-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, AYN1Y2TPzExEUhH71AVx73MII8a57gmLQdH3+f1nHMQAJsDUdcTCbyng445LeQ3G 9DdyVu70mheRemM4wVAJQw== 0000916457-02-000036.txt : 20021118 0000916457-02-000036.hdr.sgml : 20021118 20021114174613 ACCESSION NUMBER: 0000916457-02-000036 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 20020930 FILED AS OF DATE: 20021114 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CALPINE CORP CENTRAL INDEX KEY: 0000916457 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 770212977 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-12079 FILM NUMBER: 02826684 BUSINESS ADDRESS: STREET 1: 50 WEST SAN FERNANDO ST CITY: SAN JOSE STATE: CA ZIP: 95113 BUSINESS PHONE: 4089955115 MAIL ADDRESS: STREET 1: 50 W SAN FERNANDO STREET 2: SUITE 500 CITY: SAN JOSE STATE: CA ZIP: 95113 10-Q 1 q3-2002.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 September 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: 377,999,176 shares of Common Stock, par value $.001 per share, outstanding on November 12, 2002 ================================================================================ CALPINE CORPORATION AND SUBSIDIARIES Report on Form 10-Q For the Quarter Ended September 30, 2002
INDEX Page No. PART I - FINANCIAL INFORMATION Item 1. Financial Statements. Consolidated Condensed Balance Sheets September 30, 2002 and December 31, 2001....................... 3 Consolidated Condensed Statements of Operations For the Three and Nine Months Ended September 30, 2002 and 2001.................................................................. 5 Consolidated Condensed Statements of Cash Flows For the Nine Months Ended September 30, 2002 and 2001.................................................................. 7 Notes to Consolidated Condensed Financial Statements September 30, 2002.............................. 8 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations................... 29 Item 3. Quantitative and Qualitative Disclosures About Market Risk.............................................. 50 Item 4. Controls and Procedures................................................................................. 50 PART II - OTHER INFORMATION Item 1. Legal Proceedings....................................................................................... 50 Item 6. Exhibits and Reports on Form 8-K........................................................................ 52 Signatures........................................................................................................... 54 Certifications....................................................................................................... 55
-2- PART I - FINANCIAL INFORMATION Item 1. Financial Statements. CALPINE CORPORATION AND SUBSIDIARIES Consolidated Condensed Balance Sheets September 30, 2002 and December 31, 2001 (In thousands, except share amounts)
September 30, December 31, 2002 2001 -------------- ------------ (unaudited) ASSETS Current assets: Cash and cash equivalents ..................................................................... $ 659,694 $ 1,525,417 Accounts receivable, net ...................................................................... 838,632 956,596 Margin deposits and other prepaid expense ..................................................... 200,036 480,656 Inventories ................................................................................... 104,813 78,862 Current derivative assets ..................................................................... 556,259 763,162 Current assets held for sale .................................................................. 19,920 9,484 Other current assets .......................................................................... 297,742 193,525 ------------ ------------ Total current assets ....................................................................... 2,677,096 4,007,702 ------------ ------------ Restricted cash .................................................................................. 101,291 95,833 Notes receivable, net of current portion ......................................................... 193,767 158,124 Project development costs ........................................................................ 156,743 176,296 Investments in power projects .................................................................... 428,610 390,609 Deferred financing costs ......................................................................... 213,636 210,811 Property, plant and equipment, net ............................................................... 17,483,400 14,971,080 Goodwill and other intangible assets, net ........................................................ 128,281 141,120 Long-term derivative assets ...................................................................... 548,510 564,952 Long-term assets held for sale ................................................................... 241,474 308,463 Other assets ..................................................................................... 516,518 304,562 ------------ ------------ Total assets ............................................................................. $ 22,689,326 $ 21,329,552 ============ ============ LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable .............................................................................. $ 1,117,801 $ 1,283,843 Accrued payroll and related expense ........................................................... 46,352 57,285 Accrued interest payable ...................................................................... 202,947 160,115 Notes payable and borrowings under lines of credit, current portion ........................... 250,389 23,238 Capital lease obligation, current portion ..................................................... 3,001 2,206 Construction/project financing, current portion ............................................... 167,509 -- Zero-Coupon Convertible Debentures Due 2021 ................................................... -- 878,000 Current derivative liabilities ................................................................ 449,521 625,339 Current liabilities held for sale ............................................................. 4,522 4,576 Other current liabilities ..................................................................... 193,117 194,236 ------------ ------------ Total current liabilities .................................................................. 2,435,159 3,228,838 ------------ ------------ Term loan ........................................................................................ 1,000,000 -- Notes payable and borrowings under lines of credit, net of current portion ....................... 2,453 74,750 Capital lease obligation, net of current portion ................................................. 205,149 207,219 Construction/project financing, net of current portion ........................................... 3,510,595 3,393,410 Convertible Senior Notes Due 2006 ................................................................ 1,200,000 1,100,000 Senior notes ..................................................................................... 7,089,746 7,049,038 Deferred income taxes, net ....................................................................... 1,036,539 958,399 Deferred lease incentive ......................................................................... 54,608 57,236 Deferred revenue ................................................................................. 243,214 154,381 Long-term derivative liabilities ................................................................. 549,569 822,848 Long-term liabilities held for sale .............................................................. 5,983 5,947 Other liabilities ................................................................................ 112,409 96,504 ------------ ------------ Total liabilities ........................................................................ 17,445,424 17,148,570 ------------ ------------ Company-obligated mandatorily redeemable convertible preferred securities of subsidiary trusts ... 1,123,787 1,123,024 Minority interests ............................................................................... 198,875 47,389 ------------ ------------
(continues next page) -3- CALPINE CORPORATION AND SUBSIDIARIES Consolidated Condensed Balance Sheets September 30, 2002 and December 31, 2001 (In thousands, except share amounts) (continued)
September 30, December 31, 2002 2001 -------------- ------------ (unaudited) LIABILITIES AND STOCKHOLDERS' EQUITY (continued) 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 377,830,124 shares in 2002 and 307,058,751 shares in 2001 ............. 378 307 Additional paid-in capital ....................................................................... 2,795,582 2,040,836 Retained earnings ................................................................................ 1,355,597 1,196,000 Accumulated other comprehensive (loss) ........................................................... (230,317) (226,574) ------------ ------------ Total stockholders' equity .................................................................... 3,921,240 3,010,569 ------------ ------------ Total liabilities and stockholders' equity ................................................. $ 22,689,326 $ 21,329,552 ============ ============
The accompanying notes are an integral part of these consolidated condensed financial statements. -4- CALPINE CORPORATION AND SUBSIDIARIES Consolidated Condensed Statements of Operations For the Three and Nine Months Ended September 30, 2002 and 2001 (In thousands, except per share amounts) (unaudited)
Three Months Ended Nine Months Ended September 30, September 30, --------------------------- ---------------------------- 2002 2001 2002 2001 ----------- ----------- ----------- ------------ Revenue: Electric generation and marketing revenue Electricity and steam revenue ................................ $ 947,326 $ 710,506 $ 2,269,892 $ 1,804,889 Sales of purchased power for hedging and optimization ........ 1,282,976 1,653,088 2,526,555 2,680,488 ----------- ----------- ----------- ----------- Total electric generation and marketing revenue ............ 2,230,302 2,363,594 4,796,447 4,485,377 Oil and gas production and marketing revenue Oil and gas sales ............................................ 21,827 54,693 89,585 239,940 Sales of purchased gas for hedging and optimization .......... 231,893 56,916 666,095 412,782 ----------- ----------- ----------- ----------- Total oil and gas production and marketing revenue ......... 253,720 111,609 755,680 652,722 Trading revenue, net Realized revenue on power and gas trading transactions, net ......................................................... 6,845 16,700 15,276 21,340 Unrealized mark-to-market gain (loss) on power and gas transactions, net ........................................... (10,957) 7,128 (5,952) 107,862 ----------- ----------- ----------- ----------- Total trading revenue, net ................................. (4,112) 23,828 9,324 129,202 Income from unconsolidated investments in power projects ........ 10,176 6,859 10,499 9,021 Other revenue ................................................... 4,924 14,261 14,792 28,444 ----------- ----------- ----------- ----------- Total revenue ........................................... 2,495,010 2,520,151 5,586,742 5,304,766 ----------- ----------- ----------- ----------- Cost of revenue: Electric generation and marketing expense Plant operating expense ...................................... 141,262 93,709 374,497 246,045 Royalty expense .............................................. 4,743 5,255 13,092 23,181 Purchased power expense for hedging and optimization ......... 1,059,840 1,394,871 2,039,954 2,396,804 ----------- ----------- ----------- ----------- Total electric generation and marketing expense ............ 1,205,845 1,493,835 2,427,543 2,666,030 Oil and gas production and marketing expense Oil and gas production expense ............................... 22,953 13,009 67,381 62,371 Purchased gas expense for hedging and optimization ........... 220,775 52,856 678,192 389,814 ----------- ----------- ----------- ----------- Total oil and gas production and marketing expense ......... 243,728 65,865 745,573 452,185 Fuel expense .................................................... 525,478 327,947 1,208,092 846,195 Depreciation, depletion and amortization expense ................ 117,568 80,044 310,943 199,509 Operating lease expense ......................................... 36,520 27,830 108,917 83,289 Other expense ................................................... 3,539 3,485 8,333 9,474 ----------- ----------- ----------- ----------- Total cost of revenue ................................... 2,132,678 1,999,006 4,809,401 4,256,682 ----------- ----------- ----------- ----------- Gross profit ......................................... 362,332 521,145 777,341 1,048,084 Project development expense ........................................ 23,922 4,894 59,973 25,106 Equipment cancellation charge ...................................... 3,714 -- 172,185 -- General and administrative expense ................................. 57,280 29,357 170,369 114,924 Merger expense ..................................................... -- -- -- 41,627 ----------- ----------- ----------- ----------- Income from operations .......................................... 277,416 486,894 374,814 866,427 Interest expense ................................................... 113,847 47,657 239,112 107,473 Distributions on trust preferred securities ........................ 15,386 15,385 46,159 45,948 Interest income .................................................... (10,842) (21,073) (32,780) (60,870) Other (income)/expense ............................................. (33,778) (7,875) (49,128) (15,092) ----------- ----------- ----------- ----------- Income before provision for income taxes ........................ 192,803 452,800 171,451 788,968 Provision for income taxes ......................................... 48,406 139,304 38,805 278,161 ----------- ----------- ----------- ----------- Income before discontinued operations and cumulative effect of a change in accounting principle ............................ 144,397 313,496 132,646 510,807 Discontinued operations, net of tax provision of $9,675, $4,903, $15,059 and $24,374 .................. 16,950 7,303 26,950 36,284 Cumulative effect of a change in accounting principle, net of tax provision of $--, $--, $--and $669 ............................ -- -- -- 1,036 ----------- ----------- ----------- ----------- Net income ........................................... $ 161,347 $ 320,799 $ 159,596 $ 548,127 =========== =========== =========== ===========
(continues next page) -5- CALPINE CORPORATION AND SUBSIDIARIES Consolidated Condensed Statements of Operations For the Three and Nine Months Ended September 30, 2002 and 2001 (In thousands, except per share amounts) (unaudited) (continued)
Three Months Ended Nine Months Ended September 30, September 30, --------------------------- ---------------------------- 2002 2001 2002 2001 ----------- ----------- ----------- ------------ Basic earnings per common share: Weighted average shares of common stock outstanding ............. 376,957 304,666 346,816 302,649 Income before discontinued operations and cumulative effect of a change in accounting principle ............................ $ 0.38 $ 1.03 $ 0.38 $ 1.69 Income from discontinued operations, net of tax ................. $ 0.05 $ 0.02 $ 0.08 $ 0.12 Cumulative effect of a change in accounting principle ........... $ -- $ -- $ -- $ -- ----------- ----------- ----------- ----------- Net income ........................................... $ 0.43 $ 1.05 $ 0.46 $ 1.81 =========== =========== =========== =========== Diluted earnings per common share: Weighted average shares of common stock outstanding before dilutive effect of certain convertible securities .............. 382,607 318,552 355,577 317,880 Income before dilutive effect of certain convertible securities, discontinued operations and cumulative effect of a change in accounting principle ............................ $ 0.38 $ 0.98 $ 0.37 $ 1.61 Dilutive effect of certain convertible securities (1) ........... $ (0.05) $ (0.12) $ -- $ (0.14) ----------- ----------- ----------- ----------- Income before discontinued operations and cumulative effect of a change in accounting principle ............................ $ 0.33 $ 0.86 $ 0.37 $ 1.47 Income from discontinued operations, net of tax ................. $ 0.03 $ 0.02 $ 0.08 $ 0.10 Cumulative effect of a change in accounting principle ........... $ -- $ -- $ -- $ -- ----------- ----------- ----------- ----------- Net income ........................................... $ 0.36 $ 0.88 $ 0.45 $ 1.57 =========== =========== =========== =========== - ---------- (1) Includes the effect of the assumed conversion of certain dilutive convertible securities. No convertible securities were included in the nine months ended September 30, 2002, amounts as the securities were antidilutive. For the three months ended September 30, 2002, and for the three and nine months ended September 30, 2001, the assumed conversion calculation added 99,377, 58,153, and 52,353 shares of common stock and $14,326, $12,435, and $33,204 to the net income results, respectively.
The accompanying notes are an integral part of these consolidated condensed financial statements. -6- CALPINE CORPORATION AND SUBSIDIARIES Consolidated Condensed Statements of Cash Flows For the Nine Months Ended September 30, 2002 and 2001 (In thousands) (unaudited)
Nine Months Ended September 30, 2002 2001 ----------- ------------ Cash flows from operating activities: Net income ...................................................................................... $ 159,596 $ 548,127 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion and amortization ..................................................... 368,674 242,547 Equipment cancellation cost .................................................................. 172,212 -- Development cost write-off ................................................................... 32,269 -- Deferred income taxes, net ................................................................... 215,296 202,444 Gain on sale of assets ....................................................................... (37,151) (13,514) (Gain) loss on extinguishment of debt ........................................................ (3,491) 1,803 Minority interests ........................................................................... (2,672) (3,198) Income from unconsolidated investments in power projects ..................................... (10,499) (9,022) Distributions from unconsolidated investments in power projects .............................. 2,144 3,596 Change in operating assets and liabilities, net of effects of acquisitions: Accounts receivable ........................................................................ 107,528 (561,964) Notes receivable ........................................................................... (35,526) (74,709) Current derivative assets .................................................................. 206,903 (663,840) Other current assets ....................................................................... 157,690 (227,058) Long-term derivative assets ................................................................ 16,442 (541,898) Other assets ............................................................................... (32,853) (115,203) Accounts payable and accrued expense ....................................................... (131,292) 421,451 Current derivative liabilities ............................................................. (175,818) (744,322) Long-term derivative liabilities ........................................................... (273,279) 459,657 Other liabilities .......................................................................... 85,986 1,355,208 Other comprehensive income (loss) relating to derivatives .................................. (37,144) 195,900 ----------- ----------- Net cash provided by operating activities ............................................... 785,015 476,005 ----------- ----------- Cash flows from investing activities: Purchases of property, plant and equipment ...................................................... (3,177,525) (5,785,194) Disposals of property, plant and equipment ...................................................... 125,135 21,898 Advances to joint ventures ...................................................................... (64,707) (103,496) Increase in notes receivable .................................................................... 8,648 (140,152) Maturities of collateral securities ............................................................. 4,633 4,035 Project development costs ....................................................................... (84,833) (55,734) Increase in restricted cash ..................................................................... (14,453) (35,740) Other ........................................................................................... 5,312 8,384 ----------- ----------- Net cash used in investing activities ................................................... (3,197,790) (6,085,999) ----------- ----------- 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 ....................................... (869,736) -- Borrowings from notes payable and borrowings under lines of credit .............................. 1,252,453 141,543 Repayments of notes payable and borrowings under lines of credit ................................ (75,734) (444,820) Borrowings from project financing ............................................................... 438,521 2,324,209 Repayments of project financing ................................................................. (153,827) (1,234,776) Proceeds from issuance of Convertible Senior Notes Due 2006 ..................................... 100,000 -- Repayments of senior notes ...................................................................... -- (105,000) Proceeds from senior debt offerings ............................................................. -- 3,853,290 Proceeds from issuance of common stock .......................................................... 755,363 62,283 Proceeds from Income Trust Offering ............................................................. 169,400 -- Financing costs ................................................................................. (71,665) (86,452) Other ........................................................................................... -- (19,986) ----------- ----------- Net cash provided by financing activities ............................................... 1,544,775 5,490,291 ----------- ----------- Effect of exchange rate changes on cash and cash equivalents ....................................... 2,277 -- Net decrease in cash and cash equivalents .......................................................... (865,723) (119,703) Cash and cash equivalents, beginning of period ..................................................... 1,525,417 596,077 ----------- ----------- Cash and cash equivalents, end of period ........................................................... $ 659,694 $ 476,374 =========== =========== Cash paid during the period for: Interest, net of amounts capitalized ............................................................ $ 131,760 $ 27,626 Income taxes .................................................................................... $ 14,457 $ 114,667
The accompanying notes are an integral part of these consolidated condensed financial statements. -7- CALPINE CORPORATION AND SUBSIDIARIES Notes to Consolidated Condensed Financial Statements September 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"), the adoption of accounting standards relating to discontinued operations and the presentation of trading revenue on a net versus gross basis. 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, capitalization of interest 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. Where applicable, revenues are recognized under Emerging Issues Task Force ("EITF") No. 91-6, "Revenue Recognition of Long Term Power Sales Contracts," and are recognized ratably over the terms of the related contracts. To protect and enhance the profit potential of its electric generation plants, the Company, through its subsidiary, Calpine Energy Services, 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 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, when CES does not hold these contracts for trading purposes and, in accordance with Staff Accounting Bulletin No. 101, "Revenue Recognition in Financial Statements" and EITF Issue No. 99-19, -8- "Reporting Revenue Gross as a Principal Versus Net as an Agent," the Company records settlement of its non-trading physical forward contracts on a gross basis. Effective July 1, 2002, the Company now records all gains and losses from derivatives held for trading purposes on a net basis. Prior to July 1, 2002, physical trading contracts were recorded on a gross basis but have been reclassified to a net basis in this filing to conform to the current presentation. The Company settles its financial swap and option transactions net and does not take title to the underlying commodity. Accordingly, the Company records gains and losses from settlement of financial swaps and options net within net income. Managed risks typically include commodity price risk associated with fuel purchases and power sales. The Company, through its wholly owned subsidiary, Power Systems Mfg., LLC ("PSM"), designs and manufactures certain spare parts for gas turbines. The Company also generates revenue by occasionally loaning funds to power projects, by providing operation and maintenance ("O&M") services to third parties and to certain unconsolidated power projects, and by performing engineering services for data centers and other facilities requiring highly reliable power. The Company also has begun to sell engineering and construction services to third parties for power projects. Further details of the Company's revenue recognition policy for each type of revenue transaction are provided below: Electric Generation and Marketing Revenue -- This includes electricity and steam sales and sales of purchased power for hedging and optimization. Subject to market and other conditions, the Company manages the revenue stream for its portfolio of electric generating facilities. The Company markets on a system basis both power generated by its plants in excess of amounts under direct contract between the plant and a third party, and power purchased from third parties, through hedging, balancing and optimization transactions. CES performs a market-based allocation of total electric generation and marketing revenue to electricity and steam sales (based on electricity delivered by the Company's electric generating facilities) and the balance is allocated to sales of purchased power. Oil and Gas Production and Marketing Revenue -- This includes sales to third parties of oil, gas and related products that are produced by the Company's Calpine Natural Gas and Calpine Canada Natural Gas subsidiaries and, subject to market and other conditions, sales of purchased gas arising from hedging, balancing and optimization transactions. Oil and gas sales for produced products are recognized pursuant to the sales method. Trading Revenue, Net -- This includes realized settlements of and unrealized mark-to-market gains and losses on both power and gas derivative instruments held for trading purposes. Gains and losses due to ineffectiveness on hedging instruments are also included in unrealized mark-to-market gains and losses. Income from Unconsolidated Investments in Power Projects -- The Company uses the equity method to recognize as revenue its pro rata share of the net income or loss of the unconsolidated investment until such time, if applicable, that the Company's investment is reduced to zero, at which time equity income is generally recognized only upon receipt of cash distributions from the investee. Other Revenue -- This includes O&M contract revenue, interest income on loans to power projects, PSM revenue from sales to third parties, engineering revenue and miscellaneous revenue. Purchased Power and Purchased Gas Expense -- The cost of power purchased from third parties for hedging, balancing and optimization activities is recorded as purchased power expense, a component of electric generation and marketing expense. The Company records the cost of gas consumed in its power plants as fuel expense, while gas purchased from third parties for hedging, balancing, and optimization activities is recorded as purchased gas expense, a component of oil and gas production and marketing expense. Derivative Instruments -- Financial Accounting Standards Board ("FASB") Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities" as amended by SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities -- Deferral of the Effective Date of FASB Statement No. 133 -- an Amendment of FASB Statement No. 133," 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, establishes 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. 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 -9- 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. New Accounting Pronouncements -- In July 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 has not completed its assessment of the impact of SFAS No. 143. 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 net effect on the Company's consolidated financial statements, although certain reclassifications have been made to current and prior period financial statements to reflect the sale or designation as "held for sale" of certain oil and gas and power plant assets and classification of the operating results. In general, gains from completed sales and any anticipated losses on "held for sale" assets (of which there are none to date) are included in discontinued operations net of tax. See Note 7 - Discontinued Operations, for further information. 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" and provides 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 Company has elected early adoption, effective July 1, 2002, of the provisions related to the rescission of SFAS No. 4, the effect of which has been reflected in these financial statements as reclassifications of gains and losses from the extinguishment of debt from extraordinary gain or loss to other (income)/expense. 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 believes that the SFAS No. 145 provisions relating to extinguishment of debt may have a material effect on future presentation of its financial statements but no impact on net income. -10- 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 EITF No. 94-3, a liability for an exit cost was recognized at the date of commitment to an exit plan. SFAS No. 146 also establishes that the liability should initially be measured and recorded at fair value. Accordingly, SFAS No. 146 may affect the timing of recognizing future restructuring costs as well as the amounts recognized. The Company does not believe that SFAS No. 146 will have a material effect on its consolidated financial statements other than timing of exit costs, potentially. In October 2002 the EITF discussed EITF Issue No. 02-3, "Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities." The EITF reached a consensus to rescind EITF Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," the impact of which is to preclude mark-to-market accounting for all energy trading contracts not within the scope of SFAS No. 133. The Task Force also reached a consensus that gains and losses on derivative instruments within the scope of SFAS No. 133 should be shown net in the income statement if the derivative instruments are held for trading purposes. The Company expects that further clarifications may be forthcoming from the EITF on this issue that could have an affect on the presentation of the Company's financial statements. The Company has not completed its assessment of the impact that EITF No. 02-3 will have on its financial statements. Effective July 1, 2002, the Company reclassified certain revenue amounts and cost of revenue in all periods presented in its Statement of Operations as follows (in thousands):
Three Months Ended Nine Months Ended September 30, September 30, ------------------------- -------------------------- 2002 2001 2002 2001 --------- --------- --------- ---------- Amounts previously classified as: Sales of purchased power ........................................ $ 203,878 $ 373,969 $ 737,921 $ 483,381 Sales of purchased gas .......................................... 54,081 7,851 67,970 16,789 Purchased power expense ......................................... 201,549 369,660 734,616 479,315 Purchased gas expense ........................................... 54,848 6,659 68,517 14,937 Cost of oil and natural gas burned by power plants (fuel expense) ....................................................... (5,283) (11,199) (12,518) (15,422) --------- --------- --------- --------- Net amount reclassified to: Realized revenue on power and gas trading transactions, net ........................................... $ 6,845 $ 16,700 $ 15,276 $ 21,340 ========= ========= ========= ========= Amounts previously classified as: Electric power derivative mark-to-market gain (loss) ............ (1,068) 13,577 9,201 83,316 Natural gas derivative mark-to-market gain (loss) ............... (9,889) (6,449) (15,153) 24,546 --------- --------- --------- --------- Net amount reclassified to: Unrealized mark-to-market gain (loss) on power and gas trading transactions, net ............................... $ (10,957) $ 7,128 $ (5,952) $ 107,862 ========= ========= ========= =========
Reclassifications -- Prior period amounts in the consolidated condensed financial statements have been reclassified where necessary to conform to the 2002 presentation. -11- 3. Property, Plant and Equipment, and Capitalized Interest Property, plant and equipment, net, consisted of the following (in thousands):
September 30, December 31, 2002 2001 ------------ ------------- Buildings, machinery and equipment ................................... $ 8,655,369 $ 4,743,319 Oil and gas properties, including pipelines .......................... 2,165,849 2,043,296 Geothermal properties ................................................ 395,382 371,156 Other ................................................................ 195,884 114,239 ------------ ------------ 11,412,484 7,272,010 Less: Accumulated depreciation, depletion and amortization ....... (1,188,406) (849,016) ------------ ------------ 10,224,078 6,422,994 Land ................................................................. 77,472 80,506 Construction in progress ............................................. 7,181,850 8,467,580 ------------ ------------ Property, plant and equipment, net ................................... $ 17,483,400 $ 14,971,080 ============ ============
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 has led to a reduction in the Company's construction in progress. See Note 13 for further discussion. As of September 30, 2002, the Company has reclassified $204.4 million of equipment costs from construction in progress to other assets, as the equipment is not required for the Company's current power plant development program. During the year, the Company has recorded a $20.7 million charge to project development expense to effect a reduction in the carrying value of such equipment. The Company currently anticipates that some of the equipment will be used for future power plants and others may be sold to third parties. The Company is now in negotiations to restructure contracts for certain of its remaining gas turbines and steam turbines. 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. 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 September 30, 2002 and 2001, the total amount of interest capitalized was $123.2 million and $121.6 million, including $22.2 million and $29.0 million, respectively, of interest incurred on funds borrowed for specific construction projects and $101.0 million and $92.6 million, respectively, of interest incurred on general corporate funds used for construction. During the nine months ended September 30, 2002 and 2001, the total amount of interest capitalized was $457.3 million and $341.2 million, including $94.3 million and $94.9 million, respectively, of interest incurred on funds borrowed for specific construction projects and $363.0 million and $246.3 million, respectively, of interest incurred on general corporate funds used for construction. Upon commencement of plant operation, capitalized interest, as a component of the total cost of the plant, is amortized over the estimated useful life of the plant. The increase in the amount of interest capitalized during 2002, compared to 2001, reflects the 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 -12- 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 $600 million and $400 million 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 September 30, ------------------------------------------------------------------------- 2002 2001 ---------------------------------- ---------------------------------- Per Share Per Share ------------------- ------------------- Amount Diluted Basic Amount Diluted Basic ---------- ------- ------ ---------- ------- ------- Reported income before discontinued operations and cumulative effect of accounting changes................ $ 144,397 $ 0.33 $ 0.38 $ 313,496 $ 0.86 $ 1.03 Add: Goodwill amortization........................ -- -- -- 221 -- -- Pro forma income before discontinued operations and cumulative effect of accounting changes................ 144,397 0.33 0.38 313,717 0.86 1.03 Discontinued operations and cumulative effect of accounting changes, net of tax......................... 16,950 0.03 0.05 7,303 0.02 0.02 ---------- ------ ------ ---------- ------ ------ Pro forma net income.............................. $ 161,347 $ 0.36 $ 0.43 $ 321,020 $ 0.88 $ 1.05 ========== ====== ====== ========== ====== ====== Nine Months Ended September 30, ------------------------------------------------------------------------- 2002 2001 ---------------------------------- ---------------------------------- Per Share Per Share ------------------- ------------------- Amount Diluted Basic Amount Diluted Basic ---------- ------- ------ ---------- ------- ------- Reported income before discontinued operations and cumulative effect of accounting changes................ $ 132,646 $ 0.37 $ 0.38 $ 510,807 $ 1.47 $ 1.69 Add: Goodwill amortization........................ -- -- -- 562 -- -- Pro forma income before discontinued operations and cumulative effect of accounting changes................ 132,646 0.37 0.38 511,369 1.47 1.69 Discontinued operations and cumulative effect of accounting changes, net of tax......................... 26,950 0.08 0.08 37,320 0.10 0.12 ---------- ------ ------ ----------- ------ ------ Pro forma net income.............................. $ 159,596 $ 0.45 $ 0.46 $ 548,689 $ 1.57 $ 1.81 ========== ====== ====== =========== ====== ======
Recorded goodwill, by segment, as of September 30, 2002 and December 31, 2001, was (in thousands): September 30, 2002 December 31, 2001 Electric Generation and Marketing....... $ 29,348 $ 29,375 Oil and Gas Production and Marketing.... -- -- Corporate, Other and Eliminations....... -- -- --------- --------- Total................................ $ 29,348 $ 29,375 ========= ========= 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. -13- 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 September 30, 2002 As of December 31, 2001 --------------------------- -------------------------- Weighted Average Useful Life/Contract Carrying Accumulated Carrying Accumulated Life Amount Amortization Amount Amortization ------------- ---------- ------------ ---------- ------------ Patents........................................ 5 $ 485 $ (206) $ 485 $ (134) Power sales agreements......................... 14 159,563 (103,874) 159,563 (86,646) Fuel supply and fuel management contracts...... 26 22,198 (3,882) 22,198 (3,216) Geothermal lease rights........................ 20 19,493 (325) 19,493 (250) Steam purchase agreement....................... 14 5,073 (386) - - Other.......................................... 5 852 (58) 277 (25) ---------- ---------- ---------- ---------- Total....................................... $ 207,664 $ (108,731) $ 202,016 $ (90,271) ========== ========== ========== ==========
Amortization expense of other intangible assets was $6.4 million and $5.9 million in the three months ended September 30, 2002 and 2001, respectively, and $18.5 million and $17.8 million in the nine months ended September 30, 2002 and 2001, respectively. Assuming no future impairments of these assets or additions as the result of acquisitions, annual amortization expense will be $21.7 million for the twelve months ended December 31, 2002, $5.5 million in 2003, $5.0 million in 2004, $5.0 million in 2005 and $4.9 million in 2006. 5. 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 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 September 30, 2002, there was $117.5 million in borrowings outstanding under this agreement. 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. $50.0 million was repaid on August 7, 2002, and the remaining $50.0 million (which is classified as current project financing) is payable on November 25, 2002. 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 aggregate size of its secured corporate revolving credit facilities to $1.0 billion (the $600 million and $400 million facilities, respectively,) from $1.4 billion. At September 30, 2002, the Company had $1.0 billion in funded borrowings outstanding under the term loan facility, and $250.0 million in funded borrowings outstanding, and $595.2 million in outstanding letters of credit under the revolving credit facilities. The revolving credit facilities expire in 2003. However, any letters of credit under the $600 million revolving credit facility can be extended for one year at the Company's option. In 2004 the $1 billion term loan matures. On August 22, 2002, the Company completed a $106 million non-recourse project financing for the construction of its 300 megawatt Blue Spruce Energy Center. At September 30, 2002, the Company had $47.2 million in funded borrowings under this non-recourse construction and term-loan facility. In November 2003 and 2004 the Company's $1.0 billion and $2.5 billion secured revolving construction financing facilities will mature, requiring the Company to repay or refinance this indebtedness. At September 30, 2002, there was $969.8 million and $2,493.6 million outstanding, respectively, under these facilities. For financing activity subsequent to September 30, 2002, see Note 15 - Subsequent Events. -14- 6. Canadian Income Trust On August 29, 2002, the Company announced it had completed a Cdn$230 million (US$147.5 million) initial public offering of its Canadian income trust fund - Calpine Power Income Fund (the "Fund"). The 23 million Trust Units issued to the public were priced at Cdn$10.00 per unit, to initially yield 9.35% per annum. The Fund indirectly owns interests in two of Calpine's Canadian power generating assets, one of which is under construction, and will make a loan to a Calpine subsidiary which owns Calpine's other Canadian power generating asset. Combined, these assets represent approximately 550 net megawatts of power generating capacity. On September 20, 2002, the syndicate of underwriters fully exercised the over-allotment option that it was granted as part of the initial public offering of Trust Units and acquired 3,450,000 additional Trust Units of the Fund at Cdn$10 per Trust Unit, generating Cdn$34.5 million (US$21.9 million). This brings the total gross amount of the initial public offering to Cdn$264.5 million (US$169.4 million) as of September 30, 2002. The Company intends to retain a substantial interest and operating and management role in the Calpine Power Income Fund and the Fund assets and, accordingly, the financial results of the Fund are consolidated in the Company's financial statements. At September 30, 2002, the Company held 49% of the Fund's authorized Trust Units. The proceeds from the public offering of Trust Units were recorded as minority interests in the Company's balance sheet. 7. Discontinued Operations As a result of the significant contraction in the availability of capital for participants in the energy sector, the Company has adopted a strategy of conserving its core strategic assets. Implicit within this strategy is the disposal of certain assets, which serves primarily to strengthen the Company's balance sheet through repayment of debt. Set forth below are all of the Company's announced and/or completed asset disposals by reportable segment as of September 30, 2002: Oil and Gas Production and Marketing On August 29, 2002, the Company completed the sale of certain non-strategic oil and gas properties ("Medicine River properties") located in central Alberta to NAL Oil and Gas Trust and another institutional investor for Cdn$125 million (US$81 million). In September 2002 the Company announced an agreement with Pengrowth Corporation, administrator of Pengrowth Energy Trust, to sell substantially all of the Company's British Columbia oil and gas properties. The sale was subsequently completed on October 1, 2002, for approximately Cdn$387.5 million (US$243.7 million). See Note 15 - Subsequent Events - for further discussion. In September 2002 the Company executed a Purchase and Sale Agreement with Goldking Energy Corporation to sell all of the oil and gas properties in Drake Bay Field located in Plaquemines Parish, Louisiana for approximately $3 million. The sale was subsequently completed on October 31, 2002. Electric Generation and Marketing On June 28, 2002, the Company executed a definitive agreement with Wisconsin Public Service for the sale to Wisconsin Public Service of the Company's 180-megawatt DePere Energy Center. The closing of this transaction is subject to certain conditions. One of the conditions, the receipt of regulatory approval by the State of Wisconsin, was satisfied on September 16, 2002. The sale is expected to close during the fourth quarter of 2002. Upon completion of the sale, Wisconsin Public Service will pay the Company $120.4 million for the DePere facility, and the existing power purchase agreement will be terminated. -15- The tables below present significant components of the Company's income from discontinued operations for the three and nine months ended 2002 and 2001, respectively (in thousands):
Three Months Ended September 30, 2002 Three Months Ended September 30, 2001 ------------------------------------------- ------------------------------------------ Electric Oil and Gas Electric Oil and Gas Generation Production Generation Production and Marketing and Marketing Total and Marketing and Marketing Total ------------- ------------- -------- ------------- ------------- -------- Total revenue...................... $ 4,440 $26,369 $ 30,809 $ 4,463 $ 30,168 $ 34,631 Gain on disposal before taxes...... -- 22,996 22,996 -- -- -- Income from discontinued operations before taxes........... 588 26,037 26,625 35 12,171 12,206 Income from discontinued operations, net of tax............ 287 16,663 16,950 20 7,283 7,303 Nine Months Ended September 30, 2002 Nine Months Ended September 30, 2001 ------------------------------------------- ------------------------------------------ Electric Oil and Gas Electric Oil and Gas Generation Production Generation Production and Marketing and Marketing Total and Marketing and Marketing Total ------------- ------------- -------- ------------- ------------- -------- Total revenue...................... $ 10,091 $73,931 $ 84,022 $ 10,936 $117,926 $128,862 Gain on disposal before taxes...... -- 22,996 22,996 -- -- -- Income from discontinuing operations before taxes........... 1,858 40,151 42,009 (293) 60,951 60,658 Income from discontinued operations, net of tax............ 1,112 25,838 26,950 (177) 36,461 36,284
The table below presents the assets and liabilities held for sale on the Company's balance sheet as of September 30, 2002 and December 31, 2001, respectively:
September 30, 2002 December 31, 2001 ------------------------------------------- ------------------------------------------ Electric Oil and Gas Electric Oil and Gas Generation Production Generation Production and Marketing and Marketing Total and Marketing and Marketing Total ------------- ------------- -------- ------------- ------------- -------- Current assets held for sale....... $ -- $ 19,920 $ 19,920 $ -- $ 9,484 $ 9,484 Long-term assets held for sale..... 76,489 164,985 241,474 70,304 238,159 308,463 -------- -------- -------- -------- -------- -------- Total assets held for sale....... $ 76,489 $184,905 $261,394 $ 70,304 $247,643 $317,947 ======== ======== ======== ======== ======== ======== Current liabilities held for sale.. $ -- $ 4,522 $ 4,522 $ -- $ 4,576 $ 4,576 Long-term liabilities held for sale 5,983 -- 5,983 5,947 -- 5,947 -------- -------- -------- -------- -------- -------- Total liabilities held for sale.. $ 5,983 $ 4,522 $ 10,505 $ 5,947 $ 4,576 $ 10,523 ======== ======== ======== ======== ======== ========
The Company allocates interest expense associated with consolidated non-specific debt to its discontinued operations based on a ratio of the net assets of its discontinued operations to the Company's total consolidated net assets, in accordance with EITF Issue No. 87-24, "Allocation of Interest to Discontinued Operations" ("EITF No. 87-24"). Also in accordance with EITF No. 87-24, the Company allocated interest expense to its British Columbia oil and gas properties for approximately $50.4 million of debt the Company is required to repay under the terms of its $1.0 billion term loan. For the three months ended September 30, 2002 and 2001, the Company allocated interest expense of $2.8 million and $1.3 million, respectively, to its discontinued operations. For the nine months ended September 30, 2002 and 2001, the Company allocated interest expense of $5.8 million and $3.1 million, respectively, to its discontinued operations. 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 -16- 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. 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. 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 September 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.......................... $ -- $ -- $ 556,259 $ 556,259 Long-term derivative assets........................ -- -- 548,510 548,510 ----------- ----------- ----------- ----------- Total assets.................................... $ -- $ -- $ 1,104,769 $ 1,104,769 =========== =========== =========== =========== Current derivative liabilities..................... $ 13,486 $ 2,645 $ 433,390 $ 449,521 Long-term derivative liabilities................... 28,881 10,992 509,696 549,569 ----------- ----------- ----------- ----------- Total liabilities............................... $ 42,367 $ 13,637 $ 943,086 $ 999,090 =========== =========== =========== =========== Net derivative assets (liabilities).......... $ (42,367) $ (13,637) $ 161,683 $ 105,679 =========== =========== =========== ===========
-17- 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. 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, changes in the derivative asset or liability are no longer recorded to OCI. At this point, an accumulated OCI balance remains that 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 September 30, 2002 (in thousands):
Net derivative assets......................................................................... $ 105,679 Derivatives not designated as cash flow hedges and recognized hedge ineffectiveness........... (170,507) Cash flow hedges terminated prior to maturity................................................. (283,448) Deferred tax asset attributable to accumulated other comprehensive loss on cash flow hedges... 126,305 Accumulated OCI from unconsolidated investees................................................. 16,625 Other reconciling items....................................................................... 2,108 ---------- Accumulated other comprehensive loss from derivative instruments, net of tax.................. $ (203,238) ==========
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 September 30, 2002. September 30, 2002 ------------------------------ Gross Net ------------ ------------ Current derivative assets.................... $ 884,615 $ 556,259 Long-term derivative assets.................. 682,683 548,510 ------------ ------------ Total derivative assets................... $ 1,567,298 $ 1,104,769 ============ ============ Current derivative liabilities............... $ 761,746 $ 433,390 Long-term derivative liabilities............. 643,869 509,696 ------------ ------------ Total derivative liabilities.............. $ 1,405,615 $ 943,086 ============ ============ Net commodity derivative assets........ $ 161,683 $ 161,683 ============ ============ The table above excludes the value of interest rate and currency derivative instruments. -18- 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 nine months ended September 30, 2002 and 2001, respectively (in thousands):
Three Months Ended September 30, -------------------------------------------------------------------------------------------- 2002 2001 -------------------------------------------- --------------------------------------------- Hedge Undesignated Hedge Undesignated Ineffectiveness Derivatives Total Ineffectiveness Derivatives Total --------------- ------------ --------- --------------- ------------ -------- Natural gas derivatives............ $(2,141) $(7,748) $ (9,889) $(2,346) $(4,103) $(6,449) Power derivatives.................. (3,072) 2,004 (1,068) -- 13,577 13,577 Interest rate derivatives (1)...... (236) -- (236) (95) -- (95) ------- ------- -------- ------- ------- ------- Total........................... $(5,449) $(5,744) $(11,193) $(2,441) $ 9,474 $ 7,033 ======= ======= ======== ======= ======= ======= Nine Months Ended September 30, -------------------------------------------------------------------------------------------- 2002 2001 -------------------------------------------- --------------------------------------------- Hedge Undesignated Hedge Undesignated Ineffectiveness Derivatives Total Ineffectiveness Derivatives Total --------------- ------------ --------- --------------- ------------ -------- Natural gas derivatives............ $ 584 $(15,737) $(15,153) $(5,818) $ 30,364 $ 24,546 Power derivatives.................. (4,296) 13,497 9,201 -- 83,316 83,316 Interest rate derivatives (1)...... (577) -- (577) (112) -- (112) ------- -------- -------- ------- -------- -------- Total........................... $(4,289) $ (2,240) $ (6,529) $(5,930) $113,680 $107,750 ======= ======== ======== ======= ======== ======== - ---------- (1) Recorded within Other Income
The table below reflects the contribution of the Company's cash flow hedge activity to pre-tax earnings based on the reclassification adjustment from OCI to earnings for the three and nine months ended September 30, 2002 and 2001, respectively (in thousands):
Three Months Ended Nine Months Ended September 30, September 30, ----------------------------- ----------------------------- 2002 2001 2002 2001 ---------- ---------- ---------- ---------- Natural gas and crude oil derivatives .................. $ (43,224) $ (25,913) $(118,267) $ 2,067 Power derivatives ...................................... 90,747 126,930 252,527 120,742 Interest rate derivatives .............................. (3,385) (9,085) (8,012) (9,085) Foreign currency derivatives ........................... -- -- (2,794) -- --------- --------- --------- --------- Total derivatives ................................... $ 44,138 $ 91,932 $ 123,454 $ 113,724 ========= ========= ========= =========
As of September 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 8, 6 1/2, and 12 years, for commodity, foreign currency and interest rate derivative instruments, respectively. The Company estimates that pre-tax losses of $87.5 million would be reclassified from accumulated OCI into earnings during the twelve months ended September 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. 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. -19-
2007 Q4 2002 2003 2004 2005 2006 & After Total ---------- ---------- ---------- ---------- ---------- ---------- ---------- Crude oil OCI (1) ................ $ (2,614) $ (1,763) $ -- $ -- $ -- $ -- $ (4,377) Gas OCI .......................... (1,607) (145,939) (62,061) (61,243) (26,978) 2,842 (294,986) Power OCI ........................ 21,767 51,765 7,332 1,827 3,651 (1,149) 85,193 Interest rate OCI ................ (16,128) (18,091) (14,539) (11,995) (10,303) (29,965) (101,021) Foreign currency OCI ............. (144) (2,034) (2,004) (1,973) (1,966) (6,233) (14,354) --------- --------- --------- --------- --------- --------- --------- Total pre-tax OCI ............. $ 1,274 $(116,062) $ (71,272) $ (73,384) $ (35,596) $ (34,505) $(329,545) ========= ========= ========= ========= ========= ========= ========= - ---------- (1) Amounts in crude oil OCI relate to certain of the Company's oil and gas discontinued operations. These amounts will continue to be recognized into income from discontinued operations until the disposals have been completed. See Note 7 - Discontinued Operations - for further discussion.
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 September 30, 2002 -------------------------------------------------------------------- Cash Flow Foreign Currency Comprehensive Hedges Translation Total Income (Loss) ----------- ---------------- ----------- ------------- Accumulated other comprehensive loss at December 31, 2001............................................ $ (183,377) $ (43,197) $ (226,574) Net loss for the three months ended March 31, 2002............ $ (74,267) 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 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 September 30, 2002 -------------------------------------------------------------------- Cash Flow Foreign Currency Comprehensive Hedges Translation Total Income (Loss) ----------- ---------------- ----------- ------------- Net income for the three months ended September 30, 2002...... $ 161,347 Cash flow hedges: Comprehensive pre-tax loss on cash flow hedges before reclassification adjustment during the three months ended September 30, 2002........................ $ (74,813) Reclassification adjustment for gain included in net income for the three months ended September 30, 2002..................................... (44,138) Income tax benefit for the three months ended September 30, 2002..................................... 44,830 ---------- (74,121) $ (74,121) (74,121) Foreign currency translation loss for the three months ended September 30, 2002.................................. $ (37,489) (37,489) (37,489) ---------- ---------- ---------- ---------- Total comprehensive income for the three months ended September 30, 2002........................................... 49,737 ---------- Total comprehensive income for the nine months ended September 30, 2002........................................... $ 155,853 ========== Accumulated other comprehensive loss at September 30, 2002........................................... $ (203,238) $ (27,079) $ (230,317) ========== ========== ========== Accumulated Other Comprehensive Income (Loss) At September 30, 2001 -------------------------------------------------------------------- Cash Flow Foreign Currency Comprehensive Hedges Translation Total Income (Loss) ----------- ---------------- ----------- ------------- Accumulated other comprehensive loss at December 31, 2000............................................ $ -- $ (23,085) $ (23,085) Net loss for the three months ended March 31, 2001 $ 119,663 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 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 at June 30, 2001....... $ 103,352 $ (24,941) $ 78,411 ========== ========== ==========
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Accumulated Other Comprehensive Income (Loss) At September 30, 2002 -------------------------------------------------------------------- Cash Flow Foreign Currency Comprehensive Hedges Translation Total Income (Loss) ----------- ---------------- ----------- ------------- Net income for the three months ended September 30, 2001...... $ 320,799 Cash flow hedges: Comprehensive pre-tax loss on cash flow hedges before reclassification adjustment during the three months ended September 30, 2001........................ $ (387,558) Reclassification adjustment for gain included in net income for the three months ended September 30, 2001..................................... (91,932) Income tax benefit for the three months ended September 30, 2001..................................... 188,578 ---------- (290,912) $ (290,912) (290,912) Foreign currency translation loss for the three months ended September 30, 2001.................................. $ (10,659) (10,659) (10,659) ---------- ---------- ---------- ---------- Total comprehensive income for the three months ended September 30, 2001........................................... 19,228 ---------- Total comprehensive income for the nine months ended September 30, 2001........................................... $ 348,052 ========== Accumulated other comprehensive loss at September 30, 2001........................................... $ (187,560) $ (35,600) $ (223,160) ========== ========== ==========
10. Customers 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 requested that its power suppliers extend payment terms to help it overcome its short-term liquidity problems. In June and July 2002 NPC underpaid the Company by approximately $4.2 million, and the Company established a bad debt reserve of approximately $2.7 million against NPC receivables. 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. In September, 2002, NPC notified the Company of its intention to repay all outstanding payables owed to the Company for power deliveries made during the period of May 1, 2002 through September 15, 2002, following execution by the Company of an agreement to forebear from taking action against NPC provided NPC makes certain periodic payments. On October 25, 2002, the Company received approximately $22.2 million from NPC as repayment of past due amounts for power deliveries through September 15, 2002. As of September 30, 2002, the Company had net collection exposures of approximately $35.1 million and $9.6 million with NPC and SPPC, respectively. 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 September 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........................... $ 42.7 $ (14.8) $ 27.9 $ 20.1 $ (12.9) $ 7.2 $ 35.1 SPPC.......................... 6.3 -- 6.3 3.3 -- 3.3 9.6 ------- ------- ------- ------- ------- ------- ------- Total...................... $ 49.0 $ (14.8) $ 34.2 $ 23.4 $ (12.9) $ 10.5 $ 44.7 ======= ======= ======= ======= ======= ======= =======
-22- Under the terms of its contracts with NPC and SPPC, the Company believes that it has the right to offset asset and liability positions. NRG Power Marketing, Inc. The Company has open contract positions with NRG Power Marketing, Inc., a subsidiary of NRG Energy, Inc., which in turn is the unregulated power-generation subsidiary of XCEL Energy Inc. Almost all of the open contracts are accounted for as cash flow hedges under SFAS No. 133. NRG Energy, Inc. has reportedly experienced financial problems, defaulted on certain loan payments and has had its long-term debt rating downgraded to D by Standard & Poor's. According to a report published on November 8, 2002, NRG Energy, Inc. has discussed a Chapter 11 bankruptcy filing with its lenders. While NRG Power Marketing, Inc. has remained current in its payments to the Company through October 20, 2002, the Company has established a partial reserve in OCI in the balance sheet against the fair value of its open contract position with NRG Power Marketing, Inc. The Company will continue to closely monitor its position with NRG Power Marketing, Inc. and will adjust the value of the reserve as conditions dictate. The Company's exposure, net of the established reserve, to NRG Power Marketing, Inc. at September 30, 2002, is summarized below (in millions):
Receivables/Payables Open Positions --------------------------------------- -------------------------------------- Net Gross Gross Net Open Gross Gross Receivable Fair Value Fair Value Positions Receivable Payable (Payable) (+) (-) Value Total ---------- -------- ---------- ---------- ---------- --------- -------- NRG Power Marketing, Inc...... $ 3.0 $ (0.0) $ 3.0 $ 6.3 $ (0.5) $ 5.8 $ 8.8
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 $6 million, with no payments 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 has also filed for insolvency. However, the Dutch company has assured the Company that it has not and currently does not expect to file for insolvency. 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, the Company has not established a reserve against the related receivable but will continue to closely monitor the situation. Aquila Merchant Services, Inc. On November 13th, Aquila Inc. ("Aquila"), the parent of Aquila Merchant Services, Inc., ("AMS"), reported third quarter 2002 losses of approximately $332 million, suspended its dividend and disclosed that it had obtained debt covenant waivers expiring in April 2003 from certain of its lenders. Currently Aquila has an investment grade rating with two of the three major credit rating agencies. We believe that a downgrade in Aquila's credit rating could trigger additional collateral requirements under Aquila's and AMS's contractual commitments. We currently buy and sell electricity and natural gas from Aquila and AMS under a variety of contractual arrangements. We account for certain of our contractual arrangements with AMS as derivatives under SFAS No. 133 and, accordingly, record the fair value of the open positions under these contracts in our financial statements. We also have tolling arrangements with AMS on our Acadia facility and with Aquila on our Aries facility under which they deliver gas to, and purchase electricity from, us with 20 and 15.5 year terms, respectively. These tolling agreements are not subject to derivative accounting. We also have outstanding receivable and payable balances with Aquila and AMS. The net value of the positions in our balance sheet at September 30, 2002, is summarized below (in millions):
Receivables/Payables Open Positions --------------------------------------- -------------------------------------- Net Gross Gross Net Open Gross Gross Receivable Fair Value Fair Value Positions Receivable Payable (Payable) (+) (-) Value Total ---------- -------- ---------- ---------- ---------- --------- -------- AMS and Aquila................ $ 4.0 $ (10.6) $ (6.6) $ 53.8 $ (5.1) $ 48.7 $ 42.1
-23- 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 each counterparty's credit rating and evaluation of the financial statements. The credit department monitors these thresholds to determine the need for additional collateral or restriction of activity with the counterparty. 11. Earnings Per Share Basic earnings per common share were computed by dividing net income by the weighted average number of common shares outstanding for the period. The dilutive effect of the potential exercise of outstanding options to purchase shares of common stock is calculated using the treasury stock method. The dilutive effect of the assumed conversion of certain convertible securities into the Company's common stock is based on the dilutive common share equivalents and the after tax interest expense and distribution expense avoided upon conversion. The reconciliation of basic earnings per common share to diluted earnings per share is shown in the following table (in thousands, except per share data).
Periods Ended September 30, -------------------------------------------------------------------------- 2002 2001 ---------------------------------- ----------------------------------- Net Net Income Shares EPS Income Shares EPS ---------- -------- ------ --------- -------- ------- THREE MONTHS: Basic earnings per common share: Income before discontinued operations and cumulative effect of a change in accounting principle......................................... $ 144,397 376,957 $ 0.38 $ 313,496 304,666 $ 1.03 Discontinued operations, net of tax................ 16,950 0.05 7,303 0.02 Cumulative effect of a change in accounting principle, net of tax............................. -- -- -- -- -- -- ---------- -------- ------ --------- -------- ------- Net income.................................... $ 161,347 376,957 $ 0.43 $ 320,799 304,666 $ 1.05 ========== -------- ====== ========= -------- ======= Diluted earnings per common share: Common shares issuable upon exercise of stock options using treasury stock method............... 5,650 13,886 -------- -------- Income before dilutive effect of certain convertible securities, discontinued operations and cumulative effect of a change in accounting principle......................................... $ 144,397 382,607 0.38 $ 313,496 318,552 $ 0.98 Dilutive effect of certain convertible securities.. 14,326 99,377 (0.05) 12,435 58,153 (0.12) ---------- -------- ------ --------- -------- ------- Income before discontinued operations and cumulative effect of a change in accounting principle......................................... 158,723 481,984 0.33 325,931 376,705 0.86 Discontinued operations, net of tax................ 16,950 0.03 7,303 0.02 Cumulative effect of a change in accounting principle, net of tax............................. -- -- -- -- -- -- ---------- -------- ------ --------- -------- ------- Net income.................................... $ 175,673 481,984 $ 0.36 $ 333,234 376,705 $ 0.88 ========== ======== ====== ========= ======== =======
-24-
Periods Ended September 30, -------------------------------------------------------------------------- 2002 2001 ---------------------------------- ----------------------------------- Net Net Income Shares EPS Income Shares EPS ---------- -------- ------ --------- -------- ------- NINE MONTHS: Basic earnings per common share: Income before discontinued operations and cumulative effect of a change in accounting principle......................................... $ 132,646 346,816 $ 0.38 $ 510,807 302,649 $ 1.69 Discontinued operations , net of tax............... 26,950 0.08 36,284 0.12 Cumulative effect of a change in accounting principle, net of tax............................. -- -- -- 1,036 -- -- ---------- -------- ------ --------- -------- ------- Net income.................................... $ 159,596 346,816 $ 0.46 $ 548,127 302,649 $ 1.81 ========== -------- ====== ========= -------- ======= Diluted earnings per common share: Common shares issuable upon exercise of stock options using treasury stock method............... 8,761 15,231 -------- -------- Income before dilutive effect of certain convertible securities, discontinued operations and cumulative effect of a change in accounting principle......................................... $ 132,646 355,577 $ 0.37 $ 510,807 317,880 $ 1.61 Dilutive effect of certain convertible securities.. -- -- -- 33,204 52,353 (0.14) ---------- -------- ------ --------- -------- ------- Income before discontinued operations and cumulative effect of a change in accounting principle......................................... 132,646 355,577 0.37 544,011 370,233 1.47 Discontinued operations, net of tax................ 26,950 0.08 36,284 0.10 Cumulative effect of a change in accounting principle, net of tax............................. -- -- -- 1,036 -- -- ---------- -------- ------ --------- -------- ------- Net income.................................... $ 159,596 355,577 $ 0.45 $ 581,331 370,233 $ 1.57 ========== ======== ====== ========= ======== =======
For the three and nine months ended September 30, 2002 and for the three and nine months ended September 30, 2001, respectively, the effect of 28,149, 124,755, 2,693 and 2,683 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." On August 27, 2002, the Company announced that, effective January 1, 2003, we intended to adopt SFAS No. 123, "Accounting for Stock-Based Compensation." Had compensation cost been determined consistent with the methodology of SFAS No. 123, which provides for the accounting of options as compensation expense, the Company's net income and earnings per share would have been changed to the following pro forma amounts (in thousands, except per share amounts):
Three Months Ended Nine Months Ended September 30, September 30, -------------------------- --------------------------- 2002 2001 2002 2001 --------- --------- --------- --------- Net income As reported............................................ $ 161,347 $ 320,799 $ 159,596 $ 548,127 Pro Forma.............................................. 155,020 312,922 127,934 527,042 Earnings per share data: Basic earnings per share As reported............................................ $ 0.43 $ 1.05 $ 0.46 $ 1.81 Pro Forma.............................................. 0.41 1.03 0.37 1.74 Diluted earnings per share As reported............................................ $ 0.36 $ 0.88 $ 0.45 $ 1.57 Pro Forma.............................................. 0.35 0.86 0.36 1.51
For the three and nine months ended September 30, 2002 and 2001, respectively, the fair value of options granted was $3.56 and $5.09, and $13.79 and $22.67 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 nine months ended September 30, -25- 2002, and 76% for the three and nine months ended September 30, 2001, risk-free interest rates of 2.34% for the three months ended September 30, 2002, 2.66% for the nine months ended September 30, 2002, and 5.02% for the three and nine months ended September 30, 2001, and expected option terms after vesting of 2 years and 3 years for the three and nine months ended September 30, 2002 and 1 year for the three and nine months ended September 30, 2001. 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. 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. The Company recorded an additional pre-tax charge of $3.7 million in the third quarter of 2002, based on final resolution of this cancellation. Discussions continue with certain of the Company's major equipment manufacturers to restructure its existing orders for gas and steam turbines. The Company expects to complete this process by the end of 2002. 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 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 as defendants the Company, certain of its officers and directors, and the underwriters of the offering, 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. -26- 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 and its subsidiaries 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 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 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. -27- 14. Operating Segments The Company's primary operating segments are power generation; oil and gas production and marketing; and corporate activities and other. Power generation 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. This presentation constitutes a change from prior presentation in that management reviews results from segments inclusive of hedging activity, in contrast to the prior view of hedging activity along product line (gas hedging for power plants is now in power generation, versus oil and gas production and marketing). 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 gross profit, which is reflected below.
Oil and Gas Power Production Corporate, Other Generation and Marketing and Eliminations Total ----------------------- -------------------- --------------------- ---------------------- 2002 2001 2002 2001 2002 2001 2002 2001 ---------- ---------- ---------- -------- ---------- --------- ---------- ---------- (in thousands) For the three months ended September 30, 2002 and 2001: Revenue............................ $2,412,458 $2,465,384 $ 88,201 $ 62,185 $ (5,649) $ (7,418) $2,495,010 $2,520,151 Gross profit....................... 352,601 497,879 10,869 16,762 (1,138) 6,504 362,332 521,145 Income (loss) before provision for taxes......................... 292,317 478,888 9,993 10,894 (109,507) (36,982) 192,803 452,800 Discontinued operations, net of tax........................ 287 20 16,663 7,283 -- -- 16,950 7,303 Merger expense..................... -- -- -- -- -- -- -- -- Equipment cancellation cost........ 3,714 -- -- -- -- -- 3,714 -- Oil and Gas Power Production Corporate, Other Generation and Marketing and Eliminations Total ----------------------- -------------------- --------------------- ---------------------- 2002 2001 2002 2001 2002 2001 2002 2001 ---------- ---------- ---------- -------- ---------- --------- ---------- ---------- (in thousands) For the nine months ended September 30, 2002 and 2001: Revenue............................ $5,331,664 $5,063,070 $ 249,588 $340,696 $ 5,490 $ (99,000) $5,586,742 $5,304,766 Gross profit....................... 754,348 865,388 37,910 190,080 (14,917) (7,384) 777,341 1,048,084 Income (loss) before provision for taxes......................... 517,185 795,509 (40,159) 131,850 (305,575) (138,391) 171,451 788,968 Discontinued operations, net of tax........................ 1,112 (177) 25,838 36,461 -- -- 26,950 36,284 Merger expense..................... -- -- -- 41,627 -- -- -- 41,627 Equipment cancellation cost........ 172,185 -- -- -- -- -- 172,185 --
Oil and Gas Power Production Corporate, Other Generation and Marketing and Eliminations Total ----------- ------------- ---------------- ----------- (in thousands) Total assets: September 30, 2002 ..................... $18,334,658 $ 4,061,421 $ 293,247 $22,689,326 December 31, 2001 ...................... $12,572,848 $ 3,503,075 $ 5,253,629 $21,329,552
For the three months ended September 30, 2002 and 2001, there were intersegment revenues of approximately $144.9 million and $15.9 million, respectively. For the nine months ended September 30, 2002 and 2001, there were intersegment revenues of approximately $217.3 million and $100.8 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. -28- 15. Subsequent Events In October 2002 the Company completed the sale of substantially all of its British Columbia oil and gas properties to Calgary, Alberta-based Pengrowth Corporation for gross proceeds of approximately Cdn$387.5 million (US$243.7 million). Of the total consideration, the Company received US$155.3 million in cash. The remaining US$88.4 million was paid by Pengrowth Corporation's purchase in the open market (for an aggregate purchase price of US$88.4 million) and delivery to the Company of US$203.2 million in aggregate principal amount of the Company's debt securities. As a result of the transaction, the Company will record a US$41.5 million pre-tax gain on the sale of the properties before any gains on the repurchase of debt. The Company used approximately US$50.4 million of proceeds to repay amounts outstanding under its US$1.0 billion term loan. The debt securities delivered to the Company by Pengrowth Corporation comprised: Debt Security Principal Amount ----------------------------------------- ---------------- 7-7/8% Senior Notes Due 2008............. $ 19.5 million 7-3/4% Senior Notes Due 2009............. 20.2 million 8-5/8% Senior Notes Due 2010............. 42.4 million 8-1/2% Senior Notes Due 2011............. 121.1 million --------------- Total................................. $ 203.2 million =============== 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 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 operational 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 November 14, 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: -29- 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 nine months ended September 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 Nine Months Ended September 30, September 30, ----------------------------- ------------------------------ 2002 2001 2002 2001 ------------ ------------ ------------ ------------ (in thousands, except production and pricing data) Power Plants: Electricity and steam ("E&S") revenue: Energy................................................. $ 485,431 $ 488,621 $ 1,542,957 $ 1,266,601 Capacity............................................... 409,115 177,928 600,955 420,138 Thermal and other...................................... 52,780 43,957 125,980 118,150 ------------ ------------ ------------ ------------ Subtotal............................................. $ 947,326 $ 710,506 $ 2,269,892 $ 1,804,889 E&S revenue from discontinued operations.................. 4,440 4,463 10,091 10,936 Spread on sales of purchased power (1).................... 223,136 258,217 486,601 283,684 ------------ ------------ ------------ ------------ Adjusted E&S revenue...................................... $ 1,174,902 $ 973,186 $ 2,766,584 $ 2,099,509 Megawatt hours produced................................... 23,375,000 13,687,000 53,809,000 28,804,000 All-in electricity price per megawatt hour generated...... $ 50.26 $ 71.10 $ 51.41 $ 72.89 - ------------ (1) From hedging, balancing and optimization activities related to our generating assets. The spread on trading activities is excluded.
Credit restrictions on certain Calpine Energy Services, L.P. ("CES") activities in 2002 has negatively impacted the volume of its hedging, balancing and optimization activities and these restrictions could cause further reductions of such activities in the future. Megawatt hours produced at the power plants increased 71% and 87% for the three and nine months ended September 30, 2002, as compared to the same periods in 2001. This was primarily due to the addition of power plants that commenced commercial operation subsequent to September 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. Results of Operations Set forth below is a table summarizing the dollar amounts and percentages of our total revenue for the three and nine months ended September 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): -30-
Three Months Ended Nine Months Ended September 30, September 30, ----------------------------- ------------------------------ 2002 2001 2002 2001 ------------ ------------ ------------ ------------ Total revenue................................................. $ 2,495,010 $ 2,520,151 $ 5,586,742 $ 5,304,766 Sales of purchased power for hedging and optimization......... 1,282,976 1,653,088 2,526,555 2,680,488 As a percentage of total revenue.............................. 51.4% 65.6% 45.2% 50.5% Sales of purchased gas for hedging and optimization........... 231,893 56,916 666,095 412,782 As a percentage of total revenue.............................. 9.3% 2.3% 11.9% 7.8% Total cost of revenue ("COR")................................. 2,132,678 1,999,006 4,809,401 4,256,682 Purchased power expense for hedging and optimization.......... 1,059,840 1,394,871 2,039,954 2,396,804 As a percentage of total COR.................................. 49.7% 69.8% 42.4% 56.3% Purchased gas expense for hedging and optimization............ 220,775 52,856 678,192 389,814 As a percentage of total COR.................................. 10.4% 2.6% 14.1% 9.2%
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 physical delivery hedging contracts on a gross basis (as opposed to netting sales and cost of revenue). 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 Nine Months Ended September 30, September 30, --------------------------- ---------------------------- 2002 2001 2002 2001 ---------- ---------- ---------- ---------- (in thousands) Sales into NEPOOL ISO from power we generated................ $ 97,852 $ 99,819 $ 211,889 $ 221,275 Sales into NEPOOL ISO from hedging and other activity........ 33,964 67,776 78,770 124,420 ---------- ---------- ---------- ---------- Total sales into NEPOOL................................... $ 131,816 $ 167,595 $ 290,659 $ 345,695 Total purchases from NEPOOL ISO........................... $ 113,659 $ 152,463 $ 274,838 $ 319,023
Three Months Ended September 30, 2002, Compared to Three Months Ended September 30, 2001. Revenue -- Total revenue decreased slightly to $2,495.0 million for the three months ended September 30, 2002, compared to $2,520.2 million for the same period in 2001. Electric generation and marketing revenue decreased to $2,230.3 million in 2002 compared to $2,363.6 million in 2001. Approximately $236.8 million of the $133.3 million variance was due to electricity and steam sales, which increased due to our growing portfolio of power plants. Generation increased 71% but average pricing dropped by 29%. Our revenue for the period ended September 30, 2002, includes the consolidated results of additional facilities that we completed construction on subsequent to September 30, 2001. However, sales of purchased power decreased by $370.1 million due to lower power prices and industry-wide credit restrictions on risk management activities in 2002, which has resulted in a lower volume of hedging and optimization activity. Oil and gas production and marketing revenue increased to $253.7 million in 2002 compared to $111.6 million in 2001. The increase is due to a $175.0 million increase in sales of purchased gas, offset by a $32.9 million decrease in oil and gas sales to third parties primarily due to increased internal consumption. Trading revenue, net -- Trading revenue, net decreased from $23.8 million in 2001 to $(4.1) million in 2002. In the three months ended September 30, 2001, we recognized significant mark-to-market gains from power contracts in a market area where we did not have generation assets. Due to lower power prices and industry-wide credit restrictions on risk management and trading activities in 2002, such opportunities and other trading activities have been greatly restricted. -31- Cost of revenue -- Cost of revenue increased to $2,132.7 million in 2002 compared to $1,999.0 million in 2001. Approximately $167.9 million of the increase relates to the cost of gas purchased by our energy services organization due to increased price hedging, balancing and optimization activities. Fuel expense increased 60%, from $327.9 million in 2001 to $525.5 million in 2002, due to an increase of 81% in gas-fired megawatt hours generated as offset by slightly lower gas prices in 2002 and an improvement in average heat rate of our generation portfolio. Plant operating expense increased by 51% from $93.7 million to $141.3 million but, expressed per MWh of generation, decreased from $6.85/MWh to $6.04/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 47%, from $80.0 million to $117.6 million, due primarily to additional power facilities in consolidated operations at September 30, 2002, as compared to the same period in 2001. These increases were somewhat offset by a $335.0 million decrease in purchased power expense that was caused by lower power prices and by industry-wide credit restrictions on risk management activities in 2002, which has resulted in a lower volume of hedging and optimization activity. Project development expense -- Project development expense increased $19.0 million as we expensed approximately $7.7 million in costs related to the cancellation or indefinite suspension of certain development projects. General and administrative expense -- General and administrative expense increased to $57.3 million during the third quarter 2002 as compared to $29.4 million in the prior year. The increase is due to the growth of our infrastructure needed to support operations, whose output has grown by approximately 87% and due to severance costs relating to reduction of excess staffing. In the comparable period of 2001, we revised our estimate of bonus expense to reflect a higher mix of stock options versus cash in compensation. Interest expense -- Interest expense increased 139% to $113.8 million for the three months ended September 30, 2002, from $47.7 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 fourth quarter 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 were in commercial operation in the three months ended September 30, 2002, than in the three months ended September 30, 2001. Interest capitalized in 2002 and 2001 was $123.2 million and $121.6 million, respectively. 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, to a lesser extent, as a result of suspension of certain of our development projects. Interest income -- Interest income decreased to $10.8 million for the three months ended September 30, 2002, compared to $21.1 million for the same period in 2001. This decrease is due primarily to lower cash balances and interest rates in 2002. Other -- Other income increased by $25.9 million in the three months ended September 30, 2002, compared to the same period in 2001. In the 2002 period we recognized $38.6 million from the termination of a power sales agreement and $2.9 million in Canadian foreign exchange gains. These were partially offset by $4.7 million of letter of credit fees and a $3.0 million loss on the sale of two turbines. Provision for income taxes -- The provision for income taxes as a percent of income before provision for income taxes decreased from approximately 31% to 25% for the three months ended September 30, 2002 and 2001, respectively. The decrease in rates was due to our expansion into Canada and the United Kingdom, our cross border financings in October 2001, our revision of estimated year end earnings for 2002, and our revision of tax accruals. Discontinued operations, net of tax -- Discontinued operations, net of tax for the three months ended September 30, 2002, was $17.0 million as compared to $7.3 million in 2001. The 2002 amount includes a $12.9 million after-tax gain on the sale of certain oil and gas properties. See Note 7 to the Condensed Consolidated Financial Statements for further discussion. Nine Months Ended September 30, 2002, Compared to Nine Months Ended September 30, 2001. Revenue -- Total revenue increased to $5,586.7 million for the nine months ended September 30, 2002, compared to $5,304.8 million for the same period in 2001. Electric generation and marketing revenue increased by $311.0 million to $4,796.4 million in 2002 compared to $4,485.4 million in 2001. Sales of purchased power decreased by $153.9 million due to lower power prices and industry-wide credit restrictions on risk management activities in 2002, which has resulted in a lower volume of hedging and optimization activity. Electricity and steam sales increased by $465.0 million due to our growing portfolio of power plants. Generation increased 87%, but average pricing dropped to moderate -32- revenue growth. Our revenue for the period ended September 30, 2002, includes the consolidated results of additional facilities that we completed construction on subsequent to September 30, 2001. Oil and gas production and marketing revenue increased to $755.7 million in 2002 compared to $652.7 million in 2001. The increase is primarily due to a $253.3 million increase in the sales of purchased gas offset by a $150.4 million decrease in oil and gas sales to third parties because of much lower average natural gas pricing in 2002 and increased internal consumption. Trading revenue, net -- Trading revenue, net decreased from $129.2 million in 2001 to $9.3 million in 2002. In the nine months ended September 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 lower power prices and industry-wide credit restrictions on risk management and trading activities in 2002, such opportunities and other trading activities have been greatly restricted. Cost of revenue -- Cost of revenue increased to $4,809.4 million in 2002 compared to $4,256.7 million in 2001. Approximately $288.4 million of the $552.7 million increase relates to the cost of gas purchased by our energy services organization due to increased price hedging, balancing and optimization activities. Fuel expense increased 43%, from $846.2 million in 2001 to $1,208.1 million in 2002, due to a 104% increase in gas-fired megawatt hours generated as offset by significantly lower gas prices, increased usage of internally produced gas and an improved average heat rate of our generation portfolio in 2002. Plant operating expense increased by 52% from $246.0 million to $374.5 million but, expressed per MWh of generation, decreased from $8.54/MWh to $6.96/MWh as economies of scale are being realized due to the increase in the average size of our plants. Royalty expense decreased $10.1 million between periods due to a decrease in revenue for The Geysers geothermal plants. Depreciation, depletion and amortization expense increased by 56%, from $199.5 million to $310.9 million, due primarily to additional power facilities in consolidated operations at September 30, 2002, as compared to the same period in 2001. Operating lease expense increased 31% due to sale/leaseback transactions subsequent to September 30, 2001. Project development expense -- Project development expense increased 139% from $25.1 million for the nine months ended September 30, 2001, as compared to $60.0 million for the same period in 2002, as we expensed $28.0 million in costs related to the cancellation or indefinite suspension of certain development projects. Equipment cancellation cost -- The pre-tax equipment cancellation charge of $172.2 million in the nine months ended September 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 48% to $170.4 million for the nine months ended September 30, 2002, as compared to $114.9 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, in addition to severance costs from the reduction of our work force. General and administrative expense expressed per KWh of generation decreased to $3.17/KWh in 2002 from $3.99/KWh in 2001. Merger expense -- The merger expense of $41.6 million in the nine months ended September 30, 2001 was a result of the pooling-of-interests transaction with Encal Energy Ltd. that closed on April 19, 2001. Interest expense -- Interest expense increased 122% to $239.1 million for the nine months ended September 30, 2002, from $107.5 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 new plants going into commercial operations at which point capitalization of interest expense ceases. Interest capitalized increased from $341.2 million in the nine months ended September 30, 2001 to $457.3 million in the nine months ended September 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, to a lesser extent, as a result of suspension of certain of our development projects. Interest income -- Interest income decreased to $34.0 million for the nine months ended September 30, 2002, compared to $60.9 million for the same period in 2001. This decrease is due primarily to lower cash balances and interest rates in 2002. Other (income) expense -- Other income increased by $34.0 million in the nine months ended September 30, 2002, compared to the same period in 2001, primarily due to a $38.6 million gain we recognized on the termination of a power sales agreement. -33- Provision for income taxes -- The provision for income taxes as a percent of income before provision for income taxes decreased from approximately 35% to 23% for the nine months ended September 30, 2002 and 2001, respectively. The decrease in rates was due to our expansion into Canada and the United Kingdom, our cross border financings in April 2001 and October 2001, our revision of estimated year end earnings for 2002, and our revision of tax accruals. Discontinued operations, net of tax -- Discontinued operations, net of tax was $27.0 million and $36.3 million for the nine months ending September 30, 2002 and 2001, respectively. The decrease in 2002 results, despite a $12.9 million gain on sale of oil and gas properties, reflects substantially higher gas prices in 2001. See Note 7 to the Consolidated Condensed Financial Statements for further discussion. 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." 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 in Louisiana (50% owned by Calpine and 50% owned by Cleco Midstream Resources, an affiliate of Cleco Corporation). None of our equity investment projects have nominal carrying values as a result of material recurring losses. Further, there is no history of impairment in any of these investments. Accumulated other comprehensive loss -- The amount of the accumulated other comprehensive loss increased from $(226.6) million at December 31, 2001, to $(230.3) million at September 30, 2002. The change resulted from unrealized losses on derivatives designated as cash flow hedges of $(19.8) million, net of amounts reclassified to net loss and income taxes, and foreign currency translation gain of $16.1 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 Corp. and a perceived near term surplus supply of electric generating capacity. While we were 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 and due to current market conditions, 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 demand increases and attractive financing 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 certain 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, repay debt, 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 or use it to repay debt, 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. -34- Cash Flow Activities -- The following table summarizes our cash flow activities for the periods indicated:
Nine Months Ended September 30, ------------------------------- 2002 2001 ------------ ------------ (in thousands) Beginning cash and cash equivalents........................................... $ 1,525,417 $ 596,077 Net cash provided by (used in): Operating activities....................................................... 785,015 476,005 Investing activities....................................................... (3,197,790) (6,085,999) Financing activities....................................................... 1,544,775 5,490,291 Effect of exchange rates changes on cash and cash equivalents.............. 2,277 -- ------------ ------------ Net increase (decrease) in cash and cash equivalents....................... (865,723) (119,703) ------------ ------------ Ending cash and cash equivalents........................................ $ 659,694 $ 476,374 ============ ============
Operating activities for the nine months ended September 30, 2002, provided net cash of $785.0 million, compared to $476.0 million for the nine months ended September 30, 2001. The cash provided by operating activities for the nine months ended September 30, 2002, consisted of a $420.2 million decrease in operating assets, primarily relating to a $472.1 million decrease in accounts receivable, and current derivative assets and other current assets. This was offset by a $494.4 million decrease in operating liabilities, primarily related to derivative activity. A primary factor causing the significant increase in cash flow from operations in the nine months ended September 30, 2002, in comparison to the same period in 2001, is the realization of approximately $222.3 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 nine months of 2001, which reduced operating cash flow in that period. Investing activities for the nine months ended September 30, 2002, consumed net cash of $3.2 billion, primarily due to construction costs and capital expenditures including gas turbine generator costs and associated capitalized interest, $64.7 million of advances to joint ventures including associated capitalized interest for investments in power projects under construction, $84.8 million of capitalized project development costs including associated capitalized interest, and a $14.5 million increase in restricted cash. This was partially offset by $125.1 million of proceeds from sales of physical assets. Financing activities for the nine months ended September 30, 2002, provided $1.5 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, $1.3 billion of proceeds from drawings on our term loan and revolving lines of credit, $169.4 million of proceeds from our Canadian Income Trust Offering, and $438.5 million of proceeds from project financing. This was partially offset by $869.7 million for the repurchase of the outstanding Zero Coupons, $75.7 million for the repayment of notes payable and borrowings under our lines of credit, $153.8 million for repayments of project financing, and additional financing costs. We continue to evaluate current and forecasted cash flow as a basis for funding operating requirements and capital expenditures. In November 2003 and 2004 the Company's $1.0 billion and $2.5 billion secured revolving construction financing facilities will mature, requiring the Company to refinance this indebtedness. At September 30, 2002, there was $969.8 million and $2,493.6 million outstanding, respectively, under these facilities. We believe that we will have sufficient liquidity from cash flow from operations, borrowings available under lines of credit, access to sale/leaseback and other markets, sale of certain assets and cash balances to satisfy all obligations under outstanding indebtedness, and to fund anticipated capital expenditures and working capital requirements for the next twelve months. Enron Bankruptcy-- During 2001 we, primarily through our 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. -35- We have conducted no business with EPMI or ENA since December 31, 2001. We have terminated all of our 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. 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). Management believes, based on contractually permissible calculation methodologies, that our gross exposure to Enron and its affiliates will be significantly less than amounts previously disclosed using calculations made under generally accepted accounting principles. We expect that this amount will be offset by CES' losses, damages, attorneys' fees and other expenses arising from the default by Enron. We are engaged in confidential settlement negotiations with Enron, ENA and EPMI. It is premature to characterize these negotiations at this time. In the event settlement negotiations prove unsuccessful, we intend to pursue our rights under our agreements with Enron and its affiliates. Regardless of the outcome, we believe, based upon legal analysis, that we do not have any net collection exposure to Enron and its affiliates as at the date hereof. 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 requested that its power suppliers extend payment terms to help it overcome its short-term liquidity problems. In June and July 2002 NPC underpaid us by approximately $4.2 million, and we established a bed debt reserve of approximately $2.7 million against NPC receivables. On October 25, 2002, we received approximately $22.2 million from NPC for outstanding payables owed to us for power deliveries made during the period of May 1, 2002 through September 15, 2002. See Part II -- Other Information - Item 1 for further discussion. As of September 30, 2002, we had net collection exposures of approximately $35.1 million and $9.6 million with NPC and SPPC, respectively. 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. NRG Power Marketing, Inc.-- We have open contract positions with NRG Power Marketing, Inc., a subsidiary of NRG Energy, Inc., which in turn is the unregulated power-generation subsidiary of XCEL Energy Inc. Almost all of the open contracts are accounted for as cash flow hedges under Financial Accounting Standards Board ("FASB") Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging Activities." NRG Energy, Inc. has reportedly experienced financial problems, defaulted on certain loan payments and has had its long-term debt rating downgraded to D by Standard & Poor's. According to a report published on November 8, 2002, NRG Energy, Inc. has discussed a Chapter 11 bankruptcy filing with its lenders. While NRG Power Marketing, Inc. has remained current in its payments to us through October 20, 2002, we have established a partial reserve in other comprehensive income ("OCI") in the balance sheet against the fair value of our open contract position with NRG Power Marketing, Inc. Our exposure to NRG Power Marketing, Inc. at September 30, 2002, is approximately $8.8 million, net of established reserve. We will continue to closely monitor our position with NRG Power Marketing, Inc. and will adjust the value of the reserve as conditions dictate. PSM License Receivable -- In December 2001 our wholly owned subsidiary, Power Systems Mfg., LLC ("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. We 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 $6 million, with no payments 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 has also filed 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, we have not established a reserve against the related receivable but will continue to closely monitor the situation. -36- CES Margin Deposits and Other Credit Support -- As of September 30, 2002, CES had $49.8 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 $181.6 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. Fifteen of these facilities have subsequently achieved full or partial commercial operation as of September 30, 2002. Construction of advanced stage development projects is expected to proceed only when there is an established market need for additional generating resources at prices that will allow us to meet our 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 $172.2 million in the first nine months of 2002. Capital Availability -- As a result of the significant contraction in the availability of capital for participants in the energy sector, access to capital for many in the sector, including the Company, has been restricted. While we were able earlier in the year to access the capital and bank credit markets, the terms of financing available to us now and in the future may not be attractive to us and the timing of the availability of capital is uncertain and is dependent, in part, on market conditions that are difficult to predict and are outside of our control. 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. $50.0 million was repaid on August 7, 2002, and the remaining $50.0 million (which is classified as current project financing) is payable on November 25, 2002. On May 31, 2002, we increased our two-year secured bank term loan to $1.0 billion from $600 million, and reduced the aggregate size of our secured corporate revolving credit facilities to $1.0 billion (the $600 million and $400 million facilities, respectively,) from $1.4 billion. At September 30, 2002, we had $1.0 billion in funded borrowings outstanding under the term loan facility and $250.0 million in funded borrowings outstanding under the revolving credit facilities. Subsequently, $50.4 million of the proceeds of the sale of our British Columbia oil and gas properties to Pengrowth Corporation was applied to repay a portion of the term loan facility. Letter of credit facilities -- At September 30, 2002, we had approximately $697.0 million in letters of credit outstanding under various credit facilities to support CES risk management, and other operational and construction activities. Of the total letters of credit outstanding, $595.2 million were issued under the corporate revolving credit facilities. At December 31, 2001, we had $642.5 million in letters of credit outstanding to support CES risk management, and other operational and construction 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 entered into sale/leaseback transactions involving our Tiverton and Rumford projects in December 2000 and our South Point, Broad River and RockGen projects in October 2001. 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. In accordance with Accounting Principles Board ("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 -37- reflected on our balance sheet. At September 30, 2002, investee debt totaled $652.1 million. Based on our pro rata ownership share of each of the investments, our share would be $242.8 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, provided support arrangements until construction was completed to cover cost overruns, if any. Performance Metrics In understanding our business, we believe that certain performance metrics are particularly important. These include: o Average gross profit margin based on non-GAAP revenue and non-GAAP cost of revenue. A high percentage of our recent revenue has consisted of CES hedging, balancing and optimization 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 and optimization 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 for hedging, balancing and optimization activities 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. However, effective July 1, 2002, trading activity is now shown net in our Statements of Operations under Trading revenue, net for all periods presented. Because of the inflating effect on revenue of much of our hedging, balancing and optimization activity, we believe that revenue levels and trends do not reflect our performance as accurately as gross profit, and that it is analytically useful for investors to look at our results on a non-GAAP basis with all hedging, balancing and optimization activity netted. This analytical approach nets the sales of purchased power with purchased power expense and includes that net amount as an adjustment to E&S revenue for our generation assets. Similarly, we believe that it is analytically useful for investors to net the sales of purchased gas with purchased gas expense and include that net amount as an adjustment to fuel expense. This allows us to look at all hedging, balancing and optimization 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 GAAP revenue of hedging, balancing and optimization 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 the product of 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. 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. -38- 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 fuel expense 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 fuel expense from (b) adjusted E&S revenue and dividing the difference by (c) total generated MWh in the period. The table below presents, side-by-side, both our GAAP and non-GAAP netted revenue, costs of revenue and gross profit showing the purchases and sales of electricity and gas for hedging, balancing and optimization activity on a net basis. It also shows the other performance metrics discussed above.
Non-GAAP Netted GAAP Presentation Presentation Three Months Ended September 30, Three Months Ended September 30, -------------------------------- -------------------------------- 2002 2001 2002 2001 ----------- ----------- ----------- ----------- (In thousands) Revenue, Cost of Revenue and Gross Profit Revenue: Electric generation and marketing revenue Electricity and steam revenue(2)....................... $ 947,326 $ 710,506 $ 1,170,462 $ 968,723 Sales of purchased power for hedging and optimization (2)...................................... 1,282,976 1,653,088 -- -- ----------- ----------- ----------- ----------- Total electric generation and marketing revenue...... 2,230,302 2,363,594 1,170,462 968,723 Oil and gas production and marketing revenue Oil and gas sales...................................... 21,827 54,693 21,827 54,693 Sales of purchased gas for hedging and optimization (2)...................................... 231,893 56,916 -- -- ----------- ----------- ----------- ----------- Total oil and gas production and marketing revenue... 253,720 111,609 21,827 54,693 Trading revenue, net Realized revenue on power and gas trading transactions, net..................................... 6,845 16,700 6,845 16,700 Unrealized mark-to-market gain (loss) on power and gas transactions, net............................. (10,957) 7,128 (10,957) 7,128 ----------- ----------- ----------- ----------- Total trading revenue, net........................... (4,112) 23,828 (4,112) 23,828 Income (loss) from unconsolidated investments in power projects........................................... 10,176 6,859 10,176 6,859 Other revenue............................................. 4,924 14,261 4,924 14,261 ----------- ----------- ----------- ----------- Total revenue..................................... 2,495,010 2,520,151 1,203,277 1,068,364 ----------- ----------- ----------- -----------
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Non-GAAP Netted GAAP Presentation Presentation Three Months Ended September 30, Three Months Ended September 30, -------------------------------- -------------------------------- 2002 2001 2002 2001 ----------- ----------- ----------- ----------- (In thousands) Cost of revenue: Electric generation and marketing expense Plant operating expense................................ 141,262 93,709 141,262 93,709 Royalty expense........................................ 4,743 5,255 4,743 5,255 Purchased power expense for hedging and optimization (2)...................................... 1,059,840 1,394,871 -- -- ----------- ----------- ----------- ----------- Total electric generation and marketing expense...... 1,205,845 1,493,835 146,005 98,964 Oil and gas production and marketing expense Oil and gas production expense......................... 22,953 13,009 22,953 13,009 Purchased gas expense for hedging and optimization (2)...................................... 220,775 52,856 -- -- ----------- ----------- ----------- ----------- Total oil and gas production and marketing expense... 243,728 65,865 22,953 13,009 Fuel expense.............................................. 525,478 327,947 514,360 323,887 Depreciation, depletion and amortization expense.......... 117,568 80,044 117,568 80,044 Operating lease expense................................... 36,520 27,830 36,520 27,830 Other expense............................................. 3,539 3,485 3,539 3,485 ----------- ----------- ----------- ----------- Total cost of revenue............................. 2,132,678 1,999,006 840,945 547,219 ----------- ----------- ----------- ----------- Gross profit................................................. $ 362,332 $ 521,145 $ 362,332 $ 521,145 =========== =========== =========== =========== Gross profit margin.......................................... 15% 21% 30% 49% Non-GAAP Netted GAAP Presentation Presentation Nine Months Ended September 30, Nine Months Ended September 30, -------------------------------- -------------------------------- 2002 2001 2002 2001 ----------- ----------- ----------- ----------- (In thousands) Revenue, Cost of Revenue and Gross Profit Revenue: Electric generation and marketing revenue Electricity and steam revenue(2)....................... $ 2,269,892 $ 1,804,889 $ 2,756,493 $ 2,088,573 Sales of purchased power for hedging and optimization (2)...................................... 2,526,555 2,680,488 -- -- ----------- ----------- ----------- ----------- Total electric generation and marketing revenue...... 4,796,447 4,485,377 2,756,493 2,088,573 Oil and gas production and marketing revenue Oil and gas sales...................................... 89,585 239,940 89,585 239,940 Sales of purchased gas for hedging and optimization (2)...................................... 666,095 412,782 -- -- ----------- ----------- ----------- ----------- Total oil and gas production and marketing revenue... 755,680 652,722 89,585 239,940 Trading revenue, net Realized revenue on power and gas trading transactions, net..................................... 15,276 21,340 15,276 21,340 Unrealized mark-to-market gain (loss) on power and gas transactions, net............................. (5,952) 107,862 (5,952) 107,862 ----------- ----------- ----------- ----------- Total trading revenue, net 9,324 129,202 9,324 129,202 Income from unconsolidated investments in power projects........................................... 10,499 9,021 10,499 9,021 Other revenue............................................. 14,792 28,444 14,792 28,444 ----------- ----------- ----------- ----------- Total revenue..................................... 5,586,742 5,304,766 2,880,693 2,495,180 ----------- ----------- ----------- -----------
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Non-GAAP Netted GAAP Presentation Presentation Nine Months Ended September 30, Nine Months Ended September 30, -------------------------------- -------------------------------- 2002 2001 2002 2001 ----------- ----------- ----------- ----------- (In thousands) Cost of revenue: Electric generation and marketing expense Plant operating expense................................ 374,497 246,045 374,497 246,045 Royalty expense........................................ 13,092 23,181 13,092 23,181 Purchased power expense for hedging and optimization (2)...................................... 2,039,954 2,396,804 -- -- ----------- ----------- ----------- ----------- Total electric generation and marketing expense...... 2,427,543 2,666,030 387,589 269,226 Oil and gas production and marketing expense Oil and gas production expense......................... 67,381 62,371 67,381 62,371 Purchased gas expense for hedging and optimization (2)...................................... 678,192 389,814 -- -- ----------- ----------- ----------- ----------- Total oil and gas production and marketing expense... 745,573 452,185 67,381 62,371 Fuel expense............................................... 1,208,092 846,195 1,220,189 823,227 Depreciation, depletion and amortization expense.......... 310,943 199,509 310,943 199,509 Operating lease expense................................... 108,917 83,289 108,917 83,289 Other expense............................................. 8,333 9,474 8,333 9,474 ----------- ----------- ----------- ----------- Total cost of revenue............................. 4,809,401 4,256,682 2,103,352 1,447,096 ----------- ----------- ----------- ----------- Gross profit................................................. $ 777,341 $ 1,048,084 $ 777,341 $ 1,048,084 =========== =========== =========== =========== Gross profit margin.......................................... 14% 20% 27% 42% Non-GAAP Netted Non-GAAP Netted Presentation Presentation Three Months Ended September 30, Nine Months Ended September 30, -------------------------------- ------------------------------- 2002 2001 2002 2001 ---------- ----------- ----------- ----------- (In thousands) Other Non-GAAP Performance Metrics Average availability and capacity factor: Average availability...................................... 94% 96% 92% 93% Average capacity factor or operating rate based on total hours (excluding peakers).......................... 73% 76% 70% 71% Average heat rate for gas-fired power plants (excluding peakers) (Btu's/kWh): Not steam adjusted........................................ 7,646 8,069 7,937 8,329 Steam adjusted............................................ 7,078 7,415 7,268 7,490 Average all-in realized electric price: Adjusted electricity and steam revenue before discontinued operations (in thousands)............ $ 1,170,462 $ 968,723 $ 2,756,493 $ 2,088,573 Electricity and steam revenue from discontinued operations............................................... 4,440 4,463 10,091 10,936 Adjusted electricity and steam revenue.................... 1,174,902 973,186 2,766,584 2,099,509 MWh generated (in thousands).............................. 23,375 13,687 53,809 28,804 Average all-in realized electric price per MWh............ $ 50.26 $ 71.10 $ 51.41 $ 72.89 Average cost of natural gas: Fuel expense.............................................. $ 514,360 $ 323,887 $ 1,220,189 $ 823,227 Fuel cost elimination..................................... 46,957 9,784 116,911 88,455 Fuel expense from discontinued operations................. 2,418 2,489 4,551 5,564 ----------- ----------- ----------- ----------- Adjusted fuel expense..................................... $ 563,735 $ 336,160 $ 1,341,651 $ 917,246 MMBtu of fuel consumed by generating plants (in thousands)........................................... 158,420 92,695 377,694 193,838 Average cost of natural gas per MMBtu..................... $ 3.56 $ 3.63 $ 3.55 $ 4.73 MWh generated (in thousands).............................. 23,375 13,687 53,809 28,804 Average cost of oil and natural gas burned by power plants per MWh..................................... $ 24.12 $ 24.56 $ 24.93 $ 31.84 Average spark spread: Adjusted electricity and steam revenue (in thousands)..... $ 1,174,902 $ 973,186 $ 2,766,584 $ 2,099,509 Less: Adjusted fuel expense (in thousands)............. 563,735 336,160 1,341,651 917,246 ----------- ----------- ----------- ----------- Spark spread (in thousands)............................... $ 611,167 $ 637,026 $ 1,424,933 $ 1,182,263 MWh generated (in thousands).............................. 23,375 13,687 53,809 28,804 Average spark spread per MWh.............................. $ 26.14 $ 46.54 $ 26.48 $ 41.05
-41- For the three and nine months ended September 30, 2002 and 2001, trading revenue, net consisted of (dollars in thousands):
Three Months Ended Nine Months Ended September 30, September 30, ---------------------- ---------------------- 2002 2001 2002 2001 --------- --------- --------- -------- ELECTRICITY Realized gain (loss) Realized revenue on power trading transactions, net.. $ 2,329 $ 4,309 $ 3,305 $ 4,066 Unrealized mark-to-market gain (loss) on power Unrealized transactions, net................................... (1,068) 13,577 9,201 83,316 -------- -------- -------- -------- Subtotal................................................................. $ 1,261 $ 17,886 $ 12,506 $ 87,382 GAS Realized gain (loss) Realized revenue on gas trading transactions, net.... $ 4,516 $ 12,391 $ 11,971 $ 17,274 Unrealized mark-to-market gain (loss) on gas Unrealized transactions, net................................... (9,889) (6,449) (15,153) 24,546 -------- -------- -------- -------- Subtotal................................................................. $ (5,373) $ 5,942 $ (3,182) $ 41,820
Three Months Three Months Ended Percent of Ended Percent of September 30, Gross September 30, Gross 2002 Profit 2001 Profit ------------- --------- ------------- ---------- Total trading activity gain (loss)....................................... $ (4,112) (1.1)% $ 23,828 4.6% Realized gain............................................................ $ 6,845 1.9% $ 16,700 3.2% Unrealized (mark-to-market) gain (loss)(1)............................... $ (10,957) (3.0)% $ 7,128 1.4% Nine Months Nine Months Ended Percent of Ended Percent of September 30, Gross September 30, Gross 2002 Profit 2001 Profit ------------- --------- ------------- ---------- Total trading activity gain.............................................. $ 9,324 1.2% $ 129,202 12.3% Realized gain............................................................ $ 15,276 2.0% $ 21,340 2.0% Unrealized (mark-to-market) gain (loss)(1)............................... $ (5,952) (0.8)% $ 107,862 10.3% (1) For the three and nine months ended September 30, 2002, the mark-to-market gains shown above as "trading" activity include a net loss on hedge ineffectiveness of $(5,213) and $(3,712), consisting of an ineffectiveness loss on power hedges of $(3,072) and $(4,296) and an ineffectiveness gain (loss) on gas hedges of $(2,141) and $584. For the three and nine months ended September 30, 2001, the mark-to-market gains shown above as "trading" activity include a net loss on hedge ineffectiveness of $(2,346) and $(5,818), consisting of an ineffectiveness gain on power hedges of $0 and $0, and an ineffectiveness loss on gas hedges of $(2,346) and $(5,818). (2) Following is a reconciliation of GAAP to non-GAAP presentation further to the narrative set forth under this Performance Metrics section ($ in thousands):
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Total Net Hedging, Balancing & Netted GAAP Optimization Non-GAAP Balance Activity Balance ----------- ------------- ----------- Three months ended September 30, 2002 Electricity and steam revenue................................ $ 947,326 $ 223,136 $ 1,170,462 Sales of purchased power for hedging and optimization........ 1,282,976 (1,282,976) -- Sales of purchased gas for hedging and optimization.......... 231,893 (231,893) -- Purchased power expense for hedging and optimization......... 1,059,840 (1,059,840) -- Purchased gas expense for hedging and optimization........... 220,775 (220,775) -- Fuel expense................................................. 525,478 (11,118) 514,360 Three months ended September 30, 2001 Electricity and steam revenue................................ $ 710,506 $ 258,217 $ 968,723 Sales of purchased power for hedging and optimization........ 1,653,088 (1,653,088) -- Sales of purchased gas for hedging and optimization.......... 56,916 (56,916) -- Purchased power expense for hedging and optimization......... 1,394,871 (1,394,871) -- Purchased gas expense for hedging and optimization........... 52,856 (52,856) -- Fuel expense................................................. 327,947 (4,060) 323,887 Total Net Hedging, Balancing & Netted GAAP Optimization Non-GAAP Balance Activity Balance ----------- ------------- ----------- Nine months ended September 30, 2002 Electricity and steam revenue................................ $ 2,269,892 $ 486,601 $ 2,756,493 Sales of purchased power for hedging and optimization........ 2,526,555 (2,526,555) -- Sales of purchased gas for hedging and optimization.......... 666,095 (666,095) -- Purchased power expense for hedging and optimization......... 2,039,954 (2,039,954) -- Purchased gas expense for hedging and optimization........... 678,192 (678,192) -- Fuel expense................................................. 1,208,092 12,097 1,220,189 Nine months ended September 30, 2001 Electricity and steam revenue................................ $ 1,804,889 $ 283,684 $ 2,088,573 Sales of purchased power for hedging and optimization........ 2,680,488 (2,680,488) -- Sales of purchased gas for hedging and optimization.......... 412,782 (412,782) -- Purchased power expense for hedging and optimization......... 2,396,804 (2,396,804) -- Purchased gas expense for hedging and optimization........... 389,814 (389,814) -- Fuel expense................................................. 846,195 (22,968) 823,227
Overview Summary of Key Activities Power Plant Development and Construction: Date Project Description ----- -------------------------------- ----------------------- 7/02 Freestone Energy Center Commenced operations 7/02 Bethpage Power Plant Peaker Commenced operations 7/02 Oneta Energy Center Partial Commencement of operations 8/02 Yuba City Energy Center Commenced Operations 8/02 Acadia Energy Center Commenced Operations 8/02 Hermiston Energy Center Commenced Operations 8/02 Auburndale Peaking Energy Center Commenced Operations 10/02 Corpus Christi Energy Center Commenced Operations -43- Finance Note Repayments and New Funding: Approximate Date Amount Description - ------- -------------------- --------------------------------------- 8/7/02 $50.0 million Repayment of peaker funding 8/22/02 $106.0 million Non-Recourse project financing for the construction of the Blue Spruce Energy Center 8/29/02 US$147.5 million, Canadian Power Income Fund Cdn$230 million 8/29/02 US$81.0 million, Completed the sale of certain Cdn$125.0 million non-strategic oil and gas properties ("Medicine River properties") located in central Alberta to NAL Oil and Gas Trust and another institutional investor 9/20/02 US$21.9 million, Canadian Power Income Fund Cdn$34.5 million 10/1/02 US$243.7 million, Sale of substantially all of our British Cdn$387.5 million Columbia oil and gas properties to Calgary, Alberta-based Pengrowth Corporation Other: Date Description - -------- -------------------------------------------------------------- 9/16/02 Received regulatory approval for the sale of the DePere Energy Center 9/30/02 Renegotiation of a 10-year power sales agreement with the City of Lodi 10/25/02 Received approximately $22.2 million from Las Vegas-based Nevada Power Company 10/31/02 Received approximately $3 million from Goldking Energy Corporation for all of the oil and gas properties in Drake Bay Field 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 without admitting any liability on the part of the Company. 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. Based on the terms of the DWR contracts, we expect to 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 -44- 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. 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. In addition, as discussed above, due to industry-wide credit restrictions, our hedging, balancing and optimization activities have been reduced and may be further reduced in the future. The change in fair value of outstanding commodity derivative instruments from January 1, 2002, through September 30, 2002, is summarized in the table below (in thousands): Fair value of contracts outstanding at January 1, 2002.......................................... $ (88,123) Gains recognized or otherwise settled during the period (1).................................. (149,536) Changes in fair value attributable to changes in valuation techniques and assumptions........ -- Change in fair value attributable to new contracts and price movements (2)................... 159,769 Terminated derivatives (2)................................................................... 239,573 --------- Fair value of contracts outstanding at September 30, 2002 (3)............................. $ 161,683 ========= - ---------- (1) Recognized gains from commodity cash flow hedges of $134.3 million reported in Note 8 of the financial statements and $15.3 million realized gain on trading activity reported in the Statement of Operations under trading revenue, net. (2) Includes the value of derivatives settled before their scheduled maturity and the value of commodity financial instruments that ceased to qualify as derivative instruments. (3) Net commodity derivative 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 September 30, 2002, based on price source and the period during which the instruments will mature are summarized in the table below (in thousands):
Fair Value Source 2002 2003-2004 2005-2006 After 2006 Total - ----------------- ---------- --------- ---------- ---------- ---------- Prices actively quoted................................ $ 2,779 $ 102,030 $ -- $ -- $ 104,809 Prices provided by other external sources............. 16,087 31,777 37,252 -- 85,116 Prices based on models and other valuation methods.... (276) 3,220 (24,713) (6,473) (28,242) ---------- ---------- ---------- --------- ---------- Total fair value................................... $ 18,590 $ 137,027 $ 12,539 $ (6,473) $ 161,683 ========== ========== ========== ========= ==========
-45- 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 September 30, 2002, and the period during which the instruments will mature are summarized in the table below (in thousands):
Credit Quality (based on October 16, 2002, ratings) 2002 2003-2004 2005-2006 After 2006 Total - --------------------------------------------------- --------- --------- --------- ---------- ---------- Investment grade ..................................... $ (7,671) $ 129,826 $ 14,386 $ (11,089) $ 125,452 Non-investment grade ................................. 26,031 7,814 (1,750) 4,660 36,755 No external ratings .................................. 230 (613) (97) (44) (524) --------- --------- --------- --------- ---------- Total fair value .................................. $ 18,590 $ 137,027 $ 12,539 $ (6,473) $ 161,683 ========= ========= ========= ========= ==========
The fair value of outstanding derivative commodity instruments and the fair value that would be expected after a ten percent adverse price change are shown in the table below (in thousands): Fair Value After 10% Adverse Fair Value Price Change ---------- ------------ At September 30, 2002: Crude oil.............................. $ (4,664) $ (9,063) Electricity............................ 162,086 73,536 Natural gas............................ 4,261 (120,464) ---------- ---------- Total............................... $ 161,683 $ (55,991) ========== ========== 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 fair value of electricity derivative commodity instruments after a 10% adverse price change includes the effect of increased power prices versus our derivative forward commitments. Conversely, the fair value of the natural gas derivatives after a 10% adverse price change 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 65% from December 31, 2001, to September 30, 2002, while the total volume of open power derivative positions decreased 17% 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 OCI, net of tax, or in the statement of operations as an item (gain or loss) of current earnings. As of September 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 nine months ended September 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 -46- 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: 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. Collateral Debt Securities - The King City operating lease commitment is supported by collateral debt securities that mature serially in amounts equal to a portion of the semi-annual lease payment. We have the ability and intent to hold these securities to maturity, and as a result, we do not expect a sudden change in market interest rates to have a material affect on the value of the securities at the maturity date. The securities are recorded at an amortized cost of $85.0 million at September 30, 2002. The following tables present our different classes of collateral debt securities by expected maturity date and fair market value as of September 30, 2002, (dollars in thousands):
Expected Maturity Date ------------------------------------------------------------- Weighted Average Interest Rate 2003 2004 2005 2006 Thereafter Total -------- -------- -------- -------- -------- ---------- -------- Corporate Debt Securities .............. 7.2% $ 2,015 $ 6,050 $ 7,825 $ -- $ -- $ 15,890 Government Agency Debt Securities ............................ 6.9% 1,960 -- -- -- -- 1,960 U.S. Treasury Notes .................... 6.5% -- -- 1,975 -- -- 1,975 U.S. Treasury Securities (non-interest bearing) ................ -- 4,065 -- -- 9,700 105,250 119,015 -------- -------- -------- -------- -------- -------- Total ............................... $ 8,040 $ 6,050 $ 9,800 $ 9,700 $105,250 $138,840 ======== ======== ======== ======== ======== ========
Fair Market Value ----------------- Corporate Debt Securities........... $ 16,892 Government Agency Debt Securities... 1,994 U.S. Treasury Notes................. 2,223 U.S. Treasury Securities (non-interest bearing)............. 83,387 -------- Total............................ $104,496 ======== 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 September 30, 2002, (dollars in thousands):
Weighted Average Weighted Average Notional Principal Interest Rate Interest Rate Fair Market Maturity Date Amount (Pay) (Receive) Value ------------- ------------------ ---------------- ---------------- ----------- 2008............ $ 44,250 4.2% (1) $ (4,681) 2011............ 51,760 6.9% 3-month US LIBOR (7,838) 2012............ 117,936 6.5% 3-month US LIBOR (19,416) 2014............ 67,929 6.7% 3-month US LIBOR (10,432) ---------- --------- Total........ $ 281,875 6.3% $ (42,367) ========== ========= - ---------- (1) 1-month US LIBOR until July, 2003. 3-month US LIBOR thereafter.
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Frequency of Currency Fair Market Maturity Date Notional Principal Fixed Currency Exchange Exchange Value - ------------- ----------------------------------- ------------------------------- ------------ ----- (Pay/Receive) (Pay/Receive) 2007........... US$127,763/Cdn$200,000 US$5,545/Cdn$8,750 Semi-annually $ (9,176) 2008........... Pound sterling 109,550/Euro 175,000 Pound sterling 5,152/Euro 7,328 Semi-annually (4,461) --------- Total....... $ (13,637) =========
Debt financing -- Because of the significant capital requirements within our industry, debt financing is often needed to fund our growth. We have used three primary forms of debt: (1) long-term senior notes and related instruments, including the Convertible Senior Notes Due 2006; (2) construction/project financing; and (3) revolving credit and term loan agreements. 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 primarily 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. Our revolving credit and term loan facilities bear variable interest rates and are used for general corporate purposes. The following table summarizes the fair market value of our existing debt financing as of September 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% $ 115,000 Senior Notes Due 2006......................................... 171,750 10.5% 85,875 Senior Notes Due 2006......................................... 250,000 7.6% 107,500 Convertible Senior Notes Due 2006............................. 1,200,000 4.0% 499,788 Senior Notes Due 2007......................................... 275,000 8.8% 115,500 Senior Notes Due 2007......................................... 126,120 8.8% 63,060 Senior Notes Due 2008......................................... 400,000 7.9% 156,000 Senior Notes Due 2008......................................... 2,030,000 8.5% 832,300 Senior Notes Due 2008......................................... 172,856 8.4% 58,771 Senior Notes Due 2009......................................... 350,000 7.8% 136,500 Senior Notes Due 2010......................................... 750,000 8.6% 300,000 Senior Notes Due 2011......................................... 2,000,000 8.5% 820,000 Senior Notes Due 2011......................................... 314,020 8.9% 103,627 ------------ ------ ------------ Total long-term senior notes............................... $ 8,289,746 7.8% $ 3,393,921 ============ ====== ============ Construction/project financing: Blue Spruce Energy Center project financing................... $ 47,228 1-month US LIBOR $ 47,228 Term loan due (due 2004)...................................... 1,000,000 3-month US LIBOR 1,000,000 Calpine Construction Finance Company L.P. (due 2003).......... 969,771 1-month US LIBOR 969,771 Calpine Construction Finance Company II, LLC (due 2004)....... 2,493,596 1-month US LIBOR 2,493,596 ------------ ---------------- ------------ Total long-term construction/project financing............. $ 4,510,595 $ 4,510,595 ============ ============
Construction/project financing facilities -- In 2003 and 2004, $969.8 million and $2,493.6 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. Revolving credit and term loan facilities -- On May 31, 2002, we increased our two-year secured bank term loan to $1.0 billion from $600.0 million, and reduced the aggregate size of our secured corporate revolving credit facilities to $1.0 billion (the $600 million and $400 million facilities, respectively,) from $1.4 billion. At September 30, 2002, we had $1.0 billion in funded borrowings outstanding under the term loan facility, and $250.0 million in funded borrowings outstanding, and $595.2 million in outstanding letters of credit under the revolving credit facilities. The revolving credit facilities expire in 2003. However, any letters of credit under the $600 million revolving credit facility can be extended for one year at our option. In 2004 the $1 billion term loan matures. -48- New Accounting Pronouncements In July 2001 we adopted SFAS No. 141, "Business Combinations," which supersedes 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 our consolidated financial statements. On January 1, 2002, we 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. We were 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. We 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. See Note 4 -- Goodwill and Other Intangible Assets, for further information. In June 2001 the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations," which amends SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies." SFAS No. 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. SFAS No. 143 is effective for financial statements issued for fiscal years beginning after June 15, 2002. We have not completed our assessment of the impact of SFAS No. 143. 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 net effect on the consolidated financial statements, although certain reclassifications have been made to prior period financial statements to reflect the sale or designation as "held for sale" of certain oil and gas and power plant assets and classification of the operating results. In general gains from completed sales and any anticipated losses on "held for sale" assts (of which there are none to date) are included in discontinued operations net of tax. See Note 7 - Discontinued Operations, for further information. 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. We have elected early adoption of the provisions related to the rescission of SFAS No. 4, the effect of which has been reflected in these financial statements as reclassifications of gains and losses from the extinguishment of debt from extraordinary gain or loss to other (income) expense. The provisions related to SFAS No. 13 shall be effective for transactions occurring 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 believe that the SFAS No. 145 provisions relating to extinguishment of debt may have a material effect on future 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 -49- 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 EITF No. 94-3, a liability for an exit cost was recognized at the date of commitment to an exit plan. SFAS No. 146 also establishes that the liability should initially be measured and recorded at fair value. Accordingly, SFAS No. 146 may affect the timing of recognizing future restructuring costs as well as the amounts recognized. We do not believe that SFAS No. 146 will have a material effect on our consolidated financial statements other than timing of exit costs, potentially. In October 2002 the EITF discussed EITF Issue No. 02-3, "Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities." The EITF reached a consensus to rescind EITF Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities," the impact of which is to preclude mark-to-market accounting for all energy trading contracts not within the scope of SFAS No. 133. The Task Force also reached a consensus that gains and losses on derivative instruments within the scope of SFAS No. 133 should be shown net in the income statement if the derivative instruments are held for trading purposes. We expect that further clarifications may be forthcoming from the EITF on this issue that could have an affect on the presentation of our financial statements. We have not completed our assessment of the impact that EITF No. 02-3 will have on our financial statements. Effective July 1, 2002, we reclassified certain revenue and cost of revenue to a net rather than gross basis in all periods presented in our Statement of Operations. Item 3. Quantitative and Qualitative Disclosures About Market Risk. See "Financial Market Risks" in Item 2. Item 4. Controls and Procedures. The Company's senior management, including the Company's Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the Company's disclosure controls and procedures within 90 days of the filing date of this quarterly report. Based upon this evaluation, the Company's Chairman, President and Chief Executive Officer along with the Company's Executive Vice President and Chief Financial Officer concluded that the Company's disclosure controls and procedures are effective in ensuring that material information required to be disclosed is included in the reports that it files with the Securities and Exchange Commission. There were no significant changes in the Company's internal controls or, to the knowledge of the management of the Company, in other factors that could significantly affect these controls subsequent to the evaluation date. The certificates required by this item are filed as a part of this Form 10-Q. See Certifications. 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. -50- 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 as defendants Calpine, certain of our officers and directors, and the underwriters of the offering, 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 and its subsidiaries in each of these lawsuits to be without merit, and we intend 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 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 -51- 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 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) *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 Fourth Amendment to Second Amended and Restated Credit Agreement, dated as of September 26, 2002, among the Company, The Bank of Nova Scotia, as Administrative Agent, and the Lenders named therein. (continues next page) -52- EXHIBIT INDEX (continued) EXHIBIT NUMBER DESCRIPTION ------- --------------------------------------------------------------- +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 September 30, 2002: Date of Report Date Filed Item Reported --------------------------- ------------------ ------------- July 23, 2002............... July 24, 2002 Item 5,7 August 1, 2002.............. August 2, 2002 Item 5,7 August 9, 2002.............. August 12, 2002 Item 9 August 26, 2002............. August 27, 2002 Item 5,7 August 29, 2002............. August 30, 2002 Item 5,7 September 10, 2002.......... September 11, 2002 Item 5,7 September 19, 2002.......... September 20, 2002 Item 5,7 -53- 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: November 14, 2002 By: /s/ ROBERT D. KELLY -------------------------------------- Robert D. Kelly Executive Vice President and Chief Financial Officer (Principal Financial Officer) Date: November 14, 2002 By: /s/ CHARLES B. CLARK, JR. -------------------------------------- Charles B. Clark, Jr. Senior Vice President and Corporate Controller (Principal Accounting Officer) -54- CERTIFICATIONS Certificate of the Chairman, President and Chief Executive Officer I, Peter Cartwright, the Chairman, President and Chief Executive Officer of Calpine Corporation, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Calpine Corporation (the "registrant"); 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) Designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) Evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) Presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent function): a) All significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: November 14, 2002 /s/ Peter Cartwright -------------------- Peter Cartwright Chairman, President and Chief Executive Officer Calpine Corporation -55- Certificate of the Executive Vice President and Chief Financial Officer I, Robert D. Kelly, the Executive Vice President and Chief Financial Officer of Calpine Corporation, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Calpine Corporation (the "registrant"); 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) Designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) Evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) Presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent function): a) All significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: November 14, 2002 /s/ Robert D. Kelly ------------------- Robert D. Kelly Executive Vice President and Chief Financial Officer Calpine Corporation -56- 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 Fourth Amendment to Second Amended and Restated Credit Agreement, dated as of September 26, 2002, among the Company, The Bank of Nova Scotia, as Administrative Agent, and the Lenders named therein. +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. -57- (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. -58- EX-99 3 ex99-1.txt CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Quarterly Report of Calpine Corporation (the "Company") on Form 10-Q for the period ending September 30, 2002, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Peter Cartwright, Chairman, President and Chief Executive Officer of the Company, do hereby certify, pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge, based upon a review of the Report: (1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operation of the Company. - ------------------------- Peter Cartwright Chairman, President and Chief Executive Officer Calpine Corporation November 14, 2002 EX-99 4 ex99-2.txt CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Quarterly Report of Calpine Corporation (the "Company") on Form 10-Q for the period ending September 30, 2002, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Robert D. Kelly, Executive Vice President and Chief Financial Officer of the Company, do hereby certify, pursuant to 18 U.S.C. ss. 1350, as adopted pursuant to ss. 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge, based upon a review of the Report: (1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operation of the Company. - ------------------------- Robert D. Kelly Executive Vice President and Chief Financial Officer Calpine Corporation November 14, 2002 EX-10 5 ex10-5.txt FOURTH AMENDMENT TO SECOND AMENDED AND RESTATED CREDIT AGREEMENT THIS FOURTH AMENDMENT TO SECOND AMENDED AND RESTATED CREDIT AGREEMENT, dated as of September 26, 2002 (herein called this "Amendment"), is entered into by and among CALPINE CORPORATION, a Delaware corporation (herein called the "Company"), the various financial institutions listed on the signature page hereof (the "Lenders") and THE BANK OF NOVA SCOTIA, as administrative agent for the Lenders (herein, in such capacity, called the "Agent"). W I T N E S S E T H: - - - - - - - - - - WHEREAS, the Company, the Lenders and the Agent have heretofore entered into a certain Second Amended and Restated Credit Agreement, dated as of May 23, 2000, as amended by that certain First Amendment and Waiver to Second Amended and Restated Credit Agreement, dated as of April 19, 2001, that certain Second Amendment to Second Amended and Restated Credit Agreement, dated as of March 8, 2002 and that certain Third Amendment to Second Amended and Restated Credit Agreement, dated as of May 9, 2002 (herein called the "Credit Agreement"); and WHEREAS, the Company, the Lenders and the Agent now desire to amend the Credit Agreement in certain respects, as hereinafter provided; and NOW, THEREFORE, in consideration of the premises and the mutual agreements herein contained, the Company, the Lenders and the Agent hereby agree as follows: SECTION 1. Subsection (i) of clause (b) of Section 8.2.6 of the Credit Agreement is hereby amended and restated in its entirety to read as follows: "(i) make any payment or prepayment of principal of, or make any payment of interest on, any Senior Notes (as such term is defined in the 2002 Credit Agreement) or any Subordinated Debt on any day other than the stated date for such payment or prepayment set forth in the documents and instruments memorializing any Senior Notes or such Subordinated Debt, or which would violate the subordination provisions of any such Subordinated Debt; provided, that the Borrower may so pay or prepay all or a portion of the Senior Notes (as such term is defined in the 2002 Credit Agreement) if either (A) both before and after giving effect thereto, no Default shall have occurred or be continuing and there are no Loans outstanding hereunder or (B) both before and after giving effect thereto, no Default shall have occurred and be continuing and the aggregate amount of all such prepayments shall not exceed 50% of aggregate Net Equity Proceeds received by the Borrower from and after March 8, 2002." SECTION 2. The effectiveness of this Amendment is conditioned upon receipt by the Agent of all the following documents, each in form and substance satisfactory to the Agent: (i) This Amendment duly executed by the Company and Required Lenders; and (ii) Such other documents as the Agent shall have reasonably requested. SECTION 3. This Amendment shall be deemed to be an amendment to the Credit Agreement, and the Credit Agreement, as amended hereby, is hereby ratified, approved and confirmed in each and every respect. All references to the Credit Agreement in any other document, instrument, agreement or writing shall hereafter be deemed to refer to the Credit Agreement as amended hereby. SECTION 4. THIS AMENDMENT SHALL BE A CONTRACT MADE UNDER AND GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE INTERNAL LAWS OF THE STATE OF NEW YORK. All obligations of the Company and rights of the Lenders and the Agent expressed herein shall be in addition to and not in limitation of those provided by applicable law. Whenever possible each provision of this Amendment shall be interpreted in such manner as to be effective and valid under applicable law, but if any provision of this Amendment shall be prohibited by or invalid under applicable law, such provision shall be ineffective to the extent of such prohibition or invalidity, without invalidating the remainder of such provision or the remaining provisions of this Amendment. SECTION 5. This Amendment may be executed in any number of counterparts, all of which taken together shall constitute one and the same instrument, and any party hereto may execute this Amendment by signing one or more counterparts. SECTION 6. This Amendment shall be binding upon the Company, the Lenders and the Agent and their respective successors and assigns, and shall inure to the benefit of the Company, the Lenders and the Agent and the successors and assigns of the Lenders and the Agent. SECTION 7. THE COMPANY HEREBY KNOWINGLY, VOLUNTARILY AND INTENTIONALLY WAIVES ANY RIGHT TO A TRIAL BY JURY IN ANY ACTION OR PROCEEDING TO ENFORCE OR DEFEND ANY RIGHTS UNDER THIS AMENDMENT OR UNDER ANY AMENDMENT, INSTRUMENT, DOCUMENT OR AGREEMENT DELIVERED OR WHICH MAY IN THE FUTURE BE DELIVERED IN CONNECTION HEREWITH OR ARISING FROM ANY BANKING RELATIONSHIP EXISTING IN CONNECTION WITH THIS AMENDMENT, AND AGREES THAT ANY SUCH ACTION OR PROCEEDING SHALL BE TRIED BEFORE A COURT AND NOT BEFORE A JURY. IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be executed by their respective officers thereunto duly authorized as of the day and year first above written. CALPINE CORPORATION By: /s/ Michael Thomas ------------------------------------- Name: Michael Thomas ----------------------------------- Title: Senior Vice President - Treasury ---------------------------------- THE BANK OF NOVA SCOTIA, as Agent and Lender By: /s/ Denis P. O'Meara ------------------------------------ Name: Denis P. O'Meara ----------------------------------- Title: Managing Director ---------------------------------- BAYERISCHE LANDESBANK By: /s/ C. Stolarski ------------------------------------- Name: C. Stolarski ----------------------------------- Title: V.P. ---------------------------------- By: /s/ C. Wintergerst ------------------------------------- Name: C. Wintergerst ----------------------------------- Title: V.P. ---------------------------------- CIBC INC. By: ------------------------------------- Name: ----------------------------------- Title: ---------------------------------- CREDIT SUISSE FIRST BOSTON, NEW YORK BRANCH By: /s/ James Moran ------------------------------------- Name: James Moran ----------------------------------- Title: Director ---------------------------------- By: /s/ Thomas Murray ------------------------------------- Name: Thomas Murray ----------------------------------- Title: Directors ---------------------------------- -2- BAYERISCHE HYPO-UND VEREINSBANK AG By: ------------------------------------- Name: ----------------------------------- Title: ---------------------------------- By: ------------------------------------- Name: ----------------------------------- Title: ---------------------------------- ING CAPITAL LLC By: /s/ Erwin Thomet ------------------------------------- Name: Erwin Thomet ----------------------------------- Title: Managing Director ---------------------------------- By: /s/ G. Dominick Bellamy, Jr. ------------------------------------- Name: G. Dominick Bellamy, Jr. ----------------------------------- Title: Director ---------------------------------- TORONTO DOMINION (TEXAS) INC. By: /s/ Mark A. Baird ------------------------------------- Name: Mark A. Baird ----------------------------------- Title: Vice President ---------------------------------- UNION BANK OF CALIFORNIA, N.A. By: /s/ Bryan Read ------------------------------------- Name: Bryan Read ----------------------------------- Title: Vice President ---------------------------------- BANK OF AMERICA, N.A. By: /s/ Gabriela Millhorn ------------------------------------- Name: Gabriela Millhorn ----------------------------------- Title: Principal ---------------------------------- CREDIT LYONNAIS NEW YORK BRANCH By: /s/ Martin C. Livingston ------------------------------------- Name: Martin C. Livingston ----------------------------------- Title: Vice President ---------------------------------- -3- DRESDNER BANK AG, NEW YORK AND GRAND CAYMAN BRANCHES By: ------------------------------------- Name: ----------------------------------- Title: ---------------------------------- By: ------------------------------------- Name: ----------------------------------- Title: ---------------------------------- FLEET NATIONAL BANK By: ------------------------------------- Name: ----------------------------------- Title: ---------------------------------- FORTIS CAPITAL CORP. By: ------------------------------------- Name: ----------------------------------- Title: ---------------------------------- -4- -----END PRIVACY-ENHANCED MESSAGE-----