 13, 2001. The complaints in these fourteen actions allege that, during the purported class periods, certain senior Calpine executives issued false and misleading statements about our 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. In addition, a fifteenth securities class action, Ser v. Calpine, et al., was filed on May 13, 2002. The underlying allegations in the Ser action are substantially the same to those in the above-referenced actions. However, the Ser action is brought on behalf of a purported class of purchasers of our 8.5% Senior Notes due February 15, 2011 ("2011 Notes"), and the alleged class period is October 15, 2001, through December 13, 2001. The Ser complaint alleges that, in violation of Sections 11 and 15 of the Securities Act of 1933, the Prospectus Supplement dated October 11, 2001, for the 2011 Notes contained false and misleading statements regarding our financial condition. This action names Calpine, certain of our officers and directors, and the underwriters of the 2011 Notes offering as defendants, and seeks an unspecified amount of damages, in addition to other forms of relief. We expect that this action will either be consolidated with the above-referenced actions or will proceed as a parallel related action before the same judge presiding over the other actions. We consider the allegations against Calpine in each of these lawsuits to be without merit, and we intend to defend vigorously against them. California Business & Professions Code Section 17200 Cases--The lead case, T&E Pastorino Nursery v. Duke Energy Trading and Marketing, L.L.C., et al., was served on May 2, 2002, by T&E Pastorino Nursery, on behalf of itself and all others similarly situated. This purported class action complaint against twenty energy traders and energy companies including CES, alleges that defendants exercised market power and manipulated prices in violation of California Business & Professions Code Section 17200 et seq., and seeks injunctive relief, restitution and attorneys' fees. We also have been named in five other similar complaints for violations of Section 17200 captioned Bronco Don Holdings, LLP. v. Duke Energy Marketing and Trading, et al.; Century Theatres, Inc. v. Allegheny Energy Supply Company, LLC; RDJ Farms, Inc. v. Allegheny Energy Supply Company, LLC; J&M Karsant Family Limited Partnership v. Duke Energy Trading and Marketing, LLC; and Leo's Day and Night Pharmacy v. Duke Energy Trading and Marketing, LLC. All six of these cases have been removed in a multidistrict litigation proceeding from the various state courts in which they were originally filed to federal court, where a motion is now pending to transfer and consolidate these cases for pretrial proceedings with other cases in which we are not named as a defendant. In addition, plaintiffs in the T&E Pastorino Nursery case have filed a motion to remand that matter to California state court. We consider the allegations against Calpine in each of these lawsuits to be without merit, and we intend to vigorously defend against them. -46- California Department of Water Resources Case. On May 1, 2002, California State Senator Tom McClintock and others filed a complaint against Vikram Budhraja, a consultant to DWR, DWR itself, and more than twenty-nine energy providers and other interested parties, including Calpine. The complaint alleges that the long-term power contracts that DWR entered into with these energy providers, including Calpine, are rendered void because Budhraja, who negotiated the contracts on behalf of DWR, allegedly had an undisclosed financial interest in the contracts due to his connection to one of the energy providers, Edison International. Among other things, the complaint seeks an injunction prohibiting further performance of the long-term contracts and restitution of any funds paid to energy providers by the State of California under the contracts. We consider the allegations against Calpine in this lawsuit to be without merit and intend to vigorously defend against them. Nevada Section 206 Complaint. On December 4, 2001, NPC and SPPC filed a complaint with the Federal Energy Regulatory Commission ("FERC") under Section 206 of the Federal Power Act against a number of parties to their power sales agreements, including Calpine. NPC and SPPC allege in their complaint, which seeks a refund, that the prices they agreed to pay in certain of the power sales agreements, including those signed with Calpine, were negotiated during a time when the power market was dysfunctional and that they are unjust and unreasonable. We consider the complaint to be without merit and are vigorously defending against it. Emissions Credits Lawsuit. As described in our previous reports, on March 5, 2002, we sued Automated Credit Exchange ("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 our account with U.S. Trust Company ("US Trust"). Calpine and ACE entered into a settlement agreement on March 29, 2002, pursuant to which ACE made a payment to us of $7 million and transferred to us the rights to the emission reduction credits to be held by ACE, and we dismissed our complaint against ACE. We recognized the $7 million in the second quarter of 2002. In June 2002 a complaint was filed by InterGen North America, L.P. ("InterGen"), against Anne M. Sholtz, the owner of ACE, and EonXchange, another Sholtz-controlled entity, which filed for bankruptcy protection on May 6, 2002. InterGen alleges it suffered a loss of emission reduction credits from EonXchange in a manner similar to our loss from ACE. InterGen's complaint alleges that Anne Sholtz co-mingled assets among ACE, EonXchange and other Sholtz entities and that ACE and other Sholtz entities should be deemed to be one economic enterprise and all retroactively included in the EonXchange bankruptcy filing as of May 6, 2002. InterGen's complaint refers to the payment by ACE of $7 million to us, alleging that InterGen's ability to recover from EonXchange has been undermined thereby. We are unable to assess the likelihood of InterGen's complaint being upheld at this time. We are involved in various other claims and legal actions arising out of the normal course of our business. We do not expect that the outcome of these proceedings will have a material adverse effect on our financial position or results of operations. Item 4. Submission of Matters to a Vote of Security Holders. Our Annual Meeting of Stockholders was held on May 23, 2002, (the "Annual Meeting") in Aptos, California. At the Annual Meeting, the stockholders voted on the following matters: (i) the proposal to elect two Class III Directors to the Board of Directors for a term of three years expiring in 2005, (ii) the proposal to amend the Company's 1996 Stock Incentive Plan to increase by 12 million the number of shares of the Company's Common Stock, par value $.001 per share ("Common Stock") available for grants of options and other stock-based awards under such plan, (iii) the proposal to amend the Company's 2000 Employee Stock Purchase Plan to increase by 8 million the number of Common Stock available for grants of purchase rights under such plan, (iv) two stockholder proposals regarding (a) the composition of the Company's Board of Directors and (b) the Company's stockholder rights plan, (v) the proposal to ratify the appointment of Deloitte & Touche LLP as independent accountants for the Company for the fiscal year ending December 31, 2002. The stockholders elected management's nominees as the Class III Directors in an uncontested election, approved the amendment to the Company's 1996 Stock Incentive Plan to increase by 12 million the number of shares of the Company's Common Stock available for grants of options and other stock-based awards under such plan, approved the amendment to the Company's 2000 Employee Stock Purchase Plan to increase by 8 million the number of Common Stock available for grants of purchase rights under such plan, rejected the stockholder proposal regarding the composition of the Company's Board of Directors, approved the stockholder proposal that the Board of Directors be requested to redeem the stockholders right plan unless such plan is approved by a majority vote of the stockholders to be held as soon as may be practicable, and ratified the appointment of independent accountants by the following votes, respectively: -47- (i) Election of Peter Cartwright as Class III Director for a three-year term expiring 2005: 266,247,019 FOR and 3,748,417 ABSTAIN; Election of Susan C. Schwab as Class III Director for a three-year term expiring 2005: 266,315,844 FOR and 3,679,592 ABSTAIN; (ii) Amendment to the Company's 1996 Stock Incentive Plan to increase by 12 million the number of shares of the Company's Common Stock available for grants of options and other stock-based awards under such plan: 84,312,894 FOR, 68,320,701 AGAINST, 2,204,515 ABSTAIN, and 115,157,326 Broker non-votes; (iii) Amendment to the Company's Employee Stock Purchase Plan to increase by 8 million the number of shares of the Company's Common Stock available for grants of purchase rights under such plan: 137,879,225 FOR, 14,783,654 AGAINST, 2,175,231 ABSTAIN, and 115,157,326 Broker non-votes; (iv) Proposal regarding composition of the Company's Board of Directors: 51,697,103 FOR, 100,003,353 AGAINST, 3,137,654 ABSTAIN, and 115,157,326 Broker non-votes; (v) Proposal that the Board of Directors be requested to redeem the stockholders right plan unless such plan is approved by a majority vote of the stockholders to be held as soon as may be practicable: 92,639,512 FOR, 58,655,073 AGAINST, 3,543,525 ABSTAIN, and 115,157,326 Broker non-votes; (vi) Ratification of the appointment of Deloitte & Touche LLP as independent accountants for the fiscal year ending December 31, 2002: 261,041,303 FOR, 4,899,355 AGAINST, and 4,054,779 ABSTAIN. The three-year terms of Class I and Class II Directors continued after the Annual Meeting and will expire in 2003 and 2004, respectively. The Class I Directors are Jeffrey E. Garten, George J. Stathakis, and John O. Wilson. The Class II Directors are Ann B. Curtis, Kenneth T. Derr and Gerald Greenwald. 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 (e) *3.9 Certificate of Ownership and Merger Merging Calpine Natural Gas Company into Calpine Corporation (e) *3.10 Amended and Restated By-laws of Calpine Corporation (f) *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 (g) -48- EXHIBIT INDEX (continued) EXHIBIT NUMBER DESCRIPTION ------- ----------------------------------------------------------------- *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 (f) *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 (f) *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 (e) *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 (f) *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 (e) +10.7 Increase in Term B Loan Commitment Amount Notice, effective as of May 31, 2002, by The Bank of Nova Scotia and Citicorp USA, Inc., as Administrative Agents *10.8 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 (f) *10.9 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 (f) *10.10 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 (e) *10.11 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 (f) *10.12 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 (e) *10.13 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 (e) *10.14 Note 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 (e) +10.15 Hazardous Materials Undertaking and Indemnity (Multistate), dated as of May 9, 2002, by the Company in favor of The Bank of Nova Scotia, as Agent +10.16 Hazardous Materials Undertaking and Indemnity (California), dated as of May 9, 2002, by the Company in favor of The Bank of Nova Scotia, as Agent +10.17 Form of Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (Multistate), from the Company to Jon Burckin and Kemp Leonard, as Trustees, and The Bank of Nova Scotia, as Agent -49- EXHIBIT INDEX (continued) EXHIBIT NUMBER DESCRIPTION ------- ----------------------------------------------------------------- +10.18 Form of Deed of Trust with Power of Sale, Assignment of Production, Security Agreement, Financing Statement and Fixture Filing (California), dated as of May 1, 2002, from the Company to Chicago Title Insurance Company, as Trustee, and The Bank of Nova Scotia, as Agent +10.19 Form of Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (Colorado), dated as of May 1, 2002, from the Company to Kemp Leonard and John Quick, as Trustees, and The Bank of Nova Scotia, as Agent +10.20 Form of Mortgage, Assignment, Security Agreement and Financing Statement (Louisiana), dated as of May 1, 2002, from the Company to The Bank of Nova Scotia, as Agent +10.21 Form of Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (New Mexico), dated as of May 1, 2002, from the Company to Kemp Leonard and John Quick, as Trustees, and The Bank of Nova Scotia, as Agent +99.1 Certification of Peter Cartwright Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 +99.2 Certification of Robert D. Kelly Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 ---------------- * Incorporated by reference + Filed herewith (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 Quarterly Report on Form 10-Q dated March 31, 2002, filed with the SEC on May 15, 2002. (f) 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. (g) 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 or Form 8-K/A during the quarter ended June 30, 2002: . Date of Report Date Filed Item Reported --------------------------- ---------------- ------------- March 25, 2002.............. April 8, 2002 4,7 April 22, 2002.............. April 25, 2002 5,7 April 24, 2002.............. April 26, 2002 5,7 May 2, 2002................. May 3, 2002 5,7 May 31, 2002................ June 4, 2002 5,7 June 4, 2002................ June 6, 2002 5,7 -50- 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 Date: August 9, 2002 By: /s/ ROBERT D. KELLY ------------------------------------- Robert D. Kelly Executive Vice President and Chief Financial Officer (Principal Financial Officer) Date: August 9, 2002 By: /s/ CHARLES B. CLARK, JR. -------------------------------------- Charles B. Clark, Jr. Senior Vice President and Corporate Controller (Principal Accounting Officer) -51- 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 (e) *3.9 Certificate of Ownership and Merger Merging Calpine Natural Gas Company into Calpine Corporation (e) *3.10 Amended and Restated By-laws of Calpine Corporation (f) *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 (g) *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 (f) *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 (f) *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 (e) *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 (f) *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 (e) +10.7 Increase in Term B Loan Commitment Amount Notice, effective as of May 31, 2002, by The Bank of Nova Scotia and Citicorp USA, Inc., as Administrative Agents *10.8 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 (f) *10.9 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 (f) -52- EXHIBIT INDEX (continued) EXHIBIT NUMBER DESCRIPTION ------- ----------------------------------------------------------------- *10.10 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 (e) *10.11 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 (f) *10.12 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 (e) *10.13 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 (e) *10.14 Note 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 (e) +10.15 Hazardous Materials Undertaking and Indemnity (Multistate), dated as of May 9, 2002, by the Company in favor of The Bank of Nova Scotia, as Agent +10.16 Hazardous Materials Undertaking and Indemnity (California), dated as of May 9, 2002, by the Company in favor of The Bank of Nova Scotia, as Agent +10.17 Form of Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (Multistate), from the Company to Jon Burckin and Kemp Leonard, as Trustees, and The Bank of Nova Scotia, as Agent +10.18 Form of Deed of Trust with Power of Sale, Assignment of Production, Security Agreement, Financing Statement and Fixture Filing (California), dated as of May 1, 2002, from the Company to Chicago Title Insurance Company, as Trustee, and The Bank of Nova Scotia, as Agent +10.19 Form of Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (Colorado), dated as of May 1, 2002, from the Company to Kemp Leonard and John Quick, as Trustees, and The Bank of Nova Scotia, as Agent +10.20 Form of Mortgage, Assignment, Security Agreement and Financing Statement (Louisiana), dated as of May 1, 2002, from the Company to The Bank of Nova Scotia, as Agent +10.21 Form of Mortgage, Deed of Trust, Assignment, Security Agreement, Financing Statement and Fixture Filing (New Mexico), dated as of May 1, 2002, from the Company to Kemp Leonard and John Quick, as Trustees, and The Bank of Nova Scotia, as Agent +99.1 Certification of Peter Cartwright Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 +99.2 Certification of Robert D. Kelly Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 ---------------- * Incorporated by reference + Filed herewith (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. -53- (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 Quarterly Report on Form 10-Q dated March 31, 2002, filed with the SEC on May 15, 2002. (f) 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. (g) 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. -54-