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UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 Form 10-Q (Mark One) |X| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 2005 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 by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). 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: 569,382,412 shares of Common Stock, par value $.001 per share, outstanding on November 8, 2005. CALPINE CORPORATION AND SUBSIDIARIES REPORT ON FORM 10-Q For the Quarter Ended September 30, 2005 INDEX Page No. -------PART I -- FINANCIAL INFORMATION Item 1. Financial Statements Consolidated Condensed Balance Sheets September 30, 2005 and December 31, 2004.......... Consolidated Condensed Statements of Operations for the Three and Nine Months Ended September 30, 2005 and 2004........................................................... Consolidated Condensed Statements of Cash Flows for the Nine Months Ended September 30, 2005 and 2004........................................................... Notes to Consolidated Condensed Financial Statements...................................... 1. Organization and Operations of the Company..................................... 2. Summary of Significant Accounting Policies..................................... 3. Strategic Initiative........................................................... 4. Available-for-Sale Debt Securities............................................. 5. Property, Plant and Equipment, Net and Capitalized Interest.................... 6. Unconsolidated Investments..................................................... 7. Debt........................................................................... 8. Discontinued Operations........................................................ 9. Derivative Instruments......................................................... 10. Comprehensive Income (Loss).................................................... 11. Loss Per Share................................................................. 12. Commitments and Contingencies.................................................. 13. Operating Segments............................................................. 14. California Power Market........................................................ 15. Subsequent Events.............................................................. Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations..... Selected Operating Information.......................................................... Overview................................................................................ Results of Operations................................................................... Liquidity and Capital Resources......................................................... Performance Metrics..................................................................... Summary of Key Activities............................................................... California Power Market................................................................. Financial Market Risks.................................................................. New Accounting Pronouncements........................................................... Item 3. Quantitative and Qualitative Disclosures About Market Risk................................ Item 4. Controls and Procedures................................................................... 9 11 11 11 16 19 20 22 25 29 34 38 40 42 49 50 52 52 53 54 57 72 81 84 85 85 93 93 94 PART II -- OTHER INFORMATION Item 1. Legal Proceedings......................................................................... Item 6. Exhibits.................................................................................. Signatures.................................................................................................... 95 95 99 -2- 5 7 DEFINITIONS As used in this Form 10-Q, the abbreviations contained herein have the meanings set forth below. Additionally, the terms, "Calpine," "we," "us" and "our" refer to Calpine Corporation and its subsidiaries, unless the context clearly indicates otherwise. ABBREVIATION -----------2004 Form 10-K 2006 Convertible Notes 2014 Convertible Notes 2015 Convertible Notes 2023 Convertible Notes Acadia PP AELLC Agnews AICPA AOCI APB ARB Auburndale PP Bcfe Bear Stearns Btu CAISO CalBear CalGen Calpine Canada Calpine Cogen Calpine Jersey I Calpine Jersey II CalPX CCFC I CCFC LLC CCRC CDWR CES CFE Chubu CIP CMSC CNEM CNGT Cogen America COR CPIF CPLP CPUC CTA DB London Deer Park Diamond DOL E&S EITF Enron Enron Canada Entergy EOB EPS ERISA ESA FASB FERC FFIC FIN First Priority Notes GAAP GE Geysers Grays Ferry Hawaii Fund HBO Heat rate HIGH TIDES IP KW KWh LCRA DEFINITION ---------Calpine Corporation's Annual Report on Form 10-K for the year ended December 31, 2004, filed with the SEC on March 31, 2005 4% Convertible Senior Notes Due 2006 6% Contingent Convertible Notes Due 2014 7 3/4% Contingent Convertible Notes Due 2015 4 3/4% Contingent Convertible Senior Notes Due 2023 Acadia Power Partners, LLC Androscoggin Energy LLC O.L.S. Energy - Agnews, Inc. American Institute of Certified Public Accountants Accumulated Other Comprehensive Income Accounting Principles Board Accounting Research Bulletin Auburndale Power Partners, Limited Partnership Billion cubic feet equivalent Bear Stearns Companies, Inc. British thermal units California Independent System Operator CalBear Energy, LP Calpine Generating Company, LLC, formerly Calpine Construction Finance Company II, LLC Calpine Canada Natural Gas Partnership Calpine Cogeneration Corporation, formerly Cogen America Calpine (Jersey) Limited Calpine European Funding (Jersey) Limited California Power Exchange Calpine Construction Finance Company, L.P CCFC Preferred Holdings, LLC Calpine Canada Resources Company, f/k/a/ Calpine Canada Resources Ltd. California Department of Water Resources Calpine Energy Services, L.P. Comision Federal de Electricidad Chubu Electric Power Company, Inc. Construction in Progress Calpine Merchant Services Company, Inc. Calpine Northbrook Energy Marketing, LLC Calpine Natural Gas Trust Cogeneration Corporation of America, now called Calpine Cogeneration Corporation Cost of revenue Calpine Power Income Fund Calpine Power, L.P. California Public Utilities Commission Cumulative Translation Adjustment Deutsche Bank AG London Deer Park Energy Center Limited Partnership Diamond Generating Corporation United States Department of Labor Electricity and steam Emerging Issues Task Force Enron Corp Enron Canada Corp. Entergy Services, Inc. Electricity Oversight Board Earnings per share Employee Retirement Income Security Act Energy Services Agreement Financial Accounting Standards Board Federal Energy Regulatory Commission Fireman's Fund Insurance Company FASB Interpretation Number 9 5/8% First Priority Senior Secured Notes Due 2014 Generally accepted accounting principles General Electric International, Inc. Geysers Power Company, LLC Grays Ferry Cogeneration Partnership Hawaii Structural Ironworkers Pension Trust Fund Hedging, balancing and optimization A measure of the amount of fuel required to produce a unit of electricity Convertible Preferred Securities, Remarketable Term Income Deferrable Equity Securities (HIGH TIDES SM) International Paper Company Kilowatt(s) Kilowatt hour(s) Lower Colorado River Authority - 3 - ABBREVIATION -----------LIBOR LNG LTSA Metcalf Mitsui MLCI MMBtu Mmcfe Morris MW MWh NESCO NOL NPC O&M OCI Oneta Ontelaunee OPA Panda PCF PCF III PJM Plan POX PPA(s) PSM PUCN QF Reliant RMR Contracts Rosetta SAB Saltend SEC Second Priority Notes Second Priority Secured Debt Instruments Securities Act Senior Secured Noteholders SFAS Siemens-Westinghouse SkyGen SPE SPPC TAC TNAI TSA(s) TTS Valladolid VIE(s) Westcoast Whitby Williams DEFINITION ---------London Inter-Bank Offered Rate Liquid natural gas Long Term Service Agreement Metcalf Energy Center, LLC Mitsui & Co., Ltd. Merrill Lynch Commodities, Inc. Million Btu Million net cubic feet equivalent Morris Cogeneration, LLC, formerly known as Calpine Morris, LLC Megawatt(s) Megawatt hour(s) National Energy Systems Company Net operating loss Nevada Power Company Operations and maintenance Other Comprehensive Income Oneta Energy Center Ontelaunee Energy Center Ontario Power Authority Panda Energy International, Inc., and related party PLC II, LLC Power Contract Financing, L.L.C. Power Contract Financing III, LLC Pennsylvania-New Jersey-Maryland Calpine Corporation Retirement Savings Plan Plant operating expense Power purchase agreement(s) Power Systems MFG., LLC Public Utilities Commission of Nevada Qualifying Facilities Reliant Energy Services, Inc. Reliability must run contracts Rosetta Resources Inc. Staff Accounting Bulletin Saltend Energy Centre Securities and Exchange Commission Calpine Corporation's Second Priority Senior Secured Floating Rate Notes due 2007, 8.500% Second Priority Senior Secured Notes due 2010, 8.750% Second Priority Senior Secured Notes due 2013 and 9.875% Second Priority Senior Secured Notes due 2011 The Indentures between the Company and Wilmington Trust Company, as Trustee, relating to the Company's Second Priority Senior Secured Floating Rate Notes due 2007, 8.500% Second Priority Senior Secured Notes due 2010, 8.750% Second Priority Senior Secured Notes due 2013, 9.875% Second Priority Senior Secured Notes due 2011 and the Credit Agreement among the Company, as Borrower, Goldman Sachs Credit Partners L.P., as Administrative Agent, Sole Lead Arranger and Sole Book Runner, The Bank of Nova Scotia, as Arranger and Syndication Agent, TD Securities (USA) Inc., ING (U.S.) Capital LLC and Landesbank HessenThuringen, as Co-Arrangers, and Credit Lyonnais New York Branch and Union Bank of California, N.A., as Managing Agent, relating to the Company's Senior Secured Term Loans Due 2007, in each case as such instruments may be amended from time to time. Securities Act of 1933, as amended Holders of the First Priority Notes and the Second Priority Notes Statement of Financial Accounting Standards Siemens-Westinghouse Power Corporation (changed to "Siemens Power Generation, Inc. on August 1, 2005) SkyGen Energy LLC, now called Calpine Northbrook Energy, LLC Special-Purpose Entities Sierra Pacific Power Company Third Amended Complaint Thermal North America, Inc. Transmission service agreement(s) Thomassen Turbine Systems, B.V. Compania de Generacion Valladolid S.de R.L. de C.V. partnership Variable interest entity(ies) Westcoast Energy Inc. Whitby Cogeneration Limited Partnership The Williams Companies, Inc. -4- PART I -- FINANCIAL INFORMATION Item 1. Financial Statements. CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED BALANCE SHEETS September 30, 2005 and December 31, 2004 ASSETS Current assets: Cash and cash equivalents......................................................................... Accounts receivable, net.......................................................................... Margin deposits and other prepaid expense......................................................... Inventories....................................................................................... Restricted cash................................................................................... Current derivative assets......................................................................... Current assets held for sale...................................................................... Other current assets.............................................................................. Total current assets.......................................................................... Restricted cash, net of current portion........................................................... Notes receivable, net of current portion.......................................................... Project development costs......................................................................... Unconsolidated investments........................................................................ Deferred financing costs.......................................................................... Prepaid lease, net of current portion............................................................. Property, plant and equipment, net................................................................ Goodwill.......................................................................................... Other intangible assets, net...................................................................... Long-term derivative assets....................................................................... Long-term assets held for sale.................................................................... Other assets...................................................................................... Total assets................................................................................. LIABILITIES & STOCKHOLDERS' EQUITY Current liabilities: Accounts payable................................................................................ Accrued payroll and related expense............................................................. Accrued interest payable........................................................................ Income taxes payable............................................................................ Notes payable and borrowings under lines of credit, current portion............................. Preferred interests, current portion............................................................ Capital lease obligation, current portion....................................................... CCFC I financing, current portion............................................................... Construction/project financing, current portion................................................. Senior notes and term loans, current portion.................................................... Current derivative liabilities.................................................................. Current liabilities held for sale............................................................... Other current liabilities....................................................................... Total current liabilities..................................................................... Notes payable and borrowings under lines of credit, net of current portion........................ Convertible debentures payable to Calpine Capital Trust III....................................... Preferred interests, net of current portion....................................................... Capital lease obligation, net of current portion.................................................. CCFC I financing, net of current portion.......................................................... CalGen/CCFC II financing.......................................................................... Construction/project financing, net of current portion............................................ Convertible Notes................................................................................. Senior notes and term loans, net of current portion............................................... Deferred income taxes, net of current portion..................................................... Deferred revenue.................................................................................. Long-term derivative liabilities.................................................................. Long-term liabilities held for sale............................................................... Other liabilities................................................................................. Total liabilities............................................................................. Minority interests................................................................................ (table continues) - 5 - September 30, December 31, 2005 2004 -------------- --------------(In thousands, except share and per share amounts) (Unaudited) $ 843,136 1,537,620 415,331 151,672 1,106,685 703,665 47,152 232,741 -------------5,038,002 -------------204,433 194,076 135,291 348,058 363,513 467,658 18,542,923 45,160 66,410 925,251 210,213 547,249 -------------$ 27,088,237 ============== 718,023 1,043,061 437,593 171,639 593,304 324,206 142,096 133,643 -------------3,563,565 -------------157,868 203,680 150,179 373,108 406,844 424,586 18,397,743 45,160 68,423 506,050 2,260,401 658,481 -------------$ 27,216,088 ============== $ $ 1,192,408 85,205 406,752 64,562 208,145 159,453 7,143 3,208 85,891 967,892 974,097 6,623 355,790 -------------4,517,169 -------------586,770 -283,615 281,045 780,901 2,396,720 2,361,716 1,833,790 7,231,719 1,109,073 139,834 1,215,463 -217,257 -------------22,955,072 -------------403,197 -------------- $ 980,280 87,659 385,794 57,234 200,076 8,641 5,490 3,208 93,393 718,449 356,030 86,458 302,680 -------------3,285,392 -------------769,490 517,500 497,896 283,429 783,542 2,395,332 1,905,658 1,255,298 8,532,664 885,754 114,202 516,230 176,299 316,284 -------------22,234,970 -------------393,445 -------------- September 30, December 31, 2005 2004 -------------- --------------(In thousands, except share and per share amounts) (Unaudited) LIABILITIES & STOCKHOLDERS' EQUITY Commitments and Contingencies (Note 12) Stockholders' equity: Preferred stock, $.001 par value per share; authorized 10,000,000 shares; none issued and outstanding in 2005 and 2004................................................................... Common stock, $.001 par value per share; authorized 2,000,000,000 shares; issued and outstanding 569,382,412 shares in 2005 and 536,509,231 shares in 2004.......................... Additional paid-in capital...................................................................... Additional paid-in capital, loaned shares....................................................... Additional paid-in capital, returnable shares................................................... Retained earnings............................................................................... Accumulated other comprehensive income (loss)................................................... Total stockholders' equity................................................................. Total liabilities and stockholders' equity................................................. The accompanying notes are an integral part of these Consolidated Condensed Financial Statements. -6- -569 3,262,604 258,100 (258,100) 642,169 (175,374) -------------3,729,968 -------------$ 27,088,237 ============== -537 3,151,577 258,100 (258,100) 1,326,048 109,511 -------------4,587,673 -------------$ 27,216,088 ============== CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS For the Three and Nine Months Ended September 30, 2005 and 2004 Revenue: Electric generation and marketing revenue Electricity and steam revenue ...................................... Transmission sales revenue ......................................... Sales of purchased power for hedging and optimization .............. Total electric generation and marketing revenue ................... Oil and gas production and marketing revenue Oil and gas sales .................................................. Sales of purchased gas for hedging and optimization ................ Total oil and gas production and marketing revenue ................ Mark-to-market activities, net ....................................... Other revenue ........................................................ Total revenue ................................................... Cost of revenue: Electric generation and marketing expense Plant operating expense ............................................ Transmission purchase expense ...................................... Royalty expense .................................................... Purchased power expense for hedging and optimization ............... Total electric generation and marketing expense ................... Oil and gas operating and marketing expense Oil and gas operating expense ...................................... Purchased gas expense for hedging and optimization ................. Total oil and gas operating and marketing expense ................. Fuel expense ......................................................... Depreciation, depletion and amortization expense ..................... Operating lease expense .............................................. Other cost of revenue ................................................ Total cost of revenue ........................................... Gross profit ................................................... (Income) loss from unconsolidated investments .......................... Equipment cancellation and impairment cost ............................. Long-term service agreement cancellation charge ........................ Project development expense ............................................ Research and development expense ....................................... Sales, general and administrative expense .............................. Income from operations ............................................... Interest expense ....................................................... Interest (income) ...................................................... Minority interest expense .............................................. (Income) from repurchase of debt ....................................... Other expense (income), net ............................................ Income (loss) before benefit for income taxes ........................ Provision (benefit) for income taxes ................................... Income (loss) before discontinued operations ......................... Discontinued operations, net of tax provision of $170,514, $102,282, $137,629 and $92,061 ................................................. Net income (loss) .............................................. Basic earnings (loss) per common share: Weighted average shares of common stock outstanding................... Income (loss) before discontinued operations.......................... Discontinued operations, net of tax................................... Net income (loss)............................................... (table continues) - 7 - Three Months Ended Nine Months Ended September 30, September 30, ---------------------------------------------------2005 2004 2005 2004 -----------------------------------------(In thousands, except per share amounts) (Unaudited) $ 2,096,323 1,902 413,281 ----------2,511,506 $ 1,544,329 4,427 427,737 ----------1,976,493 $ 4,625,078 8,791 1,193,537 ----------5,827,406 $ 3,851,914 14,152 1,301,585 ----------5,167,651 -696,850 ----------696,850 40,854 32,380 ----------3,281,590 ----------- 2,690 423,733 ----------426,423 (5,229) 14,046 ----------2,411,733 ----------- -1,574,067 ----------1,574,067 40,197 84,558 ----------7,526,228 ----------- 4,707 1,258,441 ----------1,263,148 (15,316) 50,849 ----------6,466,332 ----------- 180,336 23,088 9,988 343,778 ----------557,190 159,957 22,706 8,343 348,380 ----------539,386 555,433 63,770 28,348 960,110 ----------1,607,661 522,237 53,783 21,067 1,165,674 ----------1,762,761 1,393 724,351 ----------725,744 1,567,504 131,006 28,792 32,227 ----------3,042,463 ----------239,127 (5,384) 761 553 10,098 3,342 54,593 ----------175,164 380,994 (26,640) 10,977 (15,530) 50,311 ----------(224,948) 17,487 ----------(242,435) 1,837 429,373 ----------431,210 1,052,309 117,391 25,805 19,187 ----------2,185,288 ----------226,445 11,202 7,820 3,981 3,366 3,982 53,770 ----------142,324 285,446 (16,957) 9,990 (167,154) 22,446 ----------8,553 (20,324) ----------28,877 4,318 1,623,692 ----------1,628,010 3,336,248 371,340 79,097 102,547 ----------7,124,903 ----------401,325 (14,644) 689 34,445 71,639 15,502 176,318 ----------117,376 1,027,382 (57,417) 31,763 (166,456) 71,446 ----------(789,342) (167,866) ----------(621,476) 5,824 1,243,781 ----------1,249,605 2,671,860 324,871 80,567 68,177 ----------6,157,841 ----------308,491 12,174 10,187 3,981 15,114 12,921 156,008 ----------98,106 791,242 (37,996) 23,149 (170,548) (168,934) ----------(338,807) (144,332) ----------(194,475) 25,746 ----------$ (216,689) =========== 112,248 ----------$ 141,125 =========== (62,403) ----------$ (683,879) =========== 235,710 ----------$ 41,235 =========== 478,461 $ (0.51) $ 0.06 ----------$ (0.45) =========== 444,380 $ 0.07 $ 0.25 ----------$ 0.32 =========== 458,483 $ (1.36) $ (0.13) ----------$ (1.49) =========== 425,682 $ (0.45) $ 0.55 ----------$ 0.10 =========== Diluted earnings per common share: Weighted average shares of common stock outstanding................... Income (loss) before discontinued operations.......................... Discontinued operations, net of tax................................... Net income (loss)............................................... Three Months Ended Nine Months Ended September 30, September 30, ---------------------------------------------------2005 2004 2005 2004 -----------------------------------------(In thousands, except per share amounts) (Unaudited) 478,461 $ (0.51) $ 0.06 ----------$ (0.45) =========== 446,922 $ 0.07 $ 0.25 ----------$ 0.32 =========== The accompanying notes are an integral part of these Consolidated Condensed Financial Statements. -8- 458,483 $ (1.36) $ (0.13) ----------$ (1.49) =========== 425,682 $ (0.45) $ 0.55 ----------$ 0.10 =========== CALPINE CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS For the Nine Months Ended September 30, 2005 and 2004 Cash flows from operating activities: Net income (loss) .............................................................................. Adjustments to reconcile net income (loss) to net cash used in operating activities: Depreciation, depletion and amortization (1) ................................................... Impairment charges on power projects............................................................ Development cost write-off ..................................................................... Deferred income taxes, net ..................................................................... Gain on sale of assets ......................................................................... Stock compensation expense ..................................................................... Foreign exchange losses ........................................................................ (Income) from repurchase of debt ............................................................... Change in net derivative assets and liabilities ................................................ (Income) loss from unconsolidated investments .................................................. Distributions from unconsolidated investments .................................................. Other .......................................................................................... Change in operating assets and liabilities, net of effects of acquisitions: Accounts receivable .......................................................................... Other current assets ......................................................................... Other assets ................................................................................. Accounts payable and accrued expense ......................................................... Other liabilities ............................................................................ Net cash provided by (used in) operating activities ........................................ Cash flows from investing activities: Purchases of property, plant and equipment ..................................................... Disposals of property, plant and equipment ..................................................... Disposal of subsidiary ......................................................................... Disposal of investment ......................................................................... Acquisitions, net of cash acquired ............................................................. Advances to unconsolidated investments ......................................................... Project development costs ...................................................................... Investment in HIGH TIDES ....................................................................... Disposal of HIGH TIDES investment .............................................................. Sale of collateral securities .................................................................. Increase in restricted cash .................................................................... Decrease in notes receivable ................................................................... Other .......................................................................................... Net cash provided by (used in) investing activities ........................................ Cash flows from financing activities: Borrowings from notes payable and lines of credit .............................................. Repayments of notes payable and lines of credit ................................................ Borrowings from project financing .............................................................. Repayments of project financing ................................................................ Repayments and repurchases of senior notes ..................................................... Repurchase of convertible senior notes ......................................................... Proceeds from issuance of convertible senior notes ............................................. Proceeds from issuance of senior debt offerings ................................................ Proceeds from preferred interests (2) .......................................................... Repayment of convertible debentures to Calpine Capital Trust III ............................... Proceeds from prepaid commodity contract (3) ................................................... Financing and transaction costs ................................................................ Other .......................................................................................... Net cash provided by (used in) financing activities ........................................ Effect of exchange rate changes on cash and cash equivalents ..................................... Net decrease in cash and cash equivalents including discontinued operations cash ................. Change in discontinued operations cash classified as current assets held for sale ................ Net increase in cash and cash equivalents ...................................................... Cash and cash equivalents, beginning of period ................................................... Cash and cash equivalents, end of period ......................................................... Cash paid during the period for: Interest, net of amounts capitalized ........................................................... Income taxes ................................................................................... -----------(table continues) - 9 - Nine Months Ended September 30, ----------------------------2005 2004 ----------------------(In thousands) (Unaudited) $ (683,879) $ 41,235 596,118 261,532 46,958 (30,237) (351,950) 16,430 57,182 (166,456) 17,041 (14,804) 16,862 32,452 598,856 --(52,272) (348,053) 15,190 7,521 (170,548) 40,782 11,663 22,263 74,573 (416,488) 15,788 (35,587) 205,737 25,328 ----------(407,973) ----------- (104,787) (1,202) (66,224) 218,862 (57,989) ----------229,870 ----------- (675,714) 1,860,981 -36,900 --(13,095) -132,500 -(559,946) 759 40,304 ----------822,689 ----------- (1,184,352) 1,065,834 85,412 -(187,786) (8,833) (23,605) (111,550) -93,963 (124,153) 9,979 3,157 ----------(381,934) ----------- 6,488 (808,784) 620,956 (176,799) (821,252) (15) 650,000 -565,000 (517,500) 290,571 (89,318) (28,318) ----------(308,971) ----------741 106,486 18,627 ----------125,113 ----------718,023 $ 843,136 =========== 97,191 (328,943) 3,477,854 (2,942,272) (630,275) (586,926) 867,504 878,815 ---(175,802) (23,443) ----------633,703 ----------14,377 496,016 7,694 ----------503,710 ----------954,827 $ 1,458,537 =========== $ $ $ $ 962,866 23,653 674,875 21,863 (1) Includes depreciation and amortization that is also charged to sales, general and administrative expense and to interest expense in the Consolidated Condensed Statements of Operations. (2) Relates to the $260.0 million Calpine Jersey II, $155.0 million Metcalf and $150.0 million CCFC LLC offerings of redeemable preferred securities. See Note 7 of the accompanying notes. (3) Relates to the Deer Park accompanying notes. prepaid commodity contract. See Note 9 of the Schedule of non-cash investing and financing activities: 2005 Issuance of 27.5 million shares of common stock in exchange for $94.3 million in principal amount at maturity of 2014 Convertible Notes 2004 Acquired the remaining 50% interest in the Aries power plant for $3.7 million cash and $220.0 million of assumed liabilities, including debt of $173.2 million. 2004 Issuance of 24.3 million shares of common stock in exchange for $40.0 million par value of HIGH TIDES I preferred securities and $75.0 million par value of HIGH TIDES II preferred securities. 2004 Capital lease entered into for the King City facility for an initial asset balance of $114.9 million. 2004 Issuance of 89 million shares of Calpine common stock pursuant to a Share Lending Agreement. See Note 11 of the accompanying notes for more information regarding the 89 million shares issued. 2004 Exchange of a $177.0 million note for $266.2 Contingent Convertible Senior Notes Due 2023. million of our 4.75% The accompanying notes are an integral part of these Consolidated Condensed Financial Statements. - 10 - CALPINE CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS September 30, 2005 (Unaudited) 1. Organization and Operations of the Company Calpine Corporation, a Delaware corporation, and subsidiaries (collectively, "Calpine" or the "Company") is engaged in the generation of electricity predominantly in the United States of America and Canada. The Company is involved in the development, construction, ownership and operation of power generation facilities and the sale of electricity and its by-product, thermal energy, primarily in the form of steam. In the United States, the Company has ownership interests in, and operates, gas-fired power generation and cogeneration facilities, pipelines, geothermal steam fields and geothermal power generation facilities. In Canada, the Company has ownership interests in, and operates, gas-fired power generation facilities. In Mexico, Calpine is a joint venture participant in a gas-fired power generation facility under construction. In addition, at June 30, 2005, the Company owned and operated a gas-fired power cogeneration facility in the United Kingdom, but sold this facility on July 28, 2005. The Company markets electricity produced by its generating facilities to utilities and other third party purchasers. Thermal energy produced by the gas-fired power cogeneration facilities is primarily sold to industrial users. The Company offers to third parties energy procurement, liquidation and risk management services, combustion turbine component parts and repair and maintenance services world-wide. The Company also provides engineering, procurement, construction management, commissioning and O&M services. The Company previously owned oil and gas exploration and production assets in the United States and Canada. In September 2004, the Company sold all of its Canadian and a portion of its United States oil and gas assets and, on July 7, 2005, the Company completed the sale of substantially all of its remaining oil and gas exploration and production assets. 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 SEC. 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, 2004, included in the Company's Current Report on Form 8-K dated December 31, 2004, filed with the SEC on October 17, 2005. The results for interim periods are not necessarily indicative of the results for the entire year. Reclassifications -- Certain prior years' amounts in the Consolidated Condensed Financial Statements have been reclassified to conform to the 2005 presentation. This includes a reclassification to separately disclose transmission sales revenue (formerly in other revenue). The Company has also made restatements for discontinued operations. See Note 8 for more information. In addition, the Company had certain reclassifications on its Consolidated Condensed Statement of Cash Flows to conform to the 2005 presentation. Use of Estimates in Preparation of Financial Statements -- The preparation of financial statements in conformity with generally accepted accounting principles in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expense during the reporting period. Actual results could differ from those estimates. The most significant estimates with regard to these financial statements relate to useful lives and carrying values of assets (including the carrying value of projects in development, construction and operation), provision for income taxes, fair value calculations of derivative instruments and associated reserves, capitalization of interest, impairment assessments, primary beneficiary determination for the Company's investments in VIEs, the outcome of pending litigation and estimates of oil and gas reserve quantities used to calculate depletion, depreciation and impairment of oil and gas property and equipment (prior to the July 2005 disposition). Cash and Cash Equivalents -- The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents. The carrying amount of these instruments approximates fair value because of their short maturity. The Company has certain project finance facilities and lease agreements that establish segregated cash accounts. These accounts have been pledged as security in favor of the lenders to such project finance facilities, and the use of certain cash balances on deposit in such accounts with our project financed - 11 - subsidiaries is limited to the operations of the respective projects. At September 30, 2005, and December 31, 2004, $423.5 million and $284.4 million, respectively, of the cash and cash equivalents balance that was unrestricted was subject to such project finance facilities and lease agreements. In addition, at September 30, 2005, and December 31, 2004, $50.9 million and $232.4 million, respectively, of the Company's cash and cash equivalents was held in bank accounts outside the United States. Restricted Cash -- The Company is required to maintain cash balances that are restricted by provisions of its debt agreements, lease agreements and regulatory agencies. These amounts are held by depository banks in order to comply with the contractual provisions requiring reserves for payments such as for debt service, rent service, major maintenance and debt repurchases. Funds that can be used to satisfy obligations due during the next twelve months are classified as current restricted cash, with the remainder classified as non-current restricted cash. Restricted cash is generally invested in accounts earning market rates; therefore the carrying value approximates fair value. Such cash is excluded from cash and cash equivalents in the consolidated statements of cash flows. In addition, in connection with disputes concerning the use of proceeds from the Company's sales of Saltend and of its remaining oil and gas assets (see Notes 8 and 12 for more information) approximately $609.2 million of the net proceeds of such sales has been classified as Current restricted cash as of September 31, 2005, until these disputes are resolved. Effective Tax Rate -- For the three months ended September 30, 2005, the effective rate from continuing operations increased to (7.8)% as compared to (237.6)% for the three months ended September 30, 2004. For the nine months ended September 30, 2005, and 2004, the effective tax rate was 21.3% and 42.6%, respectively. The tax rates on continuing operations for the three and nine months ended September 30, 2005, were adversely affected due to a valuation allowance recorded against certain NOL deferred tax assets associated with CCFC LLC in the amount of approximately $143.4 million. The variance in the effective tax rate for the three months ended September 30, 2005 compared to the same period in 2004 was significantly impacted by the nominal absolute dollar amount of the Company's pre-tax income (loss) in each period. For the three months ended September 30, 2004, the Company's pre-tax income from continuing operations was $8.6 million. Therefore, due to the near break-even absolute value of this amount, the tax benefit for the period translated into a high tax rate percentage, even though the benefit was only $20.3 million. Conversely, for the three months ended September 30, 2005, pre-tax loss from continuing operations was $224.9 million and the tax provision for the period was only $17.5 million. Excluding the effects of the valuation allowance associated with CCFC LLC, the Company would have recognized a tax benefit of $125.9 million for the three months ended September 30, 2005 resulting in an effective tax rate of 56.0%. While this tax benefit (excluding the effects of CCFC LLC) was $105.6 million higher than the tax benefit recognized for the three months ended September 30, 2004, the effective tax rate was significantly higher for the three months ended September 30, 2004 due to the nominal absolute value of pre-tax income from continuing operations. Also, the tax rates on continuing operations for the three and nine months ended September 30, 2004, have been restated in accordance with FIN 18, "Accounting for Income Taxes in Interim Periods - an Interpretation of APB Opinion No. 28," as amended, to reflect the effects of classifying the sale of the Company's Canadian and U.S. Rocky Mountain oil and gas assets, and the Saltend, Morris and Ontelaunee power plants as discontinued operations due to the Company's commitment to a plan of divesture in the second quarter of 2005. See Note 8 for more information. This effective tax rate on continuing operations is based on the consideration of estimated year-end earnings in estimating the quarterly effective rate, the effect of permanent non-taxable items and establishment of valuation allowances on certain deferred tax assets. Preferred Interests -- As outlined in SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity," the Company classifies preferred interests that embody obligations to transfer cash to the preferred interest holder, in short-term and long-term debt. These instruments require the Company to make priority distributions of available cash, as defined in each preferred interest agreement, representing a return of the preferred interest holder's investment over a fixed period of time and at a specified rate of return in priority to certain other distributions to equity holders. The return on investment is recorded as interest expense under the interest method over the term of the priority period. Long-Lived Assets and Impairment Evaluation -- In accordance with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," the Company evaluates the impairment of long-lived assets, including construction and development projects by first estimating projected undiscounted pre-interest expense and pre-tax expense cash flows whenever events or changes in circumstances indicate that the carrying amounts of such assets may not be recoverable. The significant assumptions that the Company uses in its undiscounted future cash flow estimates include the future supply and demand relationships for electricity and natural gas, the expected pricing for those and that the Company will hold these assets over their depreciable lives - 12 - commodities and the resultant spark spreads in the various regions where the Company generates and that the Company will hold these assets over their depreciable lives. In the event such cash flows are not expected to be sufficient to recover the recorded value of the assets, the assets are written down to their estimated fair values. Certain of the Company's generating assets are located in regions with depressed demands and market spark spreads. The Company's forecasts assume that spark spreads will increase in future years in these regions as the supply and demand relationships improve. There can be no assurance that this will occur. See Note 8 for a discussion of the impairment charge related to Ontelaunee, which met the held-for-sale criteria as of September 30, 2005, and was subsequently sold on October 6, 2005. Stock-Based Compensation -- On January 1, 2003, the Company prospectively adopted the fair value method of accounting for stock-based employee compensation pursuant to SFAS No. 123, "Accounting for Stock-Based Compensation" as amended by SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure." SFAS No. 148 amended SFAS No. 123 to provide alternative methods of transition for companies that voluntarily change their accounting for stock-based compensation from the less preferred intrinsic value based method to the more preferred fair value based method. Prior to its amendment, SFAS No. 123 required that companies enacting a voluntary change in accounting principle from the intrinsic value methodology provided by APB Opinion No. 25, "Accounting for Stock Issued to Employees," and its related implementation guidance could only do so on a prospective basis; no adoption or transition provisions were established to allow for a restatement of prior period financial statements. SFAS No. 148 provided two additional transition options to report the change in accounting principle--the modified prospective method and the retroactive restatement method. Additionally, SFAS No. 148 amended the disclosure requirements of SFAS No. 123 to require prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based employee compensation and the effect of the method used on reported results. The Company elected to adopt the provisions of SFAS No. 123 on a prospective basis; consequently, the Company is required to provide a pro-forma disclosure of net income and EPS as presented in the table below, as if SFAS No. 123 accounting had been applied to all prior periods presented within its financial statements until SFAS No. 123-R (discussed below) is adopted in January 2006. As disclosed in the table below, the Company's prospective adoption of SFAS No. 123 has had a material impact on the Company's financial statements. The table below reflects the pro forma impact of stock-based compensation on the Company's net loss and loss per share for the three and nine months ended September 30, 2005 and 2004, had the Company applied the accounting provisions of SFAS No. 123 to its financial statements in years prior to its adoption of SFAS No. 123 (in thousands, except per share amounts): Net income (loss) As reported........................................................... Pro Forma............................................................. Income (loss) per share data: Basic earnings per share As reported......................................................... Pro Forma........................................................... Diluted earnings per share As reported......................................................... Pro Forma........................................................... Stock-based compensation cost, net of tax, included in income (loss), as reported................................ Stock-based compensation cost, net of tax, included in income (loss), pro forma.................................. Three Months Ended September 30, -------------------------2005 2004 --------------------- Nine Months Ended September 30, -------------------------2005 2004 --------------------- $ (216,689) (216,751) $ 141,125 140,102 $ (683,879) (684,678) $ (0.45) (0.45) $ 0.32 0.32 $ (1.49) (1.49) $ 0.10 0.09 $ (0.45) (0.45) $ 0.32 0.31 $ (1.49) (1.49) $ 0.10 0.09 2,711 $ 3,308 $ 9,963 $ $ 2,773 4,331 10,762 $ 41,235 37,288 9,388 13,335 New Accounting Pronouncements SFAS No. 123-R In December 2004, FASB issued SFAS No. 123 (revised 2004), "Share Based Payments." This statement, referred to as SFAS No. 123-R, revises SFAS No. 123, and supersedes APB Opinion No. 25 and its related implementation guidance. This statement requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award (with limited exceptions), which must be recognized over the requisite service period (usually the vesting period) during which an employee is required to provide service in exchange for the award. The statement applies to all share-based payment transactions in which an entity acquires goods or services by issuing (or offering to issue) its shares, share options, or other equity instruments or by incurring liabilities to an employee or other supplier (a) in amounts based, at least in part, on the price of the entity's shares or other equity instruments or (b) that require or may require settlement by issuing the entity's equity shares or other equity instruments. - 13 - The statement requires the accounting for any excess tax benefits to be consistent with the existing guidance under SFAS No. 123, which provides a two-transaction model summarized as follows: o If settlement of an award creates a tax deduction that exceeds compensation cost, the additional tax benefit would be recorded as a contribution to paid-in-capital. o If the compensation cost exceeds the actual tax deduction, the write-off of the unrealized excess tax benefits would first reduce any available paid-in capital arising from prior excess tax benefits, and any remaining amount would be charged against the tax provision in the income statement. The Company is still evaluating the impact of adopting and subsequently accounting for excess tax benefits under the two-transaction model described in SFAS No. 123, but does not expect its consolidated net income, cash flows or financial position to be materially affected upon adoption of SFAS No. 123-R on January 1, 2006. The statement also amends SFAS No. 95, "Statement of Cash Flows," to require that excess tax benefits be reported as a financing cash inflow rather than as an operating cash inflow. However, the statement does not change the accounting guidance for share-based payment transactions with parties other than employees provided in SFAS No. 123 as originally issued and EITF Issue No. 96-18, "Accounting for Equity Instruments That Are Issued to Other Than Employees for Acquiring, or in Conjunction with Selling, Goods or Services." Further, this statement does not address the accounting for employee share ownership plans, which are subject to AICPA Statement of Position 93-6, "Employers' Accounting for Employee Stock Ownership Plans." The statement applies to all awards granted, modified, repurchased, or cancelled after January 1, 2006, and to the unvested portion of all awards granted prior to that date. Public entities that used the fair-value-based method for either recognition or disclosure under SFAS No. 123 may adopt SFAS 123-R using a modified version of prospective application pursuant to which compensation cost for the portion of awards for which the employee's requisite service has not been rendered, which awards are outstanding as of January 1, 2006, must be recognized as the requisite service is rendered on or after that date. The compensation cost for that portion of those awards shall be based on the original grant-date fair value of those awards as calculated for recognition under SFAS No. 123. The compensation cost for those earlier awards shall be attributed to periods beginning on or after January 1, 2006 using the attribution method that was used under SFAS No. 123. Furthermore, the method of recognizing forfeitures must now be based on an estimated forfeiture rate and can no longer be based on forfeitures as they occur. Adoption of SFAS No. 123-R is not expected to materially impact the Company's consolidated results of operations, cash flows or financial position, due to the Company's prior adoption of SFAS No. 123 as amended by SFAS No. 148, "Accounting for Stock-Based Compensation -Transition and Disclosure" on January 1, 2003. SFAS No. 148 allowed companies to adopt the fair-value-based method for recognition of compensation expense under SFAS No. 123 using prospective application. Under that transition method, compensation expense was recognized in the Company's Consolidated Statement of Operations only for stock-based compensation granted after the adoption date of January 1, 2003. Furthermore, as we have chosen the multiple option approach in recognizing compensation expense associated with the fair value of each option granted, nearly 94% of the total fair value of the stock option is recognized by the end of the third year of the vesting period, and therefore remaining compensation expense associated with options granted before January 1, 2003, is expected to be immaterial. SFAS No. 128-R FASB is expected to revise SFAS No. 128, "Earnings Per Share" to make it consistent with International Accounting Standard No. 33, "Earnings Per Share," so that EPS computations will be comparable on a global basis. This new guidance is expected to be issued by the end of 2005 and will require restatement of prior periods diluted EPS data. The proposed changes will affect the application of the treasury stock method and contingently issuable (based on conditions other than market price) share guidance for computing year-to-date diluted EPS. In addition to modifying the year-to-date calculation mechanics, the proposed revision to SFAS No. 128 would eliminate a company's ability to overcome the presumption of share settlement for those instruments or contracts that can be settled, at the issuer or holder's option, in cash or shares. Under the revised guidance, FASB has indicated that any possibility of share settlement other than in an event of bankruptcy will require a presumption of share settlement when calculating diluted EPS. The Company's 2023 Convertible Notes and 2014 Convertible Notes contain provisions that would require share settlement in the event of conversion under certain events of default, including but not limited to a bankruptcy-related event of default. Additionally, the 2023 Convertible Notes include a provision allowing the Company to meet a put with either cash or shares of stock. The Company's 2015 Convertible Notes allow for share settlement - 14 - of the principal only in the case of certain bankruptcy-related events of default. Therefore, a presumption of share settlement is required for the 2014 Convertible Notes and the 2023 Convertible Notes, but is not required for the 2015 Convertible Notes. The revised guidance will result in a significant increase in the potential dilution to the Company's EPS, particularly when the price of the Company's common stock is low, since SFAS No. 128-R requires that the more dilutive of calculations be used considering both: o normal conversion assuming a combination of cash and variable number of shares; and o conversion during events of default other than bankruptcy assuming 100% shares at the fixed conversion rate, or, in the case of 2023 Convertible Notes, meeting a put entirely with shares of stock. SFAS No. 151 In November 2004, FASB issued SFAS No. 151, "Inventory Costs, an amendment of ARB No. 43, Chapter 4." This statement amends the guidance in ARB No. 43, Chapter 4, "Inventory Pricing," to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs, and wasted material (spoilage). Paragraph 5 of ARB 43, Chapter 4, previously stated that ". . . under some circumstances, items such as idle facility expense, excessive spoilage, double freight, and rehandling costs may be so abnormal as to require treatment as current period charges. . . ." This statement requires those items to be recognized as a current-period charge regardless of whether they meet the criterion of "so abnormal." In addition, SFAS No. 151 requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. The provisions of SFAS No. 151 are applicable to inventory costs incurred during fiscal years beginning after June 15, 2005. Adoption of this statement did not materially impact the Company's consolidated results of operations, cash flows or financial position. SFAS No. 153 In December 2004, FASB issued SFAS No. 153, "Exchanges of Nonmonetary Assets." This statement eliminates the exception in APB Opinion No. 29, "Accounting for Nonmonetary Transactions" for nonmonetary exchanges of similar productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. It requires exchanges of productive assets to be accounted for at fair value, rather than at carryover basis, unless (1) neither the asset received nor the asset surrendered has a fair value that is determinable within reasonable limits or (2) the transaction lacks commercial substance (as defined). A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The new statement will not apply to the transfers of interests in assets in exchange for an interest in a joint venture and amends SFAS No. 66, "Accounting for Sales of Real Estate" to clarify that exchanges of real estate for real estate should be accounted for under APB Opinion No. 29. It also amends SFAS No. 140, to remove the existing scope exception relating to exchanges of equity method investments for similar productive assets to clarify that such exchanges are within the scope of SFAS No. 140 and not APB Opinion No. 29. SFAS No. 153 is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. Adoption of this statement did not materially impact the Company's consolidated results of operations, cash flows or financial position. SFAS No. 154 In May 2005, FASB issued SFAS No. 154, "Accounting Changes and Error Corrections." This statement replaces APB Opinion No. 20, "Accounting Changes," and FASB Statement No. 3, "Reporting Accounting Changes in Interim Financial Statements," and changes the requirements for the accounting for and reporting of a change in accounting principle. SFAS No. 154 applies to all voluntary changes in accounting principle. APB Opinion No. 20 previously required that most voluntary changes in accounting principle be recognized by including in net income for the period of the change the cumulative effect of changing to the new accounting principle. SFAS No. 154 requires retrospective application to prior periods' financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. When it is impracticable to determine the cumulative effect of applying a change in accounting principle to all prior periods, SFAS No. 154 requires that the new accounting principle be applied as if it were adopted prospectively from the earliest date practicable. SFAS No. 154 also requires that a change in depreciation, amortization, or depletion method for long-lived, nonfinancial assets be accounted for as a change in accounting estimate effected by a change in accounting principle. SFAS No. 154 is effective for fiscal years beginning after December 15, 2005. Adoption of this statement is not expected to materially impact the Company's consolidated results of operations, cash flows or financial position. - 15 - EITF Issue No. 03-13 At the November 2004 EITF meeting, the final consensus was reached on EITF Issue No. 03-13, "Applying the Conditions in Paragraph 42 of FASB Statement No. 144 in Determining Whether to Report Discontinued Operations." EITF Issue No. 03-13 is effective prospectively for disposal transactions entered into after January 1, 2005, and provides a model to assist in evaluating (a) which cash flows should be considered in the determination of whether cash flows of the disposal component have been or will be eliminated from the ongoing operations of the entity and (b) the types of continuing involvement that constitute significant continuing involvement in the operations of the disposal component. The Company has applied the model outlined in EITF Issue No. 03-13 in its evaluation of the September 2004 sale of the Canadian and U.S. Rocky Mountain oil and gas assets, the July 2005 sales of the Company's remaining oil and gas assets and Saltend facility, the sale of the Morris facility in August 2005 and the sale of the Ontelaunee facility in October 2005 (which met the criteria necessary to be classified as held-for-sale at September 30, 2005), in determining whether or not the cash flows related to these components have been or will be permanently eliminated from the ongoing operations of the Company. 3. Strategic Initiative The Company's business is capital intensive. Its ability to capitalize on growth opportunities and to service the debt it incurred to construct and operate its current fleet of power plants is dependent on the continued availability of capital. The availability of such capital in today's environment remains uncertain. To date, the Company has obtained cash from its operations; borrowings under credit facilities; issuances of debt, equity, preferred securities, convertible and contingent convertible securities; proceeds from sale/leaseback transactions; sale or partial sale of certain assets; prepayments received for power sales; contract monetizations; and project financings. The Company has utilized this cash to fund operations, service, repay or refinance debt obligations, fund acquisitions, develop and construct power generation facilities, finance capital expenditures, support hedging, balancing, optimization and trading activities, and meet other cash and liquidity needs. While the Company has been able to access the capital and bank credit markets since 2002, it has been on significantly different terms than before. In particular, the senior working capital facilities and term loan financings entered into, and the majority of the debt securities offered and sold by the Company have been secured by certain of the Company's assets and subsidiary equity interests. The Company has also provided security to support prepaid commodity transactions and, as the Company's credit ratings have been downgraded, it has been required to post collateral to support its hedging, balancing and optimization activities. In the aggregate, the average interest rate on the Company's new debt instruments, especially on recent issuances of subsidiary preferred stock and on debt incurred to refinance existing debt, has been higher. The terms of capital available now and in the future may not be attractive to the Company or its access to the capital markets may otherwise become restricted. 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 the Company's control. Consistent with the Company's strategic initiative announced in May 2005, it expects to rely to a greater extent than in the past on asset sales to reduce debt and related interest expense and to improve its liquidity position. At September 30, 2005, the Company had working capital of $520.8 million which increased approximately $242.7 million from December 31, 2004. The increase was primarily due to increases of $494.6 million, $513.4 million, and $379.5 million in accounts receivable, restricted cash, and current derivative assets, respectively, offset by increases of $212.1 million, $249.4 million and $618.1 million in accounts payable, Senior Notes, current portion and current derivative liabilities, respectively, from December 31, 2004, to September 30, 2005. The increase in accounts receivable period over period was primarily due to the significant increase in power prices during the three-month period ended September 30, 2005, and to a lesser extent, an increase in megawatt hours sold (due to additional generating capacity). Restricted cash increased primarily due to the addition of $607.5 in remaining net proceeds from the sale of Saltend and the Company's remaining oil and gas assets in July 2005. The Company's current derivative assets and liabilities increased significantly primarily as a result of significantly higher electricity and natural gas prices at the end of the third quarter in 2005. Cash flow used in operating activities during the nine-month period ended September 30, 2005 was $408.0 million and is expected to continue to be negative at least for the near term and possibly longer. On September 30, 2005, our cash and cash equivalents on hand totaled $843.1 million. The current portion of restricted cash totaled $1,106.7 million. See Note 2 for more information on the Company's cash and cash equivalents and restricted cash. Satisfying all obligations under the Company's outstanding indebtedness, and funding anticipated capital expenditures and working capital requirements for the next twelve months presents the Company with several challenges as cash requirements are expected to exceed the sum of cash on hand permitted to be used to satisfy such requirements and cash from operations. Additionally, the Company - 16 - has significant near-term maturities of debt in periods subsequent to the next twelve months including $1.4 billion in 2006 (including use of proceeds obligations described in Note 7), $1.9 billion in 2007 and $1.4 billion in 2008 (see Note 7 for further discussion of future maturities and other matters impacting the Company's debt). Accordingly, the Company has in place a strategic initiative, as discussed further below, which includes possible sales or monetizations of certain of its assets. Whether the Company will have sufficient liquidity will depend, in part, on the success of that program. No assurance can be given that the program will be successful. If it is not successful, additional asset sales, refinancings, monetizations and other items beyond those included in the strategic initiative would likely need to be made or taken, depending on market conditions. The Company's ability to reduce debt will also depend on its ability to repurchase debt securities through open market and other transactions, and the principal amount of debt able to be repurchased will be contingent upon market prices and other factors. Even if the program is successful, there can be no assurance that the Company will be able to continue work on its projects in development and suspended construction that have not successfully obtained project financing, and it could possibly incur substantial impairment losses as a result. In addition, even if the program is successful, until there are significant sustained improvements in spark spreads, the Company expects that it will not have sufficient cash flow from operations to repay all of its indebtedness at maturity or to fund its other liquidity needs. The Company expects that it will need to extend or refinance all or a portion of its indebtedness on or before maturity. While the Company currently believes that it will be successful in repaying, extending or refinancing all of its indebtedness on or before maturity, there can be no assurance that it will be able to do so on attractive terms or at all. As part of the Company's efforts to improve its financial strength, the Company announced a strategic initiative in May 2005 aimed at: o Optimizing the value of the Company's core North American power plant portfolio by selling certain power and natural gas assets to reduce debt and lower annual interest cost, and to increase cash flow in future periods. At September 30, 2005, the Company had completed the sales of Saltend in the United Kingdom, Morris in Illinois and its interest in Grays Ferry in Pennsylvania. Additionally, in October 2005 the Company completed the sale of Ontelaunee and in July 2005 completed the sale of substantially all of its remaining oil and natural gas assets. The Company is also in discussions with potential buyers for, or is considering, the sale of additional assets. See Notes 8 and 15 for further information on these transactions. o Taking actions to decrease operating and maintenance costs and lowering fuel costs to improve the operating performance of the Company's power plants, which would boost operating cash flow and liquidity. In addition, to further reduce costs, the Company has temporarily shut down two power plants and is considering others with negative cash flow, until market conditions warrant starting back up, to further reduce costs. See Note 12 for a discussion of the restructuring of certain LTSAs. o Reducing collateral requirements. On September 8, 2005, the Company and Bear Stearns announced an agreement to form a new energy marketing and trading venture to develop a third party customer business focused on physical natural gas and power trading and related structured transactions. Regulatory approval for this new entity was received on October 31, 2005, and it is anticipated that operations will begin in the fourth quarter of 2005. The transaction will include a $350 million credit intermediation agreement between CalBear, a new subsidiary of Bear Stearns, and CES. It is anticipated that this credit intermediation agreement will, among other things, positively impact Calpine's working capital position by making possible the return of cash and LCs currently posted as collateral. o Reducing total debt, net of new construction financings, by more than $3 billion from debt levels at year-end 2004, which the Company estimates would provide $275 million of annual interest savings. Calpine continues to advance its May 2005 strategic initiative aimed at optimizing its power plant portfolio, reducing debt and enhancing the Company's financial strength. While the company continues to make progress toward its goal of reducing total debt by more than $3 billion by year-end 2005 and achieving an estimated $275 million of annual interest savings, the timing of accomplishing this goal may be delayed into 2006. The cash and other consideration needed to reduce debt by that amount will be a function of the timing of asset sales, the Company's ability to use proceeds of such sales to reduce debt (we are currently involved in various litigations with the holders of certain series of our outstanding secured and unsecured bonds as described in Note 12 of the Notes to Consolidated Condensed Financial Statements), the prices at which the Company is able to repurchase debt, and other factors. At September 30, 2005, total consolidated debt was $17.2 billion, a reduction of $0.9 billion from the $18.1 billion level at March 31, 2005, before the strategic initiative was announced. Excluding the effect of new construction financing of $178.7 million, the Company has reduced debt by approximately $1.1 billion. However, regardless of whether or not the specific $3 billion debt reduction - 17 - goal can be achieved by December 31, 2005, the Company remains committed to achieving that goal as soon as practicable. In addition, as noted above, the Company seeks to identify opportunities to capture value in the skills and knowledge that it has developed, not only to improve the operating performance of its facilities but also to develop new sources of revenues, for example, by utilizing its hedging and optimization skills to develop the CalBear business and by expanding its third-party combustion turbine component parts and retail and maintenance services businesses. The Company also actively explores possible alternative sources of natural gas (such as LNG and Alaskan pipeline projects) to increase the natural gas supply in the continental United States, as well as other sources of fuel for its natural gas-fired generation facilities, such as projects to convert pet coke, an oil refinery waste product, into gas suitable for combustion in its gas turbines. There can be no assurance that the Company will be successful in developing such alternative or additional sources of fuel in the near term or otherwise. While there can be no assurance that the Company will be successful in achieving the goals of its strategic initiative and meeting its financing obligations, progress in the quarter ended September 30, 2005, included the following: o Issued $150.0 million of Class A Redeemable Preferred Shares due 2006 through its indirect subsidiary, CCFC LLC, which is an indirect parent of CCFC I, which owns a portfolio of six operating natural gas-fired power plants (not including Ontelaunee, which met the held for sale criteria as of September 30, 2005) with the generation capacity of more than 3,600 megawatts. The Redeemable Preferred Shares bear an initial dividend rate of LIBOR plus 950 basis points and were redeemable in whole or in part at any time by CCFC LLC at par plus accrued dividends. The Redeemable Preferred Shares were repurchased in full on October 14, 2005. o Completed the sale of substantially all of its remaining oil and gas exploration and production properties and assets for $1.05 billion, less adjustments, transaction fees and expenses, and less approximately $75 million to reflect the value of certain oil and gas properties for which the Company was unable to obtain consents to assignment prior to closing. Certain of the consents have been received subsequent to September 30, 2005, and the remaining consents are expected to be received by December 31, 2005. As further discussed in Note 12, the Company initiated a lawsuit seeking access to blocked proceeds remaining from this sale. o Completed the sale of Saltend, a 1,200-MW power plant in Hull, England, generating total gross proceeds of $862.9 million. Of this amount, approximately $647.1 million was used to redeem the $360.0 million Two-Year Redeemable Preferred Shares issued by our Calpine Jersey I subsidiary on October 26, 2004, and the $260.0 million Redeemable Preferred Shares issued by our Calpine Jersey II subsidiary on January 31, 2005, including interest and termination fees of $16.3 million and $10.8 million, respectively. As discussed in Note 12, certain bondholders initiated a lawsuit concerning the use of the proceeds remaining from the sale of Saltend. o Completed the sale of the Company's Inland Empire Energy Center development project to GE, for approximately $30.9 million. The project will be financed, owned and operated by GE and will be used to launch GE's most advanced gas turbine technology, the "H System (TM)." The Company will manage plant construction, market the plant's output, and manage its fuel requirements. The Company has an option to purchase the facility in years seven through fifteen following the commercial operation date and GE can require the Company to purchase the facility for a limited period of time in the fifteenth year, all subject to satisfaction of various terms and conditions. If the Company purchases the facility under the call or put, GE will continue to provide critical plant maintenance services throughout the remaining estimated useful life of the facility. Because of continuing involvement related to the purchase option and put, the Company deferred the gain generated from the sale of the development company of approximately $10 million until the call or put option is either exercised or expires. o Completed the sale of Company's 50% interest in the 175-MW Grays Ferry power plant for gross proceeds of $37.4 million. The Company recorded an impairment charge of $18.5 million related to its interest in this facility in the quarter ended June 30, 2005. o Completed the sale of the Company's 156-MW Morris power plant for approximately $84.5 million. In the three months ended June 30, 2005, the Company recorded a $106.2 million impairment charge related to its commitment to a plan of divesture of this facility which was reclassified to discontinued operations in the three month period ending September 30, 2005, upon completion of the sale. - 18 - o Repurchased approximately $138.9 million of First Priority Notes pursuant to a tender offer. Following the completion of the tender offer, the Company now has approximately $641.5 million aggregate principal amount of First Priority Notes outstanding. o Announced a 15-year Master Products and Services Agreement with GE, which is expected to lower operating costs in the future. As a result of 9 GE LTSA cancellations, the Company recorded $33.3 million in charges in the quarter ended June 30, 2005. o Signed an agreement with Siemens-Westinghouse to restructure the long-term relationship, which is expected to provide additional flexibility to self-perform maintenance work in the future. Additionally, subsequent to September 30, 2005, the Company completed the following transactions (see Note 15 for more information): o Completed the sale of the Company's 561-MW Ontelaunee power plant for $225.0 million, less transaction costs and working capital adjustments of approximately $125.0 million. The Company recorded an impairment charge of $136.8 million as of September 30, 2005 which is reflected in discontinued operations. The sale of Ontelaunee closed October 6, 2005. See Notes 5 and 8 for more information. CCFC I made offers to purchase its outstanding debt with the proceeds of the Ontelaunee sale in accordance with the instruments governing such debt. The offers have expired, and none of the holders of such debt elected to have their debt repurchased. o Received funding on CCFC LLC's $300.0 million offering of Redeemable Preferred Shares due 2011. o Repurchased the CCFC LLC $150.0 million Class A Redeemable Preferred Shares due 2006. While the Company has recognized a pre-tax gain overall on asset sales completed during the three and nine months ended September 30, 2005, the Company has recognized significant impairment charges or losses with respect to certain asset sales, including the sale of the Morris facility, as well as the sale of the Ontelaunee facility in October 2005. The Company is considering the sale of additional assets in connection with its strategic initiative program, and it is possible that some or all of the additional asset sales contemplated could lead to material impairment charges or losses upon sale. The sale of assets to reduce debt and lower annual interest costs is expected to materially lower the Company's revenues, spark spread and gross profit (loss) and the final mix of assets actually sold will determine the degree of impact on operating results. While lowering debt, the accomplishment of the strategic initiative program, in and of itself, will likely not lead to improvement in certain measures of interest and principal coverage without significant improvement in market conditions. The amount of offsetting future interest savings will be a function of the principal amount of debt retired and the interest rate born by such debt. The amount that the Company will spend to reduce debt will depend on the market price of such debt and other factors, and the final net future earnings impact of the initiatives is still uncertain. 4. Available-for-Sale Debt Securities On September 30, 2004, the Company repurchased $115.0 million in par value of HIGH TIDES III preferred securities for cash of $111.6 million. Due to the deconsolidation of Calpine Capital Trust III, the issuer of the HIGH TIDES III preferred securities, upon the adoption of FIN 46 as of December 31, 2003, and the terms of the underlying convertible debentures issued by Calpine to the Trust, the repurchased HIGH TIDES III preferred securities could not be offset against the convertible subordinated debentures and, accordingly, the Company accounted for the repurchased HIGH TIDES III preferred securities as available-for-sale securities. On July 13, 2005, the Company completed the redemption of all of the outstanding HIGH TIDES III preferred securities and of the underlying convertible debentures. Accordingly, the HIGH TIDES III preferred securities repurchased by the Company are no longer outstanding, and the Company has no available-for-sale debt securities recorded in the Consolidated Condensed Balance Sheet at September 30, 2005. See Note 7 for additional information. - 19 - 5. Property, Plant and Equipment, Net and Capitalized Interest As of September 30, 2005, and December 31, 2004, the components of property, plant and equipment, net, stated at cost less accumulated depreciation and depletion are as follows (in thousands): September 30, 2005 ------------$ 16,521,482 82,398 481,255 182,183 -----------17,267,318 (1,798,377) -----------15,468,941 94,219 2,979,763 -----------$ 18,542,923 ============ Buildings, machinery, and equipment ........................................ Pipelines .................................................................. Geothermal properties ...................................................... Other ...................................................................... Less: accumulated depreciation and depletion ............................... Land ....................................................................... Construction in progress ................................................... Property, plant and equipment, net ......................................... December 31, 2004 -----------$ 14,615,907 90,625 474,869 206,049 -----------15,387,450 (1,416,586) -----------13,970,864 104,972 4,321,907 -----------18,397,743 ============ Capital Spending -- Construction and Development Construction and Development costs in process consisted of the following at September 30, 2005 (in thousands): Projects in active construction (1) ...... Projects in suspended construction ....... Projects in advanced development ......... Projects in suspended development ........ Projects in early development ............ Other capital projects ................... Unassigned equipment ..................... Total construction and development costs # of Projects -------4 3 10 4 2 NA NA CIP ---------$ 803,004 1,130,364 721,381 309,928 -15,086 ----------$2,979,763 ========== Equipment Included in CIP ---------$ 291,709 391,505 545,458 77,624 ------------$1,306,296 ========== -----------(1) There were a total of four consolidated projects in active construction at September 30, 2005. Additionally, the Company has one project in active construction that is recorded in unconsolidated investments and is not included in the table above. Project Development Costs ---------$ --89,942 36,397 8,952 -----------$ 135,291 ========== Unassigned Equipment ---------$ ------67,691 ---------$ 67,691 ========== Construction in Progress -- CIP is primarily attributable to gas-fired power projects under construction including prepayments on gas and steam 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. Projects in Active Construction -- The four projects in active construction are projected to come on line from November 2005 to November 2007. These projects will bring on line approximately 1,247 MW of base load capacity (1,478 MW with peaking capacity). Interest and other costs related to the construction activities necessary to bring these projects to their intended use are being capitalized. At September 30, 2005, the total projected costs to complete these projects was $586.2 million. Projects in Suspended Construction -- Work and capitalization of interest on the three projects in suspended construction has been suspended or delayed due to current market conditions. These projects would bring on line approximately 1,769 MW of base load capacity (2,035 MW with peaking capacity). The Company expects to finance the remaining $324.7 million projected costs to complete these projects when construction resumes. Projects in Advanced Development -- There were ten projects in advanced development at September 30, 2005. These projects would bring on line approximately 4,151 MW of base load capacity (5,361 MW with peaking capacity). - 20 - Interest and other costs related to the development activities necessary to bring these projects to their intended use are being capitalized. However, the capitalization of interest has been suspended on four projects for which development activities are substantially complete but construction will not commence until a PPA and financing are obtained. During the quarter, the Company sold Inland Empire Energy Center, a project previously accounted for in advanced development, to a third party and moved the Wawayanda project from advanced development to suspended development. See Note 3 for more information on the sale of Inland Empire to GE. The estimated cost to complete the remaining ten projects in advanced development was approximately $2.6 billion at September 30, 2005. The Company's current plan is to finance these project costs as PPAs are executed. Suspended Development Projects --The Company has ceased capitalization of additional development costs and interest expense on four development projects on which work has been suspended due to current electric market conditions. Capitalization of costs may recommence as work on these projects resumes, if certain milestones and criteria are met indicating that it is again highly probable that the costs will be recovered through future operations. As is true for all of the Company's projects, the suspended projects are reviewed for impairment whenever there is an indication of potential reduction in a project's fair value. Further, if it is determined that it is no longer probable that the projects will be completed and all capitalized costs recovered through future operations, the carrying values of the projects would be written down to their recoverable value. The four projects in suspended development would bring on line approximately 1,365 MW of base load capacity (1,555 MW with peaking capacity). The estimated cost to complete these projects is approximately $837.6 million. Projects in Early Development -- Costs for projects that are in early stages of development are capitalized only when it is highly probable that such costs are ultimately recoverable and significant project milestones are achieved. Until then all costs, including interest costs, are expensed. The projects in early development with capitalized costs relate to two projects and include geothermal drilling costs and equipment purchases. Other Capital Projects -- Other capital projects primarily consist of enhancements to operating power plants, pipelines and geothermal resource and facilities development, as well as software developed for internal use. Unassigned Equipment -- As of September 30, 2005, the Company had made progress payments on four turbines and other equipment with an aggregate carrying value of $67.7 million. This unassigned equipment is classified on the Consolidated Condensed Balance Sheet as "Other assets" because it is not assigned to specific development and construction projects. The Company is holding this equipment for potential use on future projects. It is possible that some of this unassigned equipment may eventually be sold, potentially in combination with the Company's engineering and construction services. 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 CIP, certain pipelines under development, geothermal properties under construction, certain costs for information systems development, construction costs related to unconsolidated investments in power projects under construction, and advanced stage development costs. For the three months ended September 30, 2005 and 2004, the total amount of interest capitalized was $36.5 million and $86.6 million, respectively, including $7.8 million and $9.4 million, respectively, of interest incurred on funds borrowed for specific construction projects and $28.7 million and $77.4 million, respectively, of interest incurred on general corporate funds used for the advanced stages of development and construction. For the nine months ended September 30, 2005 and 2004, the total amount of interest capitalized was $170.9 million and $296.9 million, respectively, including $30.4 million and $43.3 million, respectively, of interest incurred on funds borrowed for specific construction projects and $140.5 million and $253.6 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 decrease in the amount of interest capitalized during the three and nine months ended September 30, 2005, reflects the completion of construction for several power plants, the suspension of certain of the Company's development and construction projects, and a reduction in the Company's development and construction program in general. In accordance with SFAS No. 34, the Company determines which debt instruments best represent a reasonable measure of the cost of financing construction assets in terms of interest cost incurred that otherwise could have been avoided. These debt instruments and associated interest cost are included in the calculation of the weighted average interest rate used for capitalizing interest on general funds. The primary debt instruments included in the rate - 21 - calculation of interest incurred on general corporate funds are the Company's Senior Notes and term loans. Impairment Evaluation -- All construction and development projects and unassigned turbines are reviewed for impairment whenever there is an indication of potential reduction in fair value. Equipment assigned to such projects is not evaluated for impairment separately, as it is integral to the assumed future operations of the project to which it is assigned. If it is determined that it is no longer probable that the projects will be completed and all capitalized costs recovered through future operations, the carrying values of the projects would be written down to the recoverable value in accordance with the provisions of SFAS No. 144. The Company reviews its unassigned equipment for potential impairment based on probability-weighted alternatives of utilizing the equipment for future projects versus selling the equipment. Utilizing this methodology, the Company does not believe that the equipment held for use is impaired. However, during the three month periods ending September 30, 2005 and 2004, and the nine month periods ended September 30, 2005 and 2004, respectively, the Company recorded to the "Equipment cancellation and impairment cost" line of the Consolidated Condensed Statement of Operations $0.8 million and $7.8 million, and $0.7 million and $10.2 million, respectively, in net losses in connection with equipment cancellations, and it may incur further losses should it decide to cancel more equipment contracts or sell unassigned equipment in the future. In the event the Company were unable to obtain PPAs or project financing and suspension or abandonment were to result, the Company could suffer substantial impairment losses on such projects. Based on an evaluation of the probability-weighted expected future cash flows, giving consideration to the continued ownership and operation of the Morris power plant or consummating the potential sale transaction at June 30, 2005, the Company determined that the carrying amount of the facility was impaired due to the high probability of consummating the sale. As a result, during the three months ended June 30, 2005, the Company recorded to the "Power plant impairment" line of the Consolidated Condensed Statement of Operations a $106.2 million impairment charge representing the difference between the proposed sale price and the facility's book value at June 30, 2005. On August 2, 2005, the Company completed the sale of the facility for approximately $84.5 million in cash and reclassified the impairment charge to discontinued operations. See Note 8 for more information on this sale. At September 30, 2005, the Company had committed to a plan to divest the Ontelaunee power plant. In accordance with SFAS No. 144, the Company recorded an impairment charge of $136.8 million for the difference between the estimated sale price (less estimated selling costs) and the facility's book value as of September 30, 2005. This charge is reflected in discontinued operations in the Consolidated Condensed Statement of Operations for the three and nine-month periods ended September 30, 2005. The sale was completed on October 6, 2005. See Notes 5 and 8 for a discussion of the Company's sale of the Ontelaunee power plant. See Note 6 for a discussion of the impairment charge in connection with the Grays Ferry power plant and Note 3 for a discussion of potential additional material impairment charges arising from the possible sale of additional assets. 6. Unconsolidated Investments The Company's unconsolidated investments are integral to its operations. The Company's joint venture investments were evaluated under FASB Interpretation No. 46 "Consolidation of Variable Interest Entities - An Interpretation of ARB 51" as amended, to determine which, if any, entities were VIEs. Based on this evaluation, the Company determined that Acadia PP, Valladolid, Grays Ferry, Whitby and AELLC were VIEs, in which the Company held a significant variable interest. However, all of the entities except for Acadia PP met the definition of a business and qualified for the business scope exception provided in paragraph 4(h) of FIN 46-R, and consequently were not subject to the VIE consolidated model. Further, based on a qualitative and quantitative assessment of the expected variability in Acadia PP, the Company was not the Primary Beneficiary. Consequently, the Company continues to account for its joint venture investments in accordance with APB Opinion No. 18, "The Equity Method of Accounting For Investments in Common Stock" and FIN 35, "Criteria for Applying the Equity Method of Accounting for Investments in Common Stock (An Interpretation of APB Opinion No. 18)." However, in the fourth quarter of 2004, the Company changed from the equity method to the cost method to account for its investment in AELLC as discussed below. Acadia PP is the owner of a 1,210-MW electric wholesale generation facility, Acadia Energy Center, located in Louisiana and is a joint venture between the Company and Cleco Corporation. The Company's involvement in this VIE began upon formation of the entity in March 2000. The Company's maximum potential exposure to loss from its equity investment at September 30, 2005, was limited to the book value of its investment of approximately $215.7 million, plus any loss that may accrue from a tolling agreement between Acadia PP and CES. - 22 - Valladolid is the owner of the Valladolid III Energy Center, a 525-MW, natural gas-fired energy center currently under construction at Valladolid, Mexico in the Yucatan Peninsula. The facility will deliver electricity to CFE under a 25-year power sales agreement. The project is a joint venture between the Company and Mitsui, and Chubu, both headquartered in Japan. The Company owns 45% of the entity while Mitsui and Chubu each own 27.5%. Construction began in May 2004 and the project is expected to achieve commercial operation in the summer of 2006. The Company's maximum potential exposure to loss at September 30, 2005, was limited to the book value of its investment of approximately $82.7 million. Grays Ferry is the owner of a 175-MW gas-fired cogeneration facility, located in Pennsylvania and was a joint venture between the Company and Trigen-Schuylkill Cogeneration, Inc. The Company's involvement in this VIE began with its acquisition of the independent power producer, Cogen America, now called Calpine Cogen, in December 1999. The Grays Ferry joint venture project was part of the portfolio of assets owned by Cogen America. On July 8, 2005, the Company completed the sale of the Grays Ferry power plant, in which it held 50% interest, for gross proceeds of $37.4 million. In June 2005, the Company recorded to the "Other expense (income), net" line of the Consolidated Condensed Statement of Operations a $18.5 million impairment charge. This transaction did not qualify as a discontinued operation under the guidance of SFAS No. 144, which specifically excludes equity method investments from its scope, unless the investment is part of a larger disposal group. Whitby is the owner of a 50-MW gas-fired cogeneration facility, located in Ontario, Canada and is a joint venture between the Company and a privately held enterprise. The Company's involvement in this VIE began with its acquisition of a portfolio of assets from Westcoast in September 2001, which included the Whitby joint venture project. The Company's maximum potential exposure to loss at September 30, 2005, was limited to the book value of its investment of approximately $49.6 million. AELLC is the owner of a 136-MW gas-fired cogeneration facility, Androscoggin Energy Center, located in Maine and is a joint venture between the Company, and affiliates of Wisvest Corporation and IP. The Company's involvement in this VIE began with its acquisition of the independent power producer, SkyGen, in October 2000. The AELLC joint venture was part of the portfolio of assets owned by SkyGen. On November 3, 2004, a jury verdict was rendered against AELLC in a breach of contract dispute with IP. The Company recorded its $11.6 million share of the award amount in the third quarter of 2004. On November 26, 2004, AELLC filed a voluntary petition for relief under Chapter 11 of the Bankruptcy Code. As a result of the bankruptcy, the Company has lost significant influence and control of the project and has adopted the cost method of accounting for its investment in AELLC. Also, in December 2004 the Company determined that its investment in AELLC, including outstanding notes receivable and O&M receivable, was impaired and recorded a $5.0 million impairment charge. The facility had third-party debt of $63.4 million outstanding as of December 31, 2004, primarily consisting of $60.3 million in construction debt. The debt was non-recourse to Calpine Corporation. On April 12, 2005, AELLC sold three fixed-price gas contracts to Merrill Lynch Commodities Canada, ULC, and used a portion of the proceeds to pay down its remaining construction debt. As of September 30, 2005, the facility had third-party debt outstanding of $3.1 million. See Note 12 for an update on this investment. The following investments are accounted for under the equity method except for Androscoggin Energy Center, which is accounted for under the cost method (in thousands): Acadia Energy Center .......................................... Valladolid III Energy Center .................................. Grays Ferry Power Plant (1) ................................... Whitby Cogeneration (2) ....................................... Androscoggin Energy Center (3) ................................ Other ......................................................... Total unconsolidated investments ............................ -----------(1) On July 8, 2005, the Company completed the sale of the Grays Ferry power plant. Please see the above paragraph for a discussion of this sale. (2) Whitby is owned 50% by the Company but a 70% economic share in the Company's ownership interest has been effectively transferred to CPLP through a loan from CPLP to the Company's entity which holds the investment interest in Whitby. - 23 - Ownership Interest as of September 30, 2005 ---------------50.0% 45.0% 50.0% 15.0% 32.3% -- Investment Balance at -------------------------------September 30, December 31, 2005 2004 -----------------------$215,657 $214,501 82,661 77,401 -48,558 49,615 32,528 --125 120 --------------$348,058 $373,108 ======== ======== (3) Excludes certain Notes Receivable. The third-party debt on the books of the unconsolidated investments is not reflected on the Company's balance sheet. At September 30, 2005, and December 31, 2004, third party investee debt was approximately $200.2 million and $133.9 million, respectively. Of these amounts, $3.1 million and $63.4 million, respectively, relate to the Company's investment in AELLC, for which the cost method of accounting was used. Based on the Company's pro rata ownership share of each of the investments, the Company's share would be approximately $74.3 million and $46.6 million for the respective periods. These amounts include the Company's share for AELLC of $1.0 million and $20.5 million, respectively. All such debt is non-recourse to the Company. The increase in investee debt between periods is primarily due to borrowings for the Valladolid III Energy Center currently under construction. The following details the Company's income and distributions from unconsolidated investments (in thousands): Acadia Energy Center ......................................... Aries Power Plant ............................................ Grays Ferry Power Plant ...................................... Whitby Cogeneration .......................................... Calpine Natural Gas Trust .................................... Androscoggin Energy Center ................................... Valladolid III Energy Center ................................. Other ........................................................ Total ...................................................... Interest income on notes receivable from power projects (1) .. Total ...................................................... Income (Loss) from Unconsolidated Investments Distributions ---------------------- --------------------For the Nine Months Ended September 30, --------------------------------------------2005 2004 2005 2004 ----------------------------$ 14,052 $ 9,490 $ 12,896 $ 14,438 -(4,265) --(739) (2,436) --1,608 870 3,768 1,515 ---6,127 -(16,680) --(213) ---(64) 7 198 183 ----------------------------$ 14,644 $(13,014) $ 16,862 $ 22,263 ======== ======== ======== ======== $ -$ 840 --------------$ 14,644 $(12,174) ======== ======== -----------(1) At September 30, 2005, and December 31, 2004, notes receivable from power projects represented an outstanding loan to AELLC, in the amounts of $4.0 million and $4.0 million, after impairment reserves, respectively. The Company provides for deferred taxes on its share of earnings. Related-Party Transactions with Unconsolidated Investments The Company and certain of its equity and cost method affiliates have entered into various service agreements with respect to power projects and oil and gas properties. Following is a general description of each of the various agreements: O&M Agreements -- The Company operates and maintains the Acadia and Androscoggin Energy Centers. This includes routine maintenance, but not major maintenance, which is typically performed under agreements with the equipment manufacturers. Responsibilities include development of annual budgets and operating plans. Payments include reimbursement of costs, including Calpine's internal personnel and other costs, and annual fixed fees. Construction Management Services Agreements -- The Company provides construction management services to the Valladolid III Energy Center. Payments include reimbursement of costs, including the Company's internal personnel and other costs. Administrative Services Agreements -- The Company handles administrative matters such as bookkeeping for certain unconsolidated investments. Payment is on a cost reimbursement basis, including Calpine's internal costs, with no additional fee. Power Marketing Agreements -- Under agreements with AELLC, CES can either market the plant's power as the power facility's agent or buy the power directly. Terms of any direct purchase are to be agreed upon at the time and incorporated into a transaction confirmation. Historically, CES has generally bought the power from the power facility rather than acting as its agent. - 24 - Gas Supply Agreement -- CES can be directed to supply gas to the Androscoggin Energy Center facility pursuant to transaction confirmations between the facility and CES. Contract terms are reflected in individual transaction confirmations. The power marketing and gas supply contracts with CES are accounted for as either purchase and sale arrangements or as tolling arrangements. In a purchase and sale arrangement, title and risk of loss associated with the purchase of gas is transferred from CES to the project at the gas delivery point. In a tolling arrangement, title to fuel provided to the project does not transfer, and CES pays the project a capacity and a variable fee based on the specific terms of the power marketing and gas supply agreements. In addition to the contracts specified above, CES maintains two tolling agreements with the Acadia facility which are accounted for as leases. All of the other power marketing and gas supply contracts are accounted for as purchases and sales. The related party balances as of September 30, 2005 and December 31, 2004, reflected in the accompanying Consolidated Condensed Balance Sheets, and the related party transactions for the three and nine months ended September 30, 2005, and 2004, reflected in the accompanying Consolidated Condensed Statements of Operations are summarized as follows (in thousands): Accounts receivable.......................... Accounts payable............................. Note receivable.............................. Other receivables............................ For the Three Months Ended September 30, Revenue...................................... Cost of revenue.............................. Interest income.............................. For the Nine Months Ended September 30, Revenue...................................... Cost of revenue.............................. Interest income.............................. Gain on sale of assets....................... September 30, 2005 ------------$ 541 5,679 4,037 428 December 31, 2004 -----------$ 765 9,489 4,037 -- 2005 ------------- 2004 ------------ $ 143 17,962 -- $ 40 25,504 347 $ 279 72,820 --- $ 953 89,623 840 6,240 7. Debt Repurchase of $138.9 million of 9 5/8% First Priority Senior Secured Notes due 2014 -- On July 12, 2005, pursuant to a tender offer in connection with the sale of the Company's remaining oil and gas assets and the related use of proceeds under the Company's indentures (see Notes 8 and 12 for more information regarding this asset sale and the subsequent use of proceeds), the Company repurchased for cash (at par) $138.9 million in principal amount of its 9 5/8% First Priority Senior Secured Notes due 2014. Following the completion of the tender offer, the Company has approximately $641.5 million aggregate principal amount of First Priority Notes outstanding as of September 30, 2005. As discussed in Note 12, the Collateral Trustee for the Company's Senior Secured Noteholders informed the Company of disagreements purportedly raised by certain holders of its First Priority Notes regarding the Company's reinvestment of the proceeds from the sale of domestic gas assets. As a result of these concerns, the Collateral Trustee informed the Company that they will be withholding further withdrawals from the gas sale proceeds account until these disagreements can be resolved. In addition, the Collateral Trustee has not released liens on certain properties for which consents were received after the closing of the sale and, accordingly, the Company has not received payment for such properties. On September 26, 2005, the Company filed a lawsuit against the Collateral Trustee and the Trustee for the First Priority Notes seeking access to the proceeds in the gas sale proceeds account. See "Indenture and Debt and Lease Covenant Compliance" below, and Note 12 for further discussion regarding the use of the proceeds of the sale of the gas assets and the status of the related legal matter. Issuance of Mandatorily Redeemable Preferred Interest -- On August 12, 2005, the Company issued $150.0 million of Class A Redeemable Preferred Shares due 2006 through its indirect subsidiary, CCFC LLC, which is an indirect parent of CCFC I. CCFC I owns a portfolio of six operating natural gas-fired power plants (not including Ontelaunee, which met the held for sale criteria as of September 30, 2005) with the generation capacity of more than 3,600 megawatts. The Redeemable Preferred Shares bear an initial dividend rate of LIBOR plus 950 basis points and may be redeemed in whole or in part at any time by the issuer at par plus accrued dividends. The Redeemable Preferred Shares were repurchased in full on October 14, 2005. Net proceeds of approximately $144.2 million from the sale will be used in accordance with the Company's existing bond indentures. - 25 - Extinguishment of HIGH TIDES III -- On July 13, 2005, the Company repaid the convertible debentures payable to Calpine Capital Trust III, the issuer of the HIGH TIDES III preferred securities. The Trust then used the proceeds to redeem the outstanding HIGH TIDES III preferred securities totaling $517.5 million, of which $115.0 million was held by Calpine. See Note 4 for additional information regarding available-for-sale debt securities. The redemption price paid per each $50 principal amount of HIGH TIDES III preferred securities was $50 plus accrued and unpaid distributions to the redemption date in the amount of $0.50. All rights of holders of the HIGH TIDES III preferred securities have ceased, except the right of such holders to receive the redemption price, which was deposited with The Depository Trust Company on July 13, 2005. Senior Note Repurchases -- During the three months ended September 30, 2005, the Company repurchased Senior Notes in open market transactions totaling $263.5 million in principal amount. The Company repurchased the Senior Notes for cash of $233.9 million plus accrued interest as follows (in thousands): Senior Notes -----------8 1/4% due 2005........................ 10 1/2 % due 2006...................... 7 5/8% due 2006........................ 8 3/4% due 2007........................ 7 7/8% due 2008........................ 8 1/2% due 2008........................ 7 3/4% due 2009........................ 9 5/8% due 2014........................ Total repurchases................... Principal ----------------$ 4,000.0 10,005.0 8,051.0 2,000.0 53,500.0 41,000.0 6,000.0 138,895.0 ---------------$ 263,451.0 ================ Cash Payment ---------------$ 3,985.0 9,671.0 7,648.4 1,570.0 39,598.8 28,632.5 3,900.0 138,895.0 ---------------$ 233,900.7 ================ For the three months ended September 30, 2005, the Company recorded an aggregate pre-tax gain of $15.5 million on the above debt repurchases and extinguishment of HIGH TIDES III after the write-off of unamortized deferred financing costs, legal fees and unamortized discounts. Annual Debt Maturities -- The annual principal repayments or maturities of notes payable and borrowings under lines of credit, preferred interests, capital lease obligation, CCFC I financing, CalGen financing, construction/project financing, convertible notes, and senior notes and term loans, as of September 30, 2005, are as follows (in thousands): October through December 2005................................. 2006.......................................................... 2007.......................................................... 2008.......................................................... 2009.......................................................... Thereafter.................................................... Total debt.................................................... (Discount) / Premium.......................................... Total....................................................... Due October - December 2005 -----------------10 1/2% Senior Notes Due 2006 .................................... 6 5/8% Senior Notes Due 2006 ..................................... 6 7/8% Senior Notes Due 2007 ..................................... Other scheduled debt maturities .................................. Estimated debt repurchase obligation (2) ......................... $ --3,125 32,853 150,020 ---------$ 185,998 ========== -----------(1) Excludes net discounts of $2,523.7 (2) See "Indenture and Debt and discussion of this obligation. Lease Covenant Compliance" below $ 35,978 1,427,080 1,857,780 1,374,781 1,630,211 11,058,266 -------------17,384,096 (196,088) -------------$ 17,188,008 ============== Due January - September 2006 ------------------(In thousands) $ 139,205 102,194 9,375 283,505 714,000 ---------$1,248,279 ========== Total Current Debt (1) ----------$ 139,205 102,194 12,500 316,358 864,000 ---------$1,434,257 ========== for a Indenture and Debt and Lease Covenant Compliance -- The covenants in certain of the Company's debt agreements currently impose restrictions on its activities, including those discussed below: - 26 - Certain of the Company's indentures place conditions on its ability to issue indebtedness if the Company's interest coverage ratio (as defined in those indentures) is below 2:1. Currently, the Company's interest coverage ratio (as so defined) is below 2:1. As such, the Company generally would not be allowed to issue new debt, except for certain types of permitted debt, such as (i) new indebtedness that refinances or replaces existing indebtedness and (ii) non-recourse debt and preferred equity interests issued by the Company's subsidiaries for purposes of financing certain types of capital expenditures, including plant development, construction and acquisition costs and expenses. In addition, if and so long as the Company's interest coverage ratio is below 2:1, the Company's ability to invest in unrestricted subsidiaries and non-subsidiary affiliates and make certain other types of restricted payments will be limited. Moreover, certain of the Company's indentures will prohibit any further investments in non-subsidiary affiliates if and for so long as its interest coverage ratio (as defined therein) is below 1.75:1 and, as of September 30, 2005, such interest coverage ratio was below 1.75:1. The Company currently does not expect this limitation on its ability to make investments in non-subsidiary affiliates to have a material impact on its business. Certain of the Company's indebtedness issued in the last half of 2004 was incurred in reliance on provisions in certain of its existing indentures pursuant to which the Company is able to incur indebtedness if, after giving effect to the incurrence and the repayment of other indebtedness with the proceeds therefrom, the Company's interest coverage ratio (as defined in those indentures) is greater than 2:1. In order to satisfy the interest coverage ratio requirement in connection with such issuances, the proceeds thereof were required to be used to repurchase or redeem other existing indebtedness. As previously reported in the Company's 2004 10-K and its Quarterly Reports on Form 10-Q for the first two quarters of 2005, the Company completed a substantial portion of such repurchases during the fourth quarter of 2004 and the first six months of 2005. The Company completed the remaining required repurchases, spending approximately $248.4 million in the third quarter of 2005 to repurchase debt, and has now fully satisfied this requirement. The amount the Company was required to spend exceeded its estimate of $184.0 million because the required principal amount of debt was repurchased at prices higher than originally anticipated. When the Company or one of its subsidiaries sells a significant asset or issues preferred equity, the Company's indentures generally require that the net proceeds of the transaction be used to make capital expenditures, to acquire permitted assets or capital stock, or to repurchase or repay indebtedness, in each case within 365 days of the closing date of the transaction. To the extent that $50 million or more of such net proceeds are not so used, the Company is required under the terms of its secured debt instruments to make an offer to purchase its outstanding senior secured indebtedness up to the amount of the unused net proceeds. This general requirement contains certain customary exceptions, and, in the case of certain assets defined as "designated assets" under some of the Company's indentures, including the gas portion of the Company's oil and gas assets sold in July 2005, there are additional provisions discussed further below that apply to the use of the proceeds of a sale of those assets. In light of these requirements, and after taking into account the amount of capital expenditures currently budgeted for the remainder of 2005 and forecasted for 2006, the Company anticipates that, in the fourth quarter of 2005 and the first three quarters of 2006, it will need to use approximately $195.5 million and $668.5 million, respectively, of the remaining net proceeds from four series of preferred equity issued by subsidiaries of the Company and three asset sale transactions, all completed prior to September 30, 2005, to repurchase or repay indebtedness or acquire assets or capital stock. The Company has, subsequent to September 30, 2005, fulfilled the portion of this obligation as required to be completed in the fourth quarter of 2005. Accordingly, assuming that the Company would fulfill these remaining obligations by repurchasing indebtedness, an aggregate amount of approximately $714.0 million of Senior notes and term loan, net of current portion, and $150.0 million of Preferred interest, net of current portion, related to this use of net proceeds requirement has been classified as Senior Notes, current portion, and Preferred interest, current portion, respectively, on the Company's Consolidated Condensed Balance Sheet as of September 30, 2005. The actual amount of the net proceeds that will be required to be used to repurchase or repay debt will depend, among other things, upon the actual amount of the net proceeds that is used to make capital expenditures or acquire other assets or capital stock, which may be more or less than the amount currently budgeted and/or forecasted. This amount includes $207.5 million of the net proceeds of the sale of Saltend. As discussed in Note 12, certain bondholders filed a lawsuit concerning the use of the proceeds from the sale of Saltend. In connection with that lawsuit, the Company is prohibited from repatriating this amount due to an order of the Court in that matter requiring such proceeds to be held at or in the control of CCRC. To the extent repatriation of such net proceeds is ultimately permitted, the repatriated net proceeds will be applied pursuant to the use of proceeds provisions of the Company's indentures described herein as if the sale of Saltend had occurred on the date of repatriation. In addition, the net proceeds from an issuance of preferred equity and an asset sale completed after September 30, 2005 will similarly be subject to such use of proceeds provisions of the Company's indentures, and the Company - 27 - anticipates that, on the basis described above (after considering capital expenditures), an additional $452.1 million will need to be used to acquire other assets or capital stock, or to repurchase or repay indebtedness, as applicable, within 365 days of the consummation of the applicable transaction. As noted above, the Company sold its remaining oil and gas assets on July 7, 2005, with the gas component of such sale constituting "designated assets" under certain of the Company's indentures. These indentures require the Company to make an offer to purchase its First Priority Notes with the net proceeds of a sale of designated assets not otherwise applied in accordance with the other permitted uses under such indentures and, to the extent any proceeds (above $50 million) remain thereafter, to make an offer to purchase its second priority senior secured debt. Accordingly, the Company made an offer to purchase the First Priority Notes in June 2005. On July 12, 2005, the Company purchased, with proceeds of the sale of the gas assets, $138.9 million in principal amount of the First Priority Notes tendered in connection with the offer to purchase. Having completed the tender offer, the Company has used approximately $308.2 million of the $708.5 million of the remaining net proceeds from the sale of its gas assets to acquire natural gas and/or geothermal energy assets permitted to be acquired under its Second Priority Secured Debt Instruments. There can be no assurance that the Company will be successful in identifying or acquiring any additional such assets on acceptable terms or at all. If the Company does not, within 180 days of receipt of the net proceeds from the sale of its gas assets, use all of the remaining net proceeds to acquire such assets, and/or to repurchase or repay (through open market or privately negotiated transactions, tender offers or otherwise) any or all of the $641.5 million aggregate principal amount of First Priority Notes remaining outstanding after consummation of the offer to purchase discussed above (either of which actions the Company may, but is not required, to take), then the Company will, to the extent that the remaining net proceeds from the sale, together with other applicable asset sales and issuances of preferred equity, exceed $50.0 million, be required under the terms of its Second Priority Secured Debt Instruments to make an offer to purchase its outstanding second priority senior secured indebtedness, of which $3.7 billion is outstanding, up to the amount of the remaining net proceeds. As described further in Note 12, on September 26, 2005, the Company filed a lawsuit seeking access to blocked proceeds remaining from this sale of designated assets. If the Company does not ultimately prevail in this lawsuit, particularly if the Company is compelled to return previously withdrawn amounts to the gas sale proceeds account as more fully described in Note 12, it could have a material adverse effect on the Company and its liquidity. In connection with several of our subsidiaries' lease financing transactions (Agnews, Geysers, Pasadena, Broad River, RockGen, and South Point) the insurance policies we have in place do not comply in every respect with the insurance requirements set forth in the financing documents. The Company has requested from the relevant financing parties, and is expecting to receive, waivers of this noncompliance. While failure to have the required insurance in place is listed in the financing documents as an event of default, the financing parties may not unreasonably withhold their approval of the Company's waiver request so long as the required insurance coverage is not reasonably available or commercially feasible, and a report is delivered from the Company's insurance consultant to that effect. The Company has delivered the required insurance consultant reports to the relevant financing parties and therefore anticipates that the necessary waivers will be executed shortly. In connection with the sale/leaseback transaction of Agnews, the Company has not fully complied with covenants pertaining to the operations and maintenance agreement, which noncompliance is technically an event of default. The Company is in the process of addressing this by seeking the lessor's approval to renew and extend the operations and maintenance agreement for the Agnews facility. In connection with the sale/leaseback transaction of Calpine Monterey Cogeneration, Inc., the Company has not fully complied with covenants pertaining to amendments to gas and power purchase agreements and the requirements to provide a detailed accounting report, which noncompliance is technically an event of default. The Company is in the process of addressing this by seeking a consent and waiver. 2014 Convertible Notes -- The Company received a letter dated October 24, 2005, on behalf of Whitebox Convertible Arbitrage Fund, L.P. and Harbert Convertible Arbitrage Master Fund, Ltd. (and certain affiliated funds of each) that, collectively, claim to hold at least 25% of the 2014 Convertible Notes. The letter purports to be a notice of default, which the Company would have 30 days to cure, under the indenture governing the 2014 Convertible Notes. The basis of the claimed default is the Company's decision not to instruct the Bid Solicitation Agent for the 2014 Convertible Notes to begin to determine the "Trading Price" of the 2014 Convertible Notes after (i) the Company received a July 5, 2005 letter from Harbert Convertible Arbitrage Master Fund, Ltd. and/or its affiliates (the "Harbert Funds") and (ii) the Harbert Funds served an affidavit on July 19, 2005 in the litigation described in Note 12, in each case claiming that the Trading Price was below a threshold specified in the 2014 Convertible Notes. The Company maintains that the information provided by the - 28 - Harbert Funds in the July 5 letter did not constitute the "reasonable evidence" required to be provided under the 2014 Convertible Notes indenture before the Company would be required to instruct the Bid Solicitation Agent to begin to determine the Trading Price. The Company also maintains that the July 19 affidavit was not a proper notice under the indenture, and in any event likewise did not constitute "reasonable evidence" as required under the indenture. Accordingly, the Company maintains that there is no default under the 2014 Convertible Notes indenture. The basis of the claimed default is currently the subject of litigation as further described in Note 12. Unrestricted Subsidiaries -- The information in this paragraph is required to be provided under the terms of the Company's Second Priority Secured Debt Instruments. The Company has designated certain of its subsidiaries as "unrestricted subsidiaries" under the Second Priority Secured Debt Instruments. A subsidiary with "unrestricted" status thereunder generally is not required to comply with the covenants contained therein that are applicable to "restricted subsidiaries." The Company has designated Calpine Gilroy 1, Inc., Calpine Gilroy 2, Inc. and Calpine Gilroy Cogen, L.P. as "unrestricted subsidiaries" for purposes of the Second Priority Secured Debt Instruments. 8. Discontinued Operations Set forth below are all of the Company's asset disposals by reportable segment that impacted the Company's Consolidated Condensed Financial Statements as of September 30, 2005, due to reclassifications to discontinued operations to reflect the sales or "held for sale" designations of the assets sold or to be sold. Oil and Gas Production and Marketing On September 1, 2004, the Company, together with Calpine Natural Gas L.P., a Delaware limited partnership, completed the sale of its U.S. Rocky Mountain gas reserves that were primarily concentrated in two geographic areas: the Colorado Piceance Basin and the New Mexico San Juan Basin. Together, these assets represented approximately 120 Bcfe of proved gas reserves, producing approximately 16.3 Mmcfe per day of gas. Under the terms of the agreement, Calpine received net cash payments of approximately $218.7 million, and recorded a pre-tax gain of approximately $103.7 million. On September 2, 2004, the Company completed the sale of its Canadian natural gas reserves and petroleum assets. These Canadian assets represented approximately 221 Bcfe of proved reserves, producing approximately 61 Mmcfe per day. Included in this sale was the Company's 25% interest in approximately 80 Bcfe of proved reserves (net of royalties) and 32 Mmcfe per day of production owned by CNGT. In accordance with SFAS No. 144, the Company's 25% equity method investment in CNGT was considered part of the larger disposal group (i.e., assets to be disposed of together as a group in a single transaction to the same buyer), and therefore evaluated and accounted for as discontinued operations. Under the terms of the agreement, Calpine received cash payments of approximately Cdn$808.1 million, or approximately US$626.4 million. Calpine initially recorded a pre-tax gain of approximately $104.5 million on the sale of these Canadian assets net of $20.1 million in foreign exchange losses recorded in connection with the settlement of forward contracts entered into to preserve the US dollar value of the Canadian proceeds. Subsequent to the close of the sale, the Company recognized an adjustment to the pre-tax gain related to working capital; this adjustment reduced the pre-tax gain by $3.2 million, resulting in a total pre-tax gain of $101.3 million. In connection with the sale of the oil and gas assets in Canada, the Company entered into a seven-year gas purchase agreement beginning on March 31, 2005, and expiring on October 31, 2011, that allows, but does not require, the Company to purchase gas from the buyer at current market index prices. The agreement is not asset specific and can be settled by any production that the buyer has available. In connection with the sale of the U.S. Rocky Mountain gas reserves, the New Mexico San Juan Basin sales agreement allows for the buyer and the Company to execute a ten-year gas purchase agreement for 100% of the underlying gas production of sold reserves, at market index prices. Any agreement would be subject to mutually agreeable collateral requirements and other customary terms and provisions. The Company believes that all final terms of the gas purchase agreements described above are on a market value and arm's length basis. If the Company elects in the future to exercise a call option over production from the disposed components, the Company will consider the call obligation to have been met as if the actual production delivered to the Company under the call was from assets other than those constituting the disposed components. On July 7, 2005, the Company completed the sale of substantially all of its remaining oil and gas assets to Rosetta for $1.05 billion, less approximately $60 million of estimated transaction fees and expenses. The Company recorded a pre-tax gain of approximately $340.2 million, which is reflected in discontinued operations in the three and nine-months ended September 30, 2005. Approximately - 29 - $75 million of the purchase price was withheld pending the transfer of certain properties for which consents had not yet been obtained at the closing date. Subsequent to September 30, 2005, the Company had received a number of these consents but none of the $75 million had been released to the Company due to the refusal of the Collateral Trustee to release liens on the applicable properties. The Company has brought a lawsuit against the Collateral Trustee as discussed below and in Note 12. It is anticipated that consents will be obtained for the remaining properties by December 31, 2005. These assets are reflected in the September 30, 2005 and December 31, 2004 Consolidated Condensed Balance Sheets as other current assets held for sale in the Summary section below. The portion of any amount received in respect of these properties for natural gas assets will constitute proceeds of a sale of "designated assets" and will be subject to the requirements described in Note 7 under "Indenture and Debt and Lease Covenant Compliance." As discussed in Note 12, the Collateral Trustee for the Company's Senior Secured Noteholders informed the Company of disagreements purportedly raised by certain holders of its First Priority Notes regarding the Company's reinvestment of the proceeds from this sale of domestic gas assets. As a result of these concerns, the Collateral Trustee informed the Company that they will be withholding further withdrawals from the gas sale proceeds account until these disagreements can be resolved. In addition, the Collateral Trustee not released liens on certain properties for which consents were received after the closing of the sale and, accordingly, the Company has not received payment for such properties. On September 26, 2005, the Company filed a lawsuit against the Collateral Trustee and the Trustee for the First Priority Notes. See Notes 7 and 12 for further discussion regarding the use of the proceeds of the sale of the gas assets and the status of the related legal matter. In connection with the sale of the oil and gas assets to Rosetta, the Company entered into a four and one-half year gas purchase agreement expiring on December 31, 2009, for 100% of the production of the Sacramento Basin assets, which represent approximately 44% of the reserve assets sold to Rosetta. The Company will pay prevailing current market index prices for all amounts acquired under the agreement. The Company believes the gas purchase agreement was negotiated on an arm's length basis and represents fair value for the production. Therefore, the agreement does not provide the Company with significant influence over the buyer's ability to realize the economic risks and rewards of owning the assets. Electric Generation and Marketing On January 15, 2004, the Company completed the sale of its 50% undivided interest in the 545-MW Lost Pines 1 Power Project to GenTex Power Corporation, an affiliate of the LCRA. Under the terms of the agreement, the Company received a cash payment of $148.6 million and recorded a gain before taxes of $35.3 million. In addition, CES entered into a tolling agreement with LCRA providing for the option to purchase 250 MW of electricity through December 31, 2004. On July 28, 2005, the Company completed the sale of its 1,200-MW Saltend Energy Centre for approximately $862.9 million, $14.5 million of which related to the estimated working capital adjustments. The Company recorded a pre-tax gain for the three and nine months ended September 30, 2005 of approximately $23.7 million, which is reflected in discontinued operations, as a result of the disposal of its UK operations. As described in Note 12, certain bondholders filed a lawsuit concerning the remaining use of proceeds from the sale of Saltend. In the three months ended September 30, 2005, the Company committed to a plan to divest its 561-MW Ontelaunee power plant in Pennsylvania. On October 6, 2005, the Company completed the sale for $225 million, less estimated transaction fees and expenses and closing adjustments of approximately $13.0 million. While the transaction closed October 6, 2005, the Company had met the criteria necessary to classify the assets and liabilities related to Ontelaunee as held for sale under SFAS No. 144 at September 30, 2005. These assets and liabilities are reflected in the September 30, 2005 and December 31, 2004 Consolidated Condensed Balance Sheets as current and long-term assets and liabilities held for sale and identified by balance sheet caption in the "Summary" section below. Also, in accordance with SFAS No. 144, the Company recorded an impairment charge of $136.8 million for the difference between the estimated sale price (less estimated selling costs) and the facility's book value as of September 30, 2005. This charge is reflected in discontinued operations in the Consolidated Condensed Statement of Operations for the three and nine-month periods ended September 30, 2005. See Note 5 for a discussion of the Company's impairment evaluation relating to the sale of Ontelaunee and Note 3 for a discussion of possible additional material impairment charges relating to the sale of other assets. In connection with the sale of Ontelaunee and in accordance with the instruments governing its indebtedness, on October 6, 2005, CCFC I commenced offers to purchase its outstanding secured term loans and notes in an amount up to the net proceeds received from the Ontelaunee sale. The offer to purchase term loans expired on October 28, 2005, and the offer to purchase notes expired on November 4, 2005, without any term loans or notes having been tendered for purchase. Any remaining proceeds from this asset sale will be used in accordance with the Company's existing bond indentures. - 30 - In connection with the sale of Ontelaunee, the Company entered into a ten-year parts and supplies service agreement, referred to as an LTSA, under which the Company will provide major maintenance services and parts supply for the significant equipment of the facility, and a five-year O&M agreement under which the Company will provide services related to the day-to-day operations and maintenance of the facility. Pricing of the LTSA and O&M service contracts is based on actual cost plus a margin and will result in estimated annual gross cash outflows of approximately $3.3 million and $2.7 million, respectively. The Company also entered into a six-month ESA under which CES will provide power management services, fuel management services, risk management services, and other services related to the Ontelaunee facility, with expected gross cash inflows of approximately $0.4 million annually. The ESA can be renewed after six months upon the mutual agreement of both Calpine and the new owner. Under the terms of the ESA, CES functions in an agency role and has no delivery or price risk and has no economic risk or reward of ownership in the operations of the Ontelaunee facility. The gross cash flows associated with the LTSA, O&M and ESA agreements are insignificant to the ongoing entity (Calpine)and the component and are considered indirect cash flows under EITF No. 03-13. Also, the Company has no significant continuing involvement in the financial and economic decision making of the disposed component. On August 2, 2005, the Company completed the sale of its interest in the 156-MW Morris power plant in Illinois for $84.5 million. The Company had previously determined that the facility was impaired at June 30, 2005, upon the Company's commitment to a plan of divesture of the facility, and recorded an impairment charge to continuing operations of $106.2 million based on the difference between the estimated sale price and the facility's book value. During the three months ended September 30, 2005, this charge was reclassified to discontinued operations once the sale had closed. The Company also recorded a pre-tax loss on the sale of $0.4 million, which is reflected in discontinued operations.Net proceeds from this asset sale will be used in accordance with the Company's existing bond indentures. In connection with the sale of Morris, the Company entered into an ESA and a gas purchase contract under which CES will provide Morris with certain energy scheduling services and gas brokerage services to facilitate gas purchases for the new owner on a month-to-month basis until the new owner can establish the necessary infrastructure to secure its own gas supply. It is anticipated that these agreements will be assigned to the new CalBear entity by year end 2005. Under the terms of the ESA, CES functions in an agency role and has no delivery or price risk and has no economic risk or reward of ownership in the operations of the Morris facility. Estimated gross cash inflows from the ESA are approximately $30,000 per month. Under the terms of the gas purchase contract, CES serves as a broker executing back-to-back purchase/sale transactions on behalf of Morris. However, CES bears only credit risk in the transaction, the nature of which is financial rather than operational and is sufficiently different in nature than the previous activities with the component. Gross estimated cash flows from the gas purchase contract is approximately $19 million on an annualized basis. The cash flows associated with these agreements are insignificant to the ongoing entity (Calpine) and are considered indirect. Also, the Company has no significant continuing involvement in the operations of the disposed component. Summary The Company made reclassifications to current and prior period financial statements to reflect the sale or designation as "held for sale" of these oil and gas and power plant assets and liabilities and to separately classify the operating results of the assets sold and gain on sale of those assets from the operating results of continuing operations to discontinued operations. - 31 - The table below presents the assets and liabilities held for sale by segment as of September 30, 2005 (in thousands). Assets Cash and cash equivalents ......................................... Accounts receivable, net .......................................... Inventories ....................................................... Other current assets .............................................. Prepaid expenses .................................................. Total current assets held for sale .............................. Property, plant and equipment ..................................... Other assets ...................................................... Total long-term assets held for sale ........................... Liabilities Accounts payable .................................................. Current derivative liabilities .................................... Other current liabilities ......................................... Total current liabilities held for sale ......................... Deferred income taxes, net of current portion ..................... Long-term derivative liabilities .................................. Other liabilities ................................................. Total long-term liabilities held for sale ...................... Assets Cash and cash equivalents ......................................... Accounts receivable, net .......................................... Inventories ....................................................... Prepaid expenses .................................................. Total current assets held for sale .............................. Property, plant and equipment ..................................... Other assets ...................................................... Total long-term assets held for sale ........................... Liabilities Accounts payable .................................................. Current derivative liabilities .................................... Other current liabilities ......................................... Total current liabilities held for sale ......................... Deferred income taxes, net of current portion ..................... Long-term derivative liabilities .................................. Other liabilities ................................................. Total long-term liabilities held for sale ...................... - 32 - September 30, 2005 ---------------------------------------------------Electric Oil and Gas Generation Production and Marketing and Marketing Total ---------------------------------$ 1 -2,007 -302 -------2,310 -------210,213 --------$ 210,213 ========== $ ---44,842 ----------44,842 --------------------$ -========== 1 -2,007 44,842 302 ---------47,152 ---------210,213 ----------$210,213 ========== $ $ $ 718 -5,905 -------6,623 -------------------$ -========== ----------------------------------$ -========== $ 718 -5,905 ---------6,623 ---------------------$ -========== December 31, 2004 ---------------------------------------------------Electric Oil and Gas Generation Production and Marketing and Marketing Total ---------------------------------$ 65,405 54,095 7,756 14,840 ---------142,096 ---------1,632,131 20,826 ---------$1,652,957 ========== $ -----------------------606,520 924 ---------$ 607,444 ========== 65,405 54,095 7,756 14,840 ---------142,096 ---------2,238,651 21,750 ---------$2,260,401 ========== $ $ $ 34,070 8,935 42,186 ---------85,191 ---------135,985 10,368 21,562 ---------$ 167,915 ========== --1,267 ---------1,267 -----------8,384 ---------$ 8,384 ========== $ 34,070 8,935 43,453 ---------86,458 ---------135,985 10,368 29,946 ---------$ 176,299 ========== The tables below presents significant components of the Company's income from discontinued operations for the three and nine months ended September 30, 2005 and 2004, respectively, (in thousands). Total revenue .................................................... Gain on disposal before taxes .................................... Operating income (loss) from discontinued operations before taxes ................................................... Income (loss) from discontinued operations before taxes .......... Income tax provision (benefit) ................................... Income from discontinued operations, net of tax .................. Total revenue..................................................... Gain on disposal before taxes..................................... Operating income (loss) from discontinued operations before taxes.................................................... Income (loss) from discontinued operations before taxes........... Income tax provision (benefit).................................... Income from discontinued operations, net of tax................... Total revenue..................................................... Gain on disposal before taxes..................................... Operating income (loss) from discontinued operations before taxes...................................................... Income (loss) from discontinued operations before taxes........... Income tax provision (benefit).................................... Income from discontinued operations, net of tax................... Total revenue..................................................... Gain on disposal before taxes..................................... Operating income (loss) from discontinued operations before taxes........................................................... Income from discontinued operations before taxes.................. Income tax provision (benefit).................................... Income from discontinued operations, net of tax................... Three Months Ended September 30, 2005 ---------------------------------------------------------------Electric Oil and Gas Corporate Generation Production and and Marketing and Marketing Other Total ------------------------------------------------$ 73,186 $ 3,261 $ -$ 76,447 ============= ============= ============= === ========= $ 25,843 $ 339,591 $ -$ 365,434 (173,414) -----------$ (147,571) 39,896 -----------$ (187,467) ============ 4,240 ------------$ 343,831 130,618 ------------$ 213,213 ============= -------------$ --------------$ -============= (169,174) -----------$ 196,260 170,514 -----------$ 25,746 ============ Three Months Ended September 30, 2004 ---------------------------------------------------------------Electric Oil and Gas Corporate Generation Production and and Marketing and Marketing Other Total ------------------------------------------------$ 130,471 $ 22,573 $ -$ 153,044 ============ ============= ============= ============ $ -$ 203,533 $ -$ 203,533 (6,701) -----------$ (6,701) (2,666) -----------$ (4,035) ============ 17,698 ------------$ 221,231 104,948 ------------$ 116,283 ============= -------------$ --------------$ -============= 10,997 -----------$ 214,530 102,282 -----------$ 112,248 ============ Nine Months Ended September 30, 2005 ---------------------------------------------------------------Electric Oil and Gas Corporate Generation Production and and Marketing and Marketing Other Total ------------------------------------------------$ 368,274 $ 25,101 $ -$ 393,375 ============ ============= ============= ============ $ 23,260 $ 337,012 $ -$ 360,272 (318,701) -----------$ (295,441) (3,186) -----------$ (292,255) ============ 33,655 ------------$ 370,667 140,815 ------------$ 229,852 ============= -------------$ --------------$ -============= (285,046) -----------$ 75,226 137,629 -----------$ (62,403) ============ Nine Months Ended September 30, 2004 ---------------------------------------------------------------Electric Oil and Gas Corporate Generation Production and and Marketing and Marketing Other Total ------------------------------------------------$ 387,289 $ 71,207 $ -$ 458,496 ============ ============= ============= ============ $ 35,327 $ 207,120 $ -$ 242,447 7,962 -----------$ 43,289 8,457 -----------$ 34,832 ============ - 33 - 77,362 ------------$ 284,482 83,604 ------------$ 200,878 ============= -------------$ --------------$ -============= 85,324 -----------$ 327,771 92,061 -----------$ 235,710 ============ The Company allocates interest to discontinued operations in accordance with EITF Issue No. 87-24, "Allocation of Interest to Discontinued Operations." The Company includes interest expense on debt which is required to be repaid as a result of a disposal transaction in discontinued operations. Additionally, other interest expense that cannot be attributed to other operations of the Company is allocated based on the ratio of net assets to be sold less debt that is required to be paid as a result of the disposal transaction to the sum of total net assets of the Company plus consolidated debt of the Company, excluding (a) debt of the discontinued operation that will be assumed by the buyer, (b) debt that is required to be paid as a result of the disposal transaction and (c) debt that can be directly attributed to other operations of the Company. Interest Expense Allocation --------------------------Electric generation and marketing Saltend Energy Centre.......................................... Morris and Ontelaunee Power Plants............................. Total....................................................... Oil and gas production and marketing Canadian and Rockies........................................... Remaining oil and gas assets................................... Total....................................................... Three Months Ended September 30, -------------------------------2005 2004 ------------------------ Nine Months Ended September 30, ------------------------------2005 2004 ------------------------- $ 6,225 2,955 -----------$ 9,180 ============ $ 1,178 4,896 ------------$ 6,074 ============= $ 45,080 14,549 ------------$ 59,629 ============= 5,170 14,797 -----------$ 19,967 ============ $ $ $ $ -357 -----------$ 357 ============ 5,158 3,138 ------------$ 8,296 ============= -10,295 ------------$ 10,295 ============= $ 17,893 7,864 -----------$ 25,757 ============ 9. Derivative Instruments Summary of Derivative Values The table below reflects the amounts that are recorded as assets and liabilities at September 30, 2005, for the Company's derivative instruments (in thousands): Current derivative assets .................................. Long-term derivative assets ................................ Total assets ............................................. Current derivative liabilities ............................. Long-term derivative liabilities ........................... Total liabilities ........................................ Net derivative liabilities ............................... Interest Rate Derivative Instruments ------------$ -1,959 ----------$ 1,959 =========== $ (15,135) (48,530) ----------$ (63,665) =========== $ (61,706) =========== Commodity Derivative Instruments Net ----------$ 703,665 923,292 ----------$ 1,626,957 =========== $ (958,962) (1,166,933) ----------$(2,125,895) =========== $ (498,938) =========== Total Derivative Instruments ----------$ 703,665 925,251 ----------$ 1,628,916 =========== $ (974,097) (1,215,463) ----------$(2,189,560) =========== $ (560,644) =========== Of the Company's net derivative liabilities, $202.1 million and $34.6 million are net derivative assets of PCF and CNEM, respectively, each of which is an entity with its existence separate from the Company and other subsidiaries of the Company. The Company fully consolidates CNEM, and the Company also records the net derivative assets of PCF in its balance sheet. On March 31, 2005, Deer Park, an indirect, wholly owned subsidiary of Calpine, entered into agreements to sell power to and buy gas from MLCI. The agreements cover 650 MW of Deer Park's capacity, and deliveries under the agreements began on April 1, 2005, and continue through December 31, 2010. To assure performance under the agreements, Deer Park granted MLCI a collateral interest in the Deer Park Energy Center. The power and gas agreements contain terms as follows: Power Agreements Under the terms of the power agreements, Deer Park will sell power to MLCI at fixed and index prices with a discount to prevailing market prices at the time the agreements were executed. In exchange for the discounted pricing, Deer Park received an initial cash payment of $195.8 million, net of $17.3 million in transaction costs during the first quarter if 2005, and subsequently received additional cash payments of $76.4 million, net of $2.9 million in transaction costs, as additional power transactions were executed with discounts to - 34 - prevailing market prices. The cash received by Deer Park is sufficiently small compared to the amount that would be required to fully prepay for the power to be delivered under the agreements that the agreements have been determined to be derivatives in their entirety under SFAS No. 133. The value of the derivative liability at September 30, 2005, was $297.4 million. As Deer Park makes power deliveries under the agreements, the liability will be satisfied and, accordingly, the derivative liability will be reduced, and Deer Park will record corresponding gains in income, supplementing the revenues recognized based on discounted pricing as deliveries take place. The upfront payments received by Deer Park from the transaction are recorded as cash flows from financing activity in accordance with guidance contained in SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" (SFAS No. 149). SFAS No. 149 requires that companies present cash flows from derivatives that contain an "other-than-insignificant" financing element as cash flows from financing activities. Under SFAS No. 149, a contract that at its inception includes off-market terms, or requires an up-front cash payment, or both is deemed to contain an "other-than-insignificant" financing element. Gas Agreements Under the terms of the gas agreements, Deer Park will receive quantities of gas such that, when combined with fuel supply provided by Deer Park's steam host, Deer Park will have sufficient contractual fuel supply to meet the fuel needs required to generate the power under the power agreements. Deer Park will pay both fixed and variable prices under the gas agreements. To the extent that Deer Park receives fixed prices for power, Deer Park will receive a volumetrically proportionate quantity of gas supply at fixed prices thereby fixing the spread between the revenue Deer Park receives under the fixed price power sales and the cost it pays under the fixed price gas purchases. To the extent that Deer Park receives index-based prices for its power sales, it will pay index-based prices for a volumetrically proportionate amount of its gas supply. Relationship of Net Derivative Assets or Liabilities to AOCI At any point in time, it is highly unlikely that total net derivative assets or liabilities will equal AOCI, 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 or asset account, 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 AOCI balance remains that is not recognized in earnings until the forecasted initially hedged 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 liabilities to its accumulated other comprehensive loss, net of tax from derivative instruments at September 30, 2005 (in thousands): Net derivative liabilities...................................................................................... Derivatives not designated as cash flow hedges and recognized hedge ineffectiveness............................. Cash flow hedges terminated prior to maturity................................................................... Deferred tax asset attributable to accumulated other comprehensive loss on cash flow hedges..................... AOCI from unconsolidated investees.............................................................................. Accumulated other comprehensive loss from derivative instruments, net of tax (1)................................ -----------(1) Amount represents one portion of the Company's total AOCI balance. See Note 10 for further information. - 35 - $ (560,644) 226,718 (24,408) 119,451 19,806 --------------$ (219,077) =============== Presentation of Revenue Under EITF Issue No. 03-11 "Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to SFAS No. 133 and Not `Held for Trading Purposes' As Defined in EITF Issue No. 02-3: "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities" -- The Company accounts for certain of its power sales and purchases on a net basis under EITF Issue No. 03-11, which the Company adopted on a prospective basis on October 1, 2003. Transactions with either of the following characteristics are presented net in the Company's Consolidated Condensed Financial Statements: (1) transactions executed in a back-to-back buy and sale pair, primarily because of market protocols; and (2) physical power purchase and sale transactions where the Company's power schedulers net the physical flow of the power purchase against the physical flow of the power sale (or "book out" the physical power flows) as a matter of scheduling convenience to eliminate the need to schedule actual power delivery. These book out transactions may occur with the same counterparty or between different counterparties where the Company has equal but offsetting physical purchase and delivery commitments. In accordance with EITF Issue No. 03-11, the Company netted the purchases of $335.8 million and $563.3 million against sales in the three months ended September 30, 2005, and September 30, 2004, respectively. The Company netted the purchases of $912.1 million and $1,255.8 million against sales in the nine months ended September 30, 2005, and September 30, 2004, respectively. The asset and liability balances for the Company's commodity derivative instruments represent the net totals after offsetting certain assets against certain liabilities under the criteria of FIN 39. For a given contract, FIN 39 will allow the offsetting of assets against liabilities so long as four criteria are met: (1) each of the two parties under contract owes the other determinable amounts; (2) the party reporting under the offset method has the right to set off the amount it owes against the amount owed to it by the other party; (3) the party reporting under the offset method intends to exercise its right to set off; and (4) the right of set-off is enforceable by law. The table below reflects both the amounts (in thousands) recorded as assets and liabilities by the Company and the amounts that would have been recorded had the Company's commodity derivative instrument contracts not qualified for offsetting as of September 30, 2005. Current derivative assets....................................................................... Long-term derivative assets..................................................................... Total derivative assets....................................................................... Current derivative liabilities.................................................................. Long-term derivative liabilities................................................................ Total derivative liabilities.................................................................. Net commodity derivative liabilities.......................................................... September 30, 2005 ---------------------------------Gross Net -----------------------------$ 4,766,711 $ 703,665 2,097,589 923,292 ----------------------------$ 6,864,300 $ 1,626,957 =============== =============== $ (5,022,008) $ (958,962) (2,341,230) (1,166,933) ----------------------------$ (7,363,238) $ (2,125,895) =============== =============== $ (498,938) $ (498,938) =============== =============== The table above excludes the value of interest rate and currency derivative instruments. The tables below reflect the impact of unrealized mark-to-market gains (losses) on the Company's 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, 2005 and 2004, respectively (in thousands): Natural gas derivatives (1) ............... Power derivatives (1) ..................... Interest rate derivatives (2) ............. Currency derivatives ...................... Total ................................... Three Months Ended September 30, --------------------------------------------------------------------------------------2005 2004 ----------------------------------------------------------------------------------Hedge Undesignated Hedge Undesignated Ineffectiveness Derivatives Total Ineffectiveness Derivatives Total --------------- ---------------------------------- -------------------$ 9,651 $ 94,546 $ 104,197 $ 777 $ (8,508) $ (7,731) (1,643) (127,642) (129,285) 1,142 (17,173) (16,031) 524 -524 2,369 -2,369 ----(12,897) (12,897) ------------------------------------------------$ 8,532 $ (33,096) $ (24,564) $ 4,288 $ (38,578) $ (34,290) ========= ========= ========= ========= ========= ========= - 36 - Natural gas derivatives (1) ............... Power derivatives (1) ..................... Interest rate derivatives (2) ............. Currency derivatives ...................... Total ................................... Nine Months Ended September 30, --------------------------------------------------------------------------------------2005 2004 ----------------------------------------------------------------------------------Hedge Undesignated Hedge Undesignated Ineffectiveness Derivatives Total Ineffectiveness Derivatives Total --------------- ---------------------------------- -------------------$ 10,417 $ 58,123 $ 68,540 $ 6,540 $ (11,610) $ (5,070) (1,947) (123,413) (125,360) 1,268 (53,818) (52,550) (316) -(316) 1,421 6,035 7,456 ----(12,897) (12,897) ------------------------------------------------$ 8,154 $ (65,290) $ (57,136) $ 9,229 $ (72,290) $ (63,061) ========= ========= ========= ========= ========= ========= -----------(1) Represents the unrealized portion of mark-to-market activity on gas and power transactions. The unrealized portion of mark-to-market activity is combined with the realized portions of mark-to-market activity and presented in the Consolidated Statements of Operations as "mark-to-market activities, net." (2) Recorded Operations. within "Other Income" in the Consolidated Statements of 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, 2005 and 2004, respectively (in thousands): Natural gas and crude oil derivatives........................................................... Power derivatives............................................................................... Interest rate derivatives....................................................................... Foreign currency derivatives.................................................................... Total derivatives............................................................................. Natural gas and crude oil derivatives........................................................... Power derivatives............................................................................... Interest rate derivatives....................................................................... Foreign currency derivatives.................................................................... Total derivatives............................................................................. Three Months Ended September 30, ---------------------------------2005 2004 ----------------- ---------------$ 27,589 $ (1,746) (297,481) (26,975) (6,665) (1,320) (498) (501) ----------------------------$ (277,055) $ (30,542) =============== =============== Nine Months Ended September 30, ---------------------------------2005 2004 ----------------- ---------------$ 44,906 $ 23,487 (336,922) (69,998) (20,570) (11,286) (1,499) (1,513) ----------------------------$ (314,085) $ (59,310) =============== =============== These tables include pre-tax losses of $175.3 million and $10.4 million for the three months ended September 30, 2005 and 2004, respectively, and $199.4 million and $1.4 million for the nine months ended September 30, 2005 and 2004, respectively, which are included in discontinued operations for all periods presented. As of September 30, 2005, the maximum length of time over which the Company was hedging its exposure to the variability in future cash flows for forecasted transactions was 7 and 11 years for commodity and interest rate derivative instruments, respectively. The Company estimates that pre-tax losses of $242.7 million would be reclassified from OCI into earnings during the twelve months ended September 30, 2006, as the hedged transactions affect earnings assuming constant gas and power prices, interest rates, and exchange rates over time; however, the actual amounts that will be reclassified will likely vary based on the probability that gas and power prices as well as interest rates and exchange rates will, in fact, change. Therefore, management is unable to predict what the actual reclassification from OCI to earnings (positive or negative) will be for the next twelve months. The table below presents the pre-tax gains (losses) currently held in OCI that will be recognized annually into earnings, assuming constant gas and power prices, interest rates, and exchange rates over time (in thousands): - 37 - Gas OCI .......................... Power OCI ........................ Interest rate OCI ................ Foreign currency OCI ............. Total pre-tax OCI .............. 2005 ---------$ 124,750 (227,309) (1,744) (498) --------$(104,801) ========= 2006 ---------$ 340,855 (510,504) (5,860) (1,993) --------$(177,502) ========= 2007 ---------$ 16,035 (33,390) (3,876) (1,603) --------$ (22,834) ========= 2008 ---------$ 2,975 (6,465) (3,169) (94) --------$ (6,753) ========= 2009 ---------$ 2,036 (5,210) (3,027) ---------$ (6,201) ========= 2010 & After ---------$ 2,621 (4,283) (18,775) ---------$ (20,437) ========= Total ---------$ 489,272 (787,161) (36,451) (4,188) --------$(338,528) ========= 10. 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 the Company's net income (loss), unrealized gains and losses from derivative instruments that qualify as cash flow hedges, unrealized gains and losses from available-for-sale securities which are marked to market, the Company's share of its equity method investee's OCI, and the effects of foreign currency translation adjustments. The Company reports AOCI in its Consolidated Balance Sheet. The tables below detail the changes during the nine months ended September 30, 2005 and 2004 in the Company's AOCI balance and the components of the Company's comprehensive income (loss) (in thousands): Accumulated other comprehensive income (loss) at January 1, 2005 ..................................... Net loss for the three months ended March 31, 2005 ....... Cash flow hedges: Comprehensive pre-tax loss on cash flow hedges before reclassification adjustment during the three months ended March 31, 2005 .................... Reclassification adjustment for gain included in net loss for the three months ended March 31, 2005 ....................................... Income tax benefit for the three months ended March 31, 2005 ....................................... Available-for-sale investments: Pre-tax gain on available-for-sale investments for the three months ended March 31, 2005 ............ Income tax provision for the three months ended March 31, 2005 ................................. Cash Flow Hedges ----------- Availablefor-Sale Investments ----------- Foreign Currency Translation ----------- $ $ $ (140,151) 582 (table continues) - 38 - 109,511 $ (168,731) (4,044) 29,998 ----------(64,765) (64,765) (64,765) 1,150 (451) ----------699 699 (12,830) ----------- Total comprehensive loss for the three months ended March 31, 2005 ................................... Net loss for the three months ended June 30, 2005 ........ Cash flow hedges: Comprehensive pre-tax loss on cash flow hedges before reclassification adjustment during the three months ended June 30, 2005 ....................... Reclassification adjustment for loss included in net loss for the three months ended June 30, 2005 .......................................... Income tax benefit for the three months ended June 30, 2005 .......................................... $ (90,719) Foreign currency translation loss for the three months ended March 31, 2005 .......................... Accumulated other comprehensive income (loss) at March 31, 2005 ...................................... 249,080 Total Accumulated Other Comprehensive Income (Loss) ------------- Comprehensive Income (Loss) for the Three Months Ended March 31, 2005, June 30, 2005, and September 30, 2005 --------------- (12,830) ----------- 699 (12,830) ----------$ (245,627) =========== $ (204,916) =========== $ 1,281 =========== $ 236,250 =========== $ 32,615 =========== $ (298,458) (134,289) 41,074 27,872 ----------(65,343) (65,343) (65,343) Available-for-sale investments: Pre-tax gain on available-for-sale investments for the three months ended June 30, 2005 ............... Income tax provision for the three months ended June 30, 2005 .................................... 2,415 (947) ----------1,468 Foreign currency translation loss for the three months ended June 30, 2005 ............................. 1,468 (20,860) ----------- Total comprehensive loss for the three months ended June 30, 2005 .................................... (20,860) ----------- $ (383,193) =========== Total comprehensive loss for the six months ended June 30, 2005 .................................... Accumulated other comprehensive income (loss) at June 30, 2005 ....................................... Net loss for the three months ended September 30, 2005 ..................................... Cash flow hedges: Comprehensive pre-tax loss on cash flow hedges before reclassification adjustment during the three months ended September 30, 2005 ................ Reclassification adjustment for loss included in net loss for the three months ended September 30, 2005 ................................... Income tax provision for the three months ended September 30, 2005 ................................... Available-for-sale investments: Pre-tax loss on available-for-sale investments for the three months ended September 30, 2005 ............ Income tax benefit for the three months ended September 30, 2005 ................................... $ (628,820) =========== $ (270,259) =========== $ 2,749 =========== $ 215,390 =========== $ (52,120) =========== $ 277,055 (16,059) ----------51,182 51,182 1,774 ----------(2,749) (171,687) ----------- (2,749) (2,749) (171,687) ----------- (171,687) ----------$ (339,943) =========== Total comprehensive loss for the nine months ended September 30, 2005 ............................... Available-for-sale investments: Pre-tax gain on available-for-sale investments for the three months ended March 31, 2004 ................ Income tax provision for the three months ended March 31, 2004 ....................................... $ (968,763) =========== $ (219,077) =========== $ -=========== $ 43,703 =========== $ (175,374) =========== $ $ $ $ (130,419) -- (table continues) - 39 - 56,594 $ (71,192) 4,426 (7,224) ----------13,065 13,065 13,065 11,817 11,817 2,078 ----------- 2,078 ----------- 19,526 (7,709) ----------11,817 2,078 ----------- Total comprehensive loss for the three months ended March 31, 2004 ................................... Net loss for the three months ended June 30, 2004 ........ 187,013 15,863 Foreign currency translation gain for the three months ended March 31, 2004 .......................... Accumulated other comprehensive income (loss) at March 31, 2004 ...................................... 51,182 (4,523) Total comprehensive loss for the three months ended September 30, 2005 ............................... Accumulated other comprehensive income (loss) at January 1, 2004 ..................................... Net loss for the three months ended March 31, 2004 ....... Cash flow hedges: Comprehensive pre-tax gain on cash flow hedges before reclassification adjustment during the three months ended March 31, 2004 .................... Reclassification adjustment for loss included in net loss for the three months ended March 31, 2004 ....... Income tax provision for the three months ended March 31, 2004 ....................................... (216,689) (209,814) Foreign currency translation loss for the three months ended September 30, 2005 ...................... Accumulated other comprehensive income (loss) at September 30, 2005 .................................. (20,860) ----------- $ (44,232) =========== $ (117,354) =========== $ 11,817 =========== $ 189,091 =========== $ 83,554 =========== $ (28,698) Cash flow hedges: Comprehensive pre-tax loss on cash flow hedges before reclassification adjustment during the three months ended June 30, 2004 ....................... Reclassification adjustment for loss included in net loss for the three months ended June 30, 2004 .......... Income tax benefit for the three months ended June 30, 2004 .......................................... Available-for-sale investments: Pre-tax loss on available-for-sale investments for the three months ended June 30, 2004 ................... Income tax benefit for the three months ended June 30, 2004 .......................................... Cash Flow Hedges ----------- $ Availablefor-Sale Investments ----------- Foreign Currency Translation ----------- Total Accumulated Other Comprehensive Income (Loss) ------------- (54,414) 12,905 13,369 ----------(28,140) (28,140) (28,140) (11,960) (11,960) (21,399) ----------- (21,399) ----------- (19,762) 7,802 ----------(11,960) Foreign currency translation loss for the three months ended June 30, 2004 ............................. (21,399) ----------- Total comprehensive loss for the three months ended June 30, 2004 .................................... $ (90,197) =========== Total comprehensive loss for the six months ended June 30, 2004 .................................... Accumulated other comprehensive income (loss) at June 30, 2004 ....................................... Net income for the three months ended September 30, 2004 ..................................... Cash flow hedges: Comprehensive pre-tax loss on cash flow hedges before reclassification adjustment during the three months ended September 30, 2004 ................ Reclassification adjustment for loss included in net loss for the three months ended September 30, 2004 ................................... Income tax benefit for the three months ended September 30, 2004 ................................... Available-for-sale investments: Pre-tax gain on available-for-sale investments for the three months ended September 30, 2004 ............ Income tax provision for the three months ended September 30, 2004 ............................. $ (134,429) =========== $ (145,494) =========== $ (143) =========== $ 167,692 =========== $ 22,055 =========== $ $ 141,125 (76,611) 30,542 11,773 ----------(34,296) (34,296) (34,296) 6,183 (2,427) ----------3,756 Foreign currency translation gain for the three months ended September 30, 2004 ...................... 24,941 ----------- Total comprehensive income for the three months ended September 30, 2004 ............................... 3,756 3,756 24,941 ----------- 24,941 ----------$ 135,526 =========== Total comprehensive income for the nine months ended September 30, 2004 ............................... Accumulated other comprehensive income (loss) at September 30, 2004 .................................. Comprehensive Income (Loss) for the Three Months Ended March 31, 2005, June 30, 2005, and September 30, 2005 --------------- $ 1,097 =========== $ (179,790) =========== $ 3,613 =========== $ 192,633 =========== $ 16,456 =========== 11. Loss Per Share Basic loss per common share was computed by dividing net loss by the weighted average number of common shares outstanding for the respective periods. The dilutive effect of the potential exercise of outstanding options to purchase shares of common stock is calculated using the treasury stock method. The dilutive effect of the assumed conversion of certain convertible securities into the Company's common stock is based on the dilutive common share equivalents and the after tax distribution expense avoided upon conversion. The reconciliation of basic and diluted loss per common share is shown in the following table (in thousands, except per share data). - 40 - Periods Ended September 30, ----------------------------------------------------------------------------------2005 2004 ------------------------------------------------------------------------------Weighted Weighted Net Income Average Average (Loss) Shares EPS Net Income Shares EPS --------------------------------------------------------------- THREE MONTHS: Basic earnings (loss) per common share: Income (loss) before discontinued operations and cumulative effect of a change in accounting principle......................... $ (242,435) Discontinued operations, net of tax........... 25,746 -----------Net income (loss)......................... $ (216,689) ============ Diluted earnings (loss) per common share: Common shares issuable upon exercise of stock options using treasury stock method.......... Income (loss) before discontinued operations and cumulative effect of a change in accounting principle......................... $ (242,435) Discontinued operations, net of tax........... 25,746 -----------Net income (loss)......................... $ (216,689) ============ 478,461 ---------478,461 ========= $ (0.51) 0.06 ----------$ (0.45) =========== $ 28,877 112,248 ----------$ 141,125 =========== -478,461 ---------478,461 ========= 444,380 --------444,380 ======== $ 0.07 0.25 ---------$ 0.32 ========== 2,542 $ (0.51) 0.06 ----------$ (0.45) =========== $ 28,877 112,248 ----------$ 141,125 =========== 446,922 $ --------446,922 $ ======== 0.07 0.25 ---------0.32 ========== Periods Ended September 30, ----------------------------------------------------------------------------------2005 2004 ------------------------------------------------------------------------------Net Loss Shares EPS Net Loss Shares EPS --------------------------------------------------------------- NINE MONTHS: Basic and diluted loss per common share: Loss before discontinued operations........... $ (621,476) Discontinued operations, net of tax........... (62,403) -----------Net income (loss)......................... $ (683,879) ============ 458,483 ---------458,483 ========= $ (1.36) (0.13) ----------$ (1.49) =========== $ (194,475) 235,710 ----------$ 41,235 =========== 425,682 --------425,682 ======== $ (0.45) 0.55 ---------$ 0.10 ========== The Company incurred losses before discontinued operations for the quarters ended September 30, 2005 and 2004. As a result, basic shares were used in the calculations of fully diluted loss per share for these periods, under the guidelines of SFAS No. 128 as using the basic shares produced the more dilutive effect on the loss per share. Potentially convertible securities, shares to be purchased under the Company's ESPP and unexercised employee stock options to purchase a weighted average of 7.7 million and 55.1 million shares of the Company's common stock were not included in the computation of diluted shares outstanding during the nine months ended September 30, 2005 and 2004, respectively, because such inclusion would be antidilutive. For the three and nine months ended September 30, 2005 and 2004, approximately 0.1 million and 4.0 million, respectively, weighted common shares of the Company's outstanding 2006 Convertible Notes, respectively, were excluded from the diluted EPS calculations as the inclusion of such shares would have been antidilutive. In connection with the convertible debentures payable to Calpine Capital Trust III, net of repurchases, for the three months ended September 30, 2005 and 2004, and the nine months ended September 30, 2005 and 2004, there were 0.0 million, 11.9 million, 6.1 million and 11.9 million weighted average common shares potentially issuable, respectively, that were excluded from the diluted EPS calculation as their inclusion would be antidilutive. The convertible debentures were redeemed in full on July 13, 2005. For the three and nine months ended September 30, 2005 and 2004, under the net share settlement method and in accordance with the new guidance of EITF 04-08 there were no shares potentially issuable and thus potentially included in the diluted EPS calculation under the Company's 2023 Convertible Notes, 2014 Convertible Notes and 2015 Convertible Notes issued in November 2003, September 2004 and June 2005, respectively, because the Company's closing stock price at each period end was below the conversion price. However, in future reporting periods where the Company's closing stock price is above the conversion price for any of these convertible instruments and the Company has income before discontinued operations and cumulative effect of a change in accounting principle, the holders of each note will receive the conversion value of the note payable in cash up to the principal amount of the note, and Calpine common stock for the notes conversion value in excess of such princpal amount.The - 41 - maximum potential shares issuable under the conversion provisions of the notes would be as presented below. The actual number of potential shares will depend on the closing stock price at conversion. o 2023 Convertible Notes -- If the Company's closing stock price is above the instrument's conversion price of $6.50, a maximum of approximately 97.5 million shares would be included (if dilutive) in the diluted EPS calculation; o 2014 Convertible Notes -- If the Company's closing stock price is above the instrument's conversion price of $3.85, a maximum of approximately 166.7 million shares would be included (if dilutive) in the diluted EPS calculation; o 2015 Convertible Notes -- If the Company's closing stock price is above the instrument's conversion price of $4.00, a maximum of approximately 163.0 million shares would be included (if dilutive) in the diluted EPS calculation; For the three and nine months ended September 30, 2005, 1.2 million weighted average common shares of the Company's contingently issuable (unvested) restricted stock was excluded from the calculation of diluted EPS because the Company's closing stock price has not reached the price at which the shares vest, and, as discussed above, inclusion would have been anti-dilutive. In conjunction with the offering of the 2014 Convertible Notes in September 2004, the Company entered into a ten-year Share Lending Agreement with DB London, under which the Company loaned DB London 89 million shares of newly issued Calpine common stock in exchange for a loan fee of $.001 per share and other consideration. The Company has excluded the 89 million shares of common stock subject to the Share Lending Agreement from the EPS calculation. See Note 2 for a discussion of the potential impact of SFAS No. 128-R on the calculation of diluted EPS. 12. Commitments and Contingencies LTSA Cancellations On July 5, 2005, Calpine and Siemens-Westinghouse executed an agreement to settle various matters related to certain warranty disputes and to terminate certain LTSAs. The Company received approximately $25.5 million as a net settlement payment related to these matters, a portion of which related to events in existence prior to June 30, 2005. Consequently, $3.6 million and $7.2 million were recorded in the three months ended June 30, 2005, and September 30, 2005, respectively, as a reduction in plant operating expense relating to warranty recoveries and contract settlements of prior period repair expenses. The remaining settlement proceeds were applied as a reduction to capitalized turbine costs in the three months ended September 30, 2005. On July 7, 2005, the Company announced that it had entered into a 15-year Master Products and Services Agreement with GE. A related agreement replaces the nine remaining LTSAs covering the Company's GE 7FA turbine fleet. The Company expects to benefit from improved power plant performance and operations and maintenance flexibility to service its plants to further lower costs. Historically, GE provided full-service turbine maintenance for a select number of Calpine power plants. Under the new agreement, Calpine will supplement its operations with a variety of GE services. As of September 30, 2005, the Company operates 44 power plants that are powered by GE gas turbines, representing approximately 10,000 MW of capacity. The Company recorded LTSA cancellation expense of $33.3 million in the three months ended June 30, 2005, as the key terms and provisions of the cancellation agreement were finalized prior to June 30, 2005. Turbines The table below sets forth future turbine payments for construction and development projects, as well as for unassigned turbines. It includes previously delivered turbines, payments and delivery by year for the last turbine to be delivered as well as payment required for the potential cancellation costs of the remaining 28 gas and steam turbines. The table does not include payments that would result if the Company were to release for manufacturing any of these remaining 28 turbines. Year -------------------------------------October through December 2005................ 2006......................................... 2007......................................... 2008......................................... Total...................................... - 42 - Units to Be Total Delivered -------------------(In thousands) $ 11,220 1 4,480 -2,332 -2,699 -------------$ 20,731 1 ========== ==== Litigation The Company is party to various litigation matters arising out of the normal course of business, the more significant of which are summarized below. The ultimate outcome of each of these matters cannot presently be determined, nor can the liability that could potentially result from a negative outcome be reasonably estimated presently for every case. The liability the Company may ultimately incur with respect to any one of these matters in the event of a negative outcome may be in excess of amounts currently accrued with respect to such matters and, as a result of these matters, may potentially be material to the Company's Consolidated Financial Statements. Securities Class Action Lawsuits. Beginning on March 11, 2002, fifteen securities class action complaints were filed in the U.S. District Court for the Northern District of California against Calpine and certain of its employees, officers, and directors. All of these actions were ultimately assigned to Judge Saundra Brown Armstrong, and Judge Armstrong ordered the actions consolidated for all purposes on August 16, 2002, as In re Calpine Corp. Securities Litigation, Master File No. C 02-1200 SBA. In mid-October, 2005, an agreement in principle to settle this case was reached. The proposed settlement will resolve the only claim remaining in these consolidated actions, which is a claim by two plaintiffs for an alleged violation of Section 11 of the Securities Act of 1933. All of the other claims brought in the consolidated actions were dismissed with prejudice in February 2004. Judge Armstrong denied the motion for class certification on August 10, 2005. The settlement amount is being paid by insurance. The Company currently expects the settlement to be finalized before the end of 2005. Hawaii Structural Ironworkers Pension Fund v. Calpine, et al. This case is a Section 11 case brought as a class action on behalf of purchasers in Calpine's April 2002 stock offering. This case was filed in San Diego County Superior Court on March 11, 2003. Defendants won a motion to transfer the case to Santa Clara County. Defendants in this case are Calpine, Peter Cartwright, Ann B. Curtis, John Wilson, Kenneth Derr, George Stathakis, Credit Suisse First Boston, Banc of America Securities, Deutsche Bank Securities, and Goldman, Sachs & Co. The Hawaii Fund alleges that the prospectus and registration statement for the April 2002 offering had false or misleading statements regarding: Calpine's actual financial results for 2000 and 2001; Calpine's projected financial results for 2002; Mr. Cartwright's agreement not to sell or purchase shares within 90 days of the offering; and Calpine's alleged involvement in "wash trades." A central allegation of the complaint is that a March 2003 restatement concerning the accounting for two sales-leaseback transactions revealed that Calpine had misrepresented its financial results in the prospectus/registration statement for the April 2002 offering. There is no trial date in this action. The next scheduled court hearing will be a case management conference on January 10, 2006, at which time the court may set a trial date. We consider this lawsuit to be without merit and intend to continue to defend vigorously against the allegations. Phelps v. Calpine Corporation, et al. On April 17, 2003, James Phelps filed a class action complaint in the Northern District of California, alleging claims under the ERISA. On May 19, 2003, a nearly identical class action complaint was filed in the Northern District by Lenette Poor-Herena. The parties agreed to have both of the ERISA actions assigned to Judge Armstrong, who oversees the above-described federal securities class action and the Gordon derivative action (see below). On August 20, 2003, pursuant to an agreement between the parties, Judge Armstrong ordered that the two ERISA actions be consolidated under the caption, In re Calpine Corp. ERISA Litig., Master File No. C 03-1685 SBA (the "ERISA Class Action"). Plaintiff James Phelps filed a consolidated ERISA complaint on January 20, 2004 ("Consolidated Complaint"). Ms. Poor-Herena is not identified as a plaintiff in the Consolidated Complaint. The Consolidated Complaint defines the class as all participants in, and beneficiaries of, the Plan for whose accounts investments were made in Calpine stock during the period from January 5, 2001 to the present. The Consolidated Complaint names as defendants Calpine, the members of its Board of Directors, the Plan's Advisory Committee and its members (Kati Miller, Lisa Bodensteiner, Rick Barraza, Tom Glymph, Patrick Price, Trevor Thor, Bob McCaffrey, and Bryan Bertacchi), signatories of the Plan's Annual Return/Report of Employee Benefit Plan Forms 5500 for 2001 and 2002 (Pamela J. Norley and Marybeth Kramer-Johnson, respectively), an employee of a consulting firm hired by the Plan (Scott Farris), and unidentified fiduciary defendants. The Consolidated Complaint alleges that defendants breached their fiduciary duties involving the Plan, in violation of ERISA, by misrepresenting Calpine's actual financial results and earnings projections, failing to disclose certain transactions between Calpine and Enron that allegedly inflated Calpine's revenues, failing to disclose that the shortage of power in California during 2000-2001 was due to withholding of capacity by certain power companies, failing to investigate whether Calpine common stock was an appropriate investment for the Plan, and failing to take appropriate actions to prevent losses to the Plan. In addition, the Consolidated Complaint alleges that certain of the individual defendants suffered from conflicts of interest due to their sales of Calpine stock during the class period. - 43 - Defendants moved to dismiss the Consolidated Complaint. Judge Armstrong granted the motion and dismissed three of the four claims with prejudice. The remaining claim, for misrepresentation, was dismissed with leave to amend. Plaintiff filed an Amended Consolidated Complaint on June 3, 2005. The Amended Consolidated Complaint names as defendants Calpine Corporation and the members of the Advisory Committee for the Plan. Defendants have filed motions to dismiss the Amended Consolidated Complaint, which are currently scheduled for hearing on December 6, 2005. We consider this lawsuit to be without merit and intend to continue to defend vigorously against the allegations. Johnson v. Peter Cartwright, et al. On December 17, 2001, a shareholder filed a derivative lawsuit on behalf of Calpine against its directors and one of its senior officers. This lawsuit is styled Johnson vs. Cartwright, et al. (No. CV803872) and is pending in California Superior Court in Santa Clara County, California. 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. In December 2002, the court dismissed the complaint with respect to certain of the director defendants for lack of personal jurisdiction, though plaintiff may appeal this ruling. In early February 2003, plaintiff filed an amended complaint, naming additional officer defendants. Calpine and the individual defendants filed demurrers (motions to dismiss) and a motion to stay the case in March 2003. On July 1, 2003, the Court granted Calpine's motion to stay this proceeding until In re Calpine Corporation Securities Litigation is resolved, or until further order of the Court. The Court did not rule on the demurrers. We consider this lawsuit to be without merit and intend to defend vigorously against the allegations if the stay is lifted. Gordon v. Peter Cartwright, et al. On August 8, 2002, a shareholder filed a derivative suit in the United States District Court for the Northern District of California on behalf of Calpine against its directors, captioned Gordon v. Cartwright, et al. similar to Johnson v. Cartwright. Motions were filed to dismiss the action against certain of the director defendants on the grounds of lack of personal jurisdiction, as well as to dismiss the complaint in total on other grounds. In February 2003, plaintiff agreed to stay these proceedings until In re Calpine Corporation Securities Litigation is resolved, and to dismiss without prejudice certain director defendants. The Court did not rule on the motions to dismiss the complaint on non-jurisdictional grounds. On March 4, 2003, plaintiff filed papers with the court voluntarily agreeing to dismiss without prejudice his claims against three of the outside directors. We consider this lawsuit to be without merit and intend to defend vigorously against the allegations if the stay is lifted. International Paper Company v. Androscoggin Energy LLC. In October 2000, International Paper Company filed a complaint against Androscoggin Energy LLC ("AELLC") alleging that AELLC breached certain contractual representations and warranties arising out of an Amended Energy Services Agreement ("ESA") by failing to disclose facts surrounding the termination, effective May 8, 1998, of one of AELLC's fixed-cost gas supply agreements. The steam price paid by IP under the ESA is derived from AELLC's price of gas under its gas supply agreements. We had acquired a 32.3% economic interest and a 49.5% voting interest in AELLC as part of the Skygen transaction, which closed in October 2000. On November 7, 2002, the court issued an opinion on the parties' cross motions for summary judgment finding in AELLC's favor on certain matters though granting summary judgment to International Paper Company on the liability aspect of a particular claim against AELLC. On December 11, 2003, the court denied in part IP's summary judgment motion pertaining to damages and determined that, (i) IP was entitled to pursue an action for damages, and (ii) ruled that sufficient questions of fact remain to deny IP summary judgment on the measure of damages. On November 3, 2004, a jury verdict in the amount of $41 million was rendered in favor of IP. AELLC was held liable on the misrepresentation claim, but not on the breach of contract claim. AELLC has made an additional accrual to recognize the jury verdict, and the Company has recognized its 32.3% share. AELLC filed a post-trial motion challenging both the determination of its liability and the damages award and, on November 16, 2004, the court entered an order staying the execution of the judgment. The order staying execution of the judgment has not expired. On September 30, 2005, the district court denied AELLC's Motion for Judgment as a Matter of Law, or, in the Alternative, Remittitur or a New Trial. AELLC intends to appeal the judgment. Additionally, on November 26, 2004, AELLC filed a voluntary petition for relief under Chapter 11 of the Bankruptcy Code. AELLC is continuing in possession of its property and is operating and maintaining its business as a debtor in possession, pursuant to Section 1107(a) and 1108 of the Bankruptcy Code. AELLC filed its, (i) Plan of Reorganization, and (ii) Disclosure Statement regarding such plan, on September 30, 2005. Finally, AELLC filed a Demand for Arbitration on July 8, 2005, seeking damages from IP regarding three separate ESA billing disputes. IP filed its Answering Statement and Counterclaim on July 29, 2005. The parties are in the preliminary stages of the AAA arbitration procedures. - 44 - Panda Energy International, Inc., et al. v. Calpine Corporation, et al. On November 5, 2003, Panda Energy International, Inc. and certain related parties, including PLC II, LLC, (collectively "Panda") filed suit against the Company and certain of its affiliates alleging, among other things, that the Company breached duties of care and loyalty allegedly owed to Panda by failing to correctly construct and operate the Oneta power plant, which the Company acquired from Panda, in accordance with Panda's original plans. Panda alleges that it is entitled to a portion of the profits of the Oneta plant and that the Company's actions have reduced the profits from Oneta thereby undermining Panda's ability to repay monies owed to the Company on December 1, 2003, under a promissory note on which approximately $38.6 million (including interest) is currently outstanding. The Company has filed a counterclaim against Panda Energy International, Inc. (and PLC II, LLC) based on a guaranty, and has also filed a motion to dismiss as to the causes of action alleging federal and state securities laws violations. The court recently granted the Company's motion to dismiss the above claims, but allowed Panda an opportunity to replead. We consider Panda's lawsuit to be without merit and intend to vigorously defend it. Discovery is currently in progress. The Company stopped accruing interest income on the promissory note due December 1, 2003, as of the due date because of Panda's default on repayment of the note. Trial is currently set for May 22, 2006. California Business & Professions Code Section 17200 Cases, of which the lead case is T&E Pastorino Nursery v. Duke Energy Trading and Marketing, L.L.C., et al. This purported class action complaint filed in May 2002 against 20 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 was also named in eight other similar complaints for violations of Section 17200. The Company considered the allegations to be without merit, and filed a motion to dismiss. The court granted the motion, and plaintiffs appealed. The Ninth Circuit has issued a decision affirming the dismissal of the Pastorino group of cases. The Plaintiff's did not attempt to appeal the Ninth Circuit's ruling to the Supreme Court so the matter is resolved. Prior to the motion to dismiss being granted, one of the actions, captioned Millar v. Allegheny Energy Supply Co., LLP, et al., was remanded to state superior court of Alameda County, California. On January 12, 2004, CES was added as a defendant in Millar. This action includes similar allegations to the other Section 17200 cases, but also seeks rescission of the long-term power contracts with the California Department of Water Resources. Millar was removed to federal court, but has now been remanded back to state superior court for handling. Hearings on multiple demurrers were held on September 7, 2005 at which time, the Judge dismissed the case without leave to amend. Millar did not attempt to appeal the dismissal ruling. Thus, the entire case is now resolved. Nevada Power Company and Sierra Pacific Power Company v. Calpine Energy Services, L.P. before the FERC, filed on December 4, 2001, Nevada Section 206 Complaint. On December 4, 2001, NPC and SPPC filed a complaint with 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, 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 spot power market was dysfunctional and that they are unjust and unreasonable. The complaint therefore sought modification of the contract prices. The administrative law judge issued an Initial Decision on December 19, 2002, that found for Calpine and the other respondents in the case and denied NPC and SPPC the relief that they were seeking. In a June 26, 2003 order, FERC affirmed the judge's findings and dismissed the complaint, and subsequently denied rehearing of that order. The matter is pending on appeal before the United States Court of Appeals for the Ninth Circuit. The Company has participated in briefing and arguments before the Ninth Circuit defending the FERC orders, but the Company is not able to predict at this time the outcome of the Ninth Circuit appeal. Transmission Service Agreement with Nevada Power Company. On September 30, 2004, Nevada Power Company ("NPC") filed a complaint in state district court of Clark County, Nevada against Calpine Corporation ("Calpine"), Moapa Energy Center, LLC, Fireman's Fund Insurance Company ("FFIC") and unnamed parties alleging, among other things, breach by Calpine of its obligations under a Transmission Service Agreement ("TSA") between Calpine and NPC for 400 megawatts of transmission capacity and breach by FFIC of its obligations under a surety bond, which surety bond was issued by FFIC to NPC to support Calpine's obligations under the TSA. This proceeding was removed from state court to United States District Court for the District of Nevada. On December 10, 2004, FFIC filed a Motion to Dismiss, which was granted on May 25, 2005 with respect to claims asserted by NPC that FFIC had breached its obligations under the surety bond by not honoring NPC's demand that the full amount of the surety bond ($33,333,333.00) be paid to NPC in light of Calpine's failure to provide replacement collateral upon the expiration of the surety bond on May 1, 2004. NPC has filed a Motion to Amend the Complaint and a Motion for Reconsideration of the above dismissal. The above dismissal is specific to NPC's claims against FFIC and does not address NPC's specific claims against Calpine or Moapa Energy Center, LLC. Discovery is proceeding. At this time, Calpine is unable to predict the outcome of this proceeding. - 45 - Calpine Canada Natural Gas Partnership v. Enron Canada Corp. On February 6, 2002, Calpine Canada filed a complaint in the Alberta Court of Queens Branch alleging that Enron Canada owed it approximately US$1.5 million from the sale of gas in connection with two Master Firm gas Purchase and Sale Agreements. To date, Enron Canada has not sought bankruptcy relief and has counterclaimed in the amount of US$18 million. We have finished discovery and are currently in settlement discussions. The Company believes that Enron Canada's counterclaim is without merit and intends to vigorously defend against it. Estate of Jones, et al. v. Calpine Corporation. On June 11, 2003, the Estate of Darrell Jones and the Estate of Cynthia Jones filed a complaint against Calpine in the United States District Court for the Western District of Washington. Calpine purchased Goldendale Energy, Inc., a Washington corporation, from Mr. Darrell Jones of NESCO. The agreement provided, among other things, that upon "Substantial Completion" of the Goldendale facility, Calpine would pay Mr. Jones (i) $6.0 million and (ii) $18.0 million less $0.2 million per day for each day that elapsed between July 1, 2002, and the date of substantial completion. Substantial completion of the Goldendale facility occurred in September 2004 and the daily reduction in the payment amount has reduced the $18.0 million payment to zero. The complaint alleged that by not achieving substantial completion by July 1, 2002, Calpine breached its contract with Mr. Jones, violated a duty of good faith and fair dealing, and caused an inequitable forfeiture. On July 28, 2003, Calpine filed a motion to dismiss the complaint for failure to state a claim upon which relief can be granted. The court granted Calpine's motion to dismiss the complaint on March 10, 2004. Plaintiffs filed a motion for reconsideration of the decision, which was denied. Subsequently, on June 7, 2004, plaintiffs filed a notice of appeal. Calpine filed a motion to recover attorneys' fees from NESCO, which was recently granted at a reduced amount. Calpine held back $100,000 of the $6 million payment to the estates (which has been remitted) to ensure payment of these fees. The matter is currently on appeal, both parties have filed briefs with the appellate court, and oral arguments were heard by the court on October 17, 2005. We are waiting for the court to issue its decision. Calpine Energy Services v. Acadia Power Partners. Calpine Corporation, through its subsidiaries, owns 50% of Acadia Power Partners, LLC ("APP") which company owns the Acadia Energy Center near Eunice, Louisiana (the "Facility"). A Cleco Corporation subsidiary owns the other 50% of the Facility. Calpine Energy Services, LP ("CES") is the purchaser under two power purchase agreements with APP pursuant to which CES has the right to purchase all of the output from the Facility. During the summer of 2003 certain transmission constraints previously unknown to CES and APP began to severely limit the ability of CES to obtain all of the energy from the Facility. CES had asserted that it is entitled to certain relief from the purchase agreements, and that APP had to cure certain defaults under the purchase agreements, to which assertions APP disagrees. After engaging in the initial alternative dispute resolution steps set forth in the power purchase agreements the parties settled their disputes. In addition, CES and APP had been discussing certain billing calculation disputes that relate to efficiency matters. The dispute covers the time period from June 2002 (COD of the plant) to June 2004. The parties have completely resolved this matter. Hulsey, et al. v. Calpine Corporation. On September 20, 2004, Virgil D. Hulsey, Jr. (a current employee) and Ray Wesley (a former employee) filed a class action wage and hour lawsuit against Calpine Corporation and certain of its affiliates. The complaint alleges that the purported class members were entitled to overtime pay and Calpine failed to pay the purported class members at legally required overtime rates. The matter has been transferred to the Santa Clara County Superior Court and Calpine filed an answer on January 7, 2005, denying plaintiffs' claims. This case has tentatively been settled. Michael Portis v. Calpine Corp. - Complaint Filed with Department of Labor. On January 25, 2005, Michael Portis ("Portis"), a former employee of Calpine, brought a complaint to the United States Department of Labor (the "DOL"), alleging that his employment with the Company was wrongfully terminated. Portis alleged that Calpine and its subsidiaries evaded sales and use tax in various states and in doing so filed false tax reports and that his employment was terminated in retaliation for having reported these allegations to management. Portis claimed that the Company's alleged actions constitute violations of the employee protection provisions of the Sarbanes Oxley Act of 2002. On April 27, 2005, the DOL determined that Portis' retaliatory discharge complaint had no merit and dismissed it. On June 13, 2005, Portis filed an objection and requested a hearing before an Administrative Law Judge. After an initial hearing with the ALJ, and a failed attempt to elicit a settlement, Portis withdrew the objection and hearing request. On August 12, 2005, the DOL's initial finding (that the complaint had no merit) was reinstated and made final. Auburndale Power Partners and Cutrale. Calpine Corporation owns an interest in the Auburndale PP cogeneration facility, which provides steam to Cutrale, a juice company. The Auburndale PP facility currently operates on a "cycling" basis whereby the plant operates only a portion of the day. During the hours that the Auburndale PP facility is not operating, Auburndale PP does not provide steam to Cutrale. Cutrale has filed an arbitration claim alleging that they are - 46 - entitled to damages due to Auburndale PP's failure to provide them with steam 24 hours a day. Auburndale PP disagreed with Cutrale's position based on its interpretation of the contractual language in the Steam Supply Agreement. Binding arbitration was conducted on the contractual interpretation issue only (reserving the remedy/damage issue for a second phase to the arbitration) and the arbitrator found in favor of Cutrale's contractual interpretation. The proceeding now turns to the second phase, the resolution of the issue regarding the appropriate remedy/damage determination. To preserve our positive relationship with Cutrale, Auburndale PP continues to try to resolve the matter through a commercial settlement. Harbert Distressed Investment Master Fund, Ltd. v. Calpine Canada Energy Finance II ULC, et al. On May 5, 2005, Harbert Distressed Investment Master Fund, Ltd. (the "Harbert Fund") filed an Originating Notice (Application) (the "Original Application") in the Supreme Court of Nova Scotia against Calpine Corporation and certain of its subsidiaries, including Calpine Canada Energy Finance II ULC ("Finance II"), the issuer of certain bonds (the "Bonds") held by the Harbert Fund and CCRC, the parent company of Finance II and the indirect parent company of Saltend. The Bonds have been guaranteed by Calpine. The Harbert Fund alleged that Calpine, CCRC and Finance II violated the Harbert Fund's rights under Nova Scotia laws in connection with certain financing transactions completed by CCRC or subsidiaries of CCRC. Wilmington Trust Company, the trustee under the indenture governing the Bonds (the "Trustee"), was a co-applicant in the suit on behalf of all holders of Bonds. The hearing was conducted on July 6, 7 and 8, 2005 before the Nova Scotia Supreme Court. The claims as against Calpine European Funding (Jersey) Limited and Calpine (Jersey) Limited, were discontinued by Consent Order dated July 20, 2005, On August 2, 2005, the Court dismissed the Harbert Fund's application for relief and denied all relief to the Harbert Fund and all other bondholders that purchased Bonds on or after September 1, 2004. However, the Court stated that a remedy should be granted to any bondholder, other than the Calpine respondent companies, that purchased Bonds prior to September 1, 2004 and that continues to hold those Bonds on August 2, 2005 (the "Eligible Bondholders"). The Court directed the Trustee to provide the face amount of qualifying Bonds and the identity of the holders of such Bonds by August 31, 2005 (subsequently modified by the Bond Indemnification Order described below). Upon receipt of such information, the Court will then issue a final order requiring Calpine to maintain in the control of CCRC sufficient proceeds from the sale of Saltend to cover the face amount of such Bonds. If there are insufficient proceeds for this purpose, Calpine will be required to place in the control of CCRC an additional amount which, when added to the net Saltend sale proceeds, will cover the face value of all such Bonds. On September 20, 2005, the Court issued a Bond Identification Order confirming a process for determining the list of Eligible Bondholders and further required the Indenture Trustee to file a report of such determination on or before November 18, 2005. The final order will further provide that CCRC shall diligently conduct its business in a proper and efficient manner so as to preserve and protect its business and assets. Pending the final order, the Court issued an interim order under which Calpine must maintain the net Saltend sale proceeds in the control of CCRC. Any party to the proceeding has the right to appeal the final order to the Nova Scotia Court of Appeal. On October 6, 2005, the Trustee and the Harbert Fund issued a demand letter to Finance II and its directors demanding that Finance II commence proceedings against CCRC to enforce various rights under a Term Debenture due 2021 issued by CCRC to Finance II. On October 7, 2005, the Trustee and the Harbert Fund filed an Originating Notice (Application) in the Supreme Court of Nova Scotia against CCRC and sought leave to commence a derivative proceeding on behalf of Finance II (the "Harbert/WTC Leave Application") seeking to enforce such rights under the Term Debenture. On October 11, 2005, Finance II and CCRC filed an Interlocutory Notice Application seeking either a dismissal of the Harbert/WTC Leave Application or, alternatively, a stay of such pending the completion of the process set out in the Bond Identification Order, issuance of a final order in the Original Application and disposition of any appeals in the Original Application ("Calpine Cross-Application") on the bases of res judicata and abuse of process, arguing that the claims and relief sought by the applicants in the Harbert/WTC Leave Application are the same, or arise out of the same facts and circumstances, as the claims and relief that those applicants sought, and were denied, in the Original Application. The Calpine Cross-Application is scheduled to be heard as a preliminary application on November 22 and 23, 2005. The final order in the Original Application, as well as the Harbert/WTC Leave Application (if necessary), are scheduled to be heard on December 19 and 20, 2005. Harbert Convertible Arbitrage Master Fund, Ltd. et al. v. Calpine Corporation. Plaintiff Harbert Convertible Arbitrage Master Fund, Ltd. and two affiliated funds filed this action on July 11, 2005, in Supreme Court, New York County, State of New York, and filed an amended complaint on July 19, 2005. In their amended complaint, plaintiffs allege that in a July 5, 2005 letter to Calpine they provided "reasonable evidence" as required under the indenture governing the 2014 Convertible Notes that, on one or more days beginning on July 1, 2005, the Trading Price of the 2014 Convertible Notes was less than 95% of - 47 - the product of the Common Stock Price multiplied by the Conversion Rate, as those terms are defined in the indenture, and that Calpine therefore was required to instruct the Bid Solicitation Agent for the 2014 Convertible Notes to determine the Trading Price beginning on the next Trading Day. If the Trading Price as determined by the Bid Solicitation Agent were below 95% of the product of the Common Stock Price multiplied by the Conversion Rate for the next five consecutive Trading Days, then the 2014 Convertible Notes would become convertible into cash and common stock for a limited period of time. Plaintiffs have asserted a claim for breach of contract, seeking unspecified damages, based on Calpine's not instructing the Bid Solicitation Agent to begin to calculate the Trading Price. In addition, plaintiffs have sought a declaration that Calpine had a duty, based on the statements in the July 5 letter, to commence the bid solicitation process, and also have sought injunctive relief to force Calpine to instruct the Bid Solicitation Agent to determine the Trading Price of the Notes. Plaintiffs made, but later withdrew, a request for a preliminary injunction. Calpine's motion to dismiss was served on September 6, 2005, opposition and reply papers were subsequently served, and the Court has scheduled argument on the motion for November 9, 2005. Harbert has informed Calpine and the court that Wilmington Trust Company, as trustee under the indenture for the 2014 Convertible Notes, intends to seek to intervene in the case and/or to file a similar action for the benefit of all holders of the 2014 Convertible Notes. Whitebox Convertible Arbitrage Fund, L.P., et al. v. Calpine Corporation. Plaintiff Whitebox Convertible Arbitrage Fund, L.P. and seven affiliated funds filed an action in the Supreme Court, New York County, State of New York, for breach of contract on October 17, 2004. The factual allegations and legal basis for the claims set forth in that action are nearly identical to those set forth in the Harbert Convertible filings detailed above. On October 19, 2005, plaintiffs filed a motion for preliminary injunctive relief, but withdrew the motion on November 7, 2005. Whitebox has informed Calpine and the court that Wilmington Trust Company, as trustee under the indenture for the 2014 Convertible Notes, intends to seek to intervene in the case and/or to file a similar action for the benefit of all holders of the 2014 Convertible Notes. SEC Informal Inquiry and Request for Documents and Information. On June 9, 2005, the Company filed a Current Report on Form 8-K with the SEC to disclose that, in April 2005, the Division of Enforcement of the SEC informed the Company that it was conducting an informal inquiry and asked the Company to voluntarily provide documents and information related to: (a) the Company's downward revision of its proved oil and gas reserve estimates at year-end 2004 as compared to such estimates at year-end 2003, and a corresponding impairment of the value of certain assets, all previously disclosed by the Company, (b) certain statements made to various regulatory agencies by Michael Portis, a terminated former employee, regarding the Company's determination of state sales and use taxes, and (c) the Company's upward restatement in April 2005 of its previously disclosed net income for the third quarter, and the first three quarters, of 2004. The Company fully cooperated with the SEC's request for documents and information. Calpine Corporation v. The Bank of New York, Collateral Trustee for Senior Secured Note Holders, et al. In September of 2005, Calpine received a letter from The Bank of New York, the Collateral Trustee (the "Collateral Trustee") for Calpine's senior secured debt holders, informing Calpine of disagreements purportedly raised by certain holders of First Priority Notes regarding the Company's reinvestment of the proceeds from its recent sale of natural gas assets to Rosetta. As a result of these concerns, the Collateral Trustee informed the Company that it would not allow further withdrawals from the gas sale proceeds account until these disagreements are resolved. On September 26, 2005, Calpine filed a Declaratory Relief Action in the Delaware Court of Chancery against the Collateral Trustee and Wilmington Trust Company, as trustee for the First Priority Notes (the "First Priority Trustee"), seeking a declaration that Calpine's past and proposed purchases of natural gas assets are permitted by the indenture for the First Priority Notes and related documents, and also seeking an injunction compelling the Collateral Trustee to release funds requested to be withdrawn. The First Priority Trustee has counterclaimed, seeking an order compelling the Company to, among other things, (i) pay damages in an amount not less than $365 million plus prejudgment interest either to the First Priority Trustee or into the gas sale proceeds account; (ii) return to the gas sale proceeds account all amounts previously withdrawn from such account and used by the Company to purchase natural gas in storage; and (iii) indemnify the First Priority Trustee for all expenses incurred in connection with defending the lawsuit and pursuing counterclaims. The Company has filed a motion to dismiss the counterclaims on the grounds that the holders of the First Priority Notes (and the First Priority Trustee on behalf of the holders of the First Priority Notes) have no right under the indenture governing the First Priority Notes to compel the return of such amounts or otherwise to object to the use of the proceeds of the gas sale because the Company made an offer to purchase all of the First Priority Notes with the proceeds of the gas sale and the holders of the First Priority Notes declined such offer. In addition, Wilmington Trust Company, as trustee for the Second Priority Notes (the "Second Priority Trustee"), has intervened in the lawsuit. The Second Priority Trustee has - 48 - counterclaimed seeking to compel the Company to return to the gas sale proceeds account all amounts previously withdrawn therefrom and used by the Company to purchase gas in storage. In its trial brief, the Company plans to request that these counterclaims be dismissed on the bases that they were filed after the deadline and without the Court's permission. Discovery in this lawsuit commenced on a fast track and is near completion. Pre-trial submissions were filed with the Court on November 7, 2005 and a bench trial is scheduled to begin on November 11, 2005. The Company expects that the trial will be completed in one day and that the Court will issue an opinion shortly thereafter. The Company maintains that its use of the proceeds of the natural gas sale to purchase natural gas in storage was appropriate and permitted under the instruments governing its senior secured debt, including the indenture governing the First Priority Notes and the Senior Secured Debt Instruments, however, no assurance can be given that the Company will prevail in this litigation. Scott, et al. v. Calpine Corporation. On September 13, 2005, Calpine received a letter from an attorney representing one current and six former employees located in the Houston, Texas office. The letter alleges claims of racial discrimination, retaliation, slander, a hostile work environment and constructive discharge. The seven individuals have also filed Notices of Charge of Discrimination with the U.S. Equal Employment Opportunity Commission. Outside counsel has been retained and has investigated the claims in anticipation of threatened litigation. We consider these claims to be without merit and intend to defend vigorously against the allegations. In addition, 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 its financial position or results of operations. 13. Operating Segments The Company is first and foremost an electric generating company. In pursuing this business strategy, it was the Company's objective to produce a portion of its fuel consumption requirements from its own natural gas reserves ("equity gas"). However, with the July 2005 sale of the Company's remaining oil and gas production and marketing activity, the Company now has one reportable segment, Electric Generation and Marketing. No other components of the business had reached the quantitative criteria to be considered a reportable segment under SFAS No. 131. See Note 8 for a discussion of the sale of the Company's oil and gas assets. Consequently, the revenue and expense from the Oil and Gas Production and Marketing reportable segment has been reclassified to discontinued operations and the remaining pipeline assets have been reflected in the table below within Corporate, Eliminations, and Other. Electric Generation and Marketing includes the development, acquisition, ownership and operation of power production facilities, hedging, balancing, optimization, and trading activity transacted on behalf of the Company's power generation facilities. Corporate and other activities necessary to support the Electric Generation and Marketing reporting segment consists primarily of financing transactions, activities of the Company's parts and services businesses, and general and administrative costs. For the three months ended September 30, Total revenue from external customers.................. Segment profit/(loss) before provision for income taxes.......................................... For the nine months ended September 30, Total revenue from external customers.................. Segment profit/(loss) before provision for income taxes...................................... Electric Generation Corporate, Eliminations, and Marketing and Other Total ------------------------ ------------------------ ----------------------2005 2004 2005 2004 2005 2004 ------------ ----------- ----------- ------------ ----------- ----------(In thousands) $3,255,141 $2,396,483 (154,256) $ (15,426) 26,449 $ (70,692) 15,250 23,979 $3,281,590 (224,948) $2,411,733 8,553 Electric Generation Corporate, Eliminations, and Marketing and Other Total ------------------------ ------------------------ ----------------------2005 2004 2005 2004 2005 2004 ------------ ----------- ----------- ------------ ----------- ----------(In thousands) $7,451,404 (758,894) $6,414,619 (244,918) - 49 - $ 74,824 (30,448) $ 51,713 93,889) $7,526,228 (789,342) $6,466,332 (338,807) Electric Generation and Marketing -------------Total assets: September 30, 2005.................................................. December 31, 2004................................................... $ $ 25,381,709 25,187,414 Corporate, Eliminations, and Other -----------------------(In thousands) $ $ 1,706,528 2,028,674 Total ---------------$ $ 27,088,237 27,216,088 14. California Power Market California Refund Proceeding/June 19 FERC Order. On August 2, 2000, the California Refund Proceeding was initiated by a complaint made at FERC by San Diego Gas & Electric Company and under Section 206 of the Federal Power Act alleging, among other things, that the markets operated by the California Independent System Operator ("CAISO") and the California Power Exchange ("CalPX") were dysfunctional. In addition to commencing an inquiry regarding the market structure, FERC established a refund effective period of October 2, 2000, to June 19, 2001, for sales made into those markets. On December 12, 2002, the Administrative Law Judge issued a Certification of Proposed Finding on California Refund Liability ("December 12 Certification") making an initial determination of refund liability. On March 26, 2003, FERC also issued an order adopting many of the ALJ's findings set forth in the December 12 Certification (the "March 26 Order"). In addition, as a result of certain findings by the FERC staff concerning the unreliability or misreporting of certain reported indices for gas prices in California during the refund period, FERC ordered that the basis for calculating a party's potential refund liability be modified by substituting a gas proxy price based upon gas prices in the producing areas plus the tariff transportation rate for the California gas price indices previously adopted in the refund proceeding. The Company believes, based on the available information, that any refund liability that may be attributable to it could total approximately $10.1 million (plus interest, if applicable), after taking the appropriate set-offs for outstanding receivables owed by CalPX and CAISO to Calpine. The Company has fully reserved the amount referenced above. The final determination of the refund liability is subject to further Commission proceedings to ascertain the allocation of payment obligations among the numerous buyers and sellers in the California markets. Furthermore, it is possible that there will be further proceedings to require refunds from certain sellers for periods prior to the originally designated Refund Period. In addition, the FERC orders concerning the Refund Period, the method for calculating refund liability and numerous other issues are pending on appeal before the U.S. Court of Appeals for the Ninth Circuit. At this time, the Company is unable to predict the timing of the completion of these proceedings or the final refund liability. The final outcome of this proceeding and the impact on the Company's business is uncertain at this time. On April 26, 2004, Dynegy Inc. entered into a settlement of the California Refund Proceeding and other proceedings with California governmental entities and the three California investor-owned utilities. The California governmental entities include the Attorney General, the California Public Utilities Commission, the California Department of Water Resources ("CDWR"), and the California Electricity Oversight Board. Also, on April 27, 2004, The Williams Companies, Inc. ("Williams") entered into a settlement of the California Refund Proceeding and other proceedings with the three California investor-owned utilities; previously, Williams had entered into a settlement of the same matters with the California governmental entities. The Williams settlement with the California governmental entities was similar to the settlement that Calpine entered into with the Governor of the State of California, acting on behalf of the executive branch of the State of California, the California Electricity Oversight Board, the California Public Utilities Commission (California Commission), and the People of the State of California by and through the Attorney General (the "AG") (collectively, the "California State Releasing Parties") on April 22, 2002. Calpine's settlement resulted in an order issued on March 26, 2004, which partially dismissed Calpine from the California Refund Proceeding to the extent that any refunds are owed for power sold by Calpine to CDWR or any of the other California State Releasing Parties. On June 30, 2004, a settlement conference was convened at the FERC to explore settlements among additional parties. On December 7, 2004, FERC approved the settlement of the California Refund Proceeding and other proceedings among Duke Energy Corporation and its affiliates, the three California investor-owned utilities, and the California governmental entities. On September 9, 2004, the Ninth Circuit Court of Appeals issued a decision on appeal (State of California, Ex. Rel. Bill Lockyer, Attorney General v. Federal Energy Regulatory Commission) of a Petition for Review of an order issued by FERC in FERC Docket No. EL02-71 wherein the AG had filed a complaint (the "AG Complaint") under Sections 205 and 206 of the Federal Power Act (the "FPA") alleging that parties who misreported or did not properly report market based transactions were in violation of their market based rate tariff and as a result were not accorded protection under section 206 of the FPA from - 50 - retroactive refund liability. The Ninth Circuit remanded the order to FERC for rehearing. FERC is required to determine whether refunds should be required for violation of reporting requirements prior to October 2, 2000. The proceeding on remand has not yet been established. In connection with its settlement agreement with various State of California entities (including the AG), Calpine and its affiliates settled all claims related to the AG Complaint. FERC Investigation into the Western Markets. On February 13, 2002, FERC initiated an investigation of potential manipulation of electric and natural gas prices in the western United States. This investigation was initiated as a result of allegations that Enron and others, through their affiliates, used their market position to distort electric and natural gas markets in the West. The scope of the investigation is to consider whether, as a result of any manipulation in the short-term markets for electric energy or natural gas, or other undue influence on the wholesale markets by any party since January 1, 2000, the rates of the long-term contracts subsequently entered into in the West are potentially unjust and unreasonable. On August 13, 2002, the FERC staff issued the Initial Report on Company-Specific Separate Proceedings and Generic Reevaluations; Published Natural Gas Price Data; and Enron Trading Strategies (the "Initial Report") summarizing its initial findings in this investigation. There were no findings or allegations of wrongdoing by the Company set forth or described in the Initial Report. On March 26, 2003, the FERC staff issued a final report in this investigation (the "Final Report"). The FERC staff recommended that FERC issue a show cause order to a number of companies, including Calpine, regarding certain power scheduling practices that may potentially be in violation of the CAISO or CalPX tariffs. The Company believes that it did not violate these tariffs and that, to the extent that such a finding could be made, any potential liability would not be material. The Final Report also recommended that FERC modify the basis for determining potential liability in the California Refund Proceeding discussed above. On June 25, 2003, FERC issued a number of orders associated with these investigations. In particular, based on the FERC staff's earlier recommendations in the Final Report, FERC issued two show cause orders each naming certain industry participants. The show cause orders have initiated proceedings wherein the named parties must demonstrate that certain market behavior did not violate either the CAISO or CalPX tariffs as prohibited market manipulative behavior. FERC did not subject the Company to either of the show cause orders. FERC also issued an order directing the FERC staff to investigate further whether market participants who bid a price in excess of $250 per megawatt hour into markets operated may have violated CAISO and CalPX tariff prohibitions. No individual market participant was identified. The Company believes that it did not violate the CAISO and CalPX tariff prohibitions referred to by FERC in this order; however, we are unable to predict at this time the final outcome of this proceeding or its impact on Calpine. CPUC Proceeding Regarding QF Contract Pricing for Past Periods. Our Qualifying Facilities ("QF") contracts with Pacific Gas and Electric Company ("PG&E") provide that the CPUC has the authority to determine the appropriate utility "avoided cost" to be used to set energy payments for certain QF contracts by determining the short run avoided cost ("SRAC") energy price formula. In mid 2000, our QF facilities elected the option set forth in Section 390 of the California Public Utilities Code, which provided QFs the right to elect to receive energy payments based on the California Power Exchange ("PX") market clearing price instead of the price determined by SRAC. Having elected such option, we were paid based upon the PX zonal day-ahead clearing price ("PX Price") from summer 2000 until January 19, 2001, when the PX ceased operating a day-ahead market. The CPUC has conducted proceedings (R.99-11-022) to determine whether the PX Price was the appropriate price for the energy component upon which to base payments to QFs which had elected the PX-based pricing option. In late 2000, the CPUC Commissioner assigned to this matter issued a proposed decision to the effect that the PX Price was the appropriate price for energy payments under the California Public Utilities Code but the CPUC has yet to issue a final decision. Therefore, it is possible that the CPUC could order a retroactive payment adjustment based on a different energy price determination. On April 29, 2004 PG&E, The Utility Reform Network, which is a consumer advocacy group, and the Office of Ratepayer Advocates, which is an independent consumer advocacy department of the CPUC, (collectively, the "PG&E Parties") filed a Motion for Briefing Schedule Regarding True-Up of Payments to QF Switchers (the "April 29 Motion"). The April 29 Motion requested that the CPUC set a briefing schedule in the R.99-11-022 docket to determine refund liability of the QFs who had switched to the PX Price during the period of June 1, 2000 until January 19, 2001. The PG&E Parties alleged that refund liability be determined using the methodology that has been developed thus far in the California Refund Proceeding discussed above. On August 16, 2005, the Administrative Law Judge assigned to hear the April 29 Motion issued a ruling setting October 11, 2005, as the date for filing prehearing conference statements and October 17, 2005, as the date of the prehearing conference. In our response, filed on October 11, 2005, we urged that the April 29 Motion should be dismissed, but if dismissal were not granted, then discovery, testimony and hearings would be required. The assigned Administrative Law Judge has not yet issued a formal ruling following the October 17, 2005 prehearing conference. We believe that the PX Price was the appropriate price for energy payments and that the basis for any refund liability based on the interim determination by the FERC in the California Refund Proceeding is unfounded, but there can be no assurance that this will be the outcome of the CPUC proceedings. - 51 - Reliability Must Run Contracts with Geysers. The CAISO, the California Electricity Oversight Board, the CPUC, PG&E, San Diego Gas & Electric Company, and Southern California Edison (collectively referred to as the "Buyers Coalition") filed a complaint on November 2, 2001 at the FERC requesting the commencement of a Federal Power Act Section 206 proceeding to challenge one component of a number of separate settlements previously reached on the terms and conditions of "reliability must run" contracts ("RMR Contracts") with certain generation owners, including Geysers, which settlements were also previously approved by the FERC. RMR Contracts require the owner of the specific generation unit to provide energy and ancillary services when called upon to do so by the CAISO to meet local transmission reliability needs or to manage transmission constraints. The Buyers Coalition asked FERC to find that the availability payments under these RMR Contracts are not just and reasonable. Geysers filed an answer to the complaint in November 2001. On June 3, 2005, FERC issued an order dismissing the Buyers Coalition's complaint against all named generation owners, including Geysers. On August 2, 2005, FERC issued an order rejecting requests for rehearing of its order. The proceeding is now concluded at FERC. On September 23, 2005, the Buyers Coalition (with the exclusion of the CAISO) filed a Petition for Review with the United States Court of Appeals for the District of Columbia Circuit, seeking review of FERC's order dismissing the complaint. 15. Subsequent Events On October 6, 2005, the Company completed the sale of its 561-megawatt Ontelaunee Energy Center to LS Power Equity Partners for $225 million, less transaction fees, costs and working capital adjustments of approximately $13.0 million. The Ontelaunee sale is the third of four planned power plant sales announced by the Company in June 2005. Net proceeds from the sale of Ontelaunee will be used in accordance with the Company's indentures. Upon its commitment to a plan of divesture of Ontelaunee and in accordance with SFAS No. 144, the Company recorded an impairment charge of $136.8 million in the three months ended September 30, 2005. The sale of Ontelaunee closed October 6, 2005. This impairment charge is reflected in discontinued operations in the three months ended September 30, 2005. See Note 5 for more information. In connection with the sale of Ontelaunee and in accordance with the instruments governing its indebtedness, on October 6, 2005, CCFC LLC commenced offers to purchase its outstanding secured term loans and notes in an amount up to the net proceeds received from the Ontelaunee sale. The offer to purchase term loans expired on October 28, 2005, and the offer to purchase notes expired on November 4, 2005, without any term loans or notes having been tendered for purchase. On October 14, 2005, the Company's indirect subsidiary, CCFC LLC, issued $300.0 million of 6-Year Redeemable Preferred Shares Due 2011 at LIBOR plus 950 basis points. Net proceeds from the offering of the Redeemable Preferred Shares will be used as permitted by Calpine's existing bond indentures. On October 14, 2005, CCFC LLC repurchased its $150.0 million in Class A Redeemable Preferred Shares due February 13, 2006. Repurchased $93.3 million of 8 1/2% Senior Notes due 2008 in October 2005, in open market transactions for cash totaling $55.7 million, plus accrued interest. Item 2. Management's Discussion and Analysis ("MD&A") of Financial Condition and Results of Operations. In addition to historical information, this report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. We use words such as "believe," "intend," "expect," "anticipate," "plan," "may," "will" and similar expressions to identify forward-looking statements. Such statements include, among others, those concerning our expected financial performance and 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 that a number of risks and uncertainties could cause actual results to differ materially from those anticipated in the forward-looking statements. Such risks and uncertainties include, but are 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, and the impact of related derivatives transactions, (iii) unscheduled outages of operating plants, (iv) unseasonable weather patterns that reduce demand for power, (v) economic slowdowns that can adversely affect consumption of power by businesses and consumers, (vi) various development and construction risks that may delay or prevent commercial operations of new plants, such as failure to obtain the necessary permits to operate, failure of third-party contractors to perform their contractual obligations or failure to obtain project financing on acceptable terms, (vii) uncertainties associated with cost estimates, that actual costs may be higher than estimated, (viii) development of lower-cost power plants or of a lower cost - 52 - means of operating a fleet of power plants by our competitors, (ix) risks associated with marketing and selling power from power plants in the evolving energy market, (x) factors that impact the exploitation of our geothermal resource, (xi) uncertainties associated with estimates of geothermal reserves, (xii) the effects on our business resulting from reduced liquidity in the trading and power generation industry, (xiii) our ability to access the capital markets on attractive terms or at all, (xiv) our ability to successfully implement the various components of our strategic initiative to increase liquidity, reduce debt and reduce operating costs, (xv) uncertainties associated with estimates of sources and uses of cash, that actual sources may be lower and actual uses may be higher than estimated, (xvi) implementation of our strategy to expand our third party service businesses and diversify our fuel source, (xvii) the direct or indirect effects on our business of a lowering of our credit rating (or actions we may take in response to changing credit rating criteria), including increased collateral requirements, refusal by our current or potential counterparties to enter into transactions with us and our inability to obtain credit or capital in desired amounts or on favorable terms, (xviii) present and possible future claims, litigation and enforcement actions, (xix) effects of the application of regulations, including changes in regulations or the interpretation thereof, and (xx) other risks identified in this report. You should also carefully review the risks described in other reports that we file with the Securities and Exchange Commission, including without limitation our Annual Report on Form 10-K for the year ended December 31, 2004, and our Current Report on Form 8-K filed with the SEC on July 1, 2005. We undertake no obligation to update any forward-looking statements, whether as a result of new information, future developments or otherwise. We file annual, quarterly and periodic 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 room at 100 F Street, NE, Room 1580, Washington, D.C. 20549. 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 100 F Street, NE, Room 1580, Washington, D.C. 20549-1004. The SEC maintains an Internet website at http://www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. Our SEC filings are accessible through the Internet at that website. Our reports on Forms 10-K, 10-Q and 8-K, and amendments to those reports, are available for download, free of charge, as soon as reasonably practicable after these reports are filed with the SEC, 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 our SEC filings, at no cost to you, by writing or telephoning us at: Calpine Corporation, 50 West San Fernando Street, San Jose, California 95113, attention: Lisa M. Bodensteiner, Assistant Secretary, telephone: (408) 995-5115. We will not send exhibits to the documents, unless the exhibits are specifically requested and you pay our fee for duplication and delivery. Selected Operating Information Set forth below is certain selected operating information for our power plants for which results are consolidated in our Consolidated Condensed Statements 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 revenues include, besides traditional capacity payments, other revenues such as Reliability Must Run and Ancillary Service revenues. The information set forth under thermal and other revenue consists of host steam sales and other thermal revenue. Power Plants: E&S revenues: Energy..................................................... Capacity................................................... Thermal and other.......................................... Subtotal................................................... Spread on sales of purchased power (1)....................... Adjusted E&S revenues before mark-to-market activities, net (non-GAAP)................................. MWh produced................................................. All-in electricity price per MWh generated before mark-to-market activities, net............................. ---------(table continues) - 53 - Three Months Ended Nine Months Ended September 30, September 30, --------------------------------------------------------------------2005 2004 2005 2004 --------------- -------------------------------------------(In thousands, except pricing data) $ 1,634,372 317,754 144,197 --------------$ 2,096,323 69,503 --------------- $ 1,133,557 312,649 98,123 --------------$ 1,544,329 79,355 --------------- $ 3,430,720 840,020 354,338 --------------$ 4,625,078 233,427 --------------- $ 2,814,915 763,234 273,765 --------------$ 3,851,914 135,912 --------------- $ 2,165,826 28,709 $ 1,623,684 26,604 $ 4,858,505 68,240 $ 3,987,826 64,357 $ 75.44 $ 61.03 $ 71.20 $ 61.96 (1) From hedging, balancing generating assets. and optimization activities related to our 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, 2005 and 2004, that represent purchased power and purchased gas sales for hedging and optimization and the costs we incurred to purchase the power and gas that we resold during these periods (in thousands, except percentage data): Three Months Ended Nine Months Ended September 30, September 30, --------------------------------------------------------------------2005 2004 2005 2004 --------------- -------------------------------------------$ 3,281,590 $ 2,411,733 $ 7,526,228 $ 6,466,332 413,281 427,737 1,193,537 1,301,585 12.6% 17.7% 15.9% 20.1% 696,850 423,733 1,574,067 1,258,441 21.2% 17.6% 20.9% 19.5% 3,042,463 2,185,288 7,124,903 6,157,841 343,778 348,380 960,110 1,165,674 11.3% 15.9% 13.5% 18.9% 724,351 429,373 1,623,692 1,243,781 23.8% 19.6% 22.8% 20.2% Total revenue............................................... Sales of purchased power for hedging and optimization (1)... As a percentage of total revenue............................ Sale of purchased gas for hedging and optimization.......... As a percentage of total revenue............................ Total COR................................................... Purchased power expense for hedging and optimization (1).... As a percentage of total COR................................ Purchased gas expense for hedging and optimization.......... As a percentage of total COR................................ -----------(1) On October 1, 2003, we adopted on a prospective basis EITF Issue No. 03-11 "Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not `Held for Trading Purposes' As Defined in EITF Issue No. 02-3: "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities" and netted certain purchases of power against sales of purchased power. See Note 2 of the Notes to Consolidated Condensed Financial Statements for a discussion of our application of EITF Issue No. 03-11. The primary reasons for the significant levels of these sales and costs of revenue items include: (a) significant levels of hedging, balancing and optimization activities by our CES risk management organization; (b) volatile markets for electricity and natural gas, which prompt us to frequently adjust our hedge positions by buying power and gas and reselling it; and (c) the accounting requirements under SAB No. 101, "Revenue Recognition in Financial Statements," and EITF Issue No. 99-19, "Reporting Revenue Gross as a Principal versus Net as an Agent," under which we show many of our hedging contracts on a gross basis (as opposed to netting sales and cost of revenue). Overview Our core business and primary source of revenue is the generation and delivery of electric power in North America. We provide power to our U.S. and Canadian customers through the integrated development, construction or acquisition, and operation of efficient and environmentally friendly electric power plants fueled primarily by natural gas and, to a much lesser degree, by geothermal resources. We protect and enhance the value of our assets with a sophisticated risk management organization. We also protect our power generation assets and control certain of our costs by producing certain of the combustion turbine replacement parts that we use at our power plants, and we generate revenue by providing combustion turbine parts to third parties. Finally, we offer services to third parties to capture value in the skills we have honed in building, commissioning, repairing and operating power plants. While we have been able to access the capital and bank credit markets since 2002, it has been on significantly different terms than before 2002. This has been due to a range of factors, including uncertainty arising from the collapse of Enron and a surplus supply of electric generating capacity in certain of our market areas. These factors coupled with an extended period of decreased spark spreads (the differential between power revenues and fuel costs) have adversely impacted our capacity utilization rates, liquidity and earnings. Additionally, natural gas prices have been volatile and, on average, have increased over the last several years. The impact of rising natural gas prices on the Company is discussed below. We recognize that the terms of capital available to us in the future may not be attractive or our access to the capital markets may otherwise be restricted. To protect against this possibility and due to current market conditions, during the past several years we have scaled back our capital expenditure program and have taken other steps to enhance our liquidity, reduce our debt and otherwise conserve our capital resources. See "Capital Availability" in Liquidity and Capital Resources below for a further discussion. - 54 - As part of our efforts to improve our financial strength, we announced a strategic initiative in May 2005 aimed at: o Optimizing the value of our core North American power plant portfolio by selling certain power and natural gas assets to reduce debt and lower annual interest cost, and to increase cash flow in future periods. At September 30, 2005, we had completed the sales of Saltend in the United Kingdom, Morris in Illinois and our interest in Grays Ferry in Pennsylvania. Additionally, in October 2005, we completed the sale of Ontelaunee and in July 2005, completed the sale of substantially all of our remaining oil and natural gas assets. We are in discussions with potential buyers for, or are considering, the sale of additional assets. See Notes 8 and 15 of the Notes to Consolidated Condensed Financial Statements for further information on these transactions. There can be no assurance that the Company will be successful in developing such alternative or additional sources of fuel in the near term or otherwise. o Taking actions to decrease operating and maintenance costs and lowering fuel costs to improve the operating performance of our power plants, which would boost operating cash flow and liquidity. In addition, to further reduce cost, we have temporarily shut down two power plants with negative cash flow, and are considering others, until market conditions warrant starting back up. See also Note 12 of the Notes to Consolidated Condensed Financial Statements for a discussion of the restructuring of certain of our LTSAs. o Reducing collateral requirements. On September 8, 2005, we and Bear Stearns announced an agreement to form a new energy marketing and trading venture to develop a third party customer business focused on physical natural gas and power trading and related structured transactions. Regulatory approval for this new entity was received on October 31, 2005, and it is anticipated that operations will begin in the fourth quarter of 2005. The transaction will include a $350 million credit intermediation agreement between CalBear, a new subsidiary of Bear Stearns, and CES. It is anticipated that this credit intermediation agreement will, among other things, positively impact our working capital position by making possible the return of cash and LCs currently posted as collateral. o Reducing total debt, net of new construction financings, by more than $3 billion from debt levels at year-end 2004, which we estimate would provide $275 million of annual interest savings. We continue to advance our May 2005 strategic initiative aimed at optimizing our power plant portfolio, reducing debt and enhancing our financial strength. While we continue to make progress toward our goal of reducing total debt by more than $3 billion by year-end 2005 and achieving an estimated $275 million of annual interest savings, the timing of accomplishing this goal may be delayed into 2006. The cash and other consideration needed to reduce debt by that amount will be a function of the timing of asset sales, our ability to use proceeds of such sales to reduce debt (we are currently involved in various litigations with the holders of certain series of our outstanding secured and unsecured bonds as described in Note 12 of the Notes to Consolidated Condensed Financial Statements), the prices at which we are able to repurchase debt and other factors. At September 30, 2005, total consolidated debt was $17.2 billion, a reduction of $0.9 billion from the $18.1 billion level at March 31, 2005, before the strategic initiative was announced. Excluding the effect of new construction financing of $178.7 million, we have reduced debt by approximately $1.1 billion during this period. However, regardless of whether or not the specific $3 billion debt reduction goal can be achieved by December 31, 2005, we remain committed to achieving that goal as soon as practicable. In addition, as noted above, we seek to identify opportunities to capture value in the skills and knowledge that we have developed, not only to improve the operating performance of our facilities but also to develop new sources of revenues by, for example, utilizing our hedging and optimization skills to develop the CalBear business and by expanding our third-party combustion turbine component parts and retail and maintenance services businesses. We are also actively exploring possible alternative sources of natural gas (such as LNG and Alaskan pipeline projects) to increase the natural gas supply in the continental United States, as well as other sources of fuel for our natural gas-fired generation facilities, such as projects to convert pet coke, an oil refinery waste product, into gas suitable for combustion in our gas turbines. There can be no assurance that we will be successful in developing such alternative or additional sources of fuel in the near term or otherwise. Other key opportunities and challenges for us include: o preserving and enhancing our liquidity while spark spreads are depressed, - 55 - o selectively adding new load-serving entities and power users to our customer list as we increase our power contract portfolio, o continuing to add value through prudent risk management and optimization activities, and o managing our exposure to volatile natural gas prices. The price of natural gas has been volatile over the last several years and has, on average, increased. We are one of the largest gas consumers (if not the largest) in the United States, and therefore, we carefully evaluate and seek to optimally manage our gas position. In markets where gas-fired power generation is "on the margin" (based on the profile of available capacity, incremental electricity generation is likely to be produced by natural gas plants), and the Company has open generation capacity for sale, higher natural gas prices can, and do, produce higher spark spreads for us when dispatched due to our efficient, low heat rate fleet of generation plants. In other situations, the impact of higher gas prices on us is neutral (or potentially positive), such as in cases where we have entered into tolling arrangements or heat rate index contracts with customers. In tolling arrangements, the customer is responsible for buying and delivering natural gas to one of our generating plants, and we receive a tolling payment to convert the customer's natural gas into electricity. In heat rate index contracts, the price for energy produced is priced by multiplying a contractual heat rate times the market fuel price over the contract term. To the extent that the contract heat rate is higher than our actual generation heat rate, we would, and do, realize improved spark spreads from higher natural gas prices. However, in situations where we have sold fixed price power and do not maintain a 100% hedged gas position, higher natural gas prices can, and do, reduce our spark spread to the extent of any short fixed-price gas position. In the third quarter of 2005, following the sale of our remaining oil and gas assets in early July 2005, we were thereafter short fixed-price gas and could remain in a short position for some period of time until the position can be rebalanced. In addition, by eliminating the equity gas benefit that we had enjoyed due to the fact that our costs of producing natural gas were significantly lower than natural gas prices in recent years through the sale of our remaining oil and gas assets to Rosetta in July 2005, we expect an increase in the future effective fuel expense (and lower spark spread) for our fleet of gas-fired generating plants. Also, we expect that purchasing additional volumes from third party producers will increase our requirements to post collateral or prepay for gas. However, the negative impacts on spark spread and gross profit (loss) are expected to be offset to some extent by lower interest expense in the future to the extent the proceeds of the sale are able to be used to repay debt. We also expect to use other hedging approaches in managing our natural gas requirements to compensate for the loss of the natural hedge position that equity gas had afforded us. In the past, when we sold fixed price power, we could use our equity gas reserves as a hedge against rising gas prices. Other techniques have included purchase of fixed-for-floating gas price swap contracts, purchasing physical gas on a fixed-price basis, or potentially buying back fixed price power contracts. In the future we will be more reliant on these other techniques, the use of which may be limited by our current credit constraints. From a physical gas purchase perspective, we will be purchasing Rosetta's California production at market prices under industry standard margining provisions. We estimate that our collateral requirements at the date of sale increased by approximately $25 million for a typical payment cycle. From a fixed price gas exposure perspective, we will not have any fixed price hedges in place with Rosetta, so our position will need to be managed with financial swaps and fixed price physical gas purchases. In addition, we may use proceeds of the sale to purchase natural gas assets as permitted by our indentures. Overview of Results -- In the third quarter of 2005, generation volume was up 7.9% from the prior year due primarily to four new facilities and one expansion project coming online in the twelve months ended September 30, 2005. Also, spark spread increased by approximately 6% in the same period. Even with the new capacity, our average baseload capacity factor for the three months ended September 30, 2005, was 54.0% compared to 55.4% in the prior year period. Demand was stronger in virtually all of the Company's key markets, except Northern California due to below normal temperatures in September 2005, and market on-peak spark spreads improved significantly in the third quarter of 2005. However, off-peak market spark spreads did not show similar improvements. Also, we estimate that our spark spread margin was reduced in the quarter as a result of being in a short fixed-price gas position following the sale of our remaining oil and gas assets in July 2005. We may be susceptible to diminished spark spreads when natural gas prices rise until we are ablt to rebalance our fixed-price gas position. Further, in the 12 months ended September 30, 2005, average natural gas prices (with Henry Hub delivery) increased by 147% from $4.99 per million BTU to $12.35 per million BTU. While this current price spike is largely attributable to the damage caused by hurricane's Katrina and Rita in August and September 2005, natural gas prices historically had a winter peak in demand due to home heating usage; however, partly as a result of increased use as a fuel for electric power generation, demand is less seasonal and is developing a summer peak in addition to the winter peak. - 56 - Set forth below are the Results of Operations for the three and nine months ended September 30, 2005 and 2004, which reflect reclassifications for discontinued operations. See Note 8 of the Notes to Consolidated Condensed Financial Statements. Results of Operations Three Months Ended September 30, 2005, Compared to Three Months Ended September 30, 2004 (In millions unless indicated otherwise, except for unit pricing information, percentages and MW volumes). In the comparative tables below, increases in revenue/income or decreases in expense (favorable variances) are shown without brackets. Decreases in revenue/income or increases in expense (unfavorable variances) are shown with brackets. Revenue Total revenue.............................................................. Three Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ 3,281.6 $ 2,411.7 $ 869.9 36.1% The change in total revenue is explained by category below. Electricity and steam revenue.............................................. Transmission sales revenue................................................. Sales of purchased power for hedging and optimization...................... Total electric generation and marketing revenue......................... Three Months Ended September 30, --------------------------2005 2004 ------------- ------------$ 2,096.3 $ 1,544.3 1.9 4.4 413.3 427.7 ------------ -----------$ 2,511.5 $ 1,976.4 ============ ============ $ Change % Change ------------- ------------$ 552.0 35.7% (2.5) (56.8)% (14.4) (3.4)% -----------$ 535.1 27.1% ============ Electricity and steam revenue increased as we completed the construction and brought into operation four additional baseload power facilities and one expansion project subsequent to September 30, 2004, and realized an increase in our average electric price before the effects of hedging, balancing and optimization, from $58.05/MWh for the three months ended September 30, 2004, to $73.02/MWh for the same period in 2005. Average total megawatts in operation of our consolidated plants increased by 7.8% to 26,126 MW, which was consistent with our increase in total generation of 7.9%. However, average baseload megawatts in operation increased by 8.8% compared to an increase of only 6.1% for baseload generation. The increase in generation, resulting in a drop in our baseload capacity factor dropped to 54.0% in the three months ended September 30, 2005, from 55.4% in the three months ended September 30, 2004. This was primarily due to the increased occurrence of unattractive off-peak market spark spreads in certain areas reflecting oversupply conditions which are expected to gradually improve over the next several years, but which caused us to cycle-off certain of our merchant plants without contracts in off-peak hours. We purchase transmission capacity so that power can move from our plants to our customers. Transmission capacity can be purchased on a long term basis and, in many of the markets in which the company operates, can be resold if we do not need it and some other party can use it. If the generation from our plants is less than we anticipated when we purchased the transmission capacity, we can and do realize revenue by selling the unused portion of the transmission capacity. We also, in many cases, bill our customers for transmission costs that we incur in serving their accounts. This is especially true in the case of many of our retail contracts. When we bill our customers for transmission expenses incurred on their behalf we recognize these billings as a component of transmission revenue. For the three months ended September 30, 2005 as compared to the same period in 2004 transmission revenues have declined as we have seen a reduction in transmission billings relating our retail customers. Sales of purchased power for hedging and optimization decreased in the three months ended September 30, 2005, due primarily to lower volumes which were partially offset by higher prices, as compared to the same period in 2004. - 57 - Oil and gas sales.......................................................... Sales of purchased gas for hedging and optimization........................ Total oil and gas production and marketing revenue...................... Three Months Ended September 30, --------------------------2005 2004 ------------- ------------$ -$ 2.7 696.9 423.7 ------------ -----------$ 696.9 $ 426.4 ============ ============ $ Change % Change ------------- ------------$ (2.7) (100.0)% 273.2 64.5% -----------$ 270.5 63.4% ============ We reclassified our remaining oil and gas operations, which were sold in July 2005, to discontinued operations in the quarter ended June 30, 2005, upon our commitment to a plan of divesture of the component. Activity in prior years relates to minor assets sold in prior years that did not meet the criteria for reclassification to discontinued operations at the time of sale. See Note 8 of the Notes to Consolidated Condensed Financial Statements for more information. Sales of purchased gas for hedging and optimization increased during 2005 due primarily to higher liquidation prices of natural gas and a moderate increase in volumes compared to the same period in 2004. Mark-to-market activities, net............................................. Three Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ 40.9 $ (5.2) $ 46.1 886.5% Mark-to-market activities, which are shown on a net basis, result from general market price movements against our open commodity derivative positions, These commodity positions represent a small portion of our overall commodity contract position. The net gain from mark-to-market activities in the three months ended September 30, 2005, as compared to the same period in 2004 is due primarily to gains on our Deer Park transaction which are recorded on a mark-to-market basis, and gains attributable to gas contracts that lost hedge accounting eligibility for the quarter. In order to qualify for hedge accounting under SFAS No. 133, price movements in the hedge contract and the hedged transaction must move in a manner whereby changes in value of the hedge contract and hedged transaction sufficiently offset. As a result of significant volatility in the gas markets, certain of our gas contracts did not meet these requirements and we recorded approximately $18.3 million in mark-to-market gains that would have otherwise been recorded through other comprehensive income. Other revenue.............................................................. Three Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ 32.4 $ 14.0 $ 18.4 131.4% Other revenue increased due primarily to higher revenues at PSM associated with sales of gas turbine components and at TTS for gas turbine maintenance services and the sale of spare turbine parts and components. Cost of Revenue Cost of revenue............................................................ - 58 - Three Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ 3,042.5 $ 2,185.3 $ (857.2) (39.2)% The increase in total cost of revenue is explained by category below. Plant operating expense.................................................... Transmission purchase expense.............................................. Royalty expense............................................................ Purchased power expense for hedging and optimization....................... Total electric generation and marketing expense......................... Three Months Ended September 30, --------------------------2005 2004 ------------- ------------$ 180.3 $ 160.0 23.1 22.7 10.0 8.3 343.8 348.4 ------------ -----------$ 557.2 $ 539.4 ============ ============ $ Change % Change ------------- ------------$ (20.3) (12.7)% (0.4) (1.8)% (1.7) (20.5)% 4.6 1.3% -----------$ (17.8) (3.3)% ============ Plant operating expense increased primarily due to four additional baseload power facilities and one expansion project in operation subsequent to September 30, 2004, which was partially offset by lower major maintenance spending versus prior year, largely due to the timing of such work. In many cases, we incur transmission costs that result from serving the accounts of our customers. This is especially true in the case of many of our retail contracts. When we incur transmission expenses on behalf of our customers we recognize these amounts as a component of transmission purchase expense. For the three months ended September 30, 2005 as compared to the same period in 2004 transmission purchase expenses have declined as we have seen a reduction in transmission purchases relating to our retail customers. Royalty expense increased primarily due to an increase in electric revenues at The Geysers geothermal plants and an increase in contingent purchase price payments to the previous owners of our Texas City and Clear Lake power plants. At The Geysers, royalties are paid mostly as a percentage of geothermal electricity revenues and royalties associated with Texas City and Clear Lake are based on a percentage of gross revenues earned at the plants. Purchased power expense for hedging and optimization decreased during the three months ended September 30, 2005, as compared to the same period in 2004 due primarily to a reduction in volumes which wer partially offset by higher prices, as compared to the same period in 2004. Oil and gas operating expense.............................................. Purchased gas expense for hedging and optimization......................... Total oil and gas operating and marketing expense....................... Three Months Ended September 30, --------------------------2005 2004 ------------- ------------$ 1.4 $ 1.8 724.3 429.4 ------------ -----------$ 725.7 $ 431.2 ============ ============ $ Change % Change ------------- ------------$ 0.4 22.2% (294.9) (68.7)% -----------$ (294.5) (68.3)% ============ The Company reclassified its remaining oil and gas operations to discontinued operations ("held for sale") in the three months ended June 30, 2005. Remaining activity in continuing operations relates primarily to gas pipeline activities which were not sold and activity in prior years also includes the results of minor assets sold in prior years that did not meet the criteria for reclassification to discontinued operations at the time of sale. See Note 8 of the Notes to Consolidated Condensed Financial Statements for more information. Purchased gas expense for hedging and optimization increased during the three months ended September 30, 2005, due to higher natural gas prices and higher volumes as compared to the same period in 2004. Fuel expense............................................................... Three Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ 1,567.5 $ 1,052.3 $ (515.2) (49.0)% Fuel expense increased during the three months ended September 30, 2005, as compared to the same period in 2004 due primarily to higher natural gas prices and an increase of 7.9% in generation due largely to the addition of four baseload power facilities and one expansion project to our consolidated - 59 - operating portfolio subsequent to September 30, 2004. Our average fuel expense before the effects of hedging, balancing and optimization increased by 41% from $5.88/MMBtu for the three months ended September 30, 2004 to $8.28/MMBtu for the same period in 2005. Depreciation, depletion and amortization expense........................... Three Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ 131.0 $ 117.4 $ (13.6) (11.6)% Depreciation, depletion and amortization expense increased primarily due to the additional power facilities in consolidated operations subsequent to September 30, 2004. Operating lease expense.................................................... Three Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ 28.8 $ 25.8 $ (3.0) (11.6)% Operating lease expense increased from the prior year due to an additional non-cash adjustment, which was necessary due to a revision in our estimated cost to dismantle our Watsonville facility at the end of the lease term in 2010. Other cost of revenue...................................................... Three Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ 32.2 $ 19.2 $ (13.0) (67.7)% Other cost of revenue increased during the three months ended September 30, 2005, as compared to the same period in 2004, due to increased gas turbine maintenance services activity and spare turbine parts and component sales at TTS and increased gas turbine component sales by PSM. (Income)/Expenses (Income) loss from unconsolidated investments.............................. Three Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ (5.4) $ 11.2 $ 16.6 148.2% The increase in income was primarily due to an increase in income from the Acadia PP investment (due mostly to lower major maintenance costs and decreased LTSA costs), and the non-recurrence of losses recorded in 2004 from our investment in the AELLC power plant. We ceased to recognize our share of the operating results of AELLC as we began to account for our investment in AELLC using the cost method following loss of effective control when AELLC filed for bankruptcy protection in November 2004. In September 2004 prior to AELLC filing for bankruptcy protection, we recognized our share of an adverse jury award related to a dispute with IP. Our share of that expense was $11.6. Equipment cancellation and impairment cost................................. Three Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ 0.8 $ 7.8 $ 7.0 89.7% During the three months ended September 30, 2005, equipment cancellation and asset impairment charge decreased by $7.0 as compared to the same period in 2004 primarily as a result of two non-recurring charges we incurred during the third quarter of 2004. During the three months ended September 30, 2004, we - 60 - incurred a loss of $4.3 recognized in connection with the impairment charge for one HRSG and a loss on the sale of 12 tube bundles in the amount of $3.5. Long-term service agreement cancellation charge............................ Three Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ 0.6 $ 4.0 $ 3.4 85.0% During the three months ended September 30, 2004, we recorded charges of $7.6 related to the cancellation and settlement of four LTSAs with Siemens Westinghouse. During the three months ended September 30, 2005, we retroactively reclassified $3.6 of these charges to discontinued operations due to our commitment to a plan to divest the Ontelaunee Energy Center. Project development expense................................................ Three Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ 10.1 $ 3.4 $ (6.7) (197.1)% Project development expense increased by $6.7 during the three months ended September 30, 2005, compared to the same period in 2004 primarily due to an increase of $6.3 in site preservation costs related to projects whose development/construction has been suspended. Research and development expense........................................... Three Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ 3.3 $ 4.0 $ 0.7 17.5% Research and development expense decreased during the three months ended September 30, 2005, as compared to the same period in 2004 primarily due to the timing of personnel expenses and consulting fees related to new research and development programs and testing at PSM. Sales, general and administrative expense.................................. Three Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ 54.6 $ 53.8 $ (0.8) (1.5)% Sales, general and administrative expense increased during the three months ended September 30, 2005, primarily due to an increase in information technology and employee compensation costs offset by decreases in consulting fees and facilities costs. Interest expense........................................................... Three Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ 381.0 $ 285.4 $ (95.6) (33.5)% Interest expense increased primarily as a result of higher average interest rates and lower capitalization of interest expense. Our average interest rate increased from 8.4% for the three months ended September 30, 2004, to 9.4% for the three months ended September 30, 2005, primarily due to the impact of rising U.S. interest rates and their effect on our existing variable rate debt portfolio and higher average interest rates incurred on new debt instruments that were entered into to replace and/or refinance existing debt instruments during 2005. Interest capitalized decreased from $86.7 for the three months ended September 30, 2004, to $36.0 for the three months ended September 30, 2005, as new plants entered commercial operations (at which point capitalization of interest expense ceases) and because of suspended capitalization of interest on three partially completed construction projects. During the three months ended September 30, 2005, (i) interest expense related to our Senior Notes, contingent convertible notes, and term loans increased by $7.4; (ii) interest expense related to our CalGen subsidiary increased $11.4; (iii) interest expense related to our construction/project financing increased by $17.3; (iv) interest expense related to our CCFC I subsidiary increased by $3.8; and (v) interest expense related to preferred interests increased by $12.2 primarily due to the June 2005 closing of the $15.5 offering of redeemable preferred securities by our indirect subsidiary, Metcalf, the August 2005 closing of the $150 offering - 61 - of redeemable preferred securities by our indirect subsidiary, CCFC LLC, the October 2004 closing of the $360 offering of redeemable preferred securities by our indirect subsidiary, Calpine Jersey I, and the $260 offering on January 31, 2005, of redeemable preferred securities by our indirect subsidiary, Calpine Jersey II (the Calpine Jersey I and Calpine Jersey II securities were repurchased with proceeds from the sale of Saltend in July 2005). These interest cost increases are partially offset by a decrease of $15.6 in interest expense on the convertible debentures payable to the Calpine Capital Trusts, which have been redeemed. Interest (income).......................................................... Three Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ (26.6) $ (17.0) $ 9.6 56.5% Interest (income) increased during the three months ended September 30, 2005, due primarily to higher interest earned on margin deposits and collateral posted to secure letters of credit and due to higher interest rates. Minority interest expense.................................................. Three Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ 11.0 $ 10.0 $ (1.0) (10.0)% Minority interest expense increased during the three months ended September 30, 2005, as compared to the same period in 2004 primarily due to an increase in income at CPLP, which is 70% owned by CPIF. The variance is largely due to an increase in steam revenue at the Island Cogen plant which was driven by higher gas prices; the price of gas is a component of the steam revenue calculation. (Income) from repurchase of debt........................................... Three Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ (15.5) $ (167.2) $ (151.7) (90.7)% The decrease in income from repurchase of debt is due to considerably higher volumes of Senior Notes repurchased during the three months ended September 30, 2004, compared to the same period in 2005. See Note 7 of the Notes to Consolidated Condensed Financial Statements for further information. Other expense (income), net................................................ Three Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ 50.3 $ 22.4 $ (27.9) (124.6)% Other expense increased for the three months ended September 30, 2005, compared to the same period in 2004, primarily due to a $31.5 increase in non-cash foreign currency transaction losses. See the "foreign currency transaction gain (loss)" discussion within "Financial Market Risks" for further information. - 62 - Provision (benefit) for income taxes....................................... Three Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ 17.5 $ (20.3) $ (37.8) (186.2)% During the three months ended September 30, 2005, our tax provision increased by $37.8 as compared to the benefit in the three months ended September 30, 2004, despite the fact that our pre-tax loss increased $233.5 in 2005. The effective tax rate increased to (7.8)% in 2005 compared to (237.6)% in the same period in 2004 largely due to a valuation allowance recorded on certain deferred tax assets associated with CCFC which had the effect of reducing the tax benefit on our pre-tax loss by approximately $143.4. The tax rates on continuing operations for the three months ended September 30, 2004, have been restated to reflect the reclassification to discontinued operations of certain tax expense related to the sale of oil and gas reserves, Saltend, and the Morris and Ontelaunee power plants. See Note 8 of the Notes to Consolidated Condensed Financial Statements for further information. Discontinued operations, net of tax provision.............................. Three Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ 25.7 $ 112.2 $ (86.5) (77.1)% During the three months ended September 30, 2005, discontinued operations activity primarily consisted of the pre-tax gain on the sale of Saltend of $26.3 and the pre-tax gain on the sale of substantially all of our remaining oil and gas assets of $342.8; both dispositions closed in July 2005. Offsetting these gains is a pre-tax impairment charge of $136.8 related to the pending sale of Ontelaunee, which met the discontinued operations criterion as of September 30, 2005 under SFAS No. 144. On a pre-tax basis, we recorded income from discontinued operations for the three months ended September 30, 2005 of $196.3. Our effective tax rate on discontinued operations for the three months ended September 30, 2005, however, was 86.9% due primarily to a large tax return gain on the sale of Saltend and, as a consequence, our after-tax gain from discontinued operations was only $25.7. Discontinued operations for the three months ended September 30, 2004, consisted primarily of a pre-tax gain from the sale of our Canadian and U.S. Rocky Mountain oil and gas assets of $203.5. On a net of tax basis, income from discontinued operations for the three months ended September 30, 2004, was $112.2, based on an effective tax rate of 47.7%. Net income (loss).......................................................... Three Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ (216.7) $ 141.1 $ (357.8) (253.6)% For the three months ended September 30, 2005, we reported revenue of $3.3 billion, representing an increase of 36% over the same period in the prior year. Including the discontinued operations discussed below, we recorded a net loss per share of $0.45, or a net loss of $216.7, compared to net income per share of $0.32, or net income of $141.1, for the same quarter in the prior year. For the three months ended September 30, 2005, our average capacity in operation for consolidated projects in continuing operations increased by 7.8% to 26,126 megawatts. Generation volume was up 7.9% from the prior year as we generated approximately 28.7 million megawatt-hours, which equated to a baseload capacity factor of 54.0%, and realized an average spark spread of $20.74 per megawatt-hour. For the same period in 2004, we generated 26.6 million megawatt-hours, which equated to a baseload capacity factor of 55.4%, and realized an average spark spread of $21.15 per megawatt-hour. Gross profit increased by $12.7 to $239.1 in the three months ended September 30, 2005, compared to the same period in the prior year as total spark spread margin increased by $32.7 period-to-period. We estimate that our spark spread margin was reduced in the quarter as a result of being in a short fixed-price gas position following the sale of our oil and gas assets. Our overall short fixed-price gas position makes us susceptible to diminished spark spreads when natural gas prices rise and will continue to do so until our - 63 - position is rebalanced. Total spark spread margin did not increase in line with the increases in plant operating expense, depreciation, other cost of revenue items and interest expense. During the three months ended September 30, 2005, financial results were positively impacted by $15.5 of income recorded from repurchase of debt, but this was lower by $151.6 than the gain recorded from repurchase of debt in the comparable period in 2004. Costs to cancel equipment orders and long-term service agreements totaled $1.3 in 2005, compared to $11.8 in the prior year, and income from unconsolidated investments was also favorable, by $16.6 versus the prior year, primarily because we recorded $11.6 of loss in the comparable period of 2004 associated with an unfavorable jury award at AELLC. However, in the third quarter of 2005, we recorded $6.7 higher project development expense compared to the prior year due mostly to higher preservation costs at suspended projects, and interest expense increased by $95.6 between periods primarily due to lower capitalization of interest expense, as fewer plants were in active construction, and due to an increase in the average interest rate. Other expense of $50.3 for the three months ended September 30, 2005 was unfavorable by $27.9, compared to other expense of $22.4 for the three months ended September 30, 2004 due to an increase of $31.5 in non-cash foreign currency transaction losses. In the three months ended September 30, 2005 we recorded a pre-tax gain from discontinued operations of $196.3. However, our effective tax rate on discontinued operations was 86.9% due primarily to a large tax return gain on the sale of Saltend and, as a consequence, our after-tax gain from discontinued operations was only $25.7. Income from discontinued operations included gains on the sale of our remaining oil and gas assets and Saltend , both of which closed in July 2005, and an impairment charge associated with Ontelaunee, which was classified as held for sale at September 30, 2005 and closed in October 2005. Discontinued operations also includes the operating results until the respective sales dates for those entities and the Morris power plant, for which we recorded an impairment charge in the second quarter of 2005 and which was sold in the third quarter of 2005. For the three months ended September 30, 2004, we recorded a net after-tax gain of $112.2 million in discontinued operations from the sales of our Canadian and U. S. Rocky Mountain oil and gas assets. Nine Months Ended September 30, 2005, Compared to Nine Months Ended September 30, 2004 (In millions unless indicated otherwise, except for unit pricing information, percentages and MW volumes). In the comparative tables below, increases in revenue/income or decreases in expense (favorable variances) are shown without brackets. Decreases in revenue/income or increases in expense (unfavorable variances) are shown with brackets. Revenue Total revenue.............................................................. Nine Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ 7,526.2 $ 6,466.3 $ 1,059.9 16.4% The change in total revenue is explained by category below. Electricity and steam revenue.............................................. Transmission sales revenue................................................. Sales of purchased power for hedging and optimization...................... Total electric generation and marketing revenue......................... Nine Months Ended September 30, --------------------------2005 2004 ------------- ------------$ 4,625.1 $ 3,851.9 8.8 14.2 1,193.5 1,301.6 ------------ -----------$ 5,827.4 $ 5,167.7 ============ ============ $ Change % Change ------------- ------------$ 773.2 20.1% (5.4) (38.0)% (108.1) (8.3)% -----------$ 659.7 12.8% ============ Electricity and steam revenue increased as we completed construction and brought into operation four new baseload power plants and one expansion project completed subsequent to September 30, 2004, and realized an increase in our average electric price before the effects of hedging, balancing and optimization, from $ 59.85/ MWh for the nine months ended September 30, 2004, to $ 67.78/ MWh for the same period in 2005. Average megawatts in operation of our consolidated plants increased by 13.2% to 25,079 MW while generation increased by 6.0%, resulting in a drop in our baseload capacity factor to 45.9% in the - 64 - nine months ended September 30, 2005, from 50.1% in the nine months ended September 30, 2004. This was primarily due to the increased occurrence of unattractive off-peak market spark spreads in certain areas reflecting oversupply conditions which are expected to gradually improve over the next several years, but which caused us to cycle-off certain of our merchant plants without contracts in off-peak hours. We purchase transmission capacity so that power can move from our plants to our customers. Transmission capacity can be purchased on a long term basis and, in many of the markets in which the company operates, can be resold if the Company does not need it and some other party can use it. If the generation from our plants is less than we anticipated when we purchased the transmission capacity, we can realize revenue by selling the unused portion of the transmission capacity. Sales of purchased power for hedging and optimization decreased in the nine months ended September 30, 2005, due primarily to lower volumes which were partially offset by higher prices, as compared to the same period in 2004. Oil and gas sales.......................................................... Sales of purchased gas for hedging and optimization........................ Total oil and gas production and marketing revenue...................... Nine Months Ended September 30, --------------------------2005 2004 ------------- ------------$ -$ 4.7 1,574.1 1,258.4 ------------ -----------$ 1,574.1 $ 1,263.1 ============ ============ $ Change % Change ------------- ------------$ (4.7) (100.0)% 315.7 25.1% -----------$ 311.0 24.6% ============ We reclassified our remaining oil and gas operations, which were sold in July 2005, to discontinued operations in the nine months ended September 30, 2005. Activity in prior years relates to minor assets sold in prior years that did not meet the criteria for reclassification to discontinued operations at the time of sale. See Note 8 of the Notes to Consolidated Condensed Financial Statements for more information. Sales of purchased gas for hedging and optimization increased during 2005 due primarily to significantly higher natural gas prices and volumes compared to the same period in 2004. Mark-to-market activities, net............................................. Nine Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ 40.2 $ (15.3) $ 55.5 362.7% Mark-to-market activities, which are shown on a net basis, result from general market price movements against our open commodity derivative positions, These commodity positions represent a small portion of our overall commodity contract position. The net gain from mark-to-market activities in the nine months ended September 30, 2005, as compared to the same period in 2004 is due primarily to gains on our Deer Park transaction which are recorded on a mark-to-market basis, and gains attributable to gas contracts that lost hedge accounting eligibility for the quarter. In order to qualify for hedge accounting under SFAS No. 133, price movements in the hedge contract and the hedged transaction must move in a manner whereby changes in value of the hedge contract and hedged transaction sufficiently offset. As a result of significant volatility in the gas markets, certain of our gas contracts did not meet these requirements and we recorded approximately $18.3 million in mark-to-market gains that would have otherwise been recorded through other comprehensive income. Other revenue.............................................................. Nine Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ 84.6 $ 50.8 $ 33.8 66.5% Other revenue increased due primarily to higher revenues at PSM associated with sales of gas turbine components and at TTS for gas turbine maintenance services and spare turbine parts and component sales. - 65 - Cost of Revenue Cost of revenue............................................................ Nine Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ 7,124.9 $ 6,157.8 $ (967.1) (15.7)% The increase in total cost of revenue is explained by category below. Plant operating expense.................................................... Transmission purchase expense.............................................. Royalty expense............................................................ Purchased power expense for hedging and optimization....................... Total electric generation and marketing expense......................... Nine Months Ended September 30, --------------------------2005 2004 ------------- ------------$ 555.4 $ 522.2 63.8 53.8 28.3 21.1 960.1 1,165.7 ------------ -----------$ 1,607.6 $ 1,762.8 ============ ============ $ Change % Change ------------- ------------$ (33.2) (6.4)% (10.0) (18.6)% (7.2) (34.1)% 205.6 17.6% -----------$ 155.2 8.8% =========== Plant operating expense increased primarily due to four additional baseload power facilities and one expansion project that achieved commercial operation subsequent to September 30, 2004 and the timing of regular maintenance activities, partially offset by a decrease in major maintenance spending, which was also affected by timing differences versus prior year. In many cases, we incur transmission costs that result from serving the accounts of our customers. This is especially true in the case of many of our retail contracts. When we incur transmission expenses on behalf of our customers we recognize these amounts as a component of transmission purchase expense. For the nine months ended September 30, 2005 as compared to the same period in 2004 transmission purchase expenses have declined as we have seen a reduction in transmission purchases relating to our retail customers. Royalty expense increased primarily due to an increase in electric revenues at The Geysers geothermal plants and due to an increase in contingent purchase price payments to the previous owners of the Texas City and Clear Lake power plants, which are based on a percentage of gross revenues at the plants. At The Geysers, royalties are paid mostly as a percentage of geothermal electricity revenues. Purchased power expense for hedging and optimization decreased during the nine months ended September 30, 2005, as compared to the same period in 2004 due primarily to lower volumes which were partially offset by higher prices, as compared to the same period in 2004. Oil and gas operating expense.............................................. Purchased gas expense for hedging and optimization......................... Total oil and gas operating and marketing expense....................... Nine Months Ended September 30, --------------------------2005 2004 ------------- ------------$ 4.3 $ 5.8 1,623.7 1,243.8 ------------ -----------$ 1,628.0 $ 1,249.6 ============ ============ $ Change % Change ------------- ------------$ 1.5 25.9% (379.9) (30.5)% -----------$ (378.4) (30.3)% ============ We reclassified our remaining oil and gas operations, which were sold in July 2005, to discontinued operations in the nine months ended September 30, 2005. Remaining activity in continuing operations relates primarily to gas pipeline activities which were not sold and activity in prior years also includes the results of minor assets sold in prior years that did not meet the criteria for reclassification to discontinued operations at the time of sale. See Note 8 of the Notes to Consolidated Condensed Financial Statements for more information. Purchased gas expense for hedging and optimization increased during the nine months ended September 30, 2005, due to significantly higher natural gas prices and higher volumes as compared to the same period in 2004. - 66 - Fuel expense............................................................... Nine Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ 3,336.2 $ 2,671.9 $ (664.3) (24.9)% Fuel expense increased during the nine months ended September 30, 2005, as compared to the same period in 2004 due primarily to higher natural gas prices and an increase of 6.0% in generation due largely to the addition of four additional baseload power facilities and one expansion project to our consolidated operating portfolio subsequent to September 30, 2004. Our average fuel expense before the effects of hedging, balancing and optimization increased by 23% from $6.01/MMBtu for the nine months ended September 30, 2004 to $7.39/MMBtu for the same period in 2005. Depreciation, depletion and amortization expense........................... Nine Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ 371.3 $ 324.9 $ (46.4) (14.3)% Depreciation, depletion and amortization expense increased primarily due to the five additional power facilities in consolidated operations subsequent to September 30, 2004. Operating lease expense.................................................... Nine Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ 79.1 $ 80.6 $ 1.5 1.9% Operating lease expense decreased from the prior year due to the restructuring of the King City lease in May 2004. After the restructuring we began to account for the King City lease as a capital lease. As a result, we stopped incurring operating lease expense at that facility and instead began to incur depreciation and interest expense. Partially offsetting this decrease was an increase in operating lease expense due to upward revisions in our estimated dismantlement costs at our Watsonville facility at the end of the lease term in 2010. Other cost of revenue...................................................... Nine Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ 102.5 $ 68.2 $ (34.3) (50.3)% Other cost of revenue increased during the nine months ended September 30, 2005, as compared to the same period in 2004, due primarily to higher volumes of parts sales at PSM and TTS and high volumes of services work and spare turbine parts and component sales at TTS. (Income)/Expenses (Income) loss from unconsolidated investments.............................. Nine Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ (14.6) $ 12.2 $ 26.8 219.7% The increase in income was primarily due to an increase in income from the Acadia PP investment (mostly due to lower major maintenance costs), and the non-recurrence of losses recorded in 2004 from our investment in the AELLC power plant. We ceased to recognize our share of the operating results of AELLC as we - 67 - began to account for our investment in AELLC using the cost method following loss of effective control when AELLC filed for bankruptcy protection in November 2004. In September 2004, we recognized our share of AELLC's adverse jury verdict related to a dispute with International Paper of approximately $11.6. Equipment cancellation and impairment cost................................. Nine Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ 0.7 $ 10.2 $ 9.5 93.1% During the nine months ended September 30, 2005, equipment cancellation and asset impairment charge decreased by $9.5 as compared to the same period in 2004 primarily as a result of three non-recurring charges we incurred during 2004. During the nine months ended September 30, 2004, we incurred $2.3 in connection with the termination of a purchase contract for HRSG components, $4.3 in connection with the impairment charge for one HRSG and a loss on the sale of 12 tube bundles in the amount of $3.5. Long-term service agreement cancellation charge............................ Nine Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ 34.4 $ 4.0 $ (30.4) (760.0)% During the nine months ended September 30, 2005, we recorded charges of $33.8 related to the cancellation of nine LTSAs with GE as part of a restructuring of our service relationship. Additionally, we revised our previous estimate and recorded an additional $0.6 in charges related to previously cancelled LTSAs with Siemens Westinghouse. Project development expense................................................ Nine Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ 71.6 $ 15.1 $ (56.5) (374.2)% Project development expense increased by $56.5 during the nine months ended September 30, 2005 compared to the same period in 2004 primarily due to a charge of $44.8 to write off three projects in suspended development and $12.3 in site preservation costs related to four projects whose development/construction has been suspended. Research and development expense........................................... Nine Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ 15.5 $ 12.9 $ (2.6) (20.2)% Research and development expense increased during the nine months ended September 30, 2005, as compared to the same period in 2004 primarily due to increased personnel expense, and consulting fees related to new research and development programs and testing at PSM. Sales, general and administrative expense.................................. Nine Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ 176.3 $ 156.0 $ (20.3) (13.0)% Sales, general and administrative expense increased during the nine months ended September 30, 2005, primarily due to an increase in legal fees and the reclassification of $7.2 to discontinued operations in the nine months ended - 68 - September 30, 2004, related to the sale of the Canadian oil and gas reserves. Also contributing to the increase, although to a lesser extent, was additional amortization related to tenant improvements and personnel costs. Interest expense........................................................... Nine Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ 1,027.4 $ 791.2 $ (236.2) (29.9)% Interest expense increased primarily as a result of higher average interest rates and lower capitalization of interest expense. Our average interest rate increased from 8.4% for the nine months ended September 30, 2004, to 9.7% for the nine months ended September 30, 2005, primarily due to the impact of rising U.S. interest rates and their effect on our existing variable rate debt portfolio and higher average interest rates incurred on new debt instruments that were entered into to replace and/or refinance existing debt instruments during 2005. Interest capitalized decreased from $296.9 for the nine months ended September 30, 2004, to $169.1 for the nine months ended September 30, 2005, as new plants entered commercial operations (at which point capitalization of interest expense ceases) and because of suspended capitalization of interest on three partially completed construction projects. We expect that the amount of interest capitalized will continue to decrease in future periods as our plants in construction are completed. During the nine months ended September 30, 2005, (i) interest expense related to our Senior Notes, contingent convertible notes, and term loans increased by $26.1; (ii) interest expense related to our CalGen subsidiary increased $36.2; (iii) interest expense related to our construction/project financing increased by $48.2; (iv) interest expense related to our CCFC I subsidiary increased by $9.4; and (v) interest expense related to preferred interests increased by $46.1 primarily due to the October 2004 closing of the $360 offering of redeemable preferred securities by our indirect subsidiary, Calpine Jersey I, and the $260 offering on January 31, 2005, of redeemable preferred securities by our indirect subsidiary, Calpine Jersey II (the Calpine Jersey I and Calpine Jersey II securities were repurchased with proceeds from the sale of Saltend in July 2005). The $155 offering of redeemable preferred securities by our indirect subsidiary, Metcalf, and the $150 offering of redeemable preferred securities by our indirect subsidiary, CCFC LLC. These increases in interest expense are partially offset by the decrease in interest expense of $33.3 related to the convertible debentures payable to the Calpine Capital Trusts, which have been redeemed. Interest (income).......................................................... Nine Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ (57.4) $ (38.0) $ 19.4 51.1% Interest (income) increased during the nine months ended September 30, 2005, due primarily to higher interest earned on margin deposits and collateral posted to secure letters of credit and due to higher interest rates. Minority interest expense.................................................. Nine Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ 31.8 $ 23.1 $ (8.7) (37.7)% Minority interest expense increased during the nine months ended September 30, 2005, as compared to the same period in 2004 primarily due to an increase in income at CPLP, which is 70% owned by CPIF. The variance is largely due to an increase in availability at the Island Cogen plant in 2005 as a result of non-recurrence of major maintenance work performed during 2004. (Income) from repurchase of debt........................................... - 69 - Nine Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ (166.5) $ (170.5) $ (4.0) (2.3)% The decrease in income from repurchase of debt is due to considerably higher volumes (approximately $356.2) of Senior Notes repurchased during the nine months ended September 30, 2004, versus 263.5in the same period in 2005. The decrease was partially offset by higher discounts associated with repurchases in the nine months ended September 30, 2005 compared to the same period in 2004. See Note 7 of the Notes to Consolidated Condensed Financial Statements for further information. Other expense (income), net................................................ Nine Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ 71.4 $ (168.9) $ (240.3) (142.3)% Other expense increased $240.3 for the nine months ended September 30, 2005, compared to a gain in the same period in 2004, primarily due to non-recurring gains in the nine months ended September 30, 2004 of $171.5 related to the restructuring and sale of power purchase agreements for two of our New Jersey plants, net of transaction costs and the write-off of unamortized deferred financing costs. Also contributing to the unfavorable variance was an impairment charge of $18.5 in 2005 related to our investment in Grays Ferry, $11.4 of additional legal reserves provided for in 2005 compared to 2004, $8.4 of higher letter of credit fees in 2005 compared to 2004 and the write-off of $5.9 of unamortized deferred financing costs in connection with the refinancing of our Metcalf facility's project debt in 2005. Finally, during the nine months ended September 30, 2005, non-cash foreign currency transaction losses were higher than the same period in 2004 by $10.7. See the "foreign currency transaction gain (loss)" discussion within "Financial Market Risks" for further information. Benefit for income taxes................................................... Nine Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ (167.9) $ (144.3) $ 23.6 16.4% During the nine months ended September 30, 2005, our tax benefit increased as compared to the nine months ended September 30, 2004 as our pre-tax loss increased in 2005 by approximately $450.5. The effective tax rate decreased to 21.3% in 2005 compared to 42.6% in the same period in 2004. The favorable variance of $23.6 was relatively moderate despite the significant increase in our pre-tax loss largely due to a reserve recorded on certain deferred tax assets associated with CCFC which had the effect of reducing the tax benefit on tour pre-tax loss by approximately $143.4 million. The tax rates on continuing operations for the nine months ended September 30, 2004, have been restated to reflect the reclassification to discontinued operations of certain tax expense related to the sale of oil and gas reserves, Saltend, and the Morris and Ontelaunee power plants. See Note 8 of the Notes to Consolidated Condensed Financial Statements for more information. Discontinued operations, net of tax........................................ Nine Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ (62.4) $ 235.7 $ (298.1) (126.5)% During the nine months ended September 30, 2005, discontinued operations activity primarily consisted of the pre-tax gain on the sale of Saltend of $23.7 and the pre-tax gain on the sale of substantially all of our remaining oil and gas assets of $340.2; both dispositions closed in July 2005. Offsetting these gains are two pre-tax impairment charges of $106.2 and $136.8, related to the sale of Morris and the pending sale of Ontelaunee, respectively; Ontelaunee met the discontinued operations criterion as of September 30, 2005, under SFAS No. 144 and was written down to the estimated sales price, less transaction costs. On a pre-tax basis, we recorded income from discontinued operations for the nine months ended September 30, 2005 of $75.2. However, our effective tax rate on discontinued operations for the three months ended September 30, 2005 was 183.0% due primarily to a large tax return gain on the sale of Saltend and, as a consequence, we recognized an after-tax loss from discontinued operations of $62.4. Discontinued operations for the nine months ended September 30, 2004 consisted primarily of a pre-tax gain from the sale of our Canadian and U.S. Rocky Mountain oil and gas assets of $203.5, and a pre-tax gain from the sale of - 70 - the Lost Pines I Power project of $35.3 as well as operating income from Lost Pines I, Saltend and our Canadian and U.S. oil and gas operations. Operating income from Saltend and the oil and gas assets were considerably higher for the nine months ended September 30, 2004 compared to the same period in 2005 primarily due to the inclusion of the Canadian and U.S. Rocky Mountain income within 2004 results and significant foreign currency transaction losses at Saltend in 2005 related to a foreign currency exposure which did not exist during the nine months ended September 30, 2004. On a net of tax basis, income from discontinued operations for the nine months ended September 30, 2004 was $235.7, based on an effective tax rate of 28.1%. Net income (loss).......................................................... Nine Months Ended September 30, --------------------------2005 2004 $ Change % Change ------------- ------------- ------------- ------------$ (683.9) $ 41.2 $ (725.1) (1,760.0)% For the nine months ended September 30, 2005, we reported revenue of $7.5 billion, representing an increase of 16.4% over the same period in the prior year. Including the discontinued operations discussed below, we recorded a net loss per share of $1.49, or a net loss of $683.9, compared to net income per share of $0.10, or net income of $41.2, for the same period in the prior year. For the nine months ended September 30, 2005, our average capacity in operation for consolidated projects in continuing operations increased by 13.2% to 25,079 megawatts. Generation volume was up 6.0% from the prior year as we generated approximately 68.2 million megawatt-hours, which equated to a baseload capacity factor of 45.9%, and realized an average spark spread of $22.16 per megawatt-hour. For the same period in 2004, we generated 64.4 million megawatt-hours, which equated to a baseload capacity factor of 50.1%, and realized an average spark spread of $20.45 per megawatt-hour. Gross profit increased by $92.8, or 30.1%, to $401.3 in the nine months ended September 30, 2005, compared to the same period in the prior year, as total spark spread increased by $196.1 period-to-period. However, spark spread did not increase in line with the increases in plant operating expense, net transmission purchase expense, depreciation, and interest expense. During the nine months ended September 30, 2005, financial results were positively impacted by $166.5 of income recorded from repurchase of debt (compared to $170.5 in the same period of 2004) and negatively impacted by $34.4 in long-term service agreement cancellation charges. In addition, we recorded $44.8 in project development expense due to the write-off of three projects in suspended development and $12.3 in project development expense on preservation costs for suspended projects. Interest expense increased $236.1 between periods primarily due to an increase in the average interest rate and lower capitalization of interest expense as fewer plants were in active construction. Other expense was $71.4 for the nine months ended September 30, 2005, compared to other income of $168.9 for the nine months ended September 30, 2004. The net expense for the nine months ended September 30, 2005, was due mainly to an impairment charge of $18.5 related to the sale of our interest in Grays Ferry in July 2005, $18.3 of non-cash foreign currency transactions losses related to inter-company transactions (versus $7.6 in the prior year), $16.6 in letter of credit fees (versus $8.4 in the prior year) and higher legal reserves. Other income for the nine months ended September 30, 2004, included approximately $171 in pre-tax gains from the restructuring and sale of power purchase agreements for two of the company's New Jersey plants, net of transaction costs and the write-off of unamortized deferred financing costs. In the nine months ended September 30, 2005 we recorded a pre-tax gain from discontinued operations of $75.2. However, our year-to-date effective tax rate on discontinued operations was 183% due primarily to a large tax return gain on the sale of Saltend and, as a consequence, we incurred an after-tax loss from discontinued operations of $62.4. Discontinued operations included gains on the sale of our remaining oil and gas assets and Saltend , both of which closed in July 2005, and an impairment charge associated with the pending sale of Ontelaunee , which was classified as held for sale at September 30, 2005 and closed in October 2005. Discontinued operations also includes the operating results until the respective sales dates for those entities and the Morris power plant, for which we recorded an impairment charge in accordance with SFAS No. 144 in the second quarter of 2005, and which was sold in the third quarter of 2005. For the nine months ended September 30, 2004, we recorded a net gain in discontinued operations of $235.7 from the sales of our Canadian and U. S. Rocky Mountain oil and gas assets and the Lost Pines 1 Power Project. - 71 - Liquidity and Capital Resources Our business is capital intensive. Our ability to capitalize on growth opportunities and to service the debt we incurred in order to construct and operate our current fleet of power plants is dependent on the continued availability of capital. The availability of such capital in today's environment remains uncertain. To date, we have obtained cash from our operations; borrowings under credit facilities; issuances of debt, equity, preferred securities and convertible and contingent convertible notes; proceeds from sale/leaseback transactions; sale or partial sale of certain assets; prepayments received for power sales; contract monetizations; and project financings. We have utilized this cash to fund operations, service, repay or refinance debt obligations, fund acquisitions, develop and construct power generation facilities, finance capital expenditures, support hedging, balancing, optimization and trading activities, and meet other cash and liquidity needs. Consistent with our strategic initiative announced in May 2005, we expect to rely to a greater extent than in the past on asset sales to reduce debt and related interest expense and to improve our liquidity position. Transactions completed in the three months ended September 30, 2005: o Issued $150.0 million of Class A Redeemable Preferred Shares due 2006, through our indirect subsidiary, CCFC LLC, which is an indirect parent of CCFC I, which owns a portfolio of six operating natural gas-fired power plants (not including Ontelaunee, which met the held for sale criteria as of September 30, 2005) with the generation capacity of more than 3,600 megawatts. The Redeemable Preferred Shares bear an initial dividend rate of LIBOR plus 950 basis points and were redeemable in whole or in part at any time by CCFC LLC at par plus accrued dividends. The Redeemable Preferred Shares were repurchased in full on October 14, 2005. o Completed the sale of substantially all of our remaining domestic oil and gas exploration and production properties and assets for $1.05 billion, less adjustments, transaction fees and expenses, and less approximately $75 million to reflect the value of certain oil and gas properties for which we were unable to obtain consents to assignment prior to closing. Certain of the consents have been received subsequent to September 30, 2005, and we expect to receive the remaining consents by December 31, 2005. As further discussed in Note 12 of the Notes to Consolidated Condensed Financial Statements, the Company initiated a lawsuit seeking access to blocked proceeds from the sale. o Completed the sale of Saltend, a 1,200-MW power plant in Hull, England, generating total gross proceeds of $862.9 million. Of this amount, approximately $647.1 million was used to redeem the $360.0 million Two-Year Redeemable Preferred Shares issued by our Calpine Jersey I subsidiary on October 26, 2004, and the $260.0 million Redeemable Preferred Shares issued by our Calpine Jersey II subsidiary on January 31, 2005, including interest and termination fees of $16.3 million and $10.8 million, respectively. As described further in Note 12 of the Notes to Consolidated Condensed Financial Statements, certain bondholders filed a lawsuit concerning the use of the proceeds remaining from the sale of Saltend. As discussed in Note 12, certain bondholders initiated a lawsuit concerning the use of the proceeds remaining from the sale of Saltend. o Completed the sale of our Inland Empire Energy Center development project to GE, for approximately $30.9 million. The project will be financed, owned and operated by GE and will be used to launch GE's most advanced gas turbine technology, the "H System (TM)." The Company will manage plant construction, market the plant's output, and manage its fuel requirements. The Company has an option to purchase the facility in years seven through fifteen following the commercial operation date and GE can require the Company to purchase the facility for a limited period of time in the fifteenth year, all subject to satisfaction of various terms and conditions. If the Company purchases the facility under the call or put, GE will continue to provide critical plant maintenance services throughout the remaining estimated useful life of the facility. Because of continuing involvement related to the purchase option and put, the Company deferred the gain of approximately $10 million until the call or put option is either exercised or expires. o Completed the sale of our 50% interest in the 175-MW Grays Ferry power plant for gross proceeds of $37.4 million. We recorded an impairment charge of $18.5 million related to our interest in the quarter ended June 30, 2005. o Completed the sale of our 156-MW Morris power plant for approximately $84.5 million. In the three months ended June 30, 2005, we recorded a $106.2 million impairment charge related to our commitment to a plan - 72 - of divesture of this facility, which was subsequently reclassified to discontinued operations in the three months ended September 30, 2005, upon completion of the sale. o Repurchased approximately $138.9 million of our First Priority Notes pursuant to a tender offer. Following the completion of the tender offer, we now have approximately $641.5 million aggregate principal amount of First Priority Notes outstanding. o Announced a 15-year Master Products and Services Agreement with GE, which is expected to lower operating costs in the future. As a result of nine GE LTSA cancellations, we recorded $33.3 million in charges in the quarter ended June 30, 2005. o Signed an agreement with Siemens-Westinghouse to restructure the long-term relationship, which we expect will provide us additional flexibility to self-perform maintenance work in the future. CalBear Transaction. On September 7, 2005, we and CES entered into a Master Transaction Agreement with Bear Stearns pursuant to which we agreed to create a new energy marketing and trading venture with Bear Stearns. At the closing of the transactions contemplated by the Master Transaction Agreement, our indirect, wholly owned subsidiary CMSC, and Bear Stearns' wholly owned subsidiary CalBear, will also become parties. Pursuant to the terms of the Master Transaction Agreement, upon closing, we and our affiliates, on the one hand, and Bear Stearns and its affiliates, on the other hand, will each refer certain trades and third party service transactions to CalBear. This referral obligation does not include any transaction that could be serviced by, used by, hedge cash flow from or otherwise optimize the results or flexibility of the assets of the referring entity. Bear Stearns has agreed to provide CalBear with all funds and collateral necessary for CalBear to perform its obligations under certain agreements and to provide certain other financial support to CalBear. The closing is subject to certain conditions, including the execution and delivery of certain agreements, including an Agency and Services Agreement by and among CMSC and CalBear, pursuant to which CMSC will act as CalBear's exclusive agent for gas and power trading; a Trading Master Agreement by and among CES, CMSC and CalBear, pursuant to which CalBear will execute credit enhancement trades on behalf of CES; and an ISDA Master Agreement, Schedule, and applicable annexes between CES and CalBear to effectuate the credit enhancement trades. Pursuant to the Agency and Services Agreement, CSMC will earn service fees (a portion of which will be held in reserve during the term of the Agency and Services Agreement) equal to 50% of CalBear's profits, which fees (including the reserve) are subject to a requirement to return based on losses at CalBear, up to 50% of such losses. We received FERC approval on October 31, 2005. The Master Transaction Agreement and the agreements entered into thereunder will terminate on November 30, 2006 unless both we and Bear Stearns affirm the continuation of the Master Transaction Agreement upon 90 days' advance notice to the other, and will terminate at the end of each calendar quarter thereafter unless extended by both parties. In addition, both we and Bear Stearns may terminate the Master Transaction Agreement voluntarily upon 90 days' advance written notice and for specified causes. In addition, none of the parties will enter into a venture that substantially replicates the transactions contemplated by the Master Transaction Agreement during its term and for a period of up to two years after its termination, depending upon the reason for the termination. Transactions completed subsequent to September 30, 2005 (See Note 15 of the Notes to Consolidated Condensed Financial Statements for more information): o Completed the sale of our 561-MW Ontelaunee power plant for $225.0 million, less transaction costs and working capital adjustments of approximately $13.0 million. The Company recorded an impairment charge of $136.8 million as of September 30, 2005, is reflected in discontinued operations. The sale of Ontelaunee closed October 6, 2005. See Notes 5 and 8 of the Notes to Consolidated Condensed Financial Statements for more information. CCFC I made offers to purchase its outstanding debt with the proceeds of the Ontelaunee sale in accordance with the instruments governing such debt. The offers have expired, and none of the holders of such debt elected to have their debt repurchased. o Received funding for CCFC LLC's $300.0 million offering of 6-year Redeemable Preferred Shares 2011. o Repurchased the CCFC LLC $150.0 million Class A Redeemable Preferred Shares due 2006. While we have recognized a pre-tax gain overall on asset sales completed during the three and nine months ended September 30, 2005, we have recognized significant impairment charges or losses with respect to certain asset sales, including the sale of the Morris facility, as well as the sale of the Ontelaunee facility in October 2005. We are considering the sale of additional assets in - 73 - connection with our strategic initiative program, and it is possible that some or all of the additional asset sales contemplated could lead to material impairment charges or losses upon sale. As a result of transactions subsequent to March 31, 2005, we have lowered our total debt at September 30, 2005, by approximately $0.9 billion to $17.2 billion. Excluding the effect of new construction financing of $178.7 million, the Company has reduced debt by approximately $1.1 billion in this six month period. Debt repurchases and redemptions during the three months ended September 30, 2005: During the three months ended September 30, 2005, we repurchased Senior Notes in open market transactions totaling $263.5 million in principal amount. For cash of $233.9 million plus accrued interest, we repurchased the Senior Notes as follows (in thousands): Senior Notes -----------8 1/4% due 2005................................................................................. 10 1/2 % due 2006............................................................................... 7 5/8% due 2006................................................................................. 8 3/4% due 2007................................................................................. 7 7/8% due 2008................................................................................. 8 1/2% due 2008................................................................................. 7 3/4% due 2009................................................................................. 9 5/8% due 2014................................................................................. Total repurchases............................................................................ Principal ----------------4,000.0 10,005.0 8,051.0 2,000.0 $ 53,500.0 41,000.0 6,000.0 138,895.0 ---------------$ 263,451.0 ================ Cash Payment --------------3,985.0 9,671.0 7,648.4 1,570.0 $ 39,598.8 3,900.0 28,632.5 138,895.0 ---------------$ 233,900.7 ================ For the three months ended September 30, 2005, we recorded an aggregate pre-tax gain of $23.6 million on the above repurchases after the write-off of unamortized deferred financing costs, legal fees, and unamortized discounts. In addition, we redeemed and extinguished HIGH TIDES III for a pre-tax loss of $8.0 million after the write-off of unamortized deferred financing costs, legal fees and unamortized discounts. The sale of assets to reduce debt and lower annual interest costs is expected to materially lower our revenues, spark spread and gross profit (loss) in the near term and possibly longer. The final mix of assets actually sold will determine the degree of impact on operating results. While lowering debt, the accomplishment of the strategic initiative program, in and of itself, will likely not lead to improvement in certain measures of interest and principal coverage without significant improvement in market conditions. The amount of offsetting future interest savings will be a function of the principal amount of debt retired, and the interest rate born by such debt, and the amount that we will spend to reduce debt will depend on the market price of such debt and other factors. The final net future earnings impact of the initiatives is still uncertain. Our ability to use the proceeds from asset sales is generally subject to restrictions in our indentures (see Note 7 to the Consolidated Condensed Financial Statements). Further, as discussed above and in Note 12 of the Notes to Consolidated Condensed Financial Statements, we have experienced certain legal challenges to our intended use of proceeds from certain asset sales, and such challenges could affect the timing or ultimate use of such proceeds. Capital Availability -- While we have been able to access the capital and bank credit markets since 2002, it has been on significantly different terms than before 2002. In particular, our senior working capital facilities and term loan financings entered into, and the majority of our debt securities offered and sold by us have been secured by certain of our assets and subsidiary equity interests. We have also provided security to support our prepaid commodity transactions and, as our credit ratings have been downgraded, we have been required to post cash collateral to support our hedging, balancing and optimization activities. In the aggregate, the average interest rate on our new debt instruments, especially on recent issuances of subsidiary preferred stock and or debt incurred to refinance existing debt, has been higher. The terms of capital available to us now and in the future may not be attractive to us or our access to capital markets may otherwise become restricted. 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. In addition, we are currently involved in various litigations with the holders of certain series of our outstanding secured and unsecured bonds as described in Note 12 of the Notes to Consolidated Condensed Financial Statements. The outcome of these litigations is uncertain, and if, as a result of these litigations, the Company's access to the proceeds of asset sales continues to be restricted, or the Company is required to restore proceeds of asset sales that have previously been utilized by the Company, it could have a material adverse effect on the Company and its liquidity. - 74 - Satisfying the obligations under our outstanding indebtedness, and funding anticipated capital expenditures and working capital requirements for the next twelve months and potentially thereafter, presents us with several challenges as our cash requirements are expected to exceed the sum of our cash on hand permitted to be used to satisfy such requirements and cash from operations. Accordingly, we have in place a strategic initiative, discussed above, which includes several components including possible sales or monetizations of certain of our assets. Whether we will have sufficient liquidity will depend, in part, on the success of that program. No assurance can be given that it will be successful. If it is not successful, additional asset sales, refinancings, monetizations and other actions beyond those included in the strategic initiative would likely need to be made or taken, depending on market conditions. Our ability to reduce debt will also depend on our ability to repurchase debt securities through open market and other transactions, and the principal amount of debt we are able to repurchase will be contingent upon market prices and other factors, including the ultimate outcome of disputes related to our intended use of the proceeds of certain asset sales (see Note 12 of the Notes to Consolidated Condensed Financial Statements for more information). Even if our strategic initiative program is successful, there can be no assurance that we will be able to continue work on our projects in development and suspended construction that have not been successfully project financed, and we could possibly incur substantial impairment losses as a result. Even if the strategic initiative is successful, until there are significant sustained improvements in spark spreads, we expect that we will not have sufficient cash flow from operations to repay all of our indebtedness at maturity or to fund our other liquidity needs. We expect that we will need to extend or refinance all or a portion of our indebtedness on or before maturity. While we currently believe that we will be successful in repaying, extending or refinancing all of our indebtedness on or before maturity, we cannot assure you that we will be able to do so on attractive terms, or at all. For further discussion of this see the risk factors in our 2004 Form 10-K and our Current Report on Form 8-K filed with the SEC on July 1, 2005. Cash Flow Activities -- The following table summarizes our cash flow activities for the periods indicated: Beginning cash and cash equivalents............................................................ Net cash provided by (used in): Operating activities......................................................................... Investing activities......................................................................... Financing activities......................................................................... Effect of exchange rates changes on cash and cash equivalents................................ Change in discontinued operations cash classified as current assets held for sale............ Net increase in cash and cash equivalents.................................................... Ending cash and cash equivalents............................................................... Nine Months Ended September 30, ---------------------------------2005 2004 --------------------------(In thousands) $ 718,023 $ 954,827 (407,973) 822,689 (308,971) 741 18,627 -------------125,113 -------------$ 843,136 ============== 229,870 (381,934) 633,703 14,377 7,694 -------------503,710 -------------$ 1,458,537 ============== Operating activities for the nine months ended September 30, 2005, used net cash of $408.0 million, as compared to providing $229.9 million for the same period in 2004. In the first nine months of 2005 there was a $205.2 million use of funds from net changes in operating assets and liabilities comprised of an increase in accounts receivable of $416.5 million and an increase in net margin deposits posted to support CES contracting activity of $24.1 million. This was offset by an increase in accounts payable of $212.1 million and a decrease in inventory of $20.0 million. The significant increase in accounts receivable period over period was primarily due to the significant increase in power prices during the three-month period ended September 30, 2005, and to a lesser extent, an increase in megawatt hours sold (due to additional generation capacity) from September 30, 2004 to September 30, 2005. In the first nine months of 2004, operating cash flows benefited from the receipt of $100.6 million from the termination of power purchase agreements for two of our New Jersey power plants and $16.4 million from the restructuring of a long-term gas supply contract. We had an $11.3 million use of funds from net changes in operating assets and liabilities, including an increase of $104.8 million in accounts receivable, partially offset by an increase of $218.9 million in accounts payable and a $14.1 million decrease in net margin deposits posted to support CES contracting activity. Investing activities for the nine months ended September 30, 2005, provided net cash of $822.7 million, as compared to using $381.9 million in the same period of 2004. Capital expenditures, including capitalized interest, for the completion of our power facilities decreased from $1,184.4 million in 2004 to - 75 - $675.7 million in 2005 as there were fewer projects under construction. Investing activities in 2005 reflected the receipt of $897.6 million from the sale of our oil and natural gas assets, $843.1 million from the sale of our Saltend power plant in the UK, $84.5 million from the sale of our Morris facility, $30.4 million from the sale of our Inland Empire development project and $36.9 million from the sale of our investment in the Grays Ferry power plant. Additionally, investing activities in 2005 reflect the receipt of $132.5 million from the disposition of our investment in High Tides III, offset by a $559.9 million increase in restricted cash, including $401.7 million from the proceeds of the sale of our oil and gas assets, which is the subject of a lawsuit. See Note 12 in the Notes to Consolidated Condensed Financial Statements for more information regarding this matter. Investing activities in 2004 reflect the receipt of $148.6 million from the sale of our 50% interest in the Lost Pines I Power Plant, $626.6 million from the sale of our Canadian oil and gas reserves, $219.1 million from the sale of our U.S. Rocky Mountain oil and gas reserves, together with the proceeds from the sale of a subsidiary holding power purchase agreements for two of our New Jersey power plants, offset by the purchase of the Brazos Valley power plant, the remaining 50% interest in the Aries power plant, and the remaining 20% interest in Calpine Cogen. Also, we used $111.6 million to purchase a portion of High Tides III and invested $124.2 million in restricted cash during the nine month period of 2004 Financing activities for the nine months ended September 30, 2005, used $309.0 million, as compared to providing $633.7 million in 2004. We continued our refinancing program in the first nine months of 2005 by raising $260.0, $155.0 and $150.0 million (which was repurchased on October 14, 2005) from preferred securities offerings by Calpine Jersey II, Metcalf and CCFC LLC, respectively, $650.0 million from the 2015 Convertible Notes offering, $621.0 million from various project financings and $290.6 million from a prepaid commodity derivative contract at our Deer Park facility. We continued our debt reduction program by using $353.3 million to repay notes payable and project financing debt, $628.5 million to repay preferred security offerings (including the Calpine Jersey II mentioned above) in addition to using $821.3 million to repay or repurchase Senior Notes and $517.5 million to repay High Tides III. Additionally, we incurred $89.3 million in financing and transaction costs. Working Capital -- At September 30, 2005, we had working capital of $520.8 million which increased approximately $242.7 million from December 31, 2004. The increase was primarily due to increases of $494.6 million, $513.4 million, and $379.5 million in accounts receivable, restricted cash, and current derivative assets, respectively, offset by increases of $212.1 million, $249.4 million and $618.1 million in accounts payable, Senior Notes, current portion and current derivative liabilities, respectively, from December 31, 2004, to September 30, 2005. The increase in accounts receivable period over the period was primarily due to the significant increase in power prices during the three-month period ended September 30, 2005, and to a lesser extent, an increase in megawatt hours sold (due to additional generating capacity). Restricted cash increased primarily due to the addition of $607.5 in remaining net proceeds from the sale of Saltend and our remaining oil and gas assets in July 2005. Our current derivative assets and liabilities increased significantly primarily as a result of significantly higher electricity and natural gas prices at the end of the third quarter in 2005. Cash flow used in operating activities during the nine-month period ended September 30, 2005, was $408.0 million and is expected to continue to be negative at least for the near term and possibly longer. On September 30, 2005, our cash and cash equivalents on hand totaled $843.1 million. The current portion of restricted cash totaled $1,106.7 million. See Note 2 for more information on our cash and cash equivalents and restricted cash. Counterparties and Customers -- Our customer and supplier base is concentrated within the energy industry. Additionally, we have exposure to trends within the energy industry, including declines in the creditworthiness of our marketing counterparties. Currently, multiple companies within the energy industry have below investment grade credit ratings and certain have sought bankruptcy protection or reorganization. However, we do not currently have any significant exposures to counterparties that are not paying on a current basis. Letter of Credit Facilities -- At September 30, 2005 and December 31, 2004, we had approximately $592.1 million and $596.1 million, respectively, in letters of credit outstanding under various credit facilities to support our risk management and other operational and construction activities. Of the total letters of credit outstanding, $194.4 million and $233.3 million, respectively, were issued under the cash collateralized letter of credit facility at September 30, 2005 and December 31, 2004, respectively. Commodity Margin Deposits and Other Credit Support -- As of September 30, 2005 and December 31, 2004, to support commodity transactions we had deposited net amounts of $273.0 million and $248.9 million, respectively, in cash as margin deposits with third parties, and we made gas and power prepayments of $78.9 million, and $78.0 million, respectively, and had letters of credit outstanding of $181.1 million and $115.9 million, respectively. Since December 31, 2004, such amounts have increased as commodity prices have risen. We use - 76 - margin deposits, prepayments and letters of credit as credit support for commodity procurement and risk management activities. Future cash collateral requirements may increase or decrease based on the extent of our involvement in standard contracts and movements in commodity prices and also based on our credit ratings and general perception of creditworthiness in the market. Unrestricted Subsidiaries -- The information in this paragraph is required to be provided under the terms of the Second Priority Secured Debt Instruments. We have designated certain of our subsidiaries as "unrestricted subsidiaries" under the Second Priority Secured Debt Instruments. A subsidiary with "unrestricted" status thereunder generally is not required to comply with the covenants contained therein that are applicable to "restricted subsidiaries." We have designated Calpine Gilroy 1, Inc., Calpine Gilroy 2, Inc. and Calpine Gilroy Cogen, L.P. as "unrestricted subsidiaries" for purposes of the Second Priority Secured Debt Instruments. The following table sets forth selected balance sheet information of Calpine Corporation and restricted subsidiaries and of such unrestricted subsidiaries at September 30, 2005, and selected income statement information for the nine months ended September 30, 2005 (in thousands): Assets...................................................... Liabilities................................................. Total revenue............................................... Total cost of revenue....................................... Interest income............................................. Interest expense............................................ Other....................................................... Net income................................................ Calpine Corporation and Restricted Subsidiaries --------------$ 26,888,675 =============== $ 22,708,923 =============== $ 7,522,915 (7,117,986) 49,947 (1,017,659) (116,371) --------------$ (679,154) =============== Unrestricted Subsidiaries --------------$ 429,183 =============== $ 246,149 =============== $ 9,781 (16,305) 12,706 (9,723) 1,132 --------------$ (2,409) =============== Eliminations --------------$ (229,621) =============== $ -================ $ (6,468) 9,388 (5,236) -----------------$ (2,316) =============== Total ---------------$ 27,088,237 =============== $ 22,955,072 =============== $ 7,526,228 (7,124,903) 57,417 (1,027,382) (115,239) --------------$ (683,879) =============== Bankruptcy-Remote Subsidiaries -- Pursuant to applicable transaction agreements, we have established certain of our entities separate from Calpine and its other subsidiaries. At September 30, 2005 these entities included: CCFC LLC, Metcalf LLC, Rocky Mountain Energy Center, LLC, Riverside Energy Center, LLC, Calpine Riverside Holdings, LLC, Calpine Energy Management, L.P., CES GP, LLC, PCF, PCF III, CNEM, Calpine Northbrook Energy Marketing Holdings, LLC, Gilroy Energy Center, LLC, Calpine Gilroy Cogen, L.P., Calpine Gilroy I, Inc., Calpine King City Cogen, LLC, Calpine Securities Company, L.P. (a parent company of Calpine King City Cogen, LLC), and Calpine King City, LLC (an indirect parent company of Calpine Securities Company, L.P.), Calpine Deer Park Partner, LLC, Calpine DP, LLC and Deer Park. Indenture and Debt and Lease Covenant Compliance -- Certain of our indentures place conditions on our ability to issue indebtedness if our interest coverage ratio (as defined in those indentures) is below 2:1. Currently, our interest coverage ratio (as so defined) is below 2:1 and, consequently, we generally would not be allowed to issue new debt, except for (i) certain types of new indebtedness that refinances or replaces existing indebtedness, and (ii) non-recourse debt and preferred equity interests issued by our subsidiaries for purposes of financing certain types of capital expenditures, including plant development, construction and acquisition expenses. In addition, if and so long as our interest coverage ratio is below 2:1, our ability to invest in unrestricted subsidiaries and non-subsidiary affiliates and make certain other types of restricted payments will be limited. Moreover, certain of our indentures will prohibit any further investments in non-subsidiary affiliates if and for so long as our interest coverage ratio (as defined therein) is below 1.75:1 and, as of September 30, 2005, such interest coverage ratio was below 1.75:1. We currently do not expect this limitation on our ability to make investments in non-subsidiary affiliates to have a material impact on our business. Certain of the Company's indebtedness issued in the last half of 2004 was incurred in reliance on provisions in certain of its existing indentures pursuant to which the Company is able to incur indebtedness if, after giving effect to the incurrence and the repayment of other indebtedness with the proceeds there from, the Company's interest coverage ratio (as defined in those indentures) is greater than 2:1. In order to satisfy the interest coverage ratio requirement in connection with such issuances, the proceeds thereof was required to be used to repurchase or redeem other existing indebtedness. As previously reported in the Company's 2004 10-K and its Quarterly Reports on Form 10-Q for the first two quarters of 2005, the Company completed a substantial portion of such repurchases during the fourth quarter of 2004 and the first six months of 2005. The Company completed the required repurchases, spending approximately - 77 - $248.4 million in the third quarter of 2005 to repurchase debt, and has now fully satisfied this requirement. The amount we were required to spend exceeded our estimate of $184.0 million because the required principal amount of debt was repurchased at prices higher than originally anticipated. When the Company or one of its subsidiaries sells a significant asset or issues preferred equity, the Company's indentures generally require that the net proceeds of the transaction be used to make capital expenditures, to acquire permitted assets or capital stock, or to repurchase or repay indebtedness, in each case within 365 days of the closing date of the transaction. To the extent that $50 million or more of such net proceeds are not so used, the Company is required under the terms of its secured debt instruments to make an offer to purchase its outstanding senior secured indebtedness up to the amount of the unused net proceeds. This general requirement contains certain customary exceptions, and, in the case of certain assets defined as "designated assets" under some of the Company's indentures, including the gas portion of the Company's oil and gas assets sold in July 2005, there are additional provisions discussed further below that apply to the use of the proceeds of a sale of those assets. In light of these requirements, and after taking into account the amount of capital expenditures currently budgeted for the remainder of 2005 and forecasted for 2006, the Company anticipates that, in the fourth quarter of 2005 and the first three quarters of 2006, it will need to use approximately $195.5 million and $668.5 million, respectively, of the net proceeds from four series of preferred equity issued by subsidiaries of the Company and three asset sale transactions, all completed prior to September 30, 2005, to repurchase or repay indebtedness or acquire assets or capital stock. The Company has, subsequent to September 30, 2005, fulfilled the portion of this obligation as required to be completed in the fourth quarter of 2005. Accordingly, assuming that the Company would fulfill the remaining obligations by repurchasing indebtedness, an aggregate amount of approximately $714.0 million of Senior notes and terms loans, net of current portion, and $150.0 million of Preferred interest, net of current portion, related to this use of remaining net proceeds requirement has been classified as Senior Notes, current portion, and Preferred interest, current portion, respectively, on the Company's Consolidated Condensed Balance Sheet as of September 30, 2005. The actual amount of the net proceeds that will be required to be used to repurchase or repay debt will depend, among other things, upon the actual amount of the net proceeds that is used to make capital expenditures or acquire other assets or capital stock, which may be more or less than the amount currently budgeted and/or forecasted. This amount includes $207.5 million of the net proceeds of the sale of Saltend. As described further in Note 12 of the Notes to Consolidated Condensed Financial Statements, certain bondholders filed a lawsuit concerning the use of the proceeds from the sale of Saltend. In connection with that lawsuit, the Company is prohibited from repatriating this amount due to an order of the Court in that matter requiring such proceeds to be held at or in the control of CCRC. To the extent repatriation of such net proceeds is ultimately permitted, the repatriated net proceeds will be applied pursuant to the use of proceeds provisions of the Company's indentures described herein as if the sale of Saltend had occurred on the date of repatriation. In addition, the net proceeds from an issuance of preferred equity and an asset sale completed after September 30, 2005 will similarly be subject to such use of proceeds provisions of the Company's indentures, and the Company anticipates that, on the basis described above (after considering capital expenditures), an additional $452.1 million will need to be used to make capital expenditures, to acquire other assets or capital stock, or to repurchase indebtedness, as applicable, within 365 days of the consummation of the applicable transaction. As noted above, our remaining oil and gas assets were sold on July 7, 2005, with the gas component of such sale constituting "designated assets" under certain of our indentures. These indentures require us to make an offer to purchase our First Priority Notes with the net proceeds of a sale of designated assets not otherwise applied in accordance with the other permitted uses under such indentures and, to the extent any proceeds (above $50.0 million remain thereafter, to make an offer to purchase its second priority senior secured debt. Accordingly, we made an offer to purchase the First Priority Notes in June 2005. On July 12, 2005, we purchased, with proceeds of the sale of the gas assets, all of the approximately $138.9 million in principal amount of the First Priority Notes tendered in connection with the offer to purchase. Having completed the tender offer, we have used approximately $308.2 million of the $708.5 million of the remaining net proceeds arising from the sale of our gas assets to acquire natural gas and/or geothermal energy assets permitted to be acquired under such indentures. However, there can be no assurance that we would be successful in identifying or acquiring any additional such assets on acceptable terms or at all. If we do not, within 180 days of receipt of the net proceeds from the sale of our gas assets, use all of the remaining net proceeds to acquire such such assets, and/or to repurchase or repay (through open market or privately-negotiated transactions, tender offers or otherwise) any or all of the approximately $641.5 million aggregate principal amount of First Priority Notes remaining outstanding after consummation of the offer to purchase described above (either of which actions we may, but are not required, to take), then we will, to the extent that the remaining net proceeds from the sale exceed $50 million, be required under the terms of our Second Priority Secured Debt - 78 - instruments to make an offer to purchase our outstanding second priority senior secured indebtedness, of which $3.7 billion is outstanding, up to the amount of the remaining net proceeds. However, as described further in Note 12, on September 26, 2005, the Company filed a lawsuit seeking acces to blocked proceeds remaing from this sale of designated assets. If the Company does not ultimately prevail in this lawsuit, particularly if the Company is compelled to return previously withdrawn amounts to the gas sale proceeds account as more fully described in Note 12 of the Notes to Consolidated Condensed Financial Statements, it could have a material adverse effect on the Company and its liquidity. In connection with several of our subsidiaries' lease financing transactions (Agnews, Geysers, Pasadena, Broad River, RockGen and South Point) the insurance policies we have in place do not comply in every respect with the insurance requirements set forth in the financing documents. We have requested from the relevant financing parties, and are expecting to receive, waivers of this noncompliance. While failure to have the required insurance in place is listed in the financing documents as an event of default, the financing parties may not unreasonably withhold their approval of our waiver request so long as the required insurance coverage is not reasonably available or commercially feasible and we deliver a report from our insurance consultant to that effect. We have delivered the required insurance consultant reports to the relevant financing parties and therefore anticipate that the necessary waivers will be executed shortly. In connection with the sale/leaseback transaction of Agnews, we have not fully complied with covenants pertaining to the operations and maintenance agreement, which noncompliance is technically an event of default. We are in the process of addressing this by seeking the lessor's approval to renew and extend the operations and maintenance agreement for the Agnews facility. In connection with the sale/leaseback transaction of Calpine Monterey Cogeneration, Inc., we have not fully complied with covenants pertaining to amendments to gas and power purchase agreements and the requirements to provide a detailed accounting report, which noncompliance is technically an event of default. We are in the process of addressing this by seeking a consent and waiver. Almost all of our operations are conducted through our subsidiaries and other affiliates. As a result, we depend almost entirely upon their cash flow to service our indebtedness, including our ability to pay the interest on and principal of our Senior Notes. However, as also described in our 2004 Form 10-K, first quarter 10-Q, second quarter 10-Q, and Current Report on Form 8-K filed with the SEC on July 1, 2005, and Current Report on Form 8-K filed with the SEC on October 17, 2005, cash flow from operations is currently insufficient to meet in full our cash, liquidity and refinancing obligations for the year, so we presently also depend in part upon the success of our strategic initiative program in order to fully service our debt. In addition, financing agreements covering a substantial portion of the indebtedness of our subsidiaries and other affiliates restrict their ability to pay dividends, make distributions or otherwise transfer funds to us prior to the payment of their obligations, including their outstanding debt, operating expenses, lease payments and reserves. Effective Tax Rate -- For the three months ended September 30, 2005, the effective rate from continuing operations increased to (7.8)% as compared to (237.6)% for the three months ended September 30, 2004. For the nine months ended September 30, 2005, and 2004, the effective tax rate was 21.3% and 42.6%, respectively. The tax rates on continuing operations for the three and nine months ended September 30, 2005, were adversely affected due to a valuation allowance recorded against certain NOL deferred tax assets associated with CCFC LLC in the amount of approximately $143.4 million. The variance in the effective tax rate for the three months ended September 30, 2005 compared to the same period in 2004 was significantly impacted by the nominal absolute dollar amount of our pre-tax income (loss) in each period. For the three months ended September 30, 2004, our pre-tax income from continuing operations was $8.6 million. Therefore, due to the near break-even absolute value of this amount, the tax benefit for the period translated into a high tax rate percentage, even though the benefit was only $20.3 million. Conversely, for the three months ended September 30, 2005, our pre-tax loss from continuing operations was $224.9 million and the tax provision for the period was $17.5 million. Excluding the effects of the valuation allowance associated with CCFC LLC, we would have recognized a tax benefit of $125.9 million for the three months ended September 30, 2005 resulting in an effective tax rate of 56.0%. While this tax benefit (excluding the effects of CCFC LLC) was $105.6 million higher than the tax benefit recognized for the three months ended September 30, 2004, the effective tax rate was significantly higher for the three months ended September 30, 2004 due to the nominal absolute value of pre-tax income from continuing operations. Also, the tax rates on continuing operations for the three and nine months ended September 30, 2004, have been restated in accordance with FIN 18, "Accounting for Income Taxes in Interim Periods - an Interpretation of APB Opinion No. 28," as amended, to reflect the effects of classifying the sale of the Company's Canadian and U.S. Rocky Mountain oil and gas assets, and the Saltend, Morris and Ontelaunee power plants. See Note 8 of the Notes to Consolidated Condensed - 79 - Financial Statements for more information on discontinued operations. This effective tax rate on continuing operations is based on the consideration of estimated year-end earnings in estimating the quarterly effective rate, the effect of permanent non-taxable items and establishment of valuation allowances on certain deferred tax assets. Off-Balance Sheet Commitments -- In accordance with SFAS No. 13 and SFAS No. 98, "Accounting for Leases" our facility operating leases, which include certain sale/leaseback transactions, are not reflected on our balance sheet. All lessors in these contracts are third parties that are unrelated to us. The sale/leaseback transactions utilize SPEs formed by the equity investors with the sole purpose of owning a power generation facility. 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. We have no ownership or other interest in any of these SPEs. Effective Tax Rate -- For the three months ended September 30, 2005, the effective rate from continuing operations increased to (7.8)% as compared to (237.6)% for the three months ended September 30, 2004. For the nine months ended September 30, 2005, and 2004, the effective tax rate was 21.3% and 42.6%, respectively. The tax rates on continuing operations for the three and nine months ended September 30, 2005, were adversely affected due to a valuation allowance recorded against certain NOL deferred tax assets associated with CCFC LLC in the amount of approximately $143.4 million. The variance in the effective tax rate for the three months ended September 30, 2005 compared to the same period in 2004 was significantly impacted by the nominal absolute dollar amount of our pre-tax income (loss) in each period. For the three months ended September 30, 2004, our pre-tax income from continuing operations was $8.6 million. Therefore, due to the near break-even absolute value of this amount, the tax benefit for the period translated into a high tax rate percentage, even though the benefit was only $20.3 million. Conversely, for the three months ended September 30, 2005, pre-tax loss from continuing operations was $224.9 million and the tax provision for the period was only $17.5 million. Excluding the effects of the valuation allowance associated with CCFC LLC, we would have recognized a tax benefit of $125.9 million for the three months ended September 30, 2005 resulting in an effective tax rate of 56.0%. While this tax benefit (excluding the effects of CCFC LLC) was $105.6 million higher than the tax benefit recognized for the three months ended September 30, 2004, the effective tax rate was significantly higher for the three months ended September 30, 2004 due to the nominal absolute value of pre-tax income from continuing operations. Also, the tax rates on continuing operations for the three and nine months ended September 30, 2004, have been restated in accordance with FIN 18, "Accounting for Income Taxes in Interim Periods - an Interpretation of APB Opinion No. 28," as amended, to reflect the effects of classifying the sale of the Company's Canadian and U.S. Rocky Mountain oil and gas assets, and the Saltend, Morris and Ontelaunee power plants as discontinued operations due to our commitment to a plan of divesture in the second quarter of 2005. See Note 8 for more information. This effective tax rate on continuing operations is based on the consideration of estimated year-end earnings in estimating the quarterly effective rate, the effect of permanent non-taxable items and establishment of valuation allowances on certain deferred tax assets. We own a 32.3% interest in AELLC. AELLC owns the 136-MW Androscoggin Energy Center located in Maine. On November 3, 2004, a jury verdict was rendered against AELLC in a breach of contract dispute with IP. See Note 12 of the Notes to Consolidated Condensed Financial Statements for more information about this legal proceeding. We recorded our $11.6 million share of the award amount in the third quarter of 2004. On November 26, 2004, AELLC filed a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code. As a result of the bankruptcy, we lost significant influence and control of the project and have adopted the cost method of accounting for our investment in AELLC. Also, in December 2004, we determined that our investment in AELLC was impaired and recorded a $5.0 million impairment reserve. On April 12, 2005, AELLC sold three fixed-price gas contracts to Merrill Lynch Commodities Canada, ULC, and used a portion of the proceeds to pay down its remaining construction debt. As of September 30, 2005, the facility had third-party debt outstanding of $3.1 million. See Note 12 of the Notes to Consolidated Condensed Financial Statements for an update on this investment. Credit Considerations -- On May 9, 2005, Standard & Poor's lowered its corporate credit rating on Calpine Corporation to B- from B. The outlook remains negative. In addition, the ratings on Calpine's debt and the ratings on the debt of its subsidiaries were also lowered by one notch, with a few exceptions. On May 12, 2005, Moody's Investor Service lowered its senior implied issuer rating on Calpine Corporation to B3 from B2. The outlook remains negative. In addition, the ratings on Calpine's debt and the ratings on the debt of its subsidiaries were also lowered by two notches, with a few exceptions. On November 4, 2005, following the announcement of our third quarter 2005 results of operation release on November 3, 2005, Fitch Ratings downgraded its ratings on our senior unsecured notes to CCC- from CCC+. Calpine Canada Energy Finance ULC bonds were also downgraded to CCC- from CCC+ (all with negative outlook). Our second priority notes were downgraded to B from BB-, while first priority notes were reduced to B- from B+. This downgrade is not expected to materially impact our operations. Credit rating downgrades have had a negative impact on our liquidity by reducing attractive financing opportunities and increasing the amount of collateral required by trading counterparties. Any future credit rating downgrades could have similar effects on our liquidity. Capital Spending -- See Note 5 of the Notes to Consolidated Condensed Financial Statements for a discussion of our development and construction projects at September 30, 2005 - 80 - Performance Metrics In understanding our business, we believe that certain non-GAAP operating performance metrics are particularly important. These are described below: o Total deliveries of power. We both generate power that we sell to third parties and purchase power for sale to third parties in HBO transactions. The former sales are recorded as electricity and steam revenue and the latter sales are recorded as sales of purchased power for hedging and optimization. The volumes in MWh for each are key indicators of our respective levels of generation and HBO activity and the sum of the two, our total deliveries of power, is relevant because there are occasions where we can either generate or purchase power to fulfill contractual sales commitments. Prospectively, beginning October 1, 2003, in accordance with EITF 03-11, "Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to SFAS No. 133 and Not `Held for Trading Purposes' As Defined in EITF Issue No. 02-3: `Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities,' certain sales of purchased power for hedging and optimization are shown net of purchased power expense for hedging and optimization in our consolidated statement of operations. Accordingly, we have also netted HBO volumes on the same basis as of October 1, 2003, in the table below. o Average availability and average baseload 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 baseload 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 baseload 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 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. Our risk management and optimization activities are integral to our power generation business and directly impact our total realized revenues from generation. Accordingly, we calculate the all-in realized electric price per MWh generated by dividing (a) adjusted electricity and steam revenue, which includes capacity revenues, energy revenues, thermal revenues, the spread on sales of purchased power for hedging, balancing, and optimization activity and generating revenue recorded in mark-to-market activities, net, by (b) total generated MWh in the period. o Average cost of natural gas expressed in dollars per millions of Btu's of fuel consumed. Our risk management and optimization activities related to fuel procurement directly impact our total fuel expense. 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 inter-company gas pipeline charges, which is eliminated in consolidation), the spread on sales of purchased gas for hedging, balancing, and optimization activity and fuel expense related to generation recorded in mark-to-market activities, net 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. - 81 - o Average plant operating expense per normalized MWh. To assess trends in electric power POX per MWh, we normalize the results from period to period by assuming a constant 70% total company-wide capacity factor (including both base load and peaker capacity) in deriving normalized MWh. By normalizing the cost per MWh with a constant capacity factor, we can better analyze trends and the results of our program to realize economies of scale, cost reductions and efficiencies at our electric generating plants. For comparison purposes we also include POX per actual MWh. The table below presents, the operating performance metrics discussed above. Operating Performance Metrics: Total deliveries of power: MWh generated.................................................. HBO and trading MWh sold....................................... MWh delivered.................................................. Average availability............................................. Average baseload capacity factor: Average total consolidated gross MW in operation............... Less: Average MW of pure peakers............................... Average baseload MW in operation............................... Hours in the period............................................ Potential baseload generation.................................. Actual total generation........................................ Less: Actual pure peakers' generation.......................... Actual baseload generation..................................... Average baseload capacity factor............................... Average heat rate for gas-fired power plants (excluding peakers) (Btu's/KWh): Not steam adjusted............................................. Steam adjusted................................................. Average all-in realized electric price: Electricity and steam revenue.................................. Spread on sales of purchased power for hedging and optimization Electricity and steam revenue before mark-to-market activities, net (in thousands)................................ Electricity and steam revenue related to power generating in mark-to-market activities, net............................. Adjusted electricity and steam revenue (in thousands).......... MWh generated (in thousands)................................... Average all-in realized electric price per MWh................. Average cost of natural gas: Fuel expense (in thousands).................................... Gas pipeline charge elimination (1)............................ Spread on sales of purchased gas for hedging and optimization.. Fuel expense related to power generation in mark-to-market activities, net................................ Adjusted fuel expense.......................................... MMBtu of fuel consumed by generating plants (in thousands)..... Average cost of natural gas per MMBtu.......................... MWh generated (in thousands)................................... Average cost of adjusted fuel expense per MWh.................. Average spark spread: Adjusted electricity and steam revenue (in thousands).......... Less: Adjusted fuel expense (in thousands)..................... Spark spread (in thousands).................................... MWh generated (in thousands)................................... Average spark spread per MWh................................... (table continues) - 82 - Three Months Ended September 30, Nine Months Ended September 30, -------------------------------- ------------------------------2005 2004 2005 2004 ------------------------------------- -------------(In thousands) 28,709 11,643 ------------40,352 ============= 97% 26,604 13,395 ------------39,999 ============= 98% 68,240 64,357 36,072 39,157 ------------- ------------104,312 103,514 ============= ============= 92% 93% 26,126 2,965 ------------23,161 2,208 51,139 28,709 1,069 ------------27,640 54.0% 24,230 2,951 ------------21,279 2,208 46,984 26,604 557 ------------26,047 55.4% 25,079 22,146 2,965 2,951 ------------- ------------22,114 19,195 6,552 6,576 144,891 126,226 68,240 64,357 1,668 1,130 ------------- ------------66,572 63,227 45.9% 50.1% 8,050 7,171 $ 8,276 7,178 8,346 7,202 8,292 7,208 2,096,323 69,503 ------------- $ 1,544,329 79,355 ------------- $ 4,625,078 233,427 ------------- $ $ $ $ $ 2,165,826 1,623,684 4,858,505 3,851,914 135,912 ------------3,987,826 82,583 ------------$ 2,248,409 28,709 $ 78.32 --------------$ 1,623,684 26,604 $ 61.03 157,096 -------------- -------------$ 5,015,601 $ 3,987,826 68,240 64,357 $ 73.50 $ 61.96 $ $ $ 1,567,504 1,803 27,501 1,052,309 3,118 5,640 3,336,248 6,738 49,625 $ 2,671,860 14,509 (14,660) 56,301 ------------$ 1,653,109 189,321 $ 8.73 28,709 $ 57.58 --------------$ 1,061,067 178,868 $ 5.93 26,604 $ 39.88 110,790 -------------- -------------3,503,401 $ 2,671,709 451,480 444,460 $ 7.76 $ 6.01 68,240 64,357 $ 51.34 $ 41.51 $ $ $ 2,248,409 1,653,109 ------------$ 595,300 28,709 $ 20.74 1,623,684 1,061,067 ------------$ 562,617 26,604 $ 21.15 $ 5,015,601 3,503,401 ------------$ 1,512,200 68,240 $ 22.16 $ 3,987,826 2,671,709 ------------$ 1,316,117 64,357 $ 20.45 Average POX per normalized MWh (for comparison purposes we also include POX per actual MWh): Average total consolidated gross MW in operations.............. Hours in the period............................................ Total potential MWh............................................ Normalized MWh (at 70% capacity factor)........................ Plant operating expense (POX).................................. POX per normalized MWh......................................... Actual MWh generated (in thousands)............................ POX per actual MWh............................................. Three Months Ended September 30, Nine Months Ended September 30, -------------------------------- ------------------------------2005 2004 2005 2004 ------------------------------------- -------------(In thousands) 26,126 2,208 57,686 40,380 $ 180,336 $ 4.47 28,709 ------------$ 6.28 ------------- -----------(1) In prior year periods, "gas pipeline charges" also included some small amounts for fuel charges related to gas assets since sold but not reclassified to discontinued operations. 24,230 2,208 53,500 37,450 $ 159,957 $ 4.27 26,604 ------------$ 6.01 ------------- 25,079 6,552 164,318 115,022 $ 555,433 $ 4.83 68,240 ------------$ 8.14 ------------- 22,146 6,576 145,632 101,942 $ 522,237 $ 5.12 64,357 ------------$ 8.11 ------------- The table below provides additional detail of total mark-to-market activity. For the three and nine months ended September 30, 2005 and 2004, mark-to-market activities, net consisted of (dollars in thousands): Realized: Power activity "Trading Activity" as defined in EITF No. 02-03................ Other mark-to-market activity (1).............................. Total realized power activity................................. Gas activity "Trading Activity" as defined in EITF No. 02-03................ Other mark-to-market activity (1).............................. Total realized gas activity................................... Total realized activity: "Trading Activity" as defined in EITF No. 02-03................ Other mark-to-market activity (1).............................. Total realized activity....................................... Unrealized: Power activity "Trading Activity" as defined in EITF No. 02-03................ Ineffectiveness related to cash flow hedges.................... Other mark-to-market activity (1).............................. Total unrealized power activity............................... Gas activity "Trading Activity" as defined in EITF No. 02-03................ Ineffectiveness related to cash flow hedges.................... Other mark-to-market activity (1).............................. Total unrealized gas activity................................. Total unrealized activity: "Trading Activity" as defined in EITF No. 02-03.................. Ineffectiveness related to cash flow hedges...................... Other mark-to-market activity (1)................................ Total unrealized activity..................................... Total mark-to-market activity: "Trading Activity" as defined in EITF No. 02-03.................. Ineffectiveness related to cash flow hedges...................... Other mark-to-market activity (1)................................ Total mark-to-market activity................................. -----------(table continues) - 83 - Three Months Ended September 30, Nine Months Ended September 30, -------------------------------- ------------------------------2005 2004 2005 2004 ------------------------------------- -------------$ 120,455 (946) ------------$ 119,509 ============= $ 9,412 (434) ------------$ 8,978 ============= $ 202,939 (9,607) ------------$ 193,332 ============= $ $ (53,280) (286) ------------$ (53,566) ============= $ 9,679 -------------$ 9,679 ============= $ (96,030) (286) ------------$ (96,316) ============= $ 9,548 -------------$ 9,548 ============= $ 67,175 (1,232) ------------$ 65,943 ============= $ 19,091 (434) ------------$ 18,657 ============= $ 106,909 (9,893) ------------$ 97,016 ============= $ 48,806 (6,378) ------------$ 42,428 ============= $ (129,578) (1,643) 1,935 ------------$ (129,286) ============= $ (17,057) 1,142 (240) ------------$ (16,155) ============= $ (127,094) (1,947) 3,681 ------------$ (125,360) ============= $ (40,926) 1,268 (13,015) ------------$ (52,673) ============= $ 94,546 9,651 -------------$ 104,197 ============= $ (8,508) 777 -------------$ (7,731) ============= $ 58,124 10,417 -------------$ 68,541 ============= $ (11,610) 6,540 -------------$ (5,070) ============= $ (35,032) 8,008 1,935 ------------$. (25,089) ============= $ (25,565) 1,919 (240) ------------$ (23,886) ============= $ (68,970) 8,470 3,681 ------------$ (56,819) ============= $ (52,536) 7,808 (13,015) ------------$ (57,743) ============= $ $ $ $ 32,143 8,008 703 ------------$ 40,854 ============= (6,474) 1,919 (674) ------------$ (5,229) ============= 37,939 8,470 (6,212) ------------$ 40,197 ============= 39,258 (6,378) ------------$ 32,880 ============= (3,730) 7,808 (19,393) ------------$ (15,315) ============= (1) Activity related to our assets but does not qualify for hedge accounting. Overview Summary of Key Activities Through September 30, 2005 Finance -- New Issuances and Amendments: Date ---------------------8/12/05............... Amount ---------------$150.0 million Description -----------------------------------------------------------------------------------------CCFC LLC completes a $150.0 million private placement of Class A Redeemable Preferred Shares; the preferred shares are repurchased in full on October 14, 2005 Finance -- Repurchases and Extinguishments: Date ---------------------7/12/05............... Amount ---------------$138.9 million 7/13/05............... $517.5 million 7/1/05-9/30/05........ $263.5 million Description -----------------------------------------------------------------------------------------Purchase $138.9 million aggregate principal of outstanding First Priority Notes pursuant to a tender offer commenced June 9, 2005 Repay the convertible debentures payable to Calpine Capital Trust III, the issuer of the HIGH TIDES III preferred securities, the proceeds of which are applied by the Trust to redeem the HIGH TIDES III preferred securities in full Repurchase Senior Notes in open market transaction totaling $263.5 million in principal for cash of $233.9 million plus accrued interest Asset Sales: Date ---------------------7/7/05................ 7/8/05................ 7/28/05............... 7/29/05............... 8/2/05................ 8/16/05............... Description -----------------------------------------------------------------------------------------------------------Complete the sale of substantially all remaining oil and gas exploration and production properties and assets for $1.05 billion, less adjustments, transaction fees, and expenses Complete the sale of 50% interest in the 175-MW Grays Ferry power plant for gross proceeds of $37.4 million Complete the sale of Saltend, a 1,200-MW power plant in Hull, England, for $862.9 million Complete the sale of Inland Empire Energy Center development project to GE for approximately $30.9 million Complete the sale of the 156-MW Morris power plant for $84.5 million Agree to sell 561-MW Ontelaunee; the sale is consummated on October 6, 2005, for $225 million less adjustments, transaction fees and expenses Power Plant Development and Construction: Date ---------------------7/1/05................ 7/5/05................ Project --------------------------------Bethpage Energy Center 3 Pastoria Energy Center (Phase II) Description -------------------Commercial Operation Commercial Operation Other: Date ---------------------7/5/05................ 7/7/05................ 7/11/05............... 8/26/05............... 8/29/05............... 9/7/05................ Description -----------------------------------------------------------------------------------------------------------Sign an agreement with Siemens-Westinghouse to restructure the long-term relationship, which is expected to provide additional flexibility to self-perform maintenance work in the future Announce a 15-year Master Products and Services Agreement with GE to supplement operations with a variety of services and to lower operating costs Major merchant power generator selects PSM to install LEC-III (R) and eliminate 90% of the power plant's nitrogen oxide emissions CES announces new service agreements with Project Orange Associates LLC and the Greater Toronto Airports Authority to provide them with marketing, scheduling, and other energy managements services CES announces five year long-term power supply agreement for 170-MW of electricity with Tampa Electric Company Agreed to form an energy marketing and trading venture with Bear Stearns Companies, Inc.( Bear Stearns). The new energy venture is expected to develop a third-party customer business focused on physical natural gas and power trading and related structured transactions. Regulatory approval was received on Oct. 31, 2005, and it is anticipated that operations will begin in the fourth quarter of 2005. - 84 - California Power Market The volatility in the California power market from mid-2000 through mid-2001 has produced significant unanticipated results. The unresolved issues arising in that market, where 41 of our 95 power plants are located, could adversely affect our performance. See Note 14 of the Notes to Consolidated Condensed Financial Statements for a further discussion. Financial Market Risks As we are 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. The change in fair value of outstanding commodity derivative instruments from January 1, 2005 through September 30, 2005, is summarized in the table below (in thousands): Fair value of contracts outstanding at January 1, 2005.......................................................... Cash losses recognized or otherwise settled during the period (1)............................................... Non-cash gains recognized or otherwise settled during the period (2)............................................ Changes in fair value attributable to new contracts (3)......................................................... Changes in fair value attributable to price movements (4)....................................................... Fair value of contracts outstanding at September 30, 2005..................................................... Realized cash flow from fair value hedges (5)................................................................... -----------(1) Realized losses from cash flow hedges and reflected in the tables below (in millions): mark-to-market activity Cash losses realized from cash flow hedges.................................................................... Realized value of mark-to-market activity (b)................................................................... Net of: Non-cash realized mark-to-market activity..................................................................... Cash gains realized on mark-to-market activity................................................................ Cash losses recognized or otherwise settled during the period................................................. Realized value as disclosed in Note 9 of the Notes to Condensed Financial Statements (b) Realized value as reported in Management's operating performance metrics Consolidated discussion and analysis of (2) This represents the non-cash amortization of deferred items embedded in our derivative assets and liabilities. (3) The change attributable to new contracts includes the $292.4 million derivative liability associated with a transaction by our Deer Park facility as discussed in Note 9 of the Notes to Consolidated Condensed Financial Statements. (4) Net commodity derivative assets reported Consolidated Condensed Financial Statements. (5) Not included as part of the roll-forward of net derivative assets and liabilities because changes in the hedge instrument and hedged item move in equal and offsetting directions to the extent the fair value hedges are perfectly effective. in Note 9 of the Notes - 85 - 37,863 1,310 38,125 (331,155) (245,081) -------------$ (498,938) ============== $ 181,097 ============== are Realized value of cash flow hedges (a).......................................................................... Net of: Terminated and monetized derivatives.......................................................................... Equity method hedges.......................................................................................... Hedges reclassified to discontinued operations................................................................ (a) $ to $ (292.1) (23.2) 2.0 (199.4) -------------$ (71.5) -------------$ 97.0 26.8 -------------70.2 -------------$ (1.3) ============== The fair value of outstanding derivative commodity instruments at September 30, 2005, based on price source and the period during which the instruments will mature, are summarized in the table below (in thousands): Fair Value Source ---------------------------------------------------Prices actively quoted ............................. Prices provided by other external sources .......... Prices based on models and other valuation methods ................................ Total fair value ................................. 2005 ---------$ 142,702 (211,699) 2006-2007 ---------$ 63,809 (382,774) 2008-2009 ---------$ -3,414 After 2009 ---------$ -(33,729) Total ---------$ 206,511 (624,788) ---------$ (68,997) ========= 189 --------$(318,776) ========= (56,563) --------$ (53,149) ========= (24,287) --------$ (58,016) ========= (80,661) --------$(498,938) ========= 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 group. 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, 2005, and the period during which the instruments will mature are summarized in the table below (in thousands): Credit Quality ---------------------------------------------------(Based on Standard & Poor's Ratings as of September 30, 2005) Investment grade.................................... Non-investment grade................................ No external ratings................................. Total fair value.................................. 2005 ---------- 2006-2007 ---------- 2008-2009 ---------- After 2009 ---------- Total ---------- $ (79,177) 11,699 (1,519) --------$ (68,997) ========= $(316,713) 1,704 (3,767) --------$(318,776) ========= $ (53,065) (20) (64) --------$ (53,149) ========= $ (58,016) ----------$ (58,016) ========= $(506,971) 13,383 (5,350) --------$(498,938) ========= 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): At September 30, 2005: Electricity............................. Natural gas............................. Total................................. Fair Value ------------ Fair Value After 10% Adverse Price Change -------------- $ (1,060,248) 561,310 -----------$ (498,938) =========== $ (1,373,769) 387,411 -----------$ (986,358) ============ Derivative commodity instruments included in the table are those included in Note 9 of the Notes to 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 the price risk exposure of our physical assets. None of the offsetting physical positions are included in the table above. Price changes were calculated by assuming an across-the-board 10% 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 10% change in prices, the fair value of our derivative portfolio would typically change by more than 10% for earlier forward months and less than 10% 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 increased by 44% - 86 - from December 31, 2004, to September 30, 2005, and the total volume of open power derivative positions increased by 135% 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, "Accounting for Derivative Instruments and Hedging Activities," 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, 2005, a significant component 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 three and nine months ended September 30, 2005, have reflected this. See Notes 9 and 10 of the Notes to Consolidated Condensed Financial Statements for additional information on derivative activity. Interest Rate Swaps -- From time to time, we use interest rate swap agreements to mitigate our exposure to interest rate fluctuations associated with certain of our debt instruments and to adjust the mix between fixed and floating rate debt in our capital structure to desired levels. We do not use interest rate swap agreements for speculative or trading purposes. The following tables summarize the fair market values of our existing interest rate swap agreements as of September 30, 2005 (dollars in thousands): Variable to Fixed Swaps Maturity Date ----------------------------------------------------2009.................................................. 2011.................................................. 2011.................................................. 2011.................................................. 2011.................................................. 2011.................................................. 2011.................................................. 2011.................................................. 2011.................................................. 2011.................................................. 2011.................................................. 2011.................................................. 2011.................................................. 2011.................................................. 2012.................................................. 2016.................................................. 2016.................................................. 2016.................................................. 2016.................................................. 2016.................................................. Total.............................................. Weighted Average Notional Interest Rate Principal Amount (Pay) ----------------- --------------$ 50,000 4.8% 57,291 4.5% 287,447 4.5% 201,003 4.4% 40,062 4.4% 12,347 6.9% 50,300 4.9% 24,695 4.8% 12,347 4.8% 15,986 4.9% 15,986 4.9% 12,347 4.8% 15,986 4.9% 12,347 4.8% 100,926 6.5% 20,355 7.3% 13,570 7.3% 40,710 7.3% 27,140 7.3% 33,925 7.3% -------------$ 1,044,770 5.1% ============== Weighted Average Interest Rate (Receive) ----------------------3-month US $LIBOR 3-month US $LIBOR 3-month US $LIBOR 3-month US $LIBOR 3-month US $LIBOR 3-month US $LIBOR 3-month US $LIBOR 3-month US $LIBOR 3-month US $LIBOR 3-month US $LIBOR 3-month US $LIBOR 3-month US $LIBOR 3-month US $LIBOR 3-month US $LIBOR 3-month US $LIBOR 3-month US $LIBOR 3-month US $LIBOR 3-month US $LIBOR 3-month US $LIBOR 3-month US $LIBOR Fair Market Value --------------$ (488) (11) (44) 725 145 (2,554) (647) (495) (248) (323) (323) (248) (323) (248) (7,742) (2,907) (1,936) (5,809) (3,872) (4,841) -------------$ (32,189) ============== Fixed to Variable Swaps Maturity Date ----------------------------------------------------2011.................................................. 2011.................................................. 2011.................................................. 2011.................................................. Total.............................................. Notional Principal Amount ---------------$ 100,000 100,000 100,000 200,000 -------------$ 500,000 ============== Weighted Average Interest Rate (Pay) -----------------------6-month US $LIBOR 6-month US $LIBOR 6-month US $LIBOR 6-month US $LIBOR - 87 - Weighted Average Interest Rate (Receive) ---------------8.5% 8.5% 8.5% 8.5% 8.5% Fair Market Value -------------$ (6,520) (7,442) (5,090) (10,465) -------------$ (29,517) ============== The fair value of outstanding interest rate swaps and the fair value that would be expected after a 1% adverse interest rate change are shown in the table below (in thousands): Net Fair Value as of September 30, 2005 --------------------------------------$(61,706)............................................ Fair Value After a 1.0% (100 Basis Point) Adverse Interest Rate Change --------------------$ (82,200) Currency Exposure -- We own subsidiary entities in several countries. These entities generally have functional currencies other than the U.S. dollar. In most cases, the functional currency is consistent with the local currency of the host country where the particular entity is located. In certain cases, we and our foreign subsidiary entities hold monetary assets and/or liabilities that are not denominated in the functional currencies referred to above. In such instances, we apply the provisions of SFAS No. 52, "Foreign Currency Translation," ("SFAS No. 52") to account for the monthly re-measurement gains and losses of these assets and liabilities into the functional currencies for each entity. In some cases we can reduce our potential exposures to net income by designating liabilities denominated in non-functional currencies as hedges of our net investment in a foreign subsidiary or by entering into derivative instruments and designating them in hedging relationships against a foreign exchange exposure. Based on our unhedged exposures at September 30, 2005, the impact to our pre-tax earnings that would be expected after a 10% adverse change in exchange rates is shown in the table below (in thousands): Currency Exposure ----------------GBP-Euro...................................... $Cdn-$US...................................... $Cdn-GBP...................................... Other......................................... Impact to Pre-Tax Net Income After 10% Adverse Exchange Rate Change ---------------------------$ (14,758) (131,367) (13,885) (1,869) In prior periods, we reported significant unhedged positions and corresponding foreign currency transaction gains and losses due to our exposure to changes in the GBP-$US exchange rate. As a result of the sale of Saltend (see Note 8 of the Notes to Consolidated Condensed Financial Statements for more information), effectively all of our GBP-$US accounting exposure has been eliminated. We expect that currency movements will continue to create volatility within our pre-tax earnings in future periods, but such volatility is not expected to result from movements in the GBP-$US exchange rate. Significant changes in exchange rates will also impact our CTA balance when translating the financial statements of our foreign operations from their respective functional currencies into our reporting currency, the U.S. dollar. An example of the impact that significant exchange rate movements can have on our Balance Sheet position occurred in 2004. During 2004, our CTA increased by approximately $62 million primarily due to a strengthening of the Canadian dollar and GBP against the U.S. dollar by approximately 7% each. Foreign Currency Transaction Gain (Loss) Three Months Ended September 30, 2005, Compared to Three Months Ended September 30, 2004: The major components of our foreign currency transaction losses from continuing operations of $43.9 million and $12.4 million for the three months ended September 30, 2005 and 2004, respectively, are as follows (amounts in millions): Loss Loss Gain Gain from $Cdn-$US fluctuations............................ from GBP-Euro fluctuations............................ (Loss) from $Cdn-GBP fluctuations..................... (Loss) from other currency fluctuations............... Total................................................... 2005 -------$ (54.6) (2.0) 12.8 (0.1) ------$ (43.9) ======= 2004 -------$ (8.6) (4.1) -0.3 ------$ (12.4) ======= The $Cdn-$US loss for the three months ended September 30, 2005, was due primarily to a significant weakening of the U.S. dollar against the Canadian dollar during the third quarter of 2005. In September 2004, we sold substantially all of our oil and gas assets in Canada, which significantly reduced the degree to which we could designate our $Cdn-denominated liabilities as hedges against our investment in Canadian dollar denominated subsidiaries. As a result, we are now considerably more exposed to fluctuations in the $Cdn-$US exchange rate as we hold several significant $Cdn-denominated liabilities that can no longer be hedged under SFAS No. 52. When the U.S. dollar weakened during - 88 - the third quarter of 2005, significant re-measurement losses were triggered on these loans. These losses were partially offset by re-measurement gains recognized on the translation of the interest receivable associated with our large intercompany loan that has been deemed a permanent investment under SFAS No. 52. While re-measurement gains and losses associated with the loan are recorded within CTA, the re-measurement of the underlying interest receivable every period continues to be recorded as a component of net income due to the fact that the interest is physically settled semi-annually. The $Cdn-$US loss for the three months ended September 30, 2004, was moderate despite the fact that the U.S. dollar weakened considerably against the Canadian dollar during the third quarter of 2004. The primary reason for this was because the majority of our existing $Cdn-$US exposures were effectively designated as hedges of our net investment in Canadian dollar subsidiaries through early September 2004. As a result, re-measurement losses that otherwise would have been recognized within our Consolidated Condensed Statements of Operations were recorded within CTA in accordance with SFAS No. 52. In September 2004, we completed the sale of our Canadian oil and gas assets and subsequent to this transaction, the Canadian dollar strengthened considerably against the U.S. dollar for the rest of the month. The loss of the majority of our natural hedge position combined with the strengthened Canadian dollar created the majority of the $Cdn-$US loss of $8.6 million for the three months ended September 30, 2004. The loss recognized was partially offset by re-measurement gains recognized on the translation of the interest receivable associated with our large intercompany loan that has been deemed a permanent investment under SFAS No. 52 as described above. During the three months ended September 30, 2005 and 2004, respectively, the Euro strengthened against the GBP, triggering re-measurement losses associated with our Euro-denominated 8 3/8% Senior Notes Due 2008. The primary driver behind our gain of $12.8 million from other $Cdn-GBP fluctuations for the three months ended September 30, 2005, was due to the sale of Saltend in July 2005, combined with a subsequent strengthening of the Canadian dollar against the GBP. One of our $Cdn-denominated subsidiaries holds a significant GBP-denominated liability position which relates to financing borrowed for the original purchase of Saltend in 2001. Prior to the sale, this liability position was designated as a hedge of the subsidiary's net investment in Saltend and as a result, all re-measurement gains and losses associated with the liability were recorded within CTA in accordance with SFAS No. 52. Subsequent to the sale, all such re-measurement gains and losses are required to be recorded within net income as we no longer own a GBP-denominated investment to hedge against. The strengthening of the Canadian dollar against the GBP during the third quarter of 2005 created significant re-measurement gains on this newly exposed liability position. For the three months ended September 30, 2004, our $Cdn-GBP liability position was effectively hedged and as a result, all re-measurement gains and losses were recorded as a component of CTA. Nine Months Ended September 30, 2005, Compared to Nine Months Ended September 30, 2004: The major components of our foreign currency transaction losses of $18.3 million and $7.6 million, respectively, for the nine months ended September 30, 2005 and 2004, respectively, are as follows (amounts in millions): Loss Gain Gain Loss from $Cdn-$US fluctuations............................ from GBP-Euro fluctuations............................ (Loss) from $Cdn-GBP fluctuations..................... from other currency fluctuations...................... Total...................................................... 2005 -------$ (35.6) 7.6 11.9 (2.2) ------$ (18.3) ======= 2004 -------$ (14.0) 6.5 -(0.1) ------$ (7.6) ======= The $Cdn-$US loss for the nine months ended September 30, 2005, was due primarily to a significant weakening of the U.S. dollar against the Canadian dollar, most significantly within the third quarter of 2005. In September 2004, we sold substantially all of our oil and gas assets in Canada, which significantly reduced the degree to which we could designate our $Cdn-denominated liabilities as hedges against our investment in Canadian dollar denominated subsidiaries. As a result, we are now considerably more exposed to fluctuations in the $Cdn-$US exchange rate as we hold several significant $Cdn-denominated liabilities that can no longer be hedged under SFAS No. 52. When the U.S. dollar weakened, significant re-measurement losses were triggered on these loans. These losses were partially offset by re-measurement gains recognized on the translation of the interest receivable associated with our large intercompany loan that has been deemed a permanent investment under SFAS No. 52. While re-measurement gains and losses associated with the loan are recorded within CTA, the re-measurement of the underlying interest receivable every period continues to be recorded as a component of net income due to the fact that the interest is physically settled semi-annually. - 89 - The $Cdn-$US loss for the nine months ended September 30, 2004 was due to two primary reasons. First, in September 2004, we completed the sale of our Canadian oil and gas assets and subsequent to this transaction, the Canadian dollar strengthened considerably against the U.S. dollar for the rest of the month. The sale eliminated the majority of our natural hedge position as described above, resulting in a large open exposure that was susceptible to volatility in the $Cdn-$US exchange rate. Second, we recognized re-measurement losses on the translation of the interest receivable associated with our large intercompany loan that has been deemed a permanent investment during the first two quarters of 2004, as the Canadian dollar weakened against the U.S. dollar during this period. As noted above, physical settlement of the interest receivable occurs semi-annually, in May and November. As a result, the most significant re-measurement gains and losses associated with this receivable generally occur within 1-2 months of the payment date, as the receivable approaches its full value for the 6-month period. From January to May 2004, the U.S. dollar strengthened considerably against the Canadian dollar while the interest receivable balance grew significantly, resulting in large re-measurement losses. These losses were partially offset during the third quarter of 2004 as the Canadian dollar strengthened against the U.S. dollar, but the average interest receivable balance outstanding during the third quarter was not as large as the balance outstanding in March and April, resulting in a net loss for the nine months ended September 30, 2004. During the nine months ended September 30, 2005 and 2004, respectively, the Euro weakened against the GBP, triggering re-measurement gains associated with our Euro-denominated 8 3/8% Senior Notes Due 2008. The primary driver behind our gain of $11.9 million from other $Cdn-GBP fluctuations for the nine months ended September 30, 2005, was due to the sale of Saltend in July 2005, combined with a subsequent strengthening of the Canadian dollar against the GBP. One of our $Cdn-denominated subsidiaries holds a significant GBP-denominated liability position which relates to financing borrowed for the original purchase of Saltend in 2001. Prior to the sale, this liability position was designated as a hedge of the subsidiary's net investment in Saltend and as a result, all re-measurement gains and losses associated with the liability were recorded within CTA in accordance with SFAS No. 52. Subsequent to the sale, all such re-measurement gains and losses are required to be recorded within net income as we no longer own a GBP-denominated investment to hedge against. The strengthening of the Canadian dollar against the GBP during the third quarter of 2005 created significant re-measurement gains on this newly exposed liability position. For the nine months ended September 30, 2004, our $Cdn-GBP liability position was effectively hedged and as a result, all re-measurement gains and losses were recorded as a component of CTA. The primary driver behind our loss of $2.2 million from other currency fluctuations for the nine months ended September 30, 2005 was a significant strengthening of the U.S. dollar against the Euro, and its impact on certain U.S. dollar-denominated intercompany trade payables owed by our TTS subsidiary. By contrast, movement in the $US-Euro exchange rate was relatively flat for the nine months ended September 30 2004 and as a result, minimal re-measurement losses were created. Available-for-Sale Debt Securities -- On July 13, 2005, we completed the redemption of all of the outstanding HIGH TIDES III preferred securities and of the underlying convertible debentures. Accordingly, the HIGH TIDES III preferred securities repurchased by us are no longer outstanding. See Notes 4 and 7 of the Notes to Consolidated Condensed Financial Statements for further information. Debt Financing -- Because of the significant capital requirements within our industry, debt financing is often needed to fund our growth. Certain debt instruments may affect us adversely because of changes in market conditions. We have used two primary forms of debt which are subject to market risk: (1) Variable rate construction/project financing and (2) other variable-rate instruments. Significant LIBOR increases could have a negative impact on our future interest expense. Our variable-rate construction/project financing is primarily through the CalGen floating rate notes, institutional term loans and revolving credit facility. Borrowings under our $200 million CalGen revolving credit agreement are used primarily for letters of credit in support of gas purchases, power contracts and transmission, and was available for the construction costs of the Pastoria Energy Center expansion project, which was completed in July 2005. Other variable-rate instruments consist primarily of our revolving credit and term loan facilities, which are used for general corporate purposes. Both our variable-rate construction/project financing and other variable-rate instruments are indexed to base rates, generally LIBOR, as shown below. On August 12, 2005, we issued $150.0 million of Class A Redeemable Preferred Shares due February 13, 2006, through our wholly owned indirect subsidiary, CCFC LLC, which is an indirect parent of CCFC I. The Redeemable Preferred Shares bear an initial dividend rate of LIBOR plus 950 basis points and may be redeemed in whole or in part at any time by the issuer at par plus accrued dividends. The Redeemable Preferred Shares were repurchased in full on October 14, 2005. - 90 - The following table summarizes by maturity date our variable-rate debt exposed to interest rate risk as of September 30, 2005. All fair market values are shown net of applicable premium or discount, if any (dollars in thousands): 3-month US $LIBOR weighted average interest rate basis (4) MEP Pleasant Hill Term Loan, Tranche A ........................... Riverside Energy Center project financing ........................ Rocky Mountain Energy Center project financing ................... Total of 3-month US $LIBOR rate debt ........................... 1-month EURLIBOR weighted average interest rate basis (4) Thomassen revolving line of credit ............................... Total of 1-month EURLIBOR rate debt ............................ 1-month US $LIBOR weighted average interest rate basis (4) First Priority Secured Floating Rate Notes Due 2009 (CalGen) ........................................................ Total of 1-month US $LIBOR weighted average interest rate debt ............................................ 1-month US $LIBOR interest rate basis (4) Freeport Energy Center project financing ......................... Mankato Energy Center project financing .......................... Total 1-month US $LIBOR interest rate .......................... 6-month US $LIBOR weighted average interest rate basis (4) Third Priority Secured Floating Rate Notes Due 2011 (CalGen) ........................................................ Total of 6-month US $LIBOR rate debt ........................... (1)(4) Class A Redeemable Preferred Shares (CCFC) ....................... Metcalf Energy Center, LLC preferred interest .................... First Priority Secured Institutional Term Loan Due 2009 (CCFC I) ........................................................ Second Priority Senior Secured Floating Rate Notes Due 2011 (CCFC I) ............................................... Total of variable rate debt as defined at (1) below ............ (2)(4) Second Priority Senior Secured Term Loan B Notes Due 2007 ........................................................ Total of variable rate debt as defined at (2) below ............ (3)(4) Second Priority Senior Secured Floating Rate Notes Due 2007 ........................................................ Blue Spruce Energy Center project financing ...................... Total of variable rate debt as defined at (3) below ............ (5)(4) First Priority Secured Term Loans Due 2009 (CalGen) .............. Second Priority Secured Floating Rate Notes Due 2010 (CalGen) ........................................................ Second Priority Secured Term Loans Due 2010 (CalGen) ............. Metcalf Energy Center, LLC project financing ..................... Total of variable rate debt as defined at (5) below ............ (6)(4) Island Cogen ..................................................... Contra Costa ..................................................... Total of variable rate debt as defined at (6) below ............ Grand total variable-rate debt instruments (8) ............... - 91 - 2005 ---------- 2006 ---------- 2007 ---------- 2008 ---------- $ 2,528 -----------2,528 $ 7,482 3,685 2,649 ---------13,816 $ 8,132 3,685 2,649 ---------14,466 $ 2,417 ---------2,417 ------------ ------------ ------------ ----------- ----------- 1,175 ---------- 2,350 ---------- -- -- 1,175 2,350 ------------- ------------- 1,969 1,727 ---------3,696 1,810 1,781 ---------3,591 ------------ ------------ ------------ ------------ --- 150,000 -- --- --- -- 3,208 3,208 3,208 ------------ ----------153,208 ----------3,208 ----------3,208 1,875 ---------1,875 7,500 ---------7,500 725,625 ---------725,625 ------------ 1,250 938 ---------2,188 5,000 3,750 ---------8,750 483,750 3,750 ---------487,500 -3,750 ---------3,750 -- -- 3,000 6,000 ----------------------- ----------------------- ------------3,000 ---------- 3,200 500 ----------9,700 ---------- 9,860 ----------9,860 ---------$ 18,868 ========== -171 ---------171 ---------$ 183,445 ========== -179 ---------179 ---------$1,238,849 ========== -187 ---------187 ---------$ 38,391 ========== 9,271 3,685 2,649 ---------15,605 3-month US $LIBOR weighted average interest rate basis (4) MEP Pleasant Hill Term Loan, Tranche A .................................... Riverside Energy Center project financing ................................. Rocky Mountain Energy Center project financing ............................ Total of 3-month US $LIBOR rate debt .................................... 1-month EURLIBOR weighted average interest rate basis (4) Thomassen revolving line of credit ........................................ Total of 1-month EURLIBOR rate debt ..................................... 1-month US $LIBOR weighted average interest rate basis (4) First Priority Secured Floating Rate Notes Due 2009 (CalGen) .............. Total of 1-month US $LIBOR weighted average interest rate debt .......... 1-month US $LIBOR interest rate basis (4) Freeport Energy Center project financing .................................. Mankato Energy Center project financing ................................... Total 1-month US $LIBOR interest rate ................................... 6-month US $LIBOR weighted average interest rate basis (4) Third Priority Secured Floating Rate Notes Due 2011 (CalGen) .............. Total of 6-month US $LIBOR rate debt .................................... (1)(4) Class A Redeemable Preferred Shares (CCFC) ................................ Metcalf Energy Center, LLC preferred interest ............................. First Priority Secured Institutional Term Loan Due 2009 (CCFC I) ................................................................. Second Priority Senior Secured Floating Rate Notes Due 2011 (CCFC I) ................................................................. Total of variable rate debt as defined at (1) below ..................... (2)(4) Second Priority Senior Secured Term Loan B Notes Due 2007 ................. Total of variable rate debt as defined at (2) below ..................... (3)(4) Second Priority Senior Secured Floating Rate Notes Due 2007 ............... Blue Spruce Energy Center project financing ............................... Total of variable rate debt as defined at (3) below ..................... (5)(4) First Priority Secured Term Loans Due 2009 (CalGen) ....................... Second Priority Secured Floating Rate Notes Due 2010 (CalGen) ............. Second Priority Secured Term Loans Due 2010 (CalGen) ...................... Metcalf Energy Center, LLC project financing .............................. Total of variable rate debt as defined at (5) below ..................... (6)(4) Island Cogen ................................................................ Contra Costa ................................................................ Total of variable rate debt as defined at (6) below ..................... Grand total variable-rate debt instruments (8) ......................... -----------(1) British Bankers Association period of six months. LIBOR Rate for deposit in US dollars for a (2) U.S. prime rate in combination with the Federal Funds Effective Rate. (3) British Bankers Association period of three months. (4) Actual interest rates include a spread over the basis amount. (5) Choice of 1-month US $LIBOR, 2-month US $LIBOR, 3-month US $LIBOR, 6-month US $LIBOR, 12-month US $LIBOR or a base rate. (6) Bankers Acceptance Rate. (7) Fair value equals carrying value, with the exception of the Second-Priority Senior Secured Term B Loans Due 2007 and Second-Priority Senior Secured Floating Rate Notes Due 2007, which are shown at quoted trading values as of September 30, 2005. LIBOR Rate for (table continues) - 92 - deposit in US dollars for a 2009 ----------- Thereafter ---------- September 30, 2005 (7) ---------------------- $ 9,433 3,685 2,649 ----------15,767 $ 85,479 340,553 235,276 ---------661,308 $ ------------- ------------ 2,417 ----------2,417 231,475 ----------231,475 ------------ 235,000 ----------235,000 1,600 1,530 ----------3,130 122,058 112,500 ---------234,558 127,437 117,538 ----------244,975 ------------- 680,000 ---------680,000 680,000 ----------680,000 --- -155,000 150,000 155,000 365,189 -- 374,813 -----------365,189 409,296 ---------564,296 409,296 ----------1,089,109 ------------- ------------ 565,950 ----------565,950 -3,750 ----------3,750 -81,395 ---------81,395 377,300 97,333 ----------474,633 591,000 6,400 1,000 -----------598,400 ----------- -623,239 97,381 100,000 ---------820,620 ---------- 600,000 632,839 98,881 100,000 ----------1,431,720 ----------- -196 ----------196 ----------$ 1,217,907 =========== -1,381 ---------1,381 ---------$3,043,558 ========== 9,860 2,114 ----------11,974 ----------$ 5,459,268 =========== 122,325 355,293 245,872 ----------723,490 (8) The aggregate principal amount subject to variable $5,741.0 million as of September 30, 2005. interest rate risk was New Accounting Pronouncements (See Note 2 of the Notes to Consolidated Condensed Financial Statements for a discussion of new accounting pronouncements) Summary of Dilution Potential of Our Contingent Convertible Notes: 2023 Convertible Notes, 2015 Convertible Notes and 2014 Convertible Notes -- The table below assumes normal conversion for the 2014 Convertible Notes, 2015 Convertible Notes and 2023 Convertible Notes in which the principal amount is paid in cash, and the excess up to the conversion value is paid in shares of Calpine common stock. The table shows only the potential impact of our three contingent convertible notes issuances and does not include the potential dilutive effect of the now fully redeemed HIGH TIDES III preferred securities, the remaining 2006 Convertible Notes or employee stock options. Additionally, we are still assessing the potential impact of the SFAS No. 128-R exposure draft on our three series of contingent convertible securities. See Notes 2 and 11 of the Notes to Consolidated Condensed Financial Statements for more information. 2014 Convertible Notes ------------$ 641,685,000 $ 3.85 259.7402 $ 4.62 Aggregate outstanding principal amount at maturity............................ Conversion price per share.................................................... Conversion rate............................................................... Trigger price (20% over conversion price)..................................... 2015 Convertible Notes ------------$ 650,000,000 $ 4.00 250.0000 $ 4.80 2023 Convertible Notes -------------$ 633,775,000 $ 6.50 153.8462 $ 7.80 Additional Shares Future Calpine Common Stock Price --------------------------------------$5.00.................................. $7.50.................................. $10.00................................. $20.00................................. $40.00................................. $100.00................................ 2014 Convertible Notes (2) --------------38,334,429 81,113,429 102,502,929 134,587,179 150,629,304 160,254,579 2015 Convertible Notes ---------------32,500,000 75,833,333 97,500,000 130,000,000 146,250,000 156,000,000 2023 Convertible Notes ----------------13,000,542 34,126,375 65,815,125 81,659,500 91,166,125 Common shares outstanding at September 30, 2005 (1)............... 478,964,218 -----------(1) Excludes the 89 million shares issued under the Share Lending Agreement (see Note 11 of the Notes to Consolidated Condensed Financial Statements) and excludes our contingently issuable restricted stock. (2) In the case of the 2014 Convertible Notes, more shares could be issued when the accreted value is less than $1,000 than in the table above since, generally, the accreted value (initially $839 per bond) is paid in cash, and the balance of the conversion value is paid in shares. The maximum potential incremental shares assuming conversion when the accreted value is $839 per bond are shown in the table below: Incremental Future Calpine Common Stock Price Shares ------------------------------------------$5.00.................................................20,662,257 $7.50.................................................13,774,838 $10.00................................................10,331,129 $20.00.................................................5,165,564 $40.00.................................................2,582,782 $100.00................................................1,033,113 Item 3. Quantitative and Qualitative Disclosures About Market Risk. See "Financial Market Risks" in Item 2. - 93 - Share Share Dilution Subtotal Increase in EPS ---------------- ---------- -------70,834,429 14.8% 12.9% 169,947,304 35.6% 26.2% 234,129,304 49.0% 32.9% 330,402,304 69.2% 40.9% 378,538,804 79.2% 44.2% 407,420,704 85.3% 46.0% Item 4. Controls and Procedures. Disclosure Controls and Procedures We maintain disclosure controls and procedures that are designed to ensure that information we are required to disclose in reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. As of December 31, 2004, management identified a material weakness related to our tax accounting processes, procedures and controls that was discussed in Item 9A of the Company's 2004 Form 10-K. During the first three quarters of 2005, we have taken steps necessary to improve our internal controls relating to the preparation and review of interim and annual income tax provisions and to remediate this material weakness. While significant progress has been made in the remediation of these controls, the controls have not yet operated for a sufficient period of time to allow us to complete the required testing and to conclude that they are designed and operating effectively. Our senior management, including our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this quarterly report. Based on the status of the remediation of the material weakness, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures are not effective. We continue to perform additional analysis and post-closing procedures to ensure our consolidated financial statements are prepared in accordance with GAAP. Accordingly, management believes that the financial statements included in this report fairly present in all material respects our financial condition, results of operations and cash flows for the periods presented. The certificates required by this item are filed as Exhibits 31.1, 31.2 and 32.1 to this Form 10-Q. Status of Remediation of the Material Weakness During the first three quarters of 2005, we have taken the steps necessary to improve our internal controls relating to the preparation and review of interim and annual income tax provisions, including the accounting for current income taxes payable and deferred income tax assets and liabilities. We have hired additional resources and have engaged third party tax experts to improve the effectiveness of the controls over management's review of the details of the income tax calculations. We have also improved the process of preparing and reviewing the workpapers supporting our tax related calculations and conclusions. We will continue to do the following: o Complete the implementation of the CorpTax computer application and enhance other financial applications to automate more of the tax analysis and provision processes and continue to improve the clarity of supporting documentation and reports, and o Add additional resources in the tax department as well as provide tax accounting training for key personnel. We continue to monitor the effectiveness of the tax controls and procedures and will make any additional changes that management deems appropriate. Changes in Internal Control Over Financial Reporting We continuously seek to improve the efficiency and effectiveness of our internal controls. This results in refinements to processes throughout the Company. During the first three quarters of 2005, there were no significant changes in our internal control over financial reporting, other than the changes related to the tax accounting processes, procedures and controls discussed above, that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. - 94 - PART II -- OTHER INFORMATION Item 1. Legal Proceedings. See Note 12 of the Notes to Consolidated Condensed Financial Statements for a description of our legal proceedings. Item 6. Exhibits. (a) Exhibits The following exhibits are filed herewith unless otherwise indicated: EXHIBIT INDEX Exhibit Number ------- Description ----------------------------------------------------------------------- 3.1.1 Amended and Restated Certificate of Incorporation amended through June 2, 2004.(a) 3.1.2 Amendment to Amended and Restated Company, dated June 20, 2005.(b) 3.2 Amended and Restated By-laws of the Company.(c) 4.1 Amended and Restated Limited Liability Company Agreement of CCFC Preferred Holdings, LLC containing terms of its Class A Redeemable Preferred Shares due February 13, 2006.(d) 4.2 Second Amended and Restated Limited Liability Company Operating Agreement of CCFC Preferred Holdings, LLC, dated as of October 14, 2005, containing terms of its 6-Year Redeemable Preferred Shares Due 2011.(d) 10.1 Purchase and Sale Agreement dated July 7, 2005, by and among Calpine Gas Holdings LLC, Calpine Fuels Corporation, Calpine Corporation, Rosetta Resources Inc., and the other Subject Companies identified therein.(e) 10.2 Master Transaction Agreement, dated September 7, 2005, among Calpine Corporation, Calpine Energy Services, L.P., The Bear Stearns Companies Inc., and such other parties as may become party thereto from time to time. Approximately two pages of this Exhibit 10.2 have been omitted pursuant to a request for confidential treatment. The omitted language has been filed separately with the SEC.(*) 10.3 Amendment to 1996 Stock Incentive Plan, as amended.(f) 31.1 Certification of the Chairman, Certificate of of the Company, as Incorporation of the President and Chief Executive Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.(*) 31.2 Certification of the Executive Vice President and Chief Financial Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.(*) 32.1 Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.(*) ---------- (*) Filed herewith. (a) Incorporated by reference to Calpine Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, filed with the SEC on August 9, 2004. (b) Incorporated by reference to Calpine Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2005, filed with the SEC on August 9, 2005. (c) 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. (d) This document has been omitted in reliance on Item 601(b)(4)(iii) of Regulation S-K. Calpine Corporation agrees to furnish a copy of such document to the SEC upon request. (continued) - 95 - (e) Incorporated by reference to Calpine Corporation's Current Report on Form 8-K filed with the SEC on July 13, 2005. (f) Description of such amendment is incorporated by reference to Item 1.01 of Calpine Corporation's Current Report on Form 8-K filed with the SEC on September 20, 2005. Such amendment constitutes a management contract or compensatory plan or arrangement. - 96 - SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. CALPINE CORPORATION By: /s/ ROBERT D. KELLY ---------------------------------------------Robert D. Kelly Executive Vice President and Chief Financial Officer (Principal Financial Officer) Date: November 9, 2005 By: /s/ CHARLES B. CLARK, JR. ---------------------------------------------Charles B. Clark, Jr. Senior Vice President and Corporate Controller (Principal Accounting Officer) Date: November 9, 2005 - 97 - The following exhibits are filed herewith unless otherwise indicated: EXHIBIT INDEX Exhibit Number ------- Description ----------------------------------------------------------------------- 3.1.1 Amended and Restated Certificate of Incorporation amended through June 2, 2004.(a) 3.1.2 Amendment to Amended and Restated Company, dated June 20, 2005.(b) 3.2 Amended and Restated By-laws of the Company.(c) 4.1 Amended and Restated Limited Liability Company Agreement of CCFC Preferred Holdings, LLC containing terms of its Class A Redeemable Preferred Shares due February 13, 2006.(d) 4.2 Second Amended and Restated Limited Liability Company Operating Agreement of CCFC Preferred Holdings, LLC, dated as of October 14, 2005, containing terms of its 6-Year Redeemable Preferred Shares Due 2011.(d) 10.1 Purchase and Sale Agreement dated July 7, 2005, by and among Calpine Gas Holdings LLC, Calpine Fuels Corporation, Calpine Corporation, Rosetta Resources Inc., and the other Subject Companies identified therein.(e) 10.2 Master Transaction Agreement, dated September 7, 2005, among Calpine Corporation, Calpine Energy Services, L.P., The Bear Stearns Companies Inc., and such other parties as may become party thereto from time to time. Approximately [ten] pages of this Exhibit 10.2 have been omitted pursuant to a request for confidential treatment. The omitted language has been filed separately with the SEC.(*) 10.3 Amendment to 1996 Stock Incentive Plan, as amended.(f) 31.1 Certification of the Chairman, Certificate of of the Company, as Incorporation of the President and Chief Executive Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.(*) 31.2 Certification of the Executive Vice President and Chief Financial Officer Pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.(*) 32.1 Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.(*) ---------- (*) Filed herewith. (a) Incorporated by reference to Calpine Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, filed with the SEC on August 9, 2004. (b) Incorporated by reference to Calpine Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2005, filed with the SEC on August 9, 2005. (c) 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. (d) This document has been omitted in reliance on Item 601(b)(4)(iii) of Regulation S-K. Calpine Corporation agrees to furnish a copy of such document to the SEC upon request. (e) Incorporated by reference to Calpine Corporation's Current Report on Form 8-K filed with the SEC on July 13, 2005. (f) Description of such amendment is incorporated by reference to Item 1.01 of Calpine Corporation's Current Report on Form 8-K filed with the SEC on September 20, 2005. Such amendment constitutes a management contract or compensatory plan or arrangement. EXHIBIT 10.2 MASTER TRANSACTION AGREEMENT by and among Calpine Corporation, a Delaware corporation as "Calpine" Calpine Merchant Services Company, Inc., a Delaware corporation as "CMSC" and Calpine Energy Services, L.P., a Delaware limited partnership as "CES" and The Bear Stearns Companies Inc., a Delaware corporation as "Bear Stearns" and CalBear Energy LP, a Delaware limited partnership as "CalBear" Dated: September 7, 2005 TABLE OF CONTENTS ARTICLE I. DEFINITIONS......................................................................................2 ------------------------------------------------------------------------------------------------------------1.1 1.2 Defined Terms...................................................................................2 Construction...................................................................................15 ARTICLE II. FORMATION TRANSACTIONS; EFFECTIVE DATE.........................................................16 ------------------------------------------------------------------------------------------------------------2.1 2.2 2.3 Pre-Formation Transactions.....................................................................16 Formation Transactions.........................................................................16 Effective Date.................................................................................17 ARTICLE III. RELATIONSHIP OF THE PARTIES...................................................................17 ------------------------------------------------------------------------------------------------------------3.1 3.2 3.3 3.4 3.5 3.6 3.7 3.8 3.9 3.10 3.11 3.12 3.13 3.14 3.15 3.16 CalBear Business...............................................................................17 Exclusivity....................................................................................17 Certain Restrictions on Sales by Calpine of Equity Securities and Assets of CMSC...............18 Certain Restrictions on Sales by Bear Stearns of Equity Securities and Assets of CalBear.......21 No Joint Venture or Partnership Created........................................................24 Conflicts of Interest; Non-Discrimination......................................................25 Non-Solicitation of Bear Stearns Employees.....................................................25 Non-Solicitation of Calpine Employees..........................................................26 Confidential Information.......................................................................27 Netting........................................................................................29 Acknowledgements...............................................................................29 CMSC Board Representation......................................................................30 Performance of Financial Obligations of CalBear................................................30 [*]............................................................................................30 Fiscal Year of CalBear.........................................................................30 Interest on Overdue Amounts....................................................................31 ARTICLE IV. CALPINE GUARANTEE..............................................................................31 ------------------------------------------------------------------------------------------------------------4.1 4.2 4.3 Calpine Guarantee..............................................................................31 Calpine May Consolidate, etc., on Certain Terms................................................32 Release........................................................................................32 ARTICLE V. BEAR STEARNS GUARANTEE..........................................................................33 ------------------------------------------------------------------------------------------------------------5.1 5.2 5.3 Bear Stearns Guarantee.........................................................................33 Bear Stearns May Consolidate, etc., on Certain Terms...........................................34 Release........................................................................................34 ARTICLE VI. REGULATORY MATTERS.............................................................................35 ------------------------------------------------------------------------------------------------------------6.1 6.2 6.3 Regulatory Matters With Respect to Calpine.....................................................35 Regulatory Matters With Respect to Bear Stearns................................................35 Regulatory Matters With Respect to CalBear and CMSC............................................35 ARTICLE VII. NOTICES, RECORDS, MEETINGS, AUDITS AND AVAILABILITY...........................................36 ------------------------------------------------------------------------------------------------------------7.1 Notices........................................................................................36 7.2 7.3 7.4 7.5 Books and Records..............................................................................38 Meetings.......................................................................................38 Audits.........................................................................................39 Availability of Parties........................................................................40 ARTICLE VIII. REPRESENTATIONS AND WARRANTIES OF THE PARTIES................................................40 ------------------------------------------------------------------------------------------------------------8.1 8.2 8.3 8.4 Organization...................................................................................40 Authorization..................................................................................40 No Similar Business............................................................................40 Accuracy of Information Furnished..............................................................41 ARTICLE IX. REPRESENTATIONS AND WARRANTIES OF CALPINE......................................................41 ------------------------------------------------------------------------------------------------------------9.1 9.2 9.3 9.4 9.5 9.6 9.7 9.8 9.9 9.10 9.11 9.12 9.13 Calpine and Calpine Transaction Parties........................................................41 No Conflict or Violation.......................................................................41 Sufficiency of Assets..........................................................................41 Permits........................................................................................42 Litigation.....................................................................................42 Compliance with Law............................................................................42 Insurance......................................................................................42 Adequate Capital...............................................................................43 SEC Filings; Financial Statements..............................................................43 Regulation.....................................................................................43 Due Consideration..............................................................................44 Operations of CMSC.............................................................................44 Material Contracts of CMSC.....................................................................44 ARTICLE X. REPRESENTATIONS AND WARRANTIES OF BEAR STEARNS..................................................44 ------------------------------------------------------------------------------------------------------------10.1 10.2 10.3 10.4 10.5 10.6 10.7 10.8 10.9 10.10 10.11 Bear Stearns and CalBear.......................................................................44 No Conflict or Violation.......................................................................44 Sufficiency of Assets..........................................................................45 Permits........................................................................................45 Litigation.....................................................................................45 Compliance with Law............................................................................45 Insurance......................................................................................45 Adequate Capital...............................................................................46 SEC Filings; Financial Statements..............................................................46 Regulation.....................................................................................46 Operations of CalBear..........................................................................47 ARTICLE XI. PRE-EFFECTIVE DATE COVENANTS OF THE PARTIES....................................................47 ------------------------------------------------------------------------------------------------------------11.1 11.2 11.3 Notification of Certain Matters................................................................47 Consents and Commercially Reasonable Efforts...................................................47 Other Transaction Documents....................................................................48 ARTICLE XII. CONDITIONS TO CALPINE'S OBLIGATIONS...........................................................48 ------------------------------------------------------------------------------------------------------------12.1 12.2 12.3 12.4 Representations, Warranties and Covenants......................................................48 No Proceedings or Litigation...................................................................48 Bankruptcy.....................................................................................49 Effective Date Deliveries......................................................................49 ii 12.5 12.6 12.7 12.8 12.9 Transaction Documents..........................................................................49 Pre-Formation Transactions.....................................................................49 Corporate Proceedings..........................................................................49 Regulatory Approvals...........................................................................49 Opinion of Counsel to Bear Stearns.............................................................49 ARTICLE XIII. CONDITIONS TO BEAR STEARNS' OBLIGATIONS......................................................50 ------------------------------------------------------------------------------------------------------------13.1 13.2 13.3 13.4 13.5 13.6 13.7 13.8 13.9 Representations, Warranties and Covenants......................................................50 No Proceedings or Litigation...................................................................50 Bankruptcy.....................................................................................50 Effective Date Deliveries......................................................................50 Transaction Documents..........................................................................51 Pre-Formation Transactions.....................................................................51 Corporate Proceedings..........................................................................51 Regulatory Approvals...........................................................................51 Opinion of Counsel to Calpine..................................................................51 ARTICLE XIV. CERTAIN ACTIONS AFTER THE EFFECTIVE DATE......................................................51 ------------------------------------------------------------------------------------------------------------14.1 14.2 14.3 14.4 14.5 14.6 14.7 14.8 14.9 Survival of Representations, etc...............................................................51 No Conflict or Violation.......................................................................52 Sufficiency of Assets..........................................................................52 Permits........................................................................................52 Insurance......................................................................................52 Adequate Capital...............................................................................53 Further Assurances.............................................................................53 Litigation Support.............................................................................53 Organizational Documents of CMSC and CalBear...................................................53 ARTICLE XV. INDEMNIFICATION................................................................................53 ------------------------------------------------------------------------------------------------------------15.1 15.2 15.3 15.4 General Indemnification........................................................................53 Right of Offset................................................................................60 Payment........................................................................................60 Right to Indemnification Not Affected by Knowledge or Presumption..............................60 ARTICLE XVI. TERM; EVENTS OF DEFAULT AND TERMINATION.......................................................60 ------------------------------------------------------------------------------------------------------------16.1 16.2 16.3 16.4 16.5 16.6 Term...........................................................................................60 Renewal........................................................................................60 Certain Matters with Respect to Renewal........................................................62 Calpine Events of Default......................................................................62 Bear Stearns Events of Default.................................................................63 Termination; Liquidation Date; Transfer of Final Third Party Master Agreements.................63 ARTICLE XVII. LIMITATION OF LIABILITY......................................................................69 ------------------------------------------------------------------------------------------------------------17.1 17.2 17.3 17.4 Limitation Limitation Limitation Limitation of of of of Remedies.........................................................................69 Monetary Damages.................................................................70 Non-Monetary Damages.............................................................70 Consequential Damages, Etc.......................................................70 iii 17.5 17.6 Liability for Acts or Omissions of Other Persons...............................................71 Survival of Limitations........................................................................71 ARTICLE XVIII. MISCELLANEOUS...............................................................................71 ------------------------------------------------------------------------------------------------------------18.1 18.2 18.3 18.4 18.5 18.6 18.7 18.8 18.9 18.10 18.11 18.12 18.13 18.14 18.15 18.16 18.17 18.18 18.19 18.20 Assignment.....................................................................................71 Notices........................................................................................71 Choice of Law; Service of Process; Venue; Jury Trial Waiver....................................76 Dispute Resolution; Arbitration................................................................77 Continued Performance..........................................................................79 Regulatory Event...............................................................................79 Forward Contracts..............................................................................79 Effectiveness; Entire Agreement; Amendments and Waivers........................................79 Multiple Counterparts..........................................................................80 Invalidity.....................................................................................80 Titles; Currency; Schedules....................................................................80 Payments.......................................................................................80 Publicity......................................................................................80 Fees and Expenses..............................................................................81 Specific Performance; Remedies Cumulative......................................................81 Representation of Counsel; Mutual Negotiation..................................................81 Knowledge......................................................................................81 No Third Party Beneficiaries...................................................................81 Time of Essence................................................................................82 Force Majeure..................................................................................82 iv EXHIBITS Exhibit Exhibit Exhibit Exhibit Exhibit Exhibit A..................................Form of Agency and Services Agreement B.......................................Form of Trading Master Agreement C.......................................Organizational Documents of CMSC D....................................Organizational Documents of CalBear E.............................Form of Signature Page of CMSC and CalBear F.................................................Form of Renewal Notice SCHEDULES Schedule Schedule Schedule Schedule Schedule Schedule Schedule Schedule Schedule Schedule Schedule Schedule Schedule 1.1(a)......................................Calpine Existing Indentures 1.1(b)...................................Calpine Restricted Transferees 1.1(c)..............................Bear Stearns Restricted Transferees 1.1(d).........................................Significant Subsidiaries 3.7(a)........................................Employees of Bear Stearns 3.8(a).............................................Employees of Calpine 9.1.............................Calpine and Calpine Transaction Parties 9.2..........................Calpine Conflicts, Violations and Consents 10.1...........................................Bear Stearns and CalBear 10.2....................Bear Stearns Conflicts, Violations and Consents 12.9................................Opinions of Counsel to Bear Stearns 13.9.....................................Opinions of Counsel to Calpine 18.17.........................................................Knowledge v MASTER TRANSACTION AGREEMENT THIS MASTER TRANSACTION AGREEMENT (this "Agreement"), dated as of September 7, 2005, is made by and among Calpine Corporation, a Delaware corporation ("Calpine"), Calpine Energy Services, L.P., a Delaware limited partnership ("CES") and The Bear Stearns Companies Inc., a Delaware corporation ("Bear Stearns") and, on and after the Effective Date (as defined herein) Calpine Merchant Services Company, Inc., a Delaware corporation ("CMSC") and CalBear Energy LP, a Delaware limited partnership ("CalBear"). Each of Calpine, CES and Bear Stearns and, on and after the Effective Date, CMSC and CalBear, are sometimes hereinafter individually referred to as a "Party", and together referred to as the "Parties". RECITALS WHEREAS, the Calpine Transaction Parties (as defined herein) and CalBear desire to enter into a mutually beneficial arrangement to facilitate the Calpine Transaction Parties, on the one hand, and CalBear, on the other hand, trading in physical and financial gas and electric power with Third Parties (as defined herein), and engaging in certain energy management services, including power and gas transportation and transmission services (the "Transaction"); WHEREAS, Calpine and its Affiliates (as defined herein) will generally obtain more favorable terms for their purchases and sales of gas and power through the Transaction than the terms that are otherwise currently available to Calpine and its Affiliates for such purchases and sales; WHEREAS, CalBear desires CMSC to provide the Services (as defined herein) to CalBear, including acting as agent for CalBear with respect to certain Trades, all in accordance with the terms of the Agency and Services Agreement (as defined herein); WHEREAS, CMSC is willing to provide the Services to CalBear on the terms set forth in the Agency and Services Agreement and in this Agreement; WHEREAS, Calpine and Bear Stearns desire to guarantee certain obligations of CMSC and CES, on the one hand, and CalBear, on the other hand, respectively; WHEREAS, the Parties view the Transaction as one transaction, and none of the Parties would enter into any of the Transaction Documents (as defined herein) without entering into all of the Transaction Documents; and WHEREAS, the Parties desire to enter into this Agreement in order to more fully set forth certain rights and obligations with respect to the CalBear Business (as defined herein) and the Transaction and certain related matters. 1 AGREEMENT NOW, THEREFORE, in consideration of the foregoing premises and the mutual covenants and promises contained herein, and for other good and valuable consideration, the receipt and adequacy of which are hereby acknowledged, the Parties hereto agree as follows: ARTICLE I. DEFINITIONS 1.1 Defined Terms. As used herein, the terms below shall have the following meanings: "AAA" shall have the meaning given to such term in Section 18.4(b). "Action" shall mean, with respect to any Person, any outstanding action, order, writ, injunction, judgment, determination or decree or any claim, suit, litigation, proceeding, appeal, arbitration, mediation, tax audit or governmental investigation of any kind involving such Person or its business or Assets. "Affiliate" shall mean, with respect to any Person (the "referent person"), any Person that, directly or indirectly, controls the referent person, any Person that the referent Person controls, or any Person that, directly or indirectly, is under common control with the referent person. For purposes of the preceding sentence, the term "control" shall mean the power, direct or indirect, to direct or cause the direction of the management and policies of a Person through voting securities, by contract or otherwise. Any Subsidiary shall be deemed to be an "Affiliate". Neither Calpine nor any Calpine Transaction Party is, or shall be deemed to be, an "Affiliate" of Bear Stearns or CalBear. Neither Bear Stearns nor CalBear is, or shall be deemed to be, an "Affiliate" of Calpine or any Calpine Transaction Party. "Agency and Services Agreement" shall mean that certain Agency and Services Agreement, substantially in the form attached hereto as Exhibit A, to be dated on or about the Effective Date, by and between CMSC and CalBear, pursuant to which, among other matters, CalBear appoints CMSC as its agent to transact CalBear Business on behalf of CalBear. "Applicable Agency Law" shall mean any federal, state or local laws (including common law and criminal law), codes, statutes, directives, ordinances, by-laws, regulations, rules, judgments, consent orders, settlements, and agreements with Governmental Authorities, proclamations or delegated or subordinated legislation of any Governmental Authority governing the relationships and related duties of agents or attorneys-in-fact to their principals, such as any of the foregoing providing for duties of good faith, fair dealing, loyalty or due care of agents or attorneys-in-fact to principals. "Applicable Law" shall mean any federal, state or local laws (including common law and criminal law), codes, statutes, directives, ordinances, by-laws, regulations, rules, judgments, consent orders, settlements and agreements with Governmental Authorities, proclamations or delegated or subordinated legislation of any Governmental Authority that are applicable to this Agreement, the other Transaction Documents, the transactions contemplated 2 hereby or thereby, Calpine, the Calpine Transaction Parties, Bear Stearns, CalBear, the Services or the CalBear Trades, in each case other than Applicable Agency Law. "Arbitration Panel" shall have the meaning given to such term in Section 18.4(c). "Assets" shall mean, with respect to any Person, all of such Person's right, title and interest in and to all properties, assets and rights of any kind, now owned or hereafter acquired, whether tangible or intangible, real or personal, wherever located. "Bankruptcy" or "Bankruptcy Event" shall mean, with respect to any Person, if that Person shall institute a voluntary case seeking liquidation or reorganization under the Bankruptcy Law, or shall consent to an involuntary case thereunder against it; or such Person shall file a petition or consent or otherwise institute any similar proceeding under any other applicable Federal or state law, or shall consent thereto; or such Person shall apply for, or consent or acquiesce to, the appointment of a receiver, administrator, administrative receiver, liquidator, sequestrator, trustee or other officer with similar powers for itself or any substantial part of its Assets; or such Person shall make a general assignment for the benefit of its creditors; or such Person shall admit in writing its inability to pay its debts generally as they become due; or if an involuntary case shall be commenced seeking liquidation or reorganization of such Person under the Bankruptcy Law or any similar proceedings shall be commenced against such Person under any other Applicable Law and (a) the petition commencing the involuntary case or similar proceeding is not timely controverted, (b) the petition commencing the involuntary case or similar proceeding is not dismissed within thirty (30) days of its filing, (c) an interim trustee is appointed to take possession of all or a portion of the property, and/or to operate all or any part of the business of such Person and such appointment is not vacated within thirty (30) days, or (d) an order for relief shall have been issued or entered therein; or a decree or order of a court having jurisdiction in the premises for the appointment of a receiver, administrator, administrative receiver, liquidator, sequestrator, trustee or other officer having similar powers over such Person or all or a part of its property shall have been entered; or any other similar relief shall be granted against such Person under any applicable Bankruptcy Law. "Bankruptcy Law" shall mean Title 11, U.S. Code or any similar federal or state law for the relief of debtors, as amended, and all rules and regulations promulgated thereunder. "Bankruptcy Remote" shall mean, with respect to a Person that is an Affiliate of Calpine, that such Person has implemented governance procedures, organizational structure or other arrangements designed to make such Person less likely to become the subject of a Bankruptcy Event or to become consolidated into a Bankruptcy of Calpine or its Affiliates; provided that if such Person has at least two (2) directors or persons in similar governance functions designated by Bear Stearns that have the right to veto any voluntary and veto any consent to any involuntary bankruptcy filing, and all of such Persons' Contracts and arrangements with Affiliates are substantially similar to the Contracts and arrangements existing on the date of this Agreement or substantially as advantageous to such Person as the Contracts and arrangements which such Person would obtain in a comparable arm's length transaction, such Person shall be deemed to be Bankruptcy Remote. 3 "Bear Stearns Assets" shall mean the Assets of Bear Stearns, its Subsidiaries and their Affiliates (other than CalBear). "Bear Stearns Claim" shall have the meaning given to such term in Section 15.1(a)(i). "Bear Stearns Event of Default" shall have the meaning given to such term in Section 16.5. "Bear Stearns Guarantee" shall have the meaning given to such term in Section 5.1(a). "Bear Stearns Party" shall have the meaning given to such term in Section 15.1(a)(i). "Bear Stearns SEC Filings" shall have the meaning given to such term in Section 10.9(a). "Bonus Amount" shall have the meaning given to such term in the Agency and Services Agreement. "Books and Records" shall mean, with respect to any Person, all books, records, lists, ledgers, financial data, files, reports, product and design manuals, plans, drawings, technical manuals and operating records of every kind pertaining to such Person, any of its Subsidiaries or the Assets or the customers, suppliers, distributors or personnel of such Person or any of its Subsidiaries, in whatever form, including all (a) corporate books and records of such Person or any of its Subsidiaries, (b) disk or tape files, printouts, runs or other computer-based information and such Person's, or its applicable Subsidiary's, interest in all computer programs required to access, and the equipment containing, all such computer-based information, (c) product, business and marketing plans, (d) environmental control records, (e) sales, customer maintenance, distributor, supplier and production records including sales and promotional literature, and (f) personnel records and information. "Business Day" shall mean any day on which Federal Reserve member banks in New York City are open for business. "CalBear Business" shall have the meaning given to such term in Section 3.1(a). "CalBear Default Option" shall have the meaning given to such term in Section 16.6(d)(iii). "CalBear Governance Operations" shall have the meaning given to such term in the Agency and Services Agreement. "CalBear Information" shall mean the terms of, or other information relating to, this Agreement, any other Transaction Document, the transactions 4 entered into hereunder or thereunder or contemplated hereby or thereby, the Services, the CalBear Trades, the CalBear Business or any related information. "CalBear Name" shall have the meaning given to such term in Section 16.6(c)(i). "CalBear Referral Business" shall have the meaning given to such term in Section 3.1(a). "CalBear Termination Option" shall have the meaning given to such term in Section 16.6(d)(ii). "CalBear Trades" shall have the meaning given to such term in the Agency and Services Agreement. "Calpine Assets" shall mean the Assets of Calpine, its Subsidiaries and their Affiliates. "Calpine Claim" shall have the meaning given to such term in Section 15.1(b)(i). "Calpine Event of Default" shall have the meaning given to such term in Section 16.4. "Calpine Existing Indentures" shall mean the indentures listed on Schedule 1.1(a). "Calpine Guarantee" shall have the meaning given to such term in Section 4.1(a). "Calpine Party" shall have the meaning given to such term in Section 15.1(b)(i). "Calpine SEC Filings" shall have the meaning given to such term in Section 9.9(a). "Calpine Transaction Parties" shall mean each of CMSC and CES. "Capital Stock" shall mean (a) in the case of a corporation, corporate stock, (b) in the case of a partnership or limited liability company, partnership or membership interests or units (whether general or limited), and (c) any other interest or participation that confers on a Person the right to receive a share of the profits and losses of, or distribution of assets of, the issuing entity. "CEA" shall mean the Commodity Exchange Act, as amended, and all rules and regulations promulgated thereunder. "CET ISDA Agreement" shall have the meaning given to such term in the Trading Master Agreement. "CFTC" shall mean the Commodity Futures Trading Commission and its successors. 5 "Chairman" shall have the meaning given to such term in Section 18.4(c). "Claim" shall mean a claim, counterclaim, Action, inquiry, investigation, demand, charge, complaint, information or subpoena. "Claim Notice" shall have the meaning given to such term in Section 15.1(c)(i). "Confidential Information" shall mean, as to any Person, all proprietary and confidential financial, marketing, operational, organizational, know-how, personnel, customer, vendor, technical and other data relating to the business of such Person, in any form, whether oral or written, including all correspondence, memoranda, notes, summaries, analyses, compilations, forecasts, studies, models, extracts of and documents and records reflecting, based upon or derived from Confidential Information, regardless of who prepares it, as well as all copies and other reproductions thereof, whether in writing or stored or maintained in or by electronic, magnetic or other means, media or devices. "Contract" shall mean, with respect to any Person, any agreement, contract, lease, sublease, note, loan, evidence of indebtedness, indenture, guarantee, letter of credit, franchise agreement, undertaking, covenant not to compete, employment agreement, license, sublicense, instrument, obligation, commitment, purchase and/or sales order, quotation and other executory commitment to which such Person is a party or that relates to the businesses of such Person or its Assets, whether oral or written, express or implied, and that pursuant to its terms has not expired, terminated or been fully performed by the parties thereto. "Credit Enhancement Trade" shall have the meaning given to such term in the Trading Master Agreement. "Cumulative Net Trading Profits" shall have the meaning given to such term in the Agency and Services Agreement. "Damages" shall have the meaning given to such term in Section 15.1(a)(i). "Default Purchase Right" shall have the meaning given to such term in Section 16.6(d)(iii). "Default Sale Right" shall have the meaning given to such term in Section 16.6(d)(iii). "Default Termination Notice" shall have the meaning given to such term in Section 16.6(d)(iii). "Defaulting Parties" means Calpine and each Calpine Transaction Party, in respect of Calpine Events of Default, and Bear Stearns and CalBear, in respect of Bear Stearns Events of Default. "Defaulting Termination Parties" shall mean (i) if the Liquidation Date occurs pursuant to Section 16.6(b)(iv) or (v), the applicable Defaulting 6 Parties, (ii) if the Liquidation Date occurs pursuant to Section 16.6(b)(vi) or 16.6(b)(vii), the Parties other than the Party that terminated any of the other Transaction Documents in accordance with its terms, and its Affiliates, and (iii) if the Liquidation Date occurs pursuant to Section 16.6(b)(viii), Bear Stearns and CalBear. "Designated CMSC Board Member" shall have the meaning given to such term in Section 3.12. "Effective Date" shall have the meaning given to such term in Section 2.3. "Election Notice" shall have the meaning given to such term in Section 3.3(c). "Elective Non-Terminating Parties" shall mean the Parties other than the Elective Terminating Parties. "Elective Terminating Parties" shall mean the Party delivering the Termination Notice pursuant to Section 16.6(b)(iii) or Section 16.6(b)(ix) and its Affiliates that are Parties. "Encumbrance" shall mean any claim, lien, judgment, pledge, escrow, option, liability, charge, easement, restrictive covenant, security interest, deed of trust, right of first refusal, mortgage, right-of-way, encroachment, building or use restriction, encumbrance or other right of third parties, whether voluntarily incurred or arising by operation of law, and shall include any agreement to give any of the foregoing in the future, and any contingent or conditional sales agreement or other title retention agreement or lease in the nature thereof or the filing of, or agreement to give any financing statement, under the laws of any jurisdiction. "Equity Securities" shall mean (i) shares of Capital Stock or other equity securities, (ii) subscriptions, calls, warrants, options or commitments of any kind or character relating to, or entitling any Person to purchase or otherwise acquire, any Capital Stock or other equity securities, and (iii) securities convertible into or exercisable or exchangeable for shares of Capital Stock or other equity securities. "Exchange Act" shall mean the U.S. Securities Exchange Act of 1934, as amended, and all rules and regulations promulgated thereunder. "Facilities" shall mean, collectively, Power generating facilities that are located in the United States of America, Canada or Mexico. "FERC" means the Federal Energy Regulatory Commission and its successors. "Final Third Party Master Agreements" shall have the meaning given to such term in Section 16.6(d)(i). "Fiscal Quarter" shall have the meaning given to such term in the Agency and Services Agreement. 7 "Fiscal Year" shall mean a fiscal year of CalBear, which as of the date of this Agreement commences on December 1 of each calendar year and ends on November 30 of the following calendar year, subject to revision in accordance with Section 3.15; provided that (x) the first Fiscal Year shall commence on the date of this Agreement and end the earlier of (1) November 30, 2005 and (2) the Termination Date, and (y) the last Fiscal Year shall end on the Termination Date. "Force Majeure" shall mean an event or circumstance which prevents one Party from performing its obligations under the Transaction Documents, which event or circumstance was not anticipated as of the date the applicable obligation was agreed to, which is not within the reasonable control of, or the result of the negligence of, the Party claiming the Force Majeure, and which, by the exercise of commercially reasonable efforts, such Party is unable to overcome or avoid or cause to be avoided, including acts of God, acts of the public enemy including terrorism, unexpected delay by any Governmental Authority, and any change in Applicable Law. Force Majeure shall exclude any event or circumstance if its sole effect on a Party is economic, including economic effects that prevent Payment. "Formation Transactions" shall have the meaning given to such term in Section 2.2. "Forward" shall have the meaning given to such term in the Trading Master Agreement. "FPA" shall mean the Federal Power Act, as amended, and all rules and regulations promulgated thereunder. "GAAP" shall mean accounting principles generally accepted in the United States of America. The term, "GAAP," when used herein, shall mean the accounting principles generally accepted by the Securities Exchange Commission as reflected in Regulation S-X promulgated under the Exchange Act. The term "GAAP," when used herein with respect to CalBear or the CalBear Trades, shall mean GAAP as applied consistently by Bear Stearns from time to time. "Gas" shall mean physical or financial natural gas unless otherwise agreed upon between the Parties. "Gas Trade" shall mean any purchase or sale or hedge of Gas, or the transportation, transmission or storage of Gas, all on a world-wide basis. "Governmental Authority" shall mean any federal, state, local or municipal government, governmental department, commission, board, bureau, agency or instrumentality, any RTO/ISO control area or SRO, or any judicial, regulatory, administrative or quasi-governmental court, panel or other body, having or asserting jurisdiction as to the matter in question. "Hard Covenants" shall mean Section 4.2(b) of the Agency and Services Agreement (to the extent of the prohibition therein with respect to entering 8 into Trades directly with Calpine or any of its Affiliates), Sections 4.17(a), (b), (c) and (e) of the Agency and Services Agreement, and Section 3.13 of this Agreement. "Initial Notice" shall have the meaning given to such term in Section 3.3(a). "Initial Period" shall have the meaning given to such term in Section 3.3(b). "Initial Term" shall mean the period commencing on the Effective Date and ending on November 30, 2006. "ISO" shall mean any FERC-authorized independent system operator. "Latest Renewal Period" shall have the meaning given to such term in Section 16.2(a)(ii). "Liabilities" shall mean any liability, indebtedness, obligation, co-obligation, commitment, expense, claim, deficiency, guaranty or endorsement of or by any Person of any nature (whether direct or indirect, known or unknown, absolute or contingent, liquidated or unliquidated, due or to become due, accrued or unaccrued, matured or unmatured). "Liquidation" shall have the meaning given to such term in the Agency and Services Agreement. "Liquidation Date" shall mean the date on which Liquidation shall begin. "Material Adverse Effect" or "Material Adverse Change" shall mean, with respect to any Person, any change, circumstance, event or effect that, individually or in the aggregate with such other changes, circumstances, events or effects, is or is reasonably likely to constitute, a material adverse change in, or have a material adverse effect on (a) the business, operations, assets, liabilities, foreseeable prospects, financial condition or results of operations of such Person and its Subsidiaries, taken as a whole, or (b) the right or ability of such Person to consummate the transactions, taken as a whole, contemplated hereby and by the other Transaction Documents. "Misconduct" shall mean, with respect to any Person: (a) any nonfulfillment, nonperformance, nonobservance or other breach or violation of, or default under, any provision of any Transaction Document by such Person, through any act or omission, if (i) such act or omission was taken or not taken with the intent to take or not take the same by the individual acting on behalf of such Person, (ii) such individual knew that such act or omission constituted a breach or violation of the Transaction Documents or the policies of such Person or such individual had previously taken, or omitted to take, such act and had been warned that such act or omission constituted a breach or violation of the Transaction Documents or the policies of such Person, and (iii) at the time of such act or omission, an officer (or with respect to CMSC, prior to January 1, 2006, an officer seconded to CMSC under the applicable transition services agreement with an Affiliate of Calpine) of such Person knew or should have known that such act or omission was being taken or omitted to be taken, (b) any fraud by such Person with respect to the Transaction Documents or the matters covered thereby, and (c) any nonfulfillment, nonperformance, nonobservance or other 9 breach or violation of, or default under any provision of any Transaction Document by such Person through any act or omission if such act or omission constituted gross negligence in the scheduling of physical Trades. "Month" shall mean a calendar month. "MW" shall mean megawatt, or one million (1,000,000) watts of Power. "MWh" shall mean megawatt-hour, or one million watts (1,000,000) of Power for one (1) hour. "Non-Compete Defaulting Termination Parties" shall mean (i) if the Liquidation Date occurs pursuant to Section 16.6(b)(iv) or (v), the applicable Defaulting Parties, (ii) if the Liquidation Date occurs pursuant to Section 16.6(b)(vi) (except for an occurrence of the Liquidation Date as a result of a termination of the Agency and Services Agreement pursuant to Section 7.1(a)(iii) thereof) or 16.6(b)(vii) (except for an occurrence of the Liquidation Date as a result of a termination of the Agency and Services Agreement pursuant to Section 7.1(a)(iv) thereof), the Parties other than the Party that terminated any of the other Transaction Documents in accordance with its terms, and its Affiliates, and (iii) if the Liquidation Date occurs pursuant to Section 16.6(b)(viii), Bear Stearns and CalBear. "Non-Compete Period" [*] "Non-Defaulting Termination Parties" shall mean the Parties other than the Defaulting Termination Parties. "Non-Renewal Purchase Notice" shall have the meaning given to such term in Section 16.6(d)(i). "Non-Renewal Purchase Right" shall have the meaning given to such term in Section 16.6(d)(i). "Non-Renewing Parties" shall have the meaning given to such term in Section 16.2(d). "Offer" shall have the meaning given to such term in Section 3.3(b). "Offer Notice" shall have the meaning given to such term in Section 3.3(b). "Offer Period" shall have the meaning given to such term in Section 3.3(b). "Ordinary Losses" shall mean (a) any Claims or Damages with respect to the actual or prospective operations or economic results of CalBear, including losses (i) on CalBear Trades where delivery of Gas or Power or determination of price has occurred, (ii) on Forward CalBear Trades, and (iii) with respect to lost CalBear Trades, profits or opportunities, and (b) any other Claims or Damages, excluding in each case under clauses (a) and (b), Third Party Losses. 10 "Organizational Documents" shall mean the articles of incorporation, by-laws, articles of organization, limited liability company agreement, partnership agreement, formation agreement, joint venture agreement or other similar organizational documents of any Person other than any individual, as applicable with respect to such Person. "Party Arbitrator" shall have the meaning given to such term in Section 18.4(c). "Payment" shall mean any payment, repayment, return, refund, transfer, deposit, funding, posting or other type of payment or provision of an amount or collateral (including provision of letters of credit), whether as a payment or provision for services or property, capital contribution, loan, guarantee, advance, cure of default, collateral, margin, credit support or any other form of security or any other amount. "Permits" shall mean, with respect to any Person, all licenses, permits, franchises, approvals, authorizations, certifications, consents, orders, settlements, exemptions or similar items of, or filings, reports, notifications or similar items submitted to or granted by, any Governmental Authority, whether foreign, federal, state or local or otherwise, under Applicable Law, necessary for the past, present or anticipated conduct of, or relating to the operation of the businesses of or the ownership of the Assets of, such Person. "Person" shall mean any individual, corporation, partnership, joint venture, association, joint stock company, trust, unincorporated organization, limited liability company or Governmental Authority or other entity. "Power" shall mean physical or financial electric capacity as measured in MWs, physical or financial electric energy as measured in MWh, and/or any other electricity related products or services available for sale, including reserves and other ancillary services needed to support the transmission and distribution of Power from a point of generation to a delivery point, as such services are defined in applicable FERC-filed tariffs. "Power Trade" shall mean any purchase or sale or hedge of Power, or the transportation or transmission of Power, all on a world-wide basis. "Pre-Formation Transactions" shall have the meaning given to such term in Section 2.1. "PUHCA" shall mean the Public Utility Holding Company Act of 1935, as amended, and all rules and regulations promulgated thereunder. "Regulatory Approval" shall mean all Permits that are necessary for the entering into and performance of CalBear Trades, this Agreement, the other Transaction Documents, or the transactions contemplated hereby or thereby. "Regulatory Event" shall have the meaning given to such term in Section 18.6. "Remedial Parties" shall have the meaning given to such term in Section 17.1. 11 "Renewal Notice" shall have the meaning given to such term in Section 16.2(a)(i). "Renewal Period" shall have the meaning given to such term in Section 16.1. "Renewing Parties" shall have the meaning given to such term in Section 16.2(d). "Reports" shall have the meaning given to such term in the Agency and Services Agreement. "Representative" shall mean, with respect to any Person, any officer, director, principal, attorney, employee, agent, consultant, accountant or other representative of such Person. "Restricted Transferees" shall mean, with respect to Calpine, the Calpine Transaction Parties and their Affiliates, the Persons listed in Schedule 1.1(b), and with respect to Bear Stearns, CalBear and their Affiliates, the Persons listed in Schedule 1.1(c). "Returns" shall mean, with respect to any Person, any and all returns, reports, declarations, documents and information statements with respect to Taxes required to be filed by or on behalf of such Person with any governmental authority or Tax authority or agency, whether domestic or foreign, including consolidated, combined and unitary returns and all amendments thereto or thereof and any documents with respect to or accompanying requests for the extension of time in which to file any such returns, reports, declarations, documents and information statements. "Risk Policy" shall have the meaning given to such term in the Agency and Services Agreement. "RTO" shall mean any FERC-authorized regional transmission organization. "Securities Act" shall mean the U.S. Securities Act of 1933, as amended, and all rules and regulations promulgated thereunder. "Service Fee" shall have the meaning given to such term in the Agency and Services Agreement. "Service Fee Return" shall have the meaning given to such term in the Agency and Services Agreement. "Service Fee Return Refund" shall have the meaning given to such term in the Agency and Services Agreement. "Services" shall have the meaning given to such term in the Agency and Services Agreement. "Significant Subsidiary" shall mean (a) in the case of Calpine, the Subsidiaries of Calpine listed on Schedule 1.1(d), their successors, if such successors are Affiliates of Calpine, and assigns of all or substantially all of 12 their assets, if such assigns are Affiliates of Calpine and (b) in the case of Bear Stearns, the Subsidiaries of Bear Stearns listed on Schedule 1.1(d), their successors, if such successors are Affiliates of Bear Stearns, and assigns of all or substantially all of their assets, if such assigns are Affiliates of Bear Stearns. "Soft Covenants" shall mean Sections 3.1 and 3.14 of this Agreement and Sections 4.1(b), (c) and (e), and 4.4(a) of the Agency and Services Agreement. "Specified Risk Limits" shall have the meaning given to such term in the Agency and Services Agreement. "SRO" shall mean any applicable self-regulatory organization, including CFTC-designated contract markets. "Subsidiary" shall mean, with respect to any Person, any corporation or other business entity, whether or not incorporated, of which at least a majority of the securities or interests having, by their terms, ordinary voting power to elect members of the board of directors, managing members, or other persons performing similar functions with respect to such entity, is held, directly or indirectly, by such Person. "Tax(es)" shall mean all taxes, estimated taxes, withholding taxes, assessments, levies, imposts, and other like charges, including any interest, fines, penalties, additions to tax or additional amounts that have or may become payable in respect thereof, imposed by any foreign, federal, state or local government or taxing authority, whether computed on a separate, consolidated, unitary, combined or any other basis, which taxes shall include all income taxes, service, license and net worth taxes, payroll and employee withholding taxes, unemployment insurance, retirement, social security, sales and use taxes, value-added taxes, excise taxes, franchise taxes, gross receipts taxes, occupation taxes, real and personal property taxes, stamp taxes, transfer and recording taxes, workers' compensation and other obligations of the same or of a similar nature. "Termination Amount" shall have the meaning given to such term in Section 16.6(d)(ii). "Termination Date" shall have the meaning given to such term in Section 16.1. "Termination Fee" shall have the meaning given to such term in Section 16.6(d)(ii). "Termination Notice" shall mean an irrevocable notice delivered by a Party, on behalf of itself and its Affiliates that are Parties and in any manner set forth in Section 18.2, to any of the Parties that are not Affiliates of such Party, stating the intent of such Party to cause a Liquidation Date in accordance with Section 16.6(b)(iii) or Section 16.6(b)(ix) and setting forth (a) a Termination Amount, (b)(i) in the case of such notice by Calpine or any Calpine Transaction Party, (A) Calpine's or such Calpine Transaction Party's binding offer, irrevocable by its terms for two (2) Business Days following receipt of the Termination Notice by Bear Stearns or CalBear, to either (x) purchase the Final Third Party Master Agreements, in accordance with Section 13 16.6(d)(v) (including the last sentence thereof), from CalBear for the Termination Amount or (y) receive from Bear Stearns or CalBear the Termination Fee, and (B) that Bear Stearns or CalBear shall elect within such two (2) Business Day period to either sell the Final Third Party Master Agreements or pay the Termination Fee in accordance with the immediately preceding clause (A), or (ii) in the case of such notice by Bear Stearns or CalBear, (A) Bear Stearns' or CalBear's binding offer, irrevocable by its terms for two (2) Business Days following receipt of the Termination Notice by Calpine or any Calpine Transaction Party, to either (x) sell the Final Third Party Master Agreements, in accordance with Section 16.6(d)(v) (including the last sentence thereof) to Calpine or any Calpine Transaction Party for the Termination Amount or (y) pay to Calpine or any Calpine Transaction Party the Termination Fee and (B) that Calpine or any Calpine Transaction Party shall elect within such two (2) Business Day period to either purchase the Final Third Party Master Agreements or pay the Termination Fee in accordance with the immediately preceding clause (A). "Termination Purchase Right" shall have the meaning given to such term in Section 16.6(d)(ii). "Termination Sale Right" shall have the meaning given to such term in Section 16.6(d)(ii). "Third Party" shall mean, with respect to any Person, any other Person that is not an Affiliate of such Person, including any Governmental Authority. For purposes of this Agreement and the other Transaction Documents, none of Calpine or any Calpine Transaction Party shall be deemed to be a "Third Party" with respect to Bear Stearns or CalBear and neither Bear Stearns nor CalBear shall be deemed to be a "Third Party" with respect to Calpine or any Calpine Transaction Party. "Third Party Claim" shall have the meaning given to such term in Section 15.1(c)(i). "Third Party Losses" shall mean any Claims or Damages arising out of or resulting from (i) a Third Party Claim, including any such Claim by a Governmental Authority or (ii) actions taken to investigate, prevent or mitigate a potential Third Party Claim, to the extent such actions (A) are taken by Calpine or any Calpine Transaction Party or (B) are reasonable actions taken by CalBear or any of its Affiliates to investigate, prevent or mitigate potential Third Party Claims arising out of or resulting from a violation of Applicable Law by Calpine or any Calpine Transaction Party for which indemnification would be available under Section 15.1(a)(i)(A), (B), or (E), if after notice of such violation by CalBear or any of its Affiliates, neither Calpine nor any Calpine Transaction Party takes timely, reasonable actions to investigate, prevent or mitigate such potential Third Party Claims. "Third Party Master Agreement" shall have the meaning given to such term in the Agency and Services Agreement. "Third Party Service Transaction" shall mean any arrangement to provide a set of services to a Third Party related to Power or Gas contract management or physical or financial optimization activities of a counterparty, 14 to the extent that such services are related to Power generation or Gas production, purchases, sales, transmission, transportation, dispatch, scheduling, nomination, injection, withdrawal, storage, ancillary services or related physical or financial services and products. "Threshold" shall have the meaning given to such term in Section 15.1(a)(iv)(B). "Trades" shall mean any and all Gas Trades and Power Trades. "Trading Master Agreement" shall mean that certain Trading Master Agreement, substantially in the form attached hereto as Exhibit B, to be dated on or about the Effective Date, by and between CES, CMSC and CalBear, governing, among other matters, Credit Enhancement Trades. "Trading Volume" shall mean a volume of Power equal to the aggregate volume of Power (measured in MWhs) traded in any calendar year by (a) Calpine, in the CES discretionary program, and (b) CalBear. "Transaction Documents" shall mean (a) this Agreement, (b) the Agency and Services Agreement, (c) the Trading Master Agreement, and (d) the CET ISDA Agreement. "Transaction Parties" shall mean the Calpine Transaction Parties and CalBear, collectively. "Transfer" shall have the meaning given to such term in Section 3.3(a). 1.2 Construction. (a) Unless the context of this Agreement otherwise requires, (i) words of any gender include each other gender, (ii) words using the singular or plural number also include the plural or singular number, respectively, (iii) the terms "hereof," "herein," "hereby" and derivative or similar words refer to this entire Agreement, (iv) the terms "modified" and "amended" and derivative or similar words shall mean amended, supplemented, waived or otherwise modified, (v) the terms "Article" or "Section" refer to the specified Article or Section of this Agreement, (vi) the word "including" shall mean "including, without limitation," whether or not so specified, and (vii) the word "or" shall be disjunctive but not exclusive. (b) References to agreements and other documents shall be deemed to include all subsequent modifications thereto. (c) References to statutes shall include all regulations promulgated thereunder and references to statutes or regulations shall be construed as including all statutory and regulatory provisions consolidating, amending or replacing the statute or regulation. (d) The language used in this Agreement shall be deemed to be the language chosen by the Parties to express their mutual intent, and no rule of strict construction shall be applied against any Party. 15 (e) The annexes, schedules and exhibits to this Agreement are a material part hereof and shall be treated as if fully incorporated into the body of this Agreement. (f) Whenever this Agreement refers to a number of days, such number shall refer to calendar days unless Business Days are specified. (g) Whenever this Agreement refers to a right, obligation, act or omission of CalBear, the same shall mean a right, obligation, act or omission of CalBear itself, and not of CalBear through CMSC as agent or attorney-in-fact for or on behalf of or in the name of CalBear, unless the applicable provision of this Agreement expressly states otherwise. ARTICLE II. FORMATION TRANSACTIONS; EFFECTIVE DATE 2.1 Pre-Formation Transactions. As soon as reasonably practicable following the date hereof: (a) CES Marketing VII, LLC shall be converted from a limited liability company to a corporation under the laws of the State of Delaware and its name shall be changed to Calpine Merchant Services Company, Inc., and Calpine shall enter into, or cause to be entered into, amended and restated Organizational Documents of CMSC, substantially in the form attached hereto as Exhibit C; (b) Arroyo Energy LP's name shall be changed to CalBear Energy LP and Bear Stearns or its Affiliates shall enter into amended and restated Organizational Documents of CalBear, substantially in the form attached hereto as Exhibit D; (c) Calpine and the Calpine Transaction Parties shall take commercially reasonable actions to obtain any Regulatory Approvals necessary or advisable in order for CMSC to perform the Services; and (d) CalBear shall take commercially reasonable actions to obtain any Regulatory Approvals necessary or advisable in order for CalBear to execute any CalBear Trades. The transactions described in this Section 2.1 shall be referred to herein as the "Pre-Formation Transactions." 2.2 Formation Transactions. Upon the terms and subject to the conditions set forth in this Agreement, on or prior to the Effective Date: (a) Calpine shall cause CMSC and Bear Stearns shall cause CalBear to become a Party to this Agreement by executing an additional signature page to this Agreement, substantially in the form of Exhibit E hereto, and, following such execution each of CMSC and CalBear shall be a party to, shall be bound by the obligations of, and shall receive the benefits of this Agreement and shall be "CMSC" and "CalBear", respectively, and a "Party", in each case as defined herein, for all purposes hereunder; and 16 (b) CalBear and the applicable Calpine Transaction Parties shall enter into the Agency and Services Agreement, the Trading Master Agreement and the CET ISDA Agreement. The transactions described in this Section 2.2 shall be referred to herein as the "Formation Transactions." 2.3 Effective Date. Unless this Agreement shall have been terminated pursuant to Section 16.6(a) hereof, the consummation of the transactions contemplated herein to be consummated on the Effective Date shall take place at 10:00 a.m. New York time at the offices of Latham & Watkins LLP, at 885 Third Avenue, New York, NY 10022, on the third (3rd) Business Day following the satisfaction or waiver of all of the conditions precedent to the obligations of the Parties set forth in Article XII and Article XIII (other than conditions which are not capable of being satisfied until the Effective Date), or such other date as the Parties hereto agree (the "Effective Date"). ARTICLE III. RELATIONSHIP OF THE PARTIES Each of the Parties covenant and agree with each other as follows: 3.1 CalBear Business[*] (b) Notwithstanding any other provision of this Agreement, the sole and exclusive remedy for any breach of this Section 3.1 shall be, in the event of a breach by Calpine or the Calpine Transaction Parties, on the one hand, or Bear Stearns, on the other hand, the termination of this Agreement pursuant to Section 16.6(b)(iii) hereof. 3.2 Exclusivity. (a) Except as may otherwise be specifically provided in this Agreement, including Sections 3.2(b), (c) and (d), or the other Transaction Documents, from the date hereof through the earlier of (i) the date of termination of this Agreement, if this Agreement is terminated prior to the Effective Date, or (ii) in all other cases, the last day of the Non-Compete Period, neither Calpine or any of the Calpine Transaction Parties, on the one hand, nor Bear Stearns or CalBear, on the other hand, will, directly or indirectly, through one or more of their respective Affiliates or otherwise, engage in any business arrangement with a Third Party, whether structured as a strategic alliance, joint venture, partnership, co-ownership, contractual relationship, agency relationship, or otherwise, which, when taken as a whole, substantially replicates the substance of the business arrangement under the Transaction Documents, taken as a whole, and in connection therewith provides for the sharing of the profits (whether through the ownership of Equity Securities, contractually, or otherwise) of such business with the Third Party, in each case, in any state, possession, territory or other political subdivision of the United States, Canada or Mexico. (b) The foregoing Section 3.2(a) shall not prohibit any business of Calpine or any Calpine Transaction Party with a Third Party if the primary business of such Third Party and its Affiliates, taken as a whole, is the 17 ownership, operation or management of one or more Facilities or gas or electric loads or the purchase, sale, trading or transmission of Power or Gas. (c) Nothing in this Agreement shall prohibit (x) Calpine or the Calpine Transaction Parties or any of their Affiliates, on the one hand, or Bear Stearns or CalBear or any of their Affiliates, on the other hand, from having passive investments of less than five (5) percent in the aggregate of the outstanding Equity Securities of any entity listed for trading on a national stock exchange (as defined in the Exchange Act) or any recognized automatic quotation system, (y) Calpine, the Calpine Transaction Parties or any of their Affiliates, on the one hand, or Bear Stearns or CalBear or any of their Affiliates, on the other hand, from entering into any financing or credit enhancement transaction, including any transaction similar to a transactions contemplated by the Trading Master Agreement (provided that the other aspects of such transaction do not result in the engagement in a business that would otherwise violate this Section 3.2), or (z) Bear Stearns, CalBear or any of their Affiliates from acting as an underwriter, initial purchaser, lender or otherwise with respect to any debt, equity or other financing of any Person, or purchasing, owning, holding, trading or selling any security or other interest in any Person (provided that such activity or the related transactions, when taken as a whole, does not result in the engagement in a business that would otherwise violate this Section 3.2). (d) Nothing in this Agreement shall prohibit Calpine or the Calpine Transaction Parties or any of their Affiliates, on the one hand, or Bear Stearns or any of its Affiliates (other than CalBear), on the other hand, from engaging in any transaction that has been proposed to CalBear by Calpine or its Affiliates, on the one hand, or Bear Stearns or its Affiliates, on the other hand, in accordance with the terms of the Transaction Documents, if CalBear has elected not to pursue such transaction and such transaction has ceased to be CalBear Referral Business in accordance with Section 3.1(a) above. 3.3 Certain Restrictions on Sales by Calpine of Equity Securities and Assets of CMSC. (a) Calpine and each of the Calpine Transaction Parties hereby agrees that it shall not, and shall cause its Affiliates not to, directly or indirectly (through the sale of Equity Securities in an Affiliate or otherwise), sell, assign, transfer, convey, pledge, mortgage, hypothecate or otherwise encumber or dispose of (in each case, a "Transfer") any Equity Securities of, or all or substantially all of the Assets of, CMSC, except in compliance with this Section 3.3. If Calpine, any of the Calpine Transaction Parties, or any of their Affiliates wishes to Transfer any such Assets or Equity Securities, Calpine shall first deliver to Bear Stearns a letter (the "Initial Notice") signed by Calpine (and any such Calpine Transaction Party or Affiliate, if applicable) setting forth the Equity Securities and/or Assets proposed to be Transferred and the material terms of the proposed Transfer other than the price. (b) Upon receipt of an Initial Notice, Bear Stearns and its Affiliates shall have forty five (45) days (the "Initial Period") to submit a binding letter (the "Offer Notice") signed by Bear Stearns (and any such Affiliate, if applicable) setting forth (A) a proposed purchase price with respect to the Equity Securities and/or Assets proposed to be Transferred and (B) Bear Stearns' (or such Affiliate's) offer (irrevocable by its terms for five (5) Business Days 18 (such five (5) day period, the "Offer Period")) to purchase from Calpine or such Calpine Transaction Party or any of their Affiliates the Equity Securities and/or Assets described in the Initial Notice, on the terms and conditions described in the Initial Notice and for the purchase price set forth in the Offer Notice (an "Offer"). If an Offer Notice is delivered prior to the end of the Initial Period, the Initial Period shall end on the date of delivery of such Offer Notice and the Offer Period shall commence on such date. If neither Bear Stearns nor any of its Affiliates delivers an Offer Notice to Calpine within the Initial Period, Calpine or its Affiliate may, during the period beginning on the forty-sixth (46th) day following the receipt of the Initial Notice by Bear Stearns and ending on the ninetieth (90th) day following the receipt of the Initial Notice by Bear Stearns, Transfer to a Third Party all (but not less than all) of the Equity Securities and/or Assets covered by the Initial Notice, for a purchase price negotiated between Calpine or such Affiliate and such Third Party and on other terms and conditions at least as favorable to Calpine as those contained in the Initial Notice; provided that if a Third Party transferee has accepted such offer, Calpine shall have completed such Transfer within an additional one hundred eighty (180) days from the end of such ninety (90) day period; and provided, further, that, with respect to any such Transfer that is not completed within the time periods set forth in this Section 3.3(b), Calpine shall not complete any such Transfer without again complying with each provision of this Section 3.3, as applicable. (c) Upon receipt of an Offer Notice, Calpine and its Affiliates shall have the option to sell the Equity Securities and/or Assets described in the Initial Notice to Bear Stearns (or its Affiliate, as applicable) at the purchase price and upon the terms and conditions specified in the Offer. If Calpine or any of its Affiliates desires to exercise the option set forth in the preceding sentence, it shall deliver a notice (an "Election Notice") to Bear Stearns at any time during the Offer Period, which Election Notice shall specify that Calpine or any of its Affiliates has elected to exercise its option to accept the Offer and sell the Equity Securities and/or Assets described in the Initial Notice to Bear Stearns (or its Affiliate, as applicable) on the terms set forth in the Offer. If Calpine or any of its Affiliates delivers an Election Notice during the Offer Period, then Bear Stearns (or its Affiliates, as applicable) shall be obligated to purchase and Calpine (or such Affiliate, as applicable) shall be obligated to sell, the Equity Securities and/or Assets described in the Initial Notice at the purchase price and on the other terms and conditions indicated in the Offer. The closing of such purchase and sale shall occur on a closing date selected by Bear Stearns or such Affiliate, as applicable; provided, however, that such closing date shall be not less than ten (10) days nor more than ninety (90) days following the date of the Election Notice, unless more time is required to obtain any applicable regulatory or other approvals. If neither Calpine nor any of its Affiliates delivers an Election Notice to Bear Stearns (or its Affiliate, as applicable) within the Offer Period, the Offer shall automatically expire at the end of the Offer Period and neither Bear Stearns nor any of its Affiliates shall have any obligation to purchase the Equity Securities and/or Assets described in the Initial Notice. (d) If Bear Stearns or one of its Affiliates delivers an Offer Notice to Calpine within the Initial Period, but neither Calpine nor any of its Affiliates delivers an Election Notice to Bear Stearns during the Offer Period, Calpine or its Affiliate may, during the period beginning on the sixth (6th) day following the receipt of the Offer Notice by Calpine and ending on the fiftieth (50th) day following the receipt of the Offer Notice by Calpine, Transfer to a Third Party all (but not less than all) of the Equity Securities and/or Assets covered by the Initial Notice, (x) for the purchase price and on the other terms 19 and conditions contained in the Offer Notice or (y) for a purchase price more favorable financially to Calpine, and on other terms at least as favorable to Calpine, as those contained in the Offer Notice; provided that if a Third Party transferee has accepted such offer, Calpine shall have completed such Transfer within an additional one hundred eighty (180) days from the end of such fifty (50) day period; and provided, further, that, with respect to any such Transfer that is not completed within the time periods set forth in this Section 3.3(d), Calpine shall not complete such Transfer without again complying with each provision of this Section 3.3, as applicable. (e) In addition to the foregoing restrictions, Calpine (or the applicable Calpine Transaction Party or Affiliate) shall not complete any Transfer pursuant to Section 3.3(b) or Section 3.3(d) without receiving the prior consent of Bear Stearns to the transferee of such Transfer, such consent with respect to any proposed Third Party transferee not to be unreasonably withheld or delayed after Calpine's (or the applicable Calpine Transaction Party's or Affiliate's) request for such consent (and in no event shall such consent take more than the longer of ten (10) Business Days following receipt of such request by Bear Stearns or the time remaining until the end of the Initial Period or the Offer Period, as applicable); provided that Bear Stearns may give or withhold such consent in its sole and absolute discretion with respect to any proposed Transfers to a Restricted Transferee. Calpine may make the request for such consent at any time following delivery of an Initial Notice, including contemporaneously with the applicable Initial Notice; provided that Calpine must provide the identity of any proposed Third Party transferee (as well as the identity of the ultimate operating and holding company parent, if any, of each proposed Third Party transferee, if the identity of such Person(s) is not readily apparent) in each request for consent, and otherwise comply with this Section 3.3. Any consent given to a Transfer pursuant to this Section 3.3(e) shall expire (i) if no proposed Third Party transferee mentioned in a request for consent and approved by Bear Stearns has accepted Calpine's offer to Transfer the Equity Securities and/or Assets covered by the Initial Notice in accordance with Section 3.3(b) or Section 3.3(d) by the end of the ninety (90) day period set forth in Section 3.3(b) or the fifty (50) day period set forth in Section 3.3(d), respectively, at the end of such period, or (ii) if a proposed Third Party transferee approved by Bear Stearns has accepted such offer, if Calpine's Transfer to such Third Party transferee has not been completed within an additional one hundred eighty (180) days from the end of the ninety (90) day period set forth in Section 3.3(b) or the fifty (50) day period set forth in Section 3.3(d), as applicable. (f) Calpine further agrees that in connection with any Transfer subject to this Section 3.3 consented to by Bear Stearns, Calpine shall, if requested by Bear Stearns, deliver to Bear Stearns an opinion of external counsel in form and substance reasonably satisfactory to Bear Stearns and counsel for Bear Stearns, to the effect that the Transfer is not in violation of this Agreement, and, with respect to a Transfer of any Equity Security, is not in violation of the Securities Act or the securities laws of any State. Any purported Transfer in violation of the provisions of this Section 3.3, including any Transfer to a Third Party made without Bear Stearns' prior consent, shall be null and void and shall have no force or effect. (g) Notwithstanding anything herein to the contrary, this Section 3.3 shall not apply to (i) a Transfer to Calpine or any of its Affiliates, provided that if such Transfer is a Transfer of (A) Assets from CMSC, such Transfer is to 20 an Affiliate of Calpine that is Bankruptcy Remote, or (B) Equity Securities of CMSC, following such Transfer CMSC is Bankruptcy Remote, (ii) a Transfer to Bear Stearns or any of its Affiliates, or (iii) a Transfer to any Person or such Person's Subsidiaries if such Person or its Subsidiaries merge with Calpine or purchase all or substantially all of the Equity Securities or Assets of Calpine. (h) In addition to the restrictions set forth elsewhere in this Agreement, in the event of a proposed Transfer to a Third Party by Calpine or any of its Affiliates of Equity Securities and/or Assets of CMSC pursuant to this Section 3.3, Bear Stearns' consent to such Transfer shall not be deemed unreasonably withheld if such Third Party does not agree to become bound in writing at the closing of such Transfer by the terms and conditions of this Agreement and the other Transaction Documents and agree to assume the rights and obligations of Calpine and all of the Calpine Transaction Parties hereunder and thereunder pursuant to one or more instruments of assumption reasonably satisfactory in form and substance to Bear Stearns. Notwithstanding the other provisions of this Section 3.3, unless expressly waived by Bear Stearns, any otherwise permitted Transfer shall be null and void ab initio if Bear Stearns does not receive written instruments with respect to such Transfer (including copies of any instruments of assumption and the Third Party transferee's consent to be bound by this Agreement and the other Transaction Documents, as applicable) that are in a form reasonably satisfactory in form and substance to Bear Stearns. Upon the execution of such instruments of assumption by such Third Party, such Third Party shall be deemed to be Calpine and the Calpine Transaction Parties for all purposes of this Agreement. 3.4 Certain Restrictions on Sales by Bear Stearns of Equity Securities and Assets of CalBear. (a) Bear Stearns hereby agrees that it shall not, and shall cause its Affiliates not to, directly or indirectly (through the sale of Equity Securities in an Affiliate or otherwise), Transfer any Equity Securities of, or all or substantially all of the Assets of, CalBear, except in compliance with this Section 3.4. If Bear Stearns or any of its Affiliates wishes to Transfer any such Assets or Equity Securities, Bear Stearns shall first deliver to Calpine an Initial Notice signed by Bear Stearns (and any such Affiliate, if applicable) setting forth the Equity Securities and/or Assets proposed to be Transferred and the material terms of the proposed Transfer other than the price. (b) Upon receipt of an Initial Notice, Calpine and its Affiliates shall have the Initial Period to submit an Offer Notice signed by Calpine (and any such Affiliate, if applicable) setting forth (A) a proposed purchase price with respect to the Equity Securities and/or Assets proposed to be Transferred and (B) Calpine's (or such Affiliate's) offer (irrevocable by its terms for the Offer Period) to purchase from Bear Stearns or any of its Affiliates the Equity Securities and/or Assets described in the Initial Notice, on the terms and conditions described in the Initial Notice and for the purchase price set forth in the Offer Notice. If an Offer Notice is delivered prior to the end of the Initial Period, the Initial Period shall end on the date of delivery of such Offer Notice and the Offer Period shall commence on such date. If neither Calpine nor any of its Affiliates delivers an Offer Notice to Bear Stearns within the Initial Period, Bear Stearns or its Affiliate may, during the period beginning on the forty-sixth (46th) day following the receipt of the Initial Notice by Calpine and ending on the ninetieth (90th) day following the receipt 21 of the Initial Notice by Calpine, Transfer to a Third Party all (but not less than all) of the Equity Securities and/or Assets covered by the Initial Notice, for a purchase price negotiated between Bear Stearns or such Affiliate and such Third Party and on other terms and conditions at least as favorable to Bear Stearns as those contained in the Initial Notice; provided that if a Third Party transferee has accepted such offer, Bear Stearns shall have completed such Transfer within an additional one hundred eighty (180) days from the end of such ninety (90) day period; and provided, further, that, with respect to any such Transfer that is not completed within the time periods set forth in this Section 3.4(b), Bear Stearns shall not complete any such Transfer without again complying with each provision of this Section 3.4, as applicable. (c) Upon receipt of an Offer Notice, Bear Stearns and its Affiliates shall have the option to sell the Equity Securities and/or Assets described in the Initial Notice to Calpine (or its Affiliate, as applicable) at the purchase price and upon the terms and conditions specified in the Offer. If Bear Stearns or any of its Affiliates desires to exercise the option set forth in the preceding sentence, it shall deliver an Election Notice to Calpine at any time during the Offer Period, which Election Notice shall specify that Bear Stearns or any of its Affiliates has elected to exercise its option to accept the Offer and sell the Equity Securities and/or Assets described in the Initial Notice to Calpine (or its Affiliate, as applicable) on the terms set forth in the Offer. If Bear Stearns or any of its Affiliates delivers an Election Notice during the Offer Period, then Calpine (or its Affiliates, as applicable) shall be obligated to purchase and Bear Stearns (or such Affiliate, as applicable) shall be obligated to sell, the Equity Securities and/or Assets described in the Initial Notice at the purchase price and on the other terms and conditions indicated in the Offer. The closing of such purchase and sale shall occur on a closing date selected by Calpine or such Affiliate, as applicable; provided, however, that such closing date shall be not less than ten (10) days nor more than ninety (90) days following the date of the Election Notice, unless more time is required to obtain any applicable regulatory or other approvals. If neither Bear Stearns nor any of its Affiliates delivers an Election Notice to Calpine (or its Affiliate, as applicable) within the Offer Period, the Offer shall automatically expire at the end of the Offer Period and neither Calpine nor any of its Affiliates shall have any obligation to purchase the Equity Securities and/or Assets described in the Initial Notice. (d) If Calpine or one of its Affiliates delivers an Offer Notice to Bear Stearns within the Initial Period, but neither Bear Stearns nor any of its delivers an Election Notice to Calpine during the Offer Period, Bear Stearns or its Affiliate may, during the period beginning on the sixth (6th) day following the receipt of the Offer Notice by Bear Stearns and ending on the fiftieth (50th) day following the receipt of the Offer Notice by Bear Stearns, Transfer to a Third Party all (but not less than all) of the Equity Securities and/or Assets covered by the Initial Notice, (x) for the purchase price and on the other terms and conditions contained in the Offer Notice or (y) for a purchase price more favorable financially to Bear Stearns, and on other terms at least as favorable to Bear Stearns, as those contained in the Offer Notice; provided that if a Third Party transferee has accepted such offer, Bear Stearns shall have completed such Transfer within an additional one hundred eighty (180) days from the end of such fifty (50) day period; and provided, further, that, with respect to any such Transfer that is not completed within the time periods set forth in this Section 3.4(d), Bear Stearns shall not complete such Transfer without again complying with each provision of this Section 3.4, as applicable. 22 (e) In addition to the foregoing restrictions, Bear Stearns (or the applicable Affiliate) shall not complete any Transfer pursuant to Section 3.4(b) or Section 3.4(d) without receiving the prior consent of Calpine to the transferee of such Transfer, such consent with respect to any proposed Third Party transferee not to be unreasonably withheld or delayed after Bear Stearns' (or the applicable Affiliate's) request for such consent (and in no event shall such consent take more than the longer of ten (10) Business Days following receipt of such request by Calpine or the time remaining until the end of the Initial Period or the Offer Period, as applicable); provided that Calpine may give or withhold such consent in its sole and absolute discretion with respect to any proposed Transfers to a Restricted Transferee. Bear Stearns may make the request for such consent at any time following delivery of an Initial Notice, including contemporaneously with the applicable Initial Notice; provided that Bear Stearns must provide the identity of any proposed Third Party transferee (as well as the identity of the ultimate operating and holding company parent, if any, of each proposed Third Party transferee, if the identity of such Person(s) is not readily apparent) in each request for consent, and otherwise comply with this Section 3.4. Any consent given to a Transfer pursuant to this Section 3.4(e) shall expire (i) if no proposed Third Party transferee mentioned in a request for consent and approved by Calpine has accepted Bear Stearns' offer to Transfer the Equity Securities and/or Assets covered by the Initial Notice in accordance with Section 3.4(b) or Section 3.4(d) by the end of the ninety (90) day period set forth in Section 3.4(b) or the fifty (50) day period set forth in Section 3.4(d), respectively, at the end of such period, or (ii) if a proposed Third Party transferee approved by Calpine has accepted such offer, if Bear Stearns' Transfer to such Third Party transferee has not been completed within an additional one hundred eighty (180) days from the end of the ninety (90) day period set forth in Section 3.4(b) or the fifty (50) day period set forth in Section 3.4(d), as applicable. (f) Bear Stearns further agrees that in connection with any Transfer subject to this Section 3.4 consented to by Calpine, Bear Stearns shall, if requested by Calpine, deliver to Calpine an opinion of external counsel in form and substance reasonably satisfactory to Calpine and counsel for Calpine, to the effect that the Transfer is not in violation of this Agreement, and is not in violation of the Securities Act or the securities laws of any State. Any purported Transfer in violation of the provisions of this Section 3.4, including any Transfer to a Third Party made without Calpine's prior consent, shall be null and void and shall have no force or effect. (g) Notwithstanding anything herein to the contrary, this Section 3.4 shall not apply to (i) a Transfer to Bear Stearns or any of its Affiliates, (ii) a Transfer to Calpine or any of its Affiliates, including any such Transfer pursuant to Section 16.6(d), or (iii) a Transfer to any Person or such Person's Subsidiaries if such Person or its Subsidiaries merge with Bear Stearns or purchase all or substantially all of the Equity Securities or Assets of Bear Stearns. (h) In addition to the restrictions set forth elsewhere in this Agreement, in the event of a proposed Transfer to a Third Party by Bear Stearns or any of its Affiliates of Equity Securities and/or Assets of CalBear pursuant to this Section 3.4, Calpine's consent to such Transfer shall not be deemed unreasonably withheld if such Third Party does not agree to become bound in writing at the closing of such Transfer by the terms and conditions of this Agreement and the other Transaction Documents and agree to assume the rights and obligations of Bear Stearns and CalBear hereunder and thereunder pursuant to one 23 or more instruments of assumption reasonably satisfactory in form and substance to Calpine. Notwithstanding the other provisions of this Section 3.4, unless expressly waived by Calpine, any otherwise permitted Transfer shall be null and void ab initio if Calpine does not receive written instruments with respect to such Transfer (including copies of any instruments of assumption and the Third Party transferee's consent to be bound by this Agreement and the other Transaction Documents, as applicable) that are in a form reasonably satisfactory in form and substance to Calpine. Upon the execution of such instruments of assumption by such Third Party, such Third Party shall be deemed to be Bear Stearns and CalBear for all purposes of this Agreement. (i) In addition to the restrictions set forth elsewhere in this Agreement, in the event of a proposed Transfer to a Third Party by Bear Stearns or any of its Affiliates of Equity Securities and/or Assets of CalBear pursuant to this Section 3.4, Calpine's consent to such Transfer shall not be deemed unreasonably withheld if such Third Party does not have, at the time of the transfer, a credit rating by (i) Standard & Poors Ratings Group of at least BBB+ and (ii) Moody's Investor Services of at least Baa1. 3.5 No Joint Venture or Partnership Created. (a) Calpine and the Calpine Transaction Parties, on the one hand, and Bear Stearns and CalBear, on the other hand, are independent contractors. Neither Calpine or any Calpine Transaction Party, on the one hand, nor Bear Stearns or CalBear, on the other hand, is an agent (except as specifically provided in the Agency and Services Agreement), representative or partner of Bear Stearns or CalBear, or Calpine or any Calpine Transaction Party, respectively, and each of Calpine and the Calpine Transaction Parties and Bear Stearns and CalBear agrees that the Transaction, this Agreement, the other Transaction Documents and the transactions contemplated hereby and thereby are not intended to create, and shall not be interpreted, construed or deemed to create in any respect an association, joint venture, co-ownership, co-authorship, or partnership, whether general, limited or otherwise, between Calpine or any Calpine Transaction Party, on the one hand, and Bear Stearns or CalBear, on the other hand, or to impose any partnership obligation or partnership liability between Calpine or any Calpine Transaction Party, on the one hand, and Bear Stearns or CalBear, on the other hand. None of Calpine or any Calpine Transaction Party, on the one hand, nor Bear Stearns or CalBear, on the other hand, shall have any right, power or authority to negotiate, execute, authenticate or deliver any Contract for or on behalf of or in the name of, or to incur any Liability for, or to otherwise bind, Bear Stearns or Calpine, respectively, or bind CalBear or any of the Calpine Transaction Parties, respectively, except as specifically set forth in the Agency and Services Agreement or the Trading Master Agreement, in each case with respect to CalBear and CMSC. Calpine and the Calpine Transaction Parties, on the one hand, and Bear Stearns and CalBear, on the other hand, agree that they are not, and shall not be, and shall not hold Bear Stearns or CalBear, or Calpine or the Calpine Transaction Parties, respectively, out to be, co-employers. (b) The Parties will determine a public description of the Transaction mutually satisfactory to Calpine and Bear Stearns. Calpine and Bear Stearns shall not, and shall cause their Affiliates not to, make any press release that is materially inconsistent with such public description. Reference is made to Section 18.13 for other agreements with respect to press releases. 24 3.6 Conflicts of Interest; Non-Discrimination. (a) Conflicts of Interest. Calpine, CMSC, Bear Stearns and CalBear acknowledge that CMSC is providing the Services to CalBear and that Calpine (a) indirectly owns a one hundred percent (100%) equity interest in CMSC and (b) either directly or indirectly through one or more of its wholly-owned Subsidiaries, including CES or CMSC, is conducting for its own account a business similar to the CalBear Referral Business. Accordingly, Calpine, CMSC, Bear Stearns and CalBear acknowledge and agree that conflicts may arise from time to time between the interests of CalBear, on the one hand, and CMSC, CES and Calpine's other Affiliates, on the other hand. In addition, Calpine, CMSC, Bear Stearns and CalBear acknowledge and agree that CMSC may provide services similar to the Services with respect to transactions entered into by Third Parties or for or on behalf of Third Parties by CMSC. The Parties acknowledge that Section 4.2 of the Agency and Services Agreement contains certain covenants of CMSC representing the sole and exclusive agreement of the Parties with respect to such conflicts of interest. (b) Non-Discrimination. Calpine agrees that it shall, and shall cause its Affiliates to, cause CMSC to comply with its obligations pursuant to Section 4.2 of the Agency and Services Agreement. Calpine agrees that it shall not, and shall cause its Affiliates not to, take any action or enter into any agreement, transaction or arrangement with the purpose of avoiding CMSC's obligations under Section 4.2 of the Agency and Services Agreement, including by providing services substantially similar to the Services through Calpine or any of its Affiliates other than CES or CMSC with the purpose of avoiding CMSC's obligations under Section 4.2 of the Agency and Services Agreement. 3.7 Non-Solicitation of Bear Stearns Employees. (a) Prior to the termination of this Agreement and for a period of one (1) year following the date of termination of this Agreement, each of Calpine and the Calpine Transaction Parties shall not, and shall cause their Affiliates not to, directly or indirectly, for itself or on behalf of any other Person, (i) hire any employee of Bear Stearns or CalBear who is involved in the transactions contemplated hereby or by the other Transaction Documents or the CalBear Trades and who is listed on Schedule 3.7(a) (provided that Schedule 3.7(a) shall not initially include more than [*] employees) (A) while such employee is employed by Bear Stearns or CalBear, or (B) in the event of a voluntary resignation from Bear Stearns or CalBear of an employee listed on Schedule 3.7(a) at the time of such resignation, for a period of (60) days following such resignation, or (ii) solicit, induce or attempt to solicit or induce any employee of Bear Stearns or CalBear listed on Schedule 3.7(a) to leave his or her employment with Bear Stearns or CalBear, as applicable; provided that a general solicitation or an employment agency solicitation that is not directed to specifically target any such employee shall not be deemed to violate this Section 3.7(a)(ii) so long as Calpine, the Calpine Transaction Parties and their Affiliates do not hire any such employee as a result of such solicitation or inducement. (b) Once each calendar year, commencing with calendar year 2006, Bear Stearns may modify Schedule 3.7(a) to (i) increase the number of employees listed on Schedule 3.7(a) up to the number of employees that Calpine includes on Schedule 3.8(a), and/or (ii) remove employees from Schedule 3.7(a); provided 25 that if Bear Stearns modifies Schedule 3.7(a) to remove any employee therefrom, Section 3.7(a) shall no longer apply with respect to such employee; and provided, further, that such modifications to Schedule 3.7(a) shall not be effective until Bear Stearns provides a copy of such modified Schedule 3.7(a) (highlighting any modifications thereto) to Calpine in accordance with Section 18.2. In addition, after (i) the dismissal or termination of any employee listed on Schedule 3.7(a) or (ii) sixty (60) days have elapsed following a voluntary resignation of an employee listed on Schedule 3.7(a), Schedule 3.7(a) shall automatically be modified to remove the name of such employee, and Bear Stearns shall promptly provide a copy of such modified Schedule 3.7(a) to Calpine in accordance with Section 18.2. (c) Notwithstanding the provisions of Section 3.7(a), none of Calpine, the Calpine Transaction Parties or their Affiliates shall be deemed to have violated Section 3.7(a) until Bear Stearns provides notice to Calpine of the hiring and/or solicitation of any employee of Bear Stearns or CalBear in violation of Section 3.7(a) (which notice contains the name, title and position of the employee hired in violation of Section 3.7(a) or details concerning the solicitation violating Section 3.7(a)) and Bear Stearns has provided Calpine the opportunity to cure such violation in accordance with this Section 3.7(c). During the period commencing on the date of receipt of any such notice and ending on the thirtieth (30th) day thereafter (subject to an extension for any retention period or other period required by Applicable Law), Calpine shall be entitled to cure any violation of Section 3.7(a) by dismissing the employee named in the notice (on terms determined by Calpine in its discretion, but subject to the length of the cure period described above) or ceasing the activity causing the solicitation described in the notice, as applicable. 3.8 Non-Solicitation of Calpine Employees. (a) Prior to the termination of this Agreement and for a period of one (1) year following the date of termination of this Agreement, each of Bear Stearns and CalBear shall not, and shall cause their Affiliates not to, directly or indirectly, for itself or on behalf of any other Person, (i) hire any employee of Calpine or any Calpine Transaction Party who is involved in the transactions contemplated hereby or by the other Transaction Documents or the CalBear Trades or the Services and who is listed on Schedule 3.8(a) (provided that Schedule 3.8(a) shall not initially include more than [*] employees) (A) while such employee is employed by Calpine or any Calpine Transaction Party, or (B) in the event of a voluntary resignation from Calpine or any Calpine Transaction Party of an employee listed on Schedule 3.8(a) at the time of such resignation, for a period of (60) days following such resignation, or (ii) solicit, induce or attempt to solicit or induce any employee of Calpine or any Calpine Transaction Party listed on Schedule 3.8(a) to leave his or her employment with Calpine or any Calpine Transaction Party, as applicable; provided that a general solicitation or an employment agency solicitation that is not directed to specifically target any such employee shall not be deemed to violate this Section 3.8(a)(ii) so long as Bear Stearns and CalBear and their Affiliates do not hire any such employee as a result of such solicitation or inducement. (b) Once each calendar year, commencing with calendar year 2006, Calpine may modify Schedule 3.8(a) to (i) proportionally increase the number of employees listed on Schedule 3.8(a) to reflect increases in the number of 26 employees of CMSC, and/or (ii) remove employees from Schedule 3.8(a); provided that if Calpine modifies Schedule 3.8(a) to remove any employee therefrom, Section 3.8(a) shall no longer apply with respect to such employee; and provided, further, that such modifications to Schedule 3.8(a) shall not be effective until Calpine provides a copy of such modified Schedule 3.8(a) (highlighting any modifications thereto) to Bear Stearns in accordance with Section 18.2. In addition, after (i) the dismissal or termination of any employee listed on Schedule 3.8(a) or (ii) sixty (60) days have elapsed following a voluntary resignation of an employee listed on Schedule 3.8(a), Schedule 3.8(a) shall automatically be modified to remove the name of such employee, and Calpine shall promptly provide a copy of such modified Schedule 3.8(a) to Bear Stearns in accordance with Section 18.2. (c) Notwithstanding the provisions of Section 3.8(a), none of Bear Stearns, CalBear or their Affiliates shall be deemed to have violated Section 3.8(a) until Calpine provides notice to Bear Stearns of the hiring and/or solicitation of any employee of Calpine or any Calpine Transaction Party in violation of Section 3.8(a) (which notice contains the name, title and position of the employee hired in violation of Section 3.8(a) or details concerning the solicitation violating Section 3.8(a)) and Calpine has provided Bear Stearns the opportunity to cure such violation in accordance with this Section 3.8(c). During the period commencing on the date of receipt of any such notice and ending on the thirtieth (30th) day thereafter (subject to an extension for any retention period or other period required by Applicable Law), Bear Stearns shall be entitled to cure any violation of Section 3.8(a) by dismissing the employee named in the notice (on terms determined by Bear Stearns in its discretion, but subject to the length of the cure period described above) or ceasing the activity causing the solicitation described in the notice, as applicable. 3.9 Confidential Information. (a) Prior to the termination of this Agreement and for a period of one (1) year following the termination of this Agreement, the Parties shall, and shall cause their respective Affiliates and Representatives to, (i) maintain in strict confidence any and all Confidential Information concerning the Parties and the CalBear Business (including the CalBear Information) and not disclose to any Third Party any such Confidential Information and (ii) restrict the use of Confidential Information to prevent anticompetitive use of such information in violation of antitrust laws, including with respect to Confidential Information regarding trading positions, pricing models, projected trades and other commercial information related to the Power and Gas trading markets developed by CMSC, with respect to compliance by Bear Stearns and CalBear, or CalBear, with respect to compliance by Calpine and the Calpine Transaction Parties; provided that the foregoing obligations shall not apply to Calpine or the Calpine Transaction Parties in connection with a disclosure by Calpine or the Calpine Transaction Parties of the aggregate net portfolio positions of CES, but, for the avoidance of doubt, shall apply with respect to any individual Credit Enhancement Trade or any disclosure that, directly or indirectly, would allow a Third Party to identify or otherwise directly determine the terms of any Credit Enhancement Trade. It is understood that the Parties shall not have any liability hereunder with respect to information that (i) is, or through no fault of the Parties or any of their respective Affiliates or Representatives becomes, generally available to the public, (ii) is received from a Third Party and is 27 not subject to any confidentiality obligation between the receiving Party or Parties and such Third Party, (iii) is independently developed by a Party without the use of the Confidential Information, (iv) the Parties or their respective Affiliates or Representatives are legally required to disclose, or that is the subject of any disclosure request made by any Governmental Authority or by any Third Party pursuant to Applicable Law, or (v) is necessary in connection with the defense or prosecution of any Action. (b) In the event that a Party or any of its Affiliates or Representatives is required or requested to disclose any Confidential Information pursuant to Section 3.9(a)(iv) or (v), such Party shall, unless prohibited or otherwise required by Applicable Law, if an Affiliate of Calpine, promptly notify Bear Stearns, or if an Affiliate of Bear Stearns, promptly notify Calpine, so that the Parties may cooperate in seeking a protective order and/or other motion, at the expense of the Party seeking such protective order and/or other motion, to prevent or limit the production or disclosure of such Confidential Information. If such protective order is not obtained or such motion has been denied, then the Person required or requested to disclose such Confidential Information may disclose only that portion of such Confidential Information which, based on the advice of such Person's outside legal counsel, is required by Applicable Law or requested by a Governmental Authority to be disclosed (provided that the Person required or requested to disclose such information shall use all reasonable efforts to preserve the confidentiality of the remainder of such Confidential Information). Such Person shall continue to be bound by its obligations pursuant to this Section 3.9 for any Confidential Information that is not required or requested to be disclosed, or that has been afforded protective treatment, pursuant to such order or motion. (c) Notwithstanding the provisions of Section 3.9(a) above, disclosures of Confidential Information may be made (i) in the ordinary course of CalBear's business, but only to the extent reasonably necessary to conduct such business, (ii) to each Party's advisors, auditors, legal counsel and insurers and lenders who reasonably need to have access to such Confidential Information in connection with the performance of their work, (iii) to Representatives of Calpine and its Affiliates who reasonably need to have access to such Confidential Information in connection with the performance of their work, (iv) to Representatives of Bear Stearns and its Affiliates who reasonably need to have access to such Confidential Information in connection with the performance of their work, (v) to bona fide potential Third Party purchasers of an interest in any Party or its Subsidiaries, but in each case only to the extent required in connection with such transaction; provided that any such Third Party receiving any Confidential Information agrees to maintain the confidentiality of such Confidential Information in accordance with the terms hereof, and (vi) by any Party or any of their respective Affiliates at any time in connection with any reporting requirements of such Person under any Applicable Law, any bona fide debt or equity financing of such Person, any bona fide merger or sale of such Person, or any bona fide sale of all or substantially all of such Person's Assets, but in each case only to the extent reasonably necessary in connection with such transaction, and such Confidential Information may be included in any financial statements, schedules or information, any diligence materials or any prospectus, offering memorandum, information statement or proxy statement provided to any Person in connection therewith (provided that any such disclosure pursuant to this clause (vi) shall not include the terms of any individual CalBear Trade or any disclosure that, 28 directly or indirectly, would allow a Third Party to identify or otherwise directly determine the terms of any individual CalBear Trade, without prior notice to each Party that is not an Affiliate of the disclosing Party unless prohibited by Applicable Law). 3.10 Netting. Except as expressly set forth in Section 4.4(e) of the Agency and Services Agreement, in the event that, at any time, Calpine or any Calpine Transaction Party, on the one hand, or Bear Stearns or CalBear, on the other hand, is required, pursuant to this Agreement, the other Transaction Documents, the transactions contemplated hereby or thereby, the Services or the CalBear Trades, to make any Payment to Bear Stearns or CalBear, on the one hand, or Calpine or any Calpine Transaction Party, on the other hand, respectively, then in each case the amounts of such Payments between or among Calpine, the Calpine Transaction Parties, Bear Stearns and CalBear, as applicable, may be aggregated and Calpine and the Calpine Transaction Parties, on the one hand, or Bear Stearns and CalBear, on the other hand, as applicable, may discharge their obligations to make such Payments through netting, in which case the Party (or Calpine and the Calpine Transaction Parties or Bear Stearns and CalBear, in each case as a group), if any, owing the greater aggregate amount to any other Party (or Calpine and the Calpine Transaction Parties or Bear Stearns and CalBear, in each case as a group), may pay to the Party (or such group of Parties) to which the applicable Payment or Payments are owed the difference between the amounts owed. For the avoidance of doubt, this Section 3.10 is intended to permit netting of all amounts due among the Parties hereto or the parties to any other Transaction Documents to the fullest extent possible. Each Party reserves to itself all rights, setoffs, counterclaims and other remedies and defenses consistent with Article XVII (to the extent not expressly herein waived or denied) which each such Party is or may be entitled to arising from or out of this Agreement and the other Transaction Documents. All outstanding CalBear Trades, Services and obligations to make Payment in connection therewith under this Agreement and the other Transaction Documents may be offset against each other, set off or recouped therefrom. Except as provided in this Agreement or the other Transaction Documents, upon the termination of this Agreement or any other Transaction Document, the Parties shall continue to net all amounts due among them arising under this Agreement or the other Transaction Documents. 3.11 Acknowledgements. Each Party acknowledges that, in view of the nature of the Transaction and the CalBear Business, and the consideration given by the Parties therefore, the restrictions contained in Sections 3.2, 3.3, 3.4, 3.5, 3.6, 3.7, 3.8, 3.9, 3.12, and 3.15 are reasonably necessary to protect the legitimate business interests of the Parties and that any violation of such restrictions will result in irreparable injury to the Parties, the Transaction and the CalBear Business for which damages will not be an adequate remedy. Each Party therefore acknowledges that, if any such restrictions are violated by it, each other Party that is not an Affiliate of such Party shall be entitled to preliminary and injunctive relief or other equitable remedies. Each Party has independently consulted with its counsel and after such consultation agrees that the covenants set forth in Sections 3.2, 3.3, 3.4, 3.5, 3.6, 3.7, 3.8, 3.9, 3.12, and 3.15 are reasonable and appropriate. If the final judgment of a court or arbitration body of competent jurisdiction declares that any term or provision of Sections 3.2, 3.3, 3.4, 3.5, 3.6, 3.7, 3.8, 3.9, 3.12, and 3.15 is invalid or unenforceable, the Parties agree that the court or arbitration body making the determination of invalidity or unenforceability shall have the power to reduce the scope, duration, or area of the term or provision, to delete specific words or phrases, or to replace any invalid or unenforceable term or 29 provision with a term or provision that is valid and enforceable and that comes closest to expressing the intention of the invalid or unenforceable term or provision, and this Agreement shall be enforceable as so modified after the expiration of the time within which the judgment or determination may be appealed. 3.12 CMSC Board Representation. CalBear shall be entitled to designate up to two (2) members of the board of directors of CMSC (each, a "Designated CMSC Board Member"); provided that each such Designated CMSC Board Member shall be either (a) a professional independent director compensated by Bear Stearns or its Affiliates (other than CalBear) and reasonably acceptable to Calpine, or (b) an employee of Bear Stearns or its Affiliates with a title of Managing Director or equivalent or a more senior title. CalBear shall be entitled to designate a replacement for any Designated CMSC Board Member at any time, whether upon the death, removal or resignation of such Designated CMSC Board Member or otherwise. If CalBear designates any Designated CMSC Board Member at any time, Calpine and each of the Calpine Transaction Parties agrees, and agrees to cause its Affiliates to (a) vote for, elect or appoint each such Designated CMSC Board Member designated by CalBear to the board of directors of CMSC promptly following such designation, (b) vote for, elect or appoint any replacement Designated CMSC Board Member designated by CalBear to the board of directors of CMSC promptly following such designation, and (c) unless otherwise requested by Bear Stearns, maintain the Designated CMSC Board Members (as replaced by CalBear from time to time) as directors of CMSC at all times prior to the termination of this Agreement. CMSC's Organizational Documents shall provide that any decision of the board of directors of CMSC shall require the consent of the Designated CMSC Board Members, if any, to (i) initiate a voluntary Bankruptcy Event, (ii) consent to an involuntary Bankruptcy Event, or (iii) modify the Organizational Documents of CMSC to eliminate or otherwise alter the voting rights of the Designated CMSC Board Members or CalBear's right to designate, or Calpine and its Affiliates duty to appoint, such Designated CMSC Board Members. CMSC's Organizational Documents shall also provide that the Designated CMSC Board Members shall not be entitled to vote with respect to any matter presented to the board of directors of CMSC other than the matters listed in the preceding sentence. 3.13 Performance of Financial Obligations of CalBear. Bear Stearns shall provide to CalBear all funds and collateral necessary for CalBear to perform its obligations under the Third Party Master Agreements, and the CalBear Trades, and to pay the amounts required to be paid by CalBear pursuant to Section 4.17 of the Agency and Services Agreement, and shall itself or shall cause CalBear to perform CalBear's Payment obligations under the Third Party Master Agreements and the CalBear Trades, and to pay the amounts required to be paid by CalBear pursuant to Section 4.17 of the Agency and Services Agreement, in each case in accordance with such Section. 3.14 [*]3.15 Fiscal Year of CalBear. CalBear shall not change its Fiscal Year without the prior consent of Calpine, such consent not to be unreasonably withheld; provided that Calpine's consent shall not be required in the event that such change is made to conform CalBear's fiscal year to Bear Stearns' fiscal year in connection with a change of Bear Stearns' fiscal year; and provided, further, that in connection with any change in the Fiscal Year of 30 CalBear, the provisions of the Transaction Documents shall be adjusted as applicable to conform to such adjusted fiscal year and shall also be adjusted to the extent necessary to give effect to the original intent of the provisions of the Transaction Documents, as if such change in the Fiscal Year of CalBear had not occurred, including appropriate proration or other adjustment of any Payments paid pursuant to the Transaction Documents. 3.16 Interest on Overdue Amounts. In the event that, at any time, Calpine or any Calpine Transaction Party, on the one hand, or Bear Stearns or CalBear, on the other hand, fails to make any Payment when due to Bear Stearns or CalBear, on the one hand, or Calpine or any Calpine Transaction Party, on the other hand, then the outstanding principal amount of such overdue Payment shall bear interest at the lesser of (a) a rate equal to LIBOR [*](or shall bear additional interest at a rate equal to the existing interest rate on such overdue Payment [*], if such overdue Payment already bears interest; provided that any overdue Payment already bearing default or additional interest shall not bear further interest pursuant to this Section 3.16) or (b) the highest rate permitted by law, until such overdue Payment plus all accumulated but unpaid interest (and additional interest, if applicable) thereon is paid in full, and the Party making such overdue Payment shall pay all accumulated but unpaid interest (and additional interest, if applicable) on the amount of such overdue Payment at the time the principal of such overdue Payment is paid. ARTICLE IV. CALPINE GUARANTEE Calpine covenants and agrees with Bear Stearns and CalBear that from and after the Effective Date: 4.1 Calpine Guarantee. (a) Subject to the terms of this Article IV, in consideration of each of Bear Stearns and CalBear entering into the Transaction Documents, Calpine hereby unconditionally and irrevocably guarantees, as primary obligor and not as surety (the "Calpine Guarantee"), to each of Bear Stearns and CalBear, and their respective successors and assigns: (i) the prompt payment in full when due of all amounts owed by and due from any Calpine Transaction Party to Bear Stearns or CalBear pursuant to the terms of the Transaction Documents, including all amounts owed by and due from any Calpine Transaction Party to Bear Stearns or CalBear pursuant to Section 15.1(a) and pursuant to Section 6.3 of the Trading Master Agreement; and (ii) that in case of any extension of time of payment of any of such obligations, such obligations will be promptly paid in full when due in accordance with the terms of the extension. Failing payment when due of any amount so guaranteed for any reason whatsoever, Calpine will promptly pay the same on the date such payment is due. The Parties agree that this is a guarantee of payment and not a guarantee of collection or performance. 31 (b) Calpine hereby agrees that its obligations under this Calpine Guarantee are absolute, irrevocable and unconditional, irrespective of the validity, regularity or enforceability of this Agreement or the other Transaction Documents, the absence of any Action to enforce the same, any waiver or consent by Bear Stearns or CalBear, any course of dealings among the Parties with respect to any provisions hereof or thereof, the recovery of any judgment against any Calpine Transaction Party, any Action to enforce the same or any other circumstance which might otherwise constitute a legal or equitable discharge of defense of Calpine. Calpine hereby waives diligence, presentment, demand of payment, filing of claims with a court in the event of any Bankruptcy of Calpine or any Calpine Transaction Party, any right to require a proceeding first against any Calpine Transaction Party, protest, notice and all demands whatsoever and covenants that this Calpine Guarantee will not be discharged except by complete performance and payment of the obligations contained in this Agreement and the other Transaction Documents. (c) If Bear Stearns or CalBear is required by any Governmental Authority or otherwise to return to Calpine or any Calpine Transaction Party or any custodian, trustee, liquidator or other similar official acting in relation to Calpine or any Calpine Transaction Party, any amount paid by them to Bear Stearns or CalBear, this Calpine Guarantee, to the extent theretofore discharged, will be reinstated in full force and effect with respect to such amount. (d) Calpine agrees that it will not be entitled to any right of subrogation in relation to Bear Stearns or CalBear in respect of any obligations guaranteed hereby until payment in full of all obligations guaranteed hereby. Calpine further agrees that, as between Calpine, on the one hand, and Bear Stearns or CalBear, on the other hand, (i) the maturity of any obligations guaranteed hereby that may be accelerated pursuant to the terms of the Transaction Documents, may be so accelerated for the purposes of this Calpine Guarantee, notwithstanding any stay, injunction or other prohibition preventing such acceleration in respect of the obligations guaranteed hereby and (ii) in the event of any declaration of acceleration of such obligations as provided in the Transaction Documents, such obligations (whether or not due and payable) will forthwith become due and payable by Calpine for the purpose of this Calpine Guarantee. Calpine will have the right to seek contribution from any non-paying Calpine Transaction Party so long as the exercise of such right does not impair the rights of Bear Stearns or CalBear under this Calpine Guarantee. 4.2 Calpine May Consolidate, etc., on Certain Terms. Calpine may not sell or otherwise dispose of all or substantially all of its Assets to, or consolidate with or merge with or into (whether or not Calpine is the surviving Person) another Person unless the Person acquiring the property in any such sale or disposition or the Person formed by or surviving any such consolidation or merger unconditionally assumes all the obligations of Calpine under this Agreement, the Calpine Guarantee and the other Transaction Documents. Except as set forth in this Section 4.2, nothing contained in this Agreement will prevent any consolidation or merger of Calpine or any sale or conveyance of all or substantially all of the property of Calpine. 4.3 Release. 32 Upon termination of this Agreement in accordance with Section 16.6 and full and final discharge of all obligations of Calpine and the Calpine Transaction Parties under the Transaction Documents, Calpine shall be fully and unconditionally released and relieved from any obligation under the Calpine Guarantee; provided that if, following such discharge, Bear Stearns or CalBear is required by any Governmental Authority or otherwise to return to Calpine or any Calpine Transaction Party or any custodian, trustee, liquidator or other similar official acting in relation to Calpine or any Calpine Transaction Party, any amount paid by them to Bear Stearns or CalBear, the Calpine Guarantee, to the extent theretofore released, relieved or otherwise discharged, will be reinstated in full force and effect. ARTICLE V. BEAR STEARNS GUARANTEE Bear Stearns covenants and agrees with Calpine and each of the Calpine Transaction Parties that from and after the Effective Date: 5.1 Bear Stearns Guarantee. (a) Subject to the terms of this Article V, in consideration of Calpine and the Calpine Transaction Parties entering into the Transaction Documents, Bear Stearns hereby unconditionally and irrevocably guarantees, as primary obligor and not as surety (the "Bear Stearns Guarantee"), to each of Calpine and the Calpine Transaction Parties, and their respective successors and assigns: (i) the prompt payment in full when due of all amounts owed by and due from CalBear to Calpine or any Calpine Transaction Party pursuant to the terms of the Transaction Documents, including all amounts owed by and due from CalBear to Calpine or any Calpine Transaction Party pursuant to Section 15.1(b); and (ii) that in case of any extension of time of payment of any of such obligations, such obligations will be promptly paid in full when due in accordance with the terms of the extension. Failing payment when due of any amount so guaranteed for any reason whatsoever, Bear Stearns will promptly pay the same on the date such payment is due. The Parties agree that this is a guarantee of payment and not a guarantee of collection or performance. (b) Bear Stearns hereby agrees that its obligations under this Bear Stearns Guarantee are absolute, irrevocable and unconditional, irrespective of the validity, regularity or enforceability of this Agreement or the other Transaction Documents, the absence of any Action to enforce the same, any waiver or consent by Calpine or any Calpine Transaction Party, any course of dealings among the Parties with respect to any provisions hereof or thereof, the recovery of any judgment against CalBear, any Action to enforce the same or any other circumstance which might otherwise constitute a legal or equitable discharge of defense of Bear Stearns. Bear Stearns hereby waives diligence, presentment, demand of payment, filing of claims with a court in the event of any Bankruptcy of Bear Stearns or CalBear, any right to require a proceeding first against CalBear, protest, notice and all demands whatsoever and covenants that this Bear 33 Stearns Guarantee will not be discharged except by complete performance and payment of the obligations contained in this Agreement and the other Transaction Documents. (c) If Calpine or any Calpine Transaction Party is required by any Governmental Authority or otherwise to return to Bear Stearns or CalBear or any custodian, trustee, liquidator or other similar official acting in relation to Bear Stearns or CalBear, any amount paid by them to Calpine or any Calpine Transaction Party, this Bear Stearns Guarantee, to the extent theretofore discharged, will be reinstated in full force and effect with respect to such amount. (d) Bear Stearns agrees that it will not be entitled to any right of subrogation in relation to Calpine or the Calpine Transaction Parties in respect of any obligations guaranteed hereby until payment in full of all obligations guaranteed hereby. Bear Stearns further agrees that, as between Bear Stearns, on the one hand, and Calpine or the Calpine Transaction Parties, on the other hand, (i) the maturity of any obligations guaranteed hereby that may be accelerated pursuant to the terms of the Transaction Documents, may be so accelerated for the purposes of this Bear Stearns Guarantee, notwithstanding any stay, injunction or other prohibition preventing such acceleration in respect of the obligations guaranteed hereby and (ii) in the event of any declaration of acceleration of such obligations as provided in the Transaction Documents, such obligations (whether or not due and payable) will forthwith become due and payable by Bear Stearns for the purpose of this Bear Stearns Guarantee. Bear Stearns will have the right to seek contribution from CalBear so long as the exercise of such right does not impair the rights of Calpine or the Calpine Transaction Parties under this Bear Stearns Guarantee. 5.2 Bear Stearns May Consolidate, etc., on Certain Terms. Bear Stearns may not sell or otherwise dispose of all or substantially all of its Assets to, or consolidate with or merge with or into (whether or not Bear Stearns is the surviving Person) another Person unless the Person acquiring the property in any such sale or disposition or the Person formed by or surviving any such consolidation or merger unconditionally assumes all the obligations of Bear Stearns under this Agreement, the Bear Stearns Guarantee and the other Transaction Documents. Except as set forth in this Section 5.2, nothing contained in this Agreement will prevent any consolidation or merger of Bear Stearns or any sale or conveyance of all or substantially all of the property of Bear Stearns. 5.3 Release. Upon termination of this Agreement in accordance with Section 16.6 and full and final discharge of all obligations of Bear Stearns and CalBear under the Transaction Documents, Bear Stearns shall be fully and unconditionally released and relieved from any obligation under the Bear Stearns Guarantee; provided that if, following such discharge, Calpine or any Calpine Transaction Party is required by any Governmental Authority or otherwise to return to Bear Stearns or CalBear or any custodian, trustee, liquidator or other similar official acting in relation to Bear Stearns or CalBear, any amount paid by them to Calpine or any Calpine Transaction Party, the Bear Stearns Guarantee, to the extent theretofore released, relieved or otherwise discharged, will be reinstated in full force and effect. 34 ARTICLE VI. REGULATORY MATTERS 6.1 Regulatory Matters With Respect to Calpine. (a) Calpine and each of the Calpine Transaction Parties hereby covenant and agree from and after the Effective Date that they shall take all necessary or appropriate actions to maintain exemption from material regulatory restrictions under PUHCA (other than Section 9(a)(2) of PUHCA). (b) CES and CMSC hereby covenant and agree from and after the Effective Date that they shall take or cause to be taken all necessary or appropriate actions to maintain for CES and CMSC, respectively, FERC authorization to sell Power at wholesale at market-based rates and, to the extent necessary, any other FERC approval required under the FPA to sell Power at wholesale, in each case to the extent necessary to permit ongoing performance by CES and CMSC under the Transaction Documents. (c) Calpine and the Calpine Transaction Parties hereby covenant and agree from and after the Effective Date to (i) obtain all material Regulatory Approvals, and (ii) comply with all material applicable federal and state energy, and federal commodity, regulatory laws, including all material notices, filings, reports, consents, authorizations or exemptions from registration required or permitted under the FPA, PUHCA, CEA and state utility laws and regulations, in each case to the extent necessary to permit ongoing performance by Calpine and the Calpine Transaction Parties under the Transaction Documents. 6.2 Regulatory Matters With Respect to Bear Stearns. (a) Bear Stearns and CalBear hereby covenant and agree from and after the Effective Date that they shall take all necessary or appropriate actions to maintain exemption from material regulatory restrictions under PUHCA (other than Section 9(a)(2) of PUHCA). (b) CalBear hereby covenants and agrees from and after the Effective Date that it shall take or cause to be taken all necessary or appropriate actions to maintain for CalBear FERC authorization to sell Power at wholesale at market-based rates and, to the extent necessary, any other FERC approval required under the FPA to sell Power at wholesale, in each case to the extent necessary to permit ongoing performance by CalBear under the Transaction Documents. (c) Subject to compliance with Section 4.1(n) of the Agency and Services Agreement by CMSC, Bear Stearns and CalBear covenant and agree from and after the Effective Date to (i) obtain all material Regulatory Approvals, and (ii) comply with all material applicable federal and state energy regulatory laws, including all material notices, filings, reports, consents or authorizations or exemptions from registration required or permitted under the FPA, PUHCA and state utility laws and regulations, in each case to the extent necessary to permit ongoing performance by Bear Stearns and CalBear under the Transaction Documents. 6.3 Regulatory Matters With Respect to CalBear and CMSC. From and after the date of this Agreement, each Party covenants and agrees that it shall 35 cooperate with the other Parties to take or cause to be taken all necessary or appropriate actions to prepare and file all documents necessary for (i) CES, (ii) CMSC's predecessor CES Marketing VII, LLC, and (iii) CalBear's predecessor Arroyo Energy LP, to obtain FERC approval under Section 203 of the FPA for (A) an internal corporate restructuring of the upstream ownership of Arroyo Energy LP, (B) the performance of the Services by CMSC, (C) the provision of energy related services by CMSC to CES, and any notice filings or other approvals, as needed under Section 203 of the FPA in respect of the Transaction. With respect to these filings, the Parties shall cooperate and use commercially reasonable efforts to share and develop information necessary for such filings and drafts of such filings and shall give each other reasonable opportunity to comment on and to revise such draft filings before such filings are submitted to FERC. ARTICLE VII. NOTICES, RECORDS, MEETINGS, AUDITS AND AVAILABILITY Each of the Parties covenants and agrees with each other that from and after the Effective Date, subject to the confidentiality obligations contained in Section 3.9: 7.1 Notices. (a) Notice from Calpine. Anything herein to the contrary notwithstanding, Calpine and the Calpine Transaction Parties shall promptly, upon obtaining knowledge thereof, submit notice to Bear Stearns and CalBear of: (i) any Actions pending or, to the knowledge of Calpine or the Calpine Transaction Parties, threatened in writing or filed by any Person, concerning the CalBear Business, the CalBear Trades, this Agreement, the other Transaction Documents or the transactions contemplated hereby or thereby; (ii) any refusal or, to the knowledge of Calpine or the Calpine Transaction Parties, refusal threatened in writing to grant, renew or extend, or any Action pending or threatened in writing that would reasonably be expected to affect, the granting, renewal or extension of any material Regulatory Approval, including CES', CMSC's or CalBear's FERC-granted market-based rate authorization; (iii) any material dispute with any Governmental Authority relating to the CalBear Trades, the Transaction Documents, the CalBear Business or Calpine's and the Calpine Trading Parties' ability to perform their obligations under the Transaction Documents; (iv) any Bankruptcy Event with respect to Calpine, any of the Calpine Transaction Parties or any Significant Subsidiary of Calpine; (v) any Material Adverse Change with respect to Calpine or any of the Calpine Transaction Parties; (vi) all material penalties or notices of violation issued or threatened by any Governmental Authority or other Person relating to the CalBear Trades or the Services; 36 (vii) the violation by Calpine or any Calpine Transaction Party in any material respect of any Applicable Law relating to the Services, the CalBear Trades, the Transaction Documents or the CalBear Business; (viii) the failure by Calpine or any Calpine Transaction Party to perform any covenant or agreement of Calpine or such Calpine Transaction Party, respectively, set forth in this Agreement or any other Transaction Document, which failure constitutes a material breach of this Agreement or such other Transaction Document; provided that any breach of this clause (viii) shall be deemed to be cured upon cure of the underlying failure to perform; or (ix) any other event or circumstance that would be reasonably likely to materially adversely affect Calpine's or any Calpine Transaction Party's ability to engage in Trades, perform Services or otherwise perform its obligations under the Transaction Documents. (b) Notice from Bear Stearns. Anything herein to the contrary notwithstanding, Bear Stearns and CalBear shall promptly, upon obtaining knowledge thereof, submit notice to Calpine and the Calpine Transaction Parties of: (i) any Actions pending or, to the knowledge of Bear Stearns or CalBear, threatened in writing or filed by any Person, concerning the CalBear Business, the CalBear Trades, this Agreement, the other Transaction Documents or the transactions contemplated hereby or thereby; (ii) any refusal or, to the knowledge of Bear Stearns or CalBear, refusal threatened in writing to grant, renew or extend, or any Action pending or threatened in writing that would reasonably be expected to affect, the granting, renewal or extension of any material Regulatory Approval, including CalBear's FERC-granted market-based rate authorization; (iii) any material dispute with any Governmental Authority relating to the CalBear Trades, the Transaction Documents, the CalBear Business or Bear Stearns' and CalBear's ability to perform their obligations under the Transaction Documents; (iv) any Bankruptcy Event with respect to Bear Stearns, CalBear or any Significant Subsidiary of Bear Stearns; (v) any Material Adverse Change with respect to Bear Stearns or CalBear; (vi) all material penalties or notices of violation issued or threatened by any Governmental Authority or other Person relating to the CalBear Trades or the Services; (vii) the violation by Bear Stearns or CalBear in any material respect of any Applicable Law relating to the CalBear Trades, the Transaction Documents or the CalBear Business; 37 (viii) the failure by Bear Stearns or CalBear to perform any covenant or agreement of Bear Stearns or CalBear, respectively, set forth in this Agreement or any other Transaction Document, which failure constitutes a material breach of this Agreement or such other Transaction Document; provided that any breach of this clause (viii) shall be deemed to be cured upon cure of the underlying failure to perform; (ix) any downgrade of the credit rating assigned to Bear Stearns by (i) Standard & Poors Ratings Group below BBB+ or (ii) Moody's Investor Services below Baa1; (x) any change of Bear Stearns' fiscal year from a November 30 year-end; or (xi) any other event or circumstance that would be reasonably likely to materially adversely affect Bear Stearns' or CalBear's ability to engage in Trades or otherwise perform its obligations under the Transaction Documents. 7.2 Books and Records. (a) Books and Records of Calpine Transaction Parties. The Calpine Transaction Parties shall maintain in good order all Books and Records relating to the CalBear Trades, any Services and the CalBear Business, including general ledgers, risk systems and related data storage, and each Calpine Transaction Party shall retain related written records for a minimum period of seven (7) years and related oral records including tapes in accordance with such Calpine Transaction Party's internal policy and, in each case, as otherwise required by Applicable Law and Regulatory Approvals. Where Books and Records relate to Actions or the settlement of claims arising out of the performance of this Agreement, the other Transaction Documents, or any related documents or agreements, the Calpine Transaction Parties shall maintain such Books and Records until the later of (x) three (3) years after the final resolution of the matter giving rise to the Action or dispute or (y) the end of the retention periods otherwise set forth in this Section 7.2(a). (b) Books and Records of CalBear. CalBear shall maintain in good order all Books and Records relating to (i) the CalBear Trades, any Services and the CalBear Business to the extent CalBear (A) produces Books and Records with respect thereto or (B) receives copies of any Books and Records with respect thereto from CMSC and (ii) CalBear Governance Operations, and CalBear shall retain related written records for a minimum period of seven (7) years and related oral records including tapes in accordance with CalBear's internal policy and, in each case, as otherwise required by Applicable Law and Regulatory Approvals. Where Books and Records relate to Actions or the settlement of claims arising out of the performance of this Agreement, the other Transaction Documents, or any related documents or agreements, CMSC, on behalf of CalBear, and CalBear shall maintain such Books and Records until the later of (x) three (3) years after the final resolution of the matter giving rise to the Action or dispute or (y) the end of the retention periods otherwise set forth in this Section 7.2(b). 7.3 Meetings. Representatives of Calpine, the Calpine Transaction Parties, Bear Stearns and/or CalBear shall meet in person or by conference call or video conference at such reasonable times as any of them may request (provided that in 38 no event shall Representatives of any Party or its Affiliates (other than CMSC and CalBear) be required to attend more than two (2) such meetings in any given Month). During such meetings, the Representatives of any Party may provide any information concerning the CalBear Business, the Trades, the Services or the Transaction to the Representatives of any other Party for discussion, and each Party shall provide any other information reasonably related to the CalBear Business, the CalBear Trades or the Transaction that is reasonably requested in advance by the Representatives of any other Party, to the extent the requested information is required to be maintained for or provided to the requesting Party under other provisions of the Transaction Documents and subject to Section 3.9 and confidentiality duties owed to Third Parties. 7.4 Audits. Each of the Calpine Transaction Parties and CalBear shall comply with the following audit provisions: (a) Subject to Section 3.9, Calpine and each Calpine Transaction Party, on the one hand, and Bear Stearns and CalBear, on the other hand, or any of their respective Representatives, has the right, in its sole discretion and at its sole expense and upon at least five (5) Business Days advance notice and during normal working hours, to examine and copy the Books and Records of CalBear or any Calpine Transaction Party, respectively, to the extent necessary to verify compliance with the provisions of this Agreement, the other Transaction Documents, any related documents and agreements and the transactions contemplated hereby and thereby (other than verifying compliance with provisions regarding general financial condition or solvency of Calpine or CES), and the accuracy of any Report or information, daily or Monthly settlement, Payment, charge or computation made or provided pursuant to the provisions of this Agreement, the other Transaction Documents, any related documents and agreements or the transactions contemplated hereby and thereby, the Trades and the Services. (b) If any audit conducted under Section 7.4(a) above reveals any inaccuracy in any Report, daily or Monthly settlement or Payment, the necessary adjustments in such settlement and the Payments thereof will be promptly made and this provision shall survive any termination of this Agreement for the purpose of such daily or Monthly settlement and Payment objections. Each Transaction Party shall preserve all applicable records held by it for the time periods set forth in Section 7.2, as applicable, following the termination of this Agreement, or such longer period as may be required by Applicable Law. Information obtained by any Party's Representatives in examining any other Party's applicable Books and Records to verify such settlements, Payments and billings and Gas and Power delivery data shall not be disclosed to Third Parties except as provided in Section 3.9. The audit rights contained in this Section 7.4 shall survive the termination of this Agreement. (c) Subject to Section 3.9, Bear Stearns or CalBear shall have the right, in its sole discretion and at its sole expense and during normal working hours, to examine, at any time and from time to time, CES' and/or CMSC's risk management protocols and procedures in a location reasonably determined by CES or CMSC, as applicable, to the extent necessary to verify compliance with the provisions of this Agreement, the other Transaction Documents, any related documents and agreements and the transactions contemplated hereby and thereby, and the accuracy of any Reports, daily or Monthly settlement, Payment, charge or 39 computation made pursuant to the provisions of this Agreement, the other Transaction Documents, any related documents and agreements or the transactions contemplated hereby and thereby, the CalBear Trades or the Services. 7.5 Availability of Parties. Each Calpine Transaction Party and CalBear shall make itself reasonably available to CalBear and the Calpine Transaction Parties, respectively, through telephone, voicemail, e-mail and/or facsimile during normal business hours, and by telephone, mobile telephone and/or pager during non-business hours. CMSC shall make itself available to CalBear through its 24-hour Power trading desk. ARTICLE VIII. REPRESENTATIONS AND WARRANTIES OF THE PARTIES As an inducement to enter into this Agreement, each Party hereby represents and warrants to each other Party, as of the date hereof (other than with respect to CMSC and CalBear) and as of the Effective Date the following: 8.1 Organization. Such Party is duly organized, validly existing and in good standing as a corporation or other entity under the laws of the state of its organization and has full organizational power and authority to own, lease and operate its Assets and to conduct its business as it is now conducted and presently proposed to be conducted. 8.2 Authorization. Such Party has the requisite organizational power and authority to, and has taken all organizational action necessary to, execute and deliver this Agreement and each other Transaction Document to which it is or will be a party, to consummate the transactions contemplated hereby and thereby and to perform its obligations contained herein and therein, and no other organizational proceedings on the part of such Party are necessary to authorize this Agreement, each other Transaction Document to which it is or will be a party and the consummation of the transactions contemplated hereby and thereby. This Agreement has been duly executed and delivered by such Party and is a valid and binding obligation of such Party, enforceable against such Party in accordance with its terms, except as the enforceability thereof may be limited by (a) applicable bankruptcy, insolvency, moratorium, reorganization or similar laws in effect which affect the enforcement of creditors rights generally or (b) general principles of equity, whether considered in a proceeding at law or in equity. Each Transaction Document (other than this Agreement) to which such Party is or will be a party has been or will be duly executed and delivered by such Party, as applicable, and is or will be a valid and binding obligation of such Party, enforceable against such Party in accordance with its terms, except as the enforceability thereof may be limited by (a) applicable bankruptcy, insolvency, moratorium, reorganization or similar laws in effect which affect the enforcement of creditors rights generally or (b) general principles of equity, whether considered in a proceeding at law or in equity. 8.3 No Similar Business. Neither such Party nor any of its respective Affiliates is currently engaged in any business relationship with any Third Party pursuant to which such Party or its Affiliates, on the one hand, and such 40 Third Party, on the other hand, engage in any business which, when taken as a whole, would be in violation of Section 3.2. 8.4 Accuracy of Information Furnished. With respect to such Party and its Affiliates, the information contained in this Agreement, any other Transaction Document, and the exhibits, schedules, certificates, documents, written information or lists attached hereto or thereto or specifically referred to herein or therein that has been delivered by or on behalf of such Party or any of its Affiliates pursuant to this Agreement or any other Transaction Document or otherwise in connection with the transactions contemplated hereby or thereby does not, to the knowledge of such Party, contain any untrue statement of a material fact, or omit to state any material fact that is necessary to make the statements contained herein and therein, taken as a whole, not misleading. ARTICLE IX. REPRESENTATIONS AND WARRANTIES OF CALPINE As an inducement to enter into this Agreement, each of Calpine and the Calpine Transaction Parties hereby represents and warrants to Bear Stearns and CalBear, as of the date hereof (other than with respect to CMSC) and as of the Effective Date, and except as otherwise disclosed in the Calpine SEC Filings, the following: 9.1 Calpine and Calpine Transaction Parties. Schedule 9.1 lists the name, type of entity and jurisdiction of organization of Calpine and each of the Calpine Transaction Parties. Calpine owns, directly or indirectly, all of the outstanding Equity Securities of each of the Calpine Transaction Parties. 9.2 No Conflict or Violation. None of the execution, delivery and performance of this Agreement or any other Transaction Documents, the consummation of the transactions contemplated hereby and thereby, compliance with any of the provisions hereof or thereof, the consummation of any CalBear Trades or the provision of the Services, by Calpine or any of the Calpine Transaction Parties will result in (a) a violation of or a conflict with any provision of the Organizational Documents of Calpine or any of the Calpine Transaction Parties, (b) a violation of, a conflict with, a breach of, or a default under (with or without notice or passage of time), the termination or acceleration of the performance required by, or the creation of any right of any party to accelerate, modify, terminate or cancel, any material term or provision of any material Contract to which Calpine or such Calpine Transaction Party is a party or by which any of its Assets are bound, (c) a violation or breach in any material respect of any Applicable Law applicable to Calpine or such Calpine Transaction Party or (d) Calpine or such Calpine Transaction Party being required to obtain any material consent, waiver, agreement, Permit or approval or material authorization of, or material declaration, filing, notice or registration to or with, or material assignment by, any Third Party or Governmental Authority, except, in each case, as set forth on Schedule 9.2. 9.3 Sufficiency of Assets. The Calpine Transaction Parties own, license, lease or otherwise have a right to use or have contracted for all Assets materially necessary and sufficient for the performance of the Services and their other obligations under the Transaction Documents, and their Assets in the 41 aggregate are materially in such operating condition and repair (subject to normal wear and tear) as is necessary and sufficient for the performance of such Services and obligations. 9.4 Permits. Except as set forth on Schedule 9.2, the Calpine Transaction Parties have all material Permits necessary for (i) the conduct of their businesses as now being conducted and as proposed to be conducted as contemplated in this Agreement and the other Transaction Documents and (ii) the performance of the Services and their other obligations under the Transaction Documents, and own or possess such Permits free and clear of any material Encumbrances. All such Permits are valid and in full force and effect in all material respects. 9.5 Litigation. There is no Action pending or, to the knowledge of the Calpine Transaction Parties, threatened in writing against, relating to or affecting Calpine or the Calpine Transaction Parties or any of their properties, rights or Assets (a) that, if pending, involves the risk of criminal liability or, if threatened, could reasonably be expected to involve the risk of criminal liability, (i) for any Calpine Transaction Party or (ii) for Calpine and its Affiliates; provided, in the case of clause (ii), such Action is material to Calpine and its Affiliates, taken as a whole, (b) that relates to the transactions contemplated by this Agreement or by the other Transaction Documents, or (c) with respect to which there is a reasonable likelihood of a determination which would prevent or delay Calpine or any of the Calpine Transaction Parties from consummating the transactions contemplated hereby or by the other Transaction Documents in any material respect or performing any material obligations hereunder or thereunder, in any court or other tribunal or before any arbitrator, mediator, authority or Governmental Authority. 9.6 Compliance with Law. None of Calpine or the Calpine Transaction Parties has violated any Applicable Laws, and each of Calpine and the Calpine Transaction Parties is in compliance with all Applicable Laws, except to the extent that any such violations or failures to comply, individually or in the aggregate, have not had a Material Adverse Effect on Calpine or any Calpine Transaction Party. None of Calpine or the Calpine Transaction Parties has received any written notice to the effect that, and the Calpine Transaction Parties do not have any knowledge that, (a) any investigation or review by any Governmental Authority related to this Agreement, the other Transaction Documents, the transactions contemplated hereby or thereby, Calpine, the Calpine Transaction Parties, the Services or the CalBear Trades is pending or threatened in writing, or (b) any currently existing circumstances are likely to result in a failure of any of Calpine or the Calpine Transaction Parties to comply with, or a violation by any of Calpine or the Calpine Transaction Parties of, any Applicable Laws, in either case which such failure to comply or violation would be reasonably expected to have a Material Adverse Effect on Calpine or any Calpine Transaction Party. 9.7 Insurance. The Calpine Transaction Parties have insurance policies, binders or other forms of insurance that provide, and during their term have provided, coverage to the extent and in the manner (a) adequate for the Calpine Transaction Parties and their Assets, businesses and operations and the risks insured against in connection therewith and (b) as may be or may have been required by material Applicable Law and by any material Contracts to which any 42 Calpine Transaction Party is or has been a party, except, in either case, as would not have a Material Adverse Effect on any Calpine Transaction Party. 9.8 Adequate Capital. Neither Calpine nor any of the Calpine Transaction Parties is insolvent or will be insolvent after giving effect to the transactions contemplated by this Agreement and the other Transaction Documents, as the term insolvent is used in applicable state and federal fraudulent conveyance or transfer laws. 9.9 SEC Filings; Financial Statements. (a) Calpine has filed all registration statements, prospectuses, forms and reports required to be filed by it under the Securities Act or the Exchange Act, as the case may be, since January 1, 2003 (collectively, the "Calpine SEC Filings"). Each Calpine SEC Filing, as amended or supplemented, complied in all material respects with the requirements of the Securities Act or the Exchange Act, as the case may be, with respect to such Calpine SEC Filing. Each Calpine SEC Filing, as amended or supplemented, if applicable, did not (as so amended or supplemented) contain any untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary in order to make the statements made therein, in the light of the circumstances under which they were made, not misleading. (b) Except as may be indicated in the notes thereto and, in the case of unaudited quarterly financial statements, except as permitted by Form 10-Q under the Exchange Act, each of the consolidated financial statements (including, in each case, any notes thereto) contained in the Calpine SEC Filings was prepared in accordance with GAAP applied on a consistent basis throughout the periods indicated, and, at the time such consolidated financial statements were filed and at the time they were amended or supplemented, if applicable, each fairly presented in all material respects the consolidated financial position of Calpine and its subsidiaries as of the respective dates thereof and for the respective periods indicated therein (subject, in the case of unaudited statements, to normal, recurring year-end adjustments which did not have a Material Adverse Effect on Calpine). 9.10 Regulation. (a) Neither Calpine nor any of the Calpine Transaction Parties is subject to regulation as an "electric utility company," a "gas utility company" a "public-utility company," or a "holding company," under PUHCA or any regulation promulgated thereunder. Neither Calpine nor any of the Calpine Transaction Parties is subject to material regulatory restrictions under PUHCA (other than Section 9(a)(2) of PUHCA). (b) CES and CMSC each have validly issued final orders authorizing CES and CMSC, respectively, to engage in Power sales at wholesale at market-based rates. CES and CMSC are in compliance with all FERC reporting and other requirements generally imposed on entities authorized to engage in wholesale sales of Power at market-based rates, including requirements to file electronic quarterly transaction reports, triennial market-power updates and changes in status, except to the extent that non-compliance could not reasonably be expected to cause a Material Adverse Effect with respect to CES or CMSC. 43 9.11 Due Consideration. Calpine and the Calpine Transaction Parties acknowledge that they will generally obtain more favorable terms for Trades through the Transaction than the terms that are currently available to them for similar transactions with Third Parties and Calpine and the Calpine Transaction Parties desire Bear Stearns to provide financial support as part of the Transaction in order to enhance the credit of certain Gas and Power trades made by CalBear and CES and in order to otherwise support certain Gas and Power trading activities of the Calpine Transaction Parties. Calpine and the Calpine Transaction Parties have received due and adequate consideration and fair and equivalent value for their agreements and obligations under this Agreement and the other Transaction Documents as determined in good faith, in each case within the meaning of applicable state and federal fraudulent conveyance laws. 9.12 Operations of CMSC. CMSC has not taken any action that would have violated Section 4.1(m) of the Agency and Services Agreement had it been subject to such Section 4.1(m) on the Effective Date. Except in connection with the transactions contemplated by the Transaction Documents or the provision of energy related services to CES, CMSC does not have any Contracts with, or Liabilities to, Third Parties or its Affiliates. 9.13 Material Contracts of CMSC. At least ten (10) days prior to the Effective Date, CMSC has provided to Bear Stearns and CalBear copies of all material Contracts to which CMSC is a party and copies of all Contracts listed on Schedules 4.1(m) to the Agency and Services Agreement. ARTICLE X. REPRESENTATIONS AND WARRANTIES OF BEAR STEARNS As an inducement to enter into this Agreement, each of Bear Stearns and CalBear hereby represents and warrants to Calpine and each of the Calpine Transaction Parties, as of the date hereof (other than with respect to CalBear) and as of the Effective Date, and except as otherwise disclosed in the Bear Stearns SEC Filings, the following: 10.1 Bear Stearns and CalBear. Schedule 10.1 lists the name, type of entity and jurisdiction of organization of Bear Stearns and CalBear. Bear Stearns owns, directly or indirectly, all of the outstanding Equity Securities of CalBear. 10.2 No Conflict or Violation. None of the execution, delivery and performance of this Agreement or any other Transaction Documents, the consummation of the transactions contemplated hereby and thereby, compliance with any of the provisions hereof or thereof, or the consummation of any CalBear Trades, by Bear Stearns or CalBear will result in (a) a violation of or a conflict with any provision of the Organizational Documents of Bear Stearns or CalBear, (b) a violation of, a conflict with, a breach of, or a default under (with or without notice or passage of time), the termination or acceleration of the performance required by, or the creation of any right of any party to accelerate, modify, terminate or cancel, any material term or provision of any material Contract to which Bear Stearns or CalBear is a party or by which any of its Assets are bound, (c) a violation or breach in any material respect of any Applicable Law applicable to Bear Stearns or CalBear or (d) subject to compliance with Section 4.1(n) of the Agency and Services Agreement by CMSC, 44 Bear Stearns or CalBear being required to obtain any material consent, waiver, agreement, Permit or approval or material authorization of, or material declaration, filing, notice or registration to or with, or material assignment by, any Third Party or Governmental Authority, except, in each case, as set forth on Schedule 10.2. 10.3 Sufficiency of Assets. CalBear owns, licenses, leases or otherwise has a right to use or has contracted for all Assets materially necessary and sufficient for the performance of its obligations under the Transaction Documents, and its Assets in the aggregate are materially in such operating condition and repair (subject to normal wear and tear) as is necessary and sufficient for the performance of such obligations. 10.4 Permits. Except as set forth on Schedule 10.2, CalBear has all material Permits necessary for (i) the conduct of its business as now being conducted and as proposed to be conducted as contemplated in this Agreement and the other Transaction Documents and (ii) the performance of its obligations under the Transaction Documents, and owns or possesses such Permits free and clear of any material Encumbrances. All such Permits are valid and in full force and effect in all material respects. 10.5 Litigation. There is no Action pending or, to the knowledge of CalBear, threatened in writing against, relating to or affecting Bear Stearns or CalBear or any of their properties, rights or Assets (a) that, if pending, involves the risk of criminal liability or, if threatened, could reasonably be expected to involve the risk of criminal liability, (i) for CalBear or (ii) for Bear Stearns and its Affiliates; provided, in the case of clause (ii), such Action is material to Bear Stearns and its Affiliates, taken as a whole, (b) that relates to the transactions contemplated by this Agreement or by the other Transaction Documents, or (c) with respect to which there is a reasonable likelihood of a determination which would prevent or delay Bear Stearns or CalBear from consummating the transactions contemplated hereby or by the other Transaction Documents in any material respect or performing any material obligations hereunder or thereunder, in any court or other tribunal or before any arbitrator, mediator, authority or Governmental Authority. 10.6 Compliance with Law. Neither Bear Stearns nor CalBear has violated any Applicable Laws, and each of Bear Stearns and CalBear is in compliance with all Applicable Laws, except to the extent that any such violations or failures to comply, individually or in the aggregate, have not had a Material Adverse Effect on Bear Stearns or CalBear. Neither Bear Stearns nor CalBear has received any written notice to the effect that, and CalBear do not have any knowledge that, (a) any investigation or review by any Governmental Authority related to this Agreement, the other Transaction Documents, the transactions contemplated hereby or thereby, CalBear, Bear Stearns, the Services or the CalBear Trades is pending or threatened in writing, or (b) any currently existing circumstances are likely to result in a failure of Bear Stearns or CalBear to comply with, or a violation by Bear Stearns or CalBear of, any Applicable Laws, in either case which such failure to comply or violation would be reasonably expected to have a Material Adverse Effect on Bear Stearns or CalBear. 10.7 Insurance. CalBear has insurance policies, binders or other forms of insurance that provide, and during their term have provided, coverage to the extent and in the manner (a) adequate for CalBear and its Assets, businesses and operations and the risks insured against in connection therewith and (b) as may 45 be or may have been required by material Applicable Law and by any material Contracts to which CalBear is or has been a party, except, in either case, as would not have a Material Adverse Effect on CalBear. 10.8 Adequate Capital. CalBear is not insolvent and will not be insolvent after giving effect to the transactions contemplated by this Agreement and the other Transaction Documents, as the term insolvent is used in applicable state and federal fraudulent conveyance or transfer laws. 10.9 SEC Filings; Financial Statements. (a) Bear Stearns has filed all registration statements, prospectuses, forms and reports required to be filed by it under the Securities Act or the Exchange Act, as the case may be, since January 1, 2003 (collectively, the "Bear Stearns SEC Filings"). Each Bear Stearns SEC Filing, as amended or supplemented, complied in all material respects with the requirements of the Securities Act or the Exchange Act, as the case may be, with respect to such Bear Stearns SEC Filing. Each Bear Stearns SEC Filing, as amended or supplemented, if applicable, did not (as so amended or supplemented) contain any untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary in order to make the statements made therein, in the light of the circumstances under which they were made, not misleading. (b) Except as may be indicated in the notes thereto and, in the case of unaudited quarterly financial statements, except as permitted by Form 10-Q under the Exchange Act, each of the consolidated financial statements (including, in each case, any notes thereto) contained in the Bear Stearns SEC Filings was prepared in accordance with GAAP applied on a consistent basis throughout the periods indicated, and, at the time such consolidated financial statements were filed and at the time they were amended or supplemented, if applicable, each fairly presented in all material respects the consolidated financial position of Bear Stearns and its subsidiaries as of the respective dates thereof and for the respective periods indicated therein (subject, in the case of unaudited statements, to normal, recurring year-end adjustments which did not have a Material Adverse Effect on Bear Stearns). 10.10 Regulation. (a) Neither Bear Stearns nor CalBear is subject to regulation as an "electric utility company," a "gas utility company" a "public-utility company," or a "holding company," under PUHCA or any regulation promulgated thereunder. Neither Bear Stearns nor CalBear is subject to material regulatory restrictions under PUHCA (other than Section 9(a)(2) of PUHCA). (b) CalBear has validly issued final orders authorizing CalBear to engage in Power sales at wholesale at market-based rates. CalBear is in compliance with all FERC reporting and other requirements generally imposed on entities authorized to engage in wholesale sales of Power at market-based rates, including requirements to file electronic quarterly transaction reports, triennial market-power updates and changes in status, except to the extent that non-compliance could not reasonably be expected to cause a Material Adverse Effect with respect to CalBear. 46 10.11 Operations of CalBear. CalBear has not taken any action that would have violated Section 4.4(f) of the Agency and Services Agreement had it been subject to such Section 4.4(f) on the Effective Date. Except in connection with the transactions contemplated by the Transaction Documents, CalBear does not have any Contracts with, or Liabilities to, Third Parties or its Affiliates. ARTICLE XI. PRE-EFFECTIVE DATE COVENANTS OF THE PARTIES From the date hereof through the Effective Date: 11.1 Notification of Certain Matters. Calpine and the Calpine Transaction Parties, on the one hand, and Bear Stearns and CalBear, on the other hand, shall promptly following knowledge thereof give notice to each other of (a) the occurrence, or failure to occur, of any event, which occurrence or failure could reasonably be expected to cause any representation or warranty of such Party or any of its Affiliates contained in this Agreement or in any exhibit, schedule, certificate, document or written instrument attached hereto to be untrue or inaccurate in any material respect, (b) any Material Adverse Change with respect to such Party or its Assets or the businesses of such Party, or any development that occurs before the Effective Date (including the commencement of any proceeding relating to the Bankruptcy of any such Party) that has a Material Adverse Effect with respect to such Party or its Assets or business, (c) any Bankruptcy of such Party or any of its Significant Subsidiaries, (d) the failure by such Party to perform any covenant or agreement of such Party set forth in this Agreement or any other Transaction Document, which failure constitutes a material breach of this Agreement or such other Transaction Document; provided that any breach of this clause (d) shall be deemed to be cured upon the cure of the underlying failure to perform, (e) any material notice or other written communication from any Person alleging that the consent of such Person is or may be required in connection with the execution, delivery or performance of this Agreement, any Transaction Document or the transactions contemplated herein and therein, and (f) any material notice or other written communication from any Governmental Authority in connection with this Agreement, any Transaction Document or the transactions contemplated herein and therein; provided, in each case, that such disclosure shall not be deemed to cure, or to relieve any Party of any Liability or obligation with respect to, any breach of or failure to satisfy any representation, warranty, covenant or agreement or to satisfy any condition hereunder. 11.2 Consents and Commercially Reasonable Efforts. Each of the Transaction Parties covenants and agrees, upon the terms and conditions contained herein, to (a) cooperate with the other Transaction Parties hereto and to pursue diligently and in good faith and use all commercially reasonable efforts to take, or cause to be taken, all actions necessary, proper or advisable to consummate and make effective the transactions contemplated hereby and by the other Transaction Documents and (b) execute any documents, instruments or conveyances of any kind that may be reasonably necessary or advisable to carry out any of the transactions contemplated hereby and by the other Transaction Documents. Without limiting the generality of the foregoing, each Transaction Party shall use all commercially reasonable best efforts to obtain at the earliest practicable date all consents, approvals, Permits, authorizations, exemptions and waivers from Governmental Authorities and other Persons (including all FERC approvals and 47 authorizations under Section 6.1(c), Section 6.2(c) and Section 6.3) required to be obtained by it and necessary or advisable to authorize, approve or permit the performance by such Transaction Party of its obligations hereunder and under each other agreement and instrument referred to herein or contemplated hereby, including all such consents, approvals, authorizations, exemptions and waivers listed on Schedules 9.2 and 10.2. 11.3 Other Transaction Documents. On or prior to the Effective Date, the Calpine Transaction Parties and CalBear, respectively, shall enter into the Transaction Documents (other than this Agreement), as applicable, and shall provide each other with original copies thereof. ARTICLE XII. CONDITIONS TO CALPINE'S OBLIGATIONS The obligation of Calpine and each of the Calpine Transaction Parties to perform its obligations under this Agreement that are to be performed from and after the Effective Date and to consummate any transactions contemplated under this Agreement to be consummated on or after the Effective Date are subject to the satisfaction, on or prior to the Effective Date, of each of the following conditions, any of which may be waived by Calpine and the Calpine Transaction Parties: 12.1 Representations, Warranties and Covenants. All representations and warranties of Bear Stearns and CalBear contained in this Agreement and qualified by the words "material," "Material Adverse Effect," "Material Adverse Change" and similar phrases shall be true and correct in all respects, and all representations and warranties of Bear Stearns and CalBear contained in this Agreement that are not so qualified shall be true and correct in all material respects, in each case, at and as of the date of this Agreement and at and as of the Effective Date, except for those representations and warranties that speak as of a particular date, which shall be true and correct as of such date, and Bear Stearns and CalBear shall have performed and satisfied in all material respects all agreements and covenants required to be performed by it hereunder prior to or on the Effective Date. 12.2 No Proceedings or Litigation. No Action by any Governmental Authority or any other Person shall have been instituted or threatened in writing for the purpose of enjoining or preventing, or which questions the validity or legality of, the transactions contemplated hereby and by the other Transaction Documents and which could reasonably be expected to damage Calpine or any Calpine Transaction Party materially if Calpine and each Calpine Transaction Party were to perform its obligations that are to be performed hereunder from and after the Effective Date or were to consummate any transactions that are to be consummated hereunder or under any of the other Transaction Documents on or after the Effective Date. Since the date of this Agreement, no Applicable Law shall have been enacted that makes performance of this Agreement or any of the other Transaction Documents by Calpine or any of the Calpine Transaction Parties illegal or otherwise prohibited or that otherwise has a Material Adverse Effect on Calpine or any of the Calpine Transaction Parties. 48 12.3 Bankruptcy. Since the date of this Agreement, there shall not have been any Bankruptcy Event with respect to Bear Stearns, CalBear or any Significant Subsidiary of Bear Stearns. 12.4 Effective Date Deliveries. Calpine and the Calpine Transaction Parties shall have received from Bear Stearns and CalBear, at or prior to the Effective Date, the following: (a) a copy of each of the Transaction Documents (other than this Agreement), duly executed by CalBear; (b) a certificate executed by an officer of Bear Stearns certifying that, as of the Effective Date, the conditions set forth in Section 12.1 and Section 12.3 have been satisfied; and (c) a certificate of an officer of CalBear, certifying the existence of CalBear and the authority of CalBear to enter into the Transaction Documents to which CalBear is a party, in form reasonably satisfactory to Calpine. 12.5 Transaction Documents. Each of the Transaction Documents (other than this Agreement) shall have been executed and delivered by each party thereto other than the Calpine Transaction Parties. All of the conditions precedent to the obligations of the parties to each of the Transaction Documents (other than this Agreement) shall have been satisfied or waived by the party or parties for whose benefit they were established. 12.6 Pre-Formation Transactions. The Pre-Formation Transactions shall have been completed. 12.7 Corporate Proceedings. All corporate proceedings of Bear Stearns and CalBear that are required in connection with the Pre-Formation Transactions, the Formation Transactions or the transactions contemplated by this Agreement and by the other Transaction Documents shall be reasonably satisfactory in form and substance to Calpine and its counsel. 12.8 Regulatory Approvals. FERC shall have issued a final order pursuant to Section 203 of the FPA, not undergoing rehearing or appeal, authorizing the internal reorganization of the upstream ownership of CalBear's predecessor, Arroyo Energy LP, and providing the authorizations required for the provision of the Services by CMSC to CalBear and the provision of energy related services by CMSC to CES. 12.9 Opinion of Counsel to Bear Stearns. Calpine shall have received (a) opinions, dated as of the Effective Date, in form and substance reasonably satisfactory to Calpine, of Latham & Watkins LLP, internal counsel to Bear Stearns and/or other counsel to Bear Stearns reasonably acceptable to Calpine, with respect to the matters set forth on Schedule 12.9 and (b) copies of any officer's certificates or other certificates, in form and substance reasonably satisfactory to Calpine, referred to in such opinions. 49 ARTICLE XIII. CONDITIONS TO BEAR STEARNS' OBLIGATIONS The obligation of each of Bear Stearns and CalBear to perform its obligations under this Agreement that are to be performed from and after the Effective Date and to consummate any transactions contemplated under this Agreement to be consummated on or after the Effective Date are subject to the satisfaction, on or prior to the Effective Date, of each of the following conditions, any of which may be waived by Bear Stearns and CalBear: 13.1 Representations, Warranties and Covenants. All representations and warranties of Calpine and of each Calpine Transaction Party contained in this Agreement and qualified by the words "material," "Material Adverse Effect," "Material Adverse Change" and similar phrases shall be true and correct in all respects, and all representations and warranties of Calpine and of each Calpine Transaction Party contained in this Agreement that are not so qualified shall be true and correct in all material respects, in each case, at and as of the date of this Agreement and at and as of the Effective Date, except for those representations and warranties that speak as of a particular date, which shall be true and correct as of such date, and Calpine and each Calpine Transaction Party shall have performed and satisfied in all material respects all agreements and covenants required to be performed by it hereunder prior to or on the Effective Date. 13.2 No Proceedings or Litigation. No Action by any Governmental Authority or any other Person shall have been instituted or threatened in writing for the purpose of enjoining or preventing, or which questions the validity or legality of, the transactions contemplated hereby and by the other Transaction Documents and which could reasonably be expected to damage Bear Stearns or CalBear materially if each of Bear Stearns and CalBear were to perform its obligations that are to be performed hereunder from and after the Effective Date or were to consummate any transactions that are to be consummated hereunder or under any of the other Transaction Documents on or after the Effective Date. Since the date of this Agreement, no Applicable Law shall have been enacted that makes performance of this Agreement or any of the other Transaction Documents by Bear Stearns or CalBear illegal or otherwise prohibited or that otherwise has a Material Adverse Effect on Bear Stearns or CalBear. 13.3 Bankruptcy. Since the date of this Agreement, there shall not have been any Bankruptcy Event with respect to Calpine, any of the Calpine Transaction Parties or any Significant Subsidiary of Calpine. 13.4 Effective Date Deliveries. Bear Stearns and CalBear shall have received from Calpine and the Calpine Transaction Parties, at or prior to the Effective Date, the following: (a) a copy of each of the Transaction Documents (other than this Agreement), duly executed by each Calpine Transaction Party that is a party thereto; (b) a certificate executed by an officer of Calpine certifying that, as of the Effective Date, the conditions set forth in Section 13.1 and Section 13.3 have been satisfied; and (c) a certificate of an officer of each Calpine Transaction Party, certifying the existence of such Calpine Transaction Party, as applicable, and the authority of such Calpine Transaction Party, as applicable, to enter into 50 the Transaction Documents to which such Calpine Transaction Party is a party, in form reasonably satisfactory to Bear Stearns. 13.5 Transaction Documents. Each of the Transaction Documents (other than this Agreement) shall have been executed and delivered by each party thereto other than CalBear. All of the conditions precedent to the obligations of the parties to each of the Transaction Documents (other than this Agreement) shall have been satisfied or waived by the party or parties for whose benefit they were established. 13.6 Pre-Formation Transactions. The Pre-Formation Transactions shall have been completed. 13.7 Corporate Proceedings. All corporate proceedings of Calpine and the Calpine Transaction Parties that are required in connection with the Pre-Formation Transactions, the Formation Transactions or the transactions contemplated by this Agreement and by the other Transaction Documents shall be reasonably satisfactory in form and substance to Bear Stearns and its counsel. 13.8 Regulatory Approvals. FERC shall have issued a final order pursuant to Section 203 of the FPA, not undergoing rehearing or appeal, authorizing the internal reorganization of the upstream ownership of CMSC's predecessor, CES Marketing VII, LLC, and providing the authorizations required for the provision of the Services by CMSC to CalBear and the provision of energy related services by CMSC to CES. 13.9 Opinion of Counsel to Calpine. Bear Stearns shall have received (a) opinions, dated as of the Effective Date, in form and substance reasonably satisfactory to Bear Stearns, of Bracewell & Giuliani LLP, internal counsel to Calpine and/or other counsel to Calpine reasonably acceptable to Bear Stearns, with respect to the matters set forth on Schedule 13.9 and (b) copies of any officer's certificates or other certificates, in form and substance reasonably satisfactory to Bear Stearns, referred to in such opinions. ARTICLE XIV. CERTAIN ACTIONS AFTER THE EFFECTIVE DATE Each of the Parties, with respect to itself only, covenants and agrees with each of the other Parties that from and after the Effective Date: 14.1 Survival of Representations, etc. The representations and warranties of each Party contained herein shall survive for one (1) year after the date on which such representations and warranties are made, unless another Party notifies such Party prior to such date of any specific claim or claims for alleged breach of any such representation or warranty, in which case such representation or warranty shall survive with respect to such claim until the later of (a) final resolution by settlement, Action or otherwise of any such claim or (b) the end of such one (1) year period. No investigation made by any Party (whether prior to, on or after the date of this Agreement) shall in any way limit the representations and warranties of the Parties. The covenants and agreements of the Parties contained herein shall survive the termination of this 51 Agreement only to the extent expressly set forth herein, including as set forth in Section 16.6(c)(ii). 14.2 No Conflict or Violation. (a) Each of CMSC and CalBear shall operate their businesses in a manner that will not result in (i) a violation of or a conflict with any provision of the Organizational Documents of such Transaction Party or (ii) a violation of or a breach or default under, the termination or acceleration of the performance required by, or the creation of any right of any party to accelerate, modify, terminate or cancel, any material term or provision of any material Contract related to the Transaction to which such Transaction Party is a party or by which any of its material Assets are bound, or (iii) a violation or breach in any material respect of any Applicable Law applicable to such Transaction Party and, in the case of CMSC, applicable to CalBear. (b) CES shall operate its businesses with respect to the Trading Master Agreement and this Agreement in a manner that will not result in (i) a violation of or a conflict with any provision of the Organizational Documents of CES or (ii) a violation of or a breach or default under, the termination or acceleration of the performance required by, or the creation of any right of any party to accelerate, modify, terminate or cancel, any material term or provision of any material Contract relating to any Credit Enhancement Trade or the Transaction to which CES is a party or by which any of its material Assets are bound, or (iii) a violation or breach in any material respect of any Applicable Law applicable to CES. 14.3 Sufficiency of Assets. Each of the Calpine Transaction Parties and CalBear shall continue to own, license, lease or otherwise have a right to use or have contracted for all Assets materially necessary and sufficient for the performance of its obligations under the Transaction Documents, and will maintain its Assets in the aggregate materially in such operating condition and repair (subject to normal wear and tear) as is necessary and sufficient for the performance of such obligations. 14.4 Permits. Subject to Section 4.1(n) of the Agency and Services Agreement, each of Calpine, the Calpine Transaction Parties, Bear Stearns and CalBear shall maintain and keep in full force and effect all material Permits needed for the performance of its obligations under the Transaction Documents, and each such Party shall continue to own or possess such Permits free and clear of any material Encumbrances. 14.5 Insurance. Each of the Calpine Transaction Parties and CalBear shall maintain and keep in full force and effect insurance policies, binders or other forms of insurance that provide coverage in connection with its obligations under the Transaction Documents and the Transaction to the extent and in the manner adequate for such Person and its material Assets, businesses and operations and the risks insured against in connection therewith, except as would not have a Material Adverse Effect. 52 14.6 Adequate Capital. Each of Calpine, the Calpine Transaction Parties, Bear Stearns and CalBear shall operate and maintain its businesses such that at all times it is not insolvent, as such term is used in applicable state and federal fraudulent conveyance or transfer laws. 14.7 Further Assurances. The Transaction Parties shall use commercially reasonable efforts to take all actions and to do all things necessary, proper or advisable to consummate and make effective the transactions contemplated by this Agreement and by the other Transaction Documents. Following the Effective Date, each Transaction Party agrees to execute such documents or instruments and take such actions as may be reasonably requested by the other Transaction Parties, and otherwise cooperate in a reasonable manner with the other Transaction Parties and their respective Affiliates and their respective Representatives in connection with any action that may be necessary, proper or advisable to carry out the provisions hereof or transactions contemplated hereby and by the other Transaction Documents. 14.8 Litigation Support. In the event and for so long as any Party is actively contesting or defending against any Action or Claim in connection with (a) any transaction contemplated under this Agreement or the other Transaction Documents or (b) any fact, situation, circumstance, status, condition, activity, practice, plan, occurrence, event, incident, action, failure to act or transaction involving the CalBear Business, the Trades or the Services, each other Party that is not an Affiliate of such Party, will use reasonable efforts to cooperate with such Party and its counsel in the contest or defense, make available its Representatives, and provide such testimony and access to its Books and Records as shall be reasonably necessary in connection with the contest or defense, all at the sole cost and expense of the contesting or defending Party (unless the contesting or defending Party is entitled to indemnification hereunder). The covenant contained in this Section 14.8 shall not apply if Calpine or any Calpine Transaction Party has an adverse Action or Claim against Bear Stearns or CalBear and shall not apply if Bear Stearns or CalBear has an adverse Action or Claim against Calpine or any Calpine Transaction Party, but shall apply equally with respect to any other Transaction Documents and shall not be in lieu of or otherwise limit the indemnification obligations of the Parties pursuant to Article XV hereof. 14.9 Organizational Documents of CMSC and CalBear. (a) Calpine shall not, and shall cause its Affiliates not to, modify the Organizational Documents of CMSC, or any provision thereof, without the prior consent of Bear Stearns, not to be unreasonably withheld. (b) Bear Stearns shall not, and shall cause its Affiliates not to, modify the Organizational Documents of CalBear, or any provision thereof, without the prior consent of Calpine, not to be unreasonably withheld. ARTICLE XV. INDEMNIFICATION 15.1 General Indemnification. (a) By CMSC and CES. 53 (i) Subject to Section 14.1 and the limitations set forth in this Article XV and Article XVII, the Calpine Transaction Parties, jointly and severally, shall indemnify, save and hold harmless Bear Stearns, CalBear, each of their Affiliates, and each of their respective directors, officers, employees, successors, transferees and assignees (each, a "Bear Stearns Party"), from and against any and all costs, losses, charges, liabilities, obligations, damages, Actions (including response Actions, removal Actions and remedial Actions), judgments, deficiencies, demands, fees, settlements and expenses, including interest, fines, penalties, costs of mitigation and cover (to the extent, but only to the extent, such costs are provided for in the definition of Third Party Losses), attorneys' fees and expenses, all amounts paid in the investigation, defense or settlement of any of the foregoing and costs of enforcing the applicable indemnity (collectively, "Damages") arising out of or resulting from: (A) any untruth, inaccuracy or incorrectness of, or other breach of, any representation or warranty of Calpine or any Calpine Transaction Party in or pursuant to this Agreement or any of the other Transaction Documents; (B) any nonfulfillment, nonperformance, nonobservance or other breach or violation of, or default under, any covenant or agreement made by Calpine or any Calpine Transaction Party in or pursuant to this Agreement or any of the other Transaction Documents; (C) any Misconduct of Calpine or any of the Calpine Transaction Parties or any of their Affiliates or their respective Representatives; (D) any Liability of Calpine, any Calpine Transaction Party or any of their Affiliates for any finder's fee, brokerage fee or commission or similar Payment in connection with the transactions contemplated hereby and by the other Transaction Documents; or (E) any violation of Applicable Law by Calpine or any of the Calpine Transaction Parties or any of their Affiliates or their respective Representatives, in each case to the extent that the Damages to a Bear Stearns Party arose out of or resulted from the transactions contemplated by the Transaction Documents or the fact that Bear Stearns or CalBear are parties to the Transaction Documents; provided that this clause (E) shall not apply to any violations of Applicable Law indemnified under clauses (A), (B) or (C) above or any violations of Applicable Law not indemnified pursuant to such clauses (A), (B) or (C) as a result of materiality, knowledge, Material Adverse Effect and similar qualifiers in the applicable provisions of this Agreement and the other Transaction Documents; (each claim for indemnity by a Bear Stearns Party pursuant to this Section 15.1(a), a "Bear Stearns Claim"). (ii) The indemnity provided for in this Section 15.1(a) is not limited to Third Party Claims against any Bear Stearns Party, but includes Bear Stearns Claims incurred or sustained by any Bear Stearns Party in the absence of 54 Third Party Claims. With respect to any Third Party Claims against any Bear Stearns Party covered by the indemnity provided in this Section 15.1(a), such indemnification shall include coverage of any consequential, indirect, special, punitive, exemplary or incidental damages included in such Third Party Claims. (iii) The indemnity provided for in this Section 15.1(a) shall not apply to Claims or Damages arising out of or resulting from any nonfulfillment, nonperformance, nonobservance or other breach or violation of or default under, or any Misconduct related to, Soft Covenants, for which the sole and exclusive rights and remedies are described in Clause (a) of Section 17.3 of this Agreement. (iv) The indemnity set forth in clauses (A) and (B) of Section 15.1(a)(i) is subject to the following additional limitations: (A) such indemnity shall not apply to Claims or Damages constituting Ordinary Losses, except to the extent such Ordinary Losses are not consequential, indirect, special, punitive, exemplary or incidental Claims or Damages and arise out of or result from (I) any nonfulfillment, nonperformance, nonobservance or other breach or violation of or default under Hard Covenants, (II) Misconduct of Calpine or any Calpine Transaction Party or any other matters indemnified in clauses (C) through (E) above, (III) any nonfulfillment, nonperformance, nonobservance or other breach or violation of or default under any provisions of any Transaction Document arising out of or resulting from the gross negligence of Calpine or any Calpine Transaction Party (except to the extent covered in the definition of "Misconduct" or limited by paragraph (v) below), to the extent that such Ordinary Losses covered under this clause (III) incurred in the same Fiscal Year in the aggregate exceed $[*] million (provided that the occurrence of losses or gains on CalBear Trades does not by itself represent the presence or absence of, respectively, gross negligence) or (IV) the failure of Calpine or a Calpine Transaction Party to make any Payment to Bear Stearns or CalBear specifically provided for pursuant to the terms of the Transaction Documents; and (B) such indemnity shall not apply to Claims or Damages constituting Third Party Losses, unless and until such Claims or Damages covered under such indemnity incurred in the same Fiscal Year in the aggregate exceed $[*] million (the "Threshold"), in which case such indemnity shall apply to all such Claims or Damages covered under such indemnity during such Fiscal Year whether or not the same exceed the Threshold, provided that this Section 15.1(a)(iv)(B) shall not apply to Claims or Damages arising out of or resulting from (I) any nonfulfillment, nonperformance, nonobservance or other breach or violation of or default under Hard Covenants, (II) Misconduct of Calpine or any Calpine Transaction Party or any other matters indemnified in clauses (C) through (E) above, (III) the failure of Calpine or a Calpine Transaction Party to make any Payment to Bear 55 Stearns or CalBear specifically provided for pursuant to the terms of the Transaction Documents, or (IV) indemnification obligations under Section 4.4(e)(iv) of the Agency and Services Agreement. (v) No Bear Stearns Party shall have the right to indemnification for any Ordinary Losses resulting from or arising out of the gross negligence of Calpine or any Calpine Transaction Party to the extent that Bear Stearns or CalBear actually knew of such gross negligence and did not promptly, after obtaining such knowledge, inform Calpine or a Calpine Transaction Party of (A) its intent to preserve any claim for indemnification under this Section 15.1(a) with respect to such gross negligence and (B) the facts, events or conditions constituting such gross negligence, to the extent then known. (b) By CalBear. (i) Subject to Section 14.1 and the limitations set forth in this Article XV and Article XVII, CalBear shall indemnify, save and hold harmless Calpine, each Calpine Transaction Party, each of their Affiliates, and each of their respective directors, officers, employees, successors, transferees and assignees (each, a "Calpine Party"), from and against any and all Damages arising out of or resulting from: (A) any untruth, inaccuracy or incorrectness of, or other breach of, any representation or warranty of Bear Stearns or CalBear in or pursuant to this Agreement or any of the other Transaction Documents; (B) any nonfulfillment, nonperformance, nonobservance or other breach or violation of, or default under, any covenant or agreement made by Bear Stearns or CalBear in or pursuant to this Agreement or any of the other Transaction Documents; (C) any Misconduct of Bear Stearns or CalBear or any of their Affiliates or their respective Representatives; (D) any Liability of Bear Stearns, CalBear or any of their Affiliates for any finder's fee, brokerage fee or commission or similar Payment in connection with the transactions contemplated hereby and by the other Transaction Documents; or (E) any violation of Applicable Law by CalBear or any of its Affiliates or their respective Representatives, in each case to the extent that the Damages to a Calpine Party arose out of or resulted from the transactions contemplated by the Transaction Documents or the fact that Calpine and the Calpine Transaction Parties are parties to the Transaction Documents; provided that this clause (E) shall not apply to any violations of Applicable Law indemnified under clauses (A), (B) or (C) above or any violations of Applicable Law not indemnified pursuant to such clauses (A), (B) or (C) as a result of materiality, knowledge, Material Adverse Effect and similar qualifiers in the applicable provisions of this Agreement and the other Transaction Documents; 56 (each claim for indemnity by a Calpine Party pursuant to this Section 15.1(b), a "Calpine Claim"); provided that in no event shall CalBear be obligated to indemnify any Calpine Party for Damages to the extent such Damages arose out of or resulted from CMSC's performance of or failure to perform any of its obligations as agent or attorney-in-fact for CalBear under the Agency and Services Agreement. (ii) The indemnity provided for in this Section 15.1(b) is not limited to Third Party Claims against any Calpine Party, but includes Calpine Claims incurred or sustained by any Calpine Party in the absence of Third Party Claims. With respect to any Third Party Claims against any Calpine Party covered by the indemnity provided in this Section 15.1(b), such indemnification shall include coverage of any consequential, indirect, special, punitive, exemplary or incidental damages included in such Third Party Claims. (iii) The indemnity provided for in this Section 15.1(b) shall not apply to Claims or Damages arising out of or resulting from any nonfulfillment, nonperformance, nonobservance or other breach or violation of or default under, or any Misconduct related to, Soft Covenants, for which the sole and exclusive rights and remedies are described in Clause (a) of Section 17.3 of this Agreement. (iv) The indemnity set forth in clauses (A) and (B) of Section 15.1(b)(i) is subject to the following additional limitations: (A) such indemnity shall not apply to Claims or Damages constituting Ordinary Losses, except to the extent such Ordinary Losses are not consequential, indirect, special, punitive, exemplary or incidental Claims or Damages and arise out of or result from (I) any nonfulfillment, nonperformance, nonobservance or other breach or violation of or default under Hard Covenants, (II) Misconduct of Bear Stearns or CalBear or any other matters indemnified in clauses (C) through (E) above, (III) any nonfulfillment, nonperformance, nonobservance or other breach or violation of or default under any provisions of any Transaction Document arising out of or resulting from the gross negligence of Bear Stearns or CalBear (except to the extent covered in the definition of "Misconduct" or limited by paragraph (v) below), to the extent that such Ordinary Losses covered under this clause (III) incurred in the same Fiscal Year in the aggregate exceed $[*] million or (IV) the failure of Bear Stearns or CalBear to make any Payment to a Calpine Transaction Party specifically provided for pursuant to the terms of the Transaction Documents; and (B) such indemnity shall not apply to Claims or Damages constituting Third Party Losses, unless and until such Claims or Damages covered under such indemnity incurred in the same Fiscal Year in the aggregate exceed the Threshold, in which case such indemnity shall apply to all such Claims or Damages covered under such indemnity during such Fiscal Year whether or not the same exceed the Threshold, provided that this Section 15.1(b)(iv)(B) shall not apply to Claims or Damages arising out of or resulting from (I) any nonfulfillment, nonperformance, nonobservance or other breach or violation of or 57 default under Hard Covenants, (II) Misconduct of Bear Stearns or CalBear or any other matters indemnified in clauses (C) through (E) above or (III) the failure of Bear Stearns or CalBear to make any Payment to Calpine or any of the Calpine Transaction Parties specifically provided for pursuant to the terms of the Transaction Documents. (v) No Calpine Party shall have the right to indemnification for any Ordinary Losses resulting from or arising out of the gross negligence of Bear Stearns or CalBear to the extent that Calpine or any Calpine Transaction Party actually knew of such gross negligence and did not promptly, after obtaining such knowledge, inform Bear Stearns or CalBear of (A) its intent to preserve any claim for indemnification under this Section 15.1(b) with respect to such gross negligence and (B) the facts, events or conditions constituting such gross negligence, to the extent then known. (c) Defense of Claims. (i) If a Claim is to be made by a Person entitled to indemnification hereunder (without regard to any thresholds), the Person claiming such indemnification shall give written notice (a "Claim Notice") to the indemnifying Person (A) as soon as practicable after the Person entitled to indemnification becomes aware of any fact, condition or event which may give rise to Damages for which indemnification may be sought under this Section 15.1 and (B) in the case of the assertion of a Claim (whether pursuant to a legal Action or otherwise) or the commencement of any Action by a Third Party other than directors, officers, employees, successors, transferees or assignees of, or other Representatives of, Calpine, any Calpine Transaction Party or their Affiliates or Bear Stearns, CalBear or their Affiliates (together, a "Third Party Claim"), promptly upon receipt of written notice of the Third Party Claim. The failure of any indemnified Person to give timely notice hereunder shall not affect rights to indemnification hereunder, except and only to the extent that the indemnifying Person demonstrates actual prejudice caused by such failure. (ii) In the case of a Third Party Claim, if the indemnifying Person shall acknowledge in writing to the indemnified Person that the indemnifying Person shall be obligated to indemnify the indemnified Person under the terms of its indemnity hereunder in connection with such Third Party Claim, then the indemnifying Person shall be entitled and, if it so elects, shall be obligated at its own cost, risk and expense, to participate in or take control of the defense and investigation of such Third Party Claim, and to pursue the defense thereof in good faith by appropriate actions or proceedings promptly taken or instituted and diligently pursued, including to employ and engage attorneys of its own choice reasonably acceptable to the indemnified Person to handle and defend the same, compromise or settle such Third Party Claim subject to Sections 15.1(c)(iii) and 15.1(c)(iv); provided that the indemnifying Person shall not be entitled to take control of the defense or investigation of a Third Party Claim, if (x) the indemnifying Person is also a party to such Third Party Claim and the indemnified Person determined in good faith, upon the advice of outside counsel, that a conflict of interest exists between the indemnified Person and the indemnifying Person with respect to such Third Party Claim, (y) the indemnifying Person fails to demonstrate to the reasonable satisfaction of the indemnified Person its financial capacity to defend such Third Party Claim 58 and provide indemnification with respect to such Third Party Claim or (z) such Third Party Claim is a Claim by a Governmental Authority. (iii) In the event the indemnifying Person elects to assume control of the defense and investigation of such Third Party Claim in accordance with Section 15.1(c)(ii), the indemnified Person may, at its own cost and expense, participate in the investigation, trial, and defense of such Third Party Claim; provided that, if (x) the named persons to an Action resulting from such Third Party Claim include both the indemnifying Person and the indemnified Person and the indemnified Person has been advised in writing by counsel that there may be one or more legal defenses available to such indemnified Person that are different from or additional to those available to the indemnifying person or that a conflict of interest exists between the indemnified Person and the indemnifying Person with respect to such Third Party Claim, or (y) such Third Party Claim is a Claim by a Governmental Authority, the indemnified Person shall be entitled, at the indemnifying person's cost, risk and expense, to reasonable fees and disbursements of separate counsel of its own choosing. In the event the indemnifying Person assumes the defense of the Third Party Claim, the indemnifying Person shall keep the indemnified Person reasonably informed of the progress of any such defense, compromise or settlement. The indemnifying Person shall not have the power to compromise or settle such Third Party Claim, except with the written consent of the indemnified Person, such consent not to be unreasonably withheld or delayed (it being understood that the failure of the indemnified Person to give such consent shall not be considered unreasonable in respect of any compromise or settlement that (A) does not include an unconditional release of such indemnified Person from all liabilities arising out of, or that may arise out of, such Third Party Claim or (B) includes a statement as to or an admission of fault, culpability or a failure to act, by or on behalf of such indemnified Person). (iv) If the indemnifying Person fails to notify the indemnified Person in writing of its election to assume the defense of such Third Party Claim in accordance with this Section 15.1(c) within ten (10) calendar days after receipt of the Claim Notice, or if the indemnifying person is not permitted to assume the defense of such Third Party Claim in accordance with this Section 15.1(c), the indemnified Person against which such Third Party Claim has been asserted shall have the right to undertake, at the indemnifying Person's cost, risk and expense, the defense, compromise and settlement of such Third Party Claim on behalf of and for the account of the indemnifying Person; provided that the indemnifying Person shall not be liable for costs of settlement of such Third Party Claim if such Third Party Claim is compromised or settled without the written consent of the indemnifying Person (which consent shall not be unreasonably withheld or delayed). (d) Loss Calculation. The amount of Claims or Damages to which an indemnity provided for in this Section 15.1 applies shall be determined after giving effect to all provisions of the Transaction Documents other than this Section 15.1 the operation of which mitigates or compensates for such Claims or Damages (to the extent such terms are given full force and effect), including (as applicable) any reductions in the Service Fee, Service Fee Return Refund or Bonus Amount 59 payable under the Agency and Services Agreement on account or in respect of such Claims and Damages. 15.2 Right of Offset. Each Party may, to the extent set forth in Section 3.10 hereof, withhold and set off against any and all amounts due to any other Party any and all amounts as to which the other Party is obligated to indemnify such Party pursuant to any provision of this Article XV. 15.3 Payment. With respect to Third Party Claims for which indemnification is payable hereunder, the indemnifying Person will pay the indemnified Person promptly after the earlier of (a) the entry of judgment against the indemnified Person and the expiration of any applicable appeal period, (b) the entry of a non-appealable judgment or final appellate decision against the indemnified person, or (c) the execution of any settlement agreement referred to in Section 15.1. Notwithstanding the foregoing, expenses of the indemnified Person for which the indemnifying Person is responsible (including reasonable fees and disbursements of counsel) shall be reimbursed on a current basis by the indemnifying Person. 15.4 Right to Indemnification Not Affected by Knowledge or Presumption. (a) Except as otherwise specifically provided herein, the right to indemnification based upon breach of representations, warranties, covenants, agreements or obligations will not be affected by any investigation conducted with respect to, or knowledge acquired (or capable of being acquired) at any time, whether before or after the execution and delivery of this Agreement or the Effective Date, whether as a result of disclosure by a Party hereto pursuant to Section 11.1 or otherwise, with respect to the accuracy or inaccuracy of or compliance with any such representation, warranty, covenant, agreement or obligation. (b) The satisfaction of any condition based on the presumed accuracy of any representation or warranty, or on the presumed performance of or compliance with any covenant, agreement or obligation, will not affect the right to indemnification, payment of Damages or other remedy based on such representations, warranties, covenants, agreements and obligations. ARTICLE XVI. TERM; EVENTS OF DEFAULT AND TERMINATION 16.1 Term. The term of this Agreement shall commence on the date hereof and, subject to the other provisions of this Agreement, the Liquidation Date shall occur on (a) November 30, 2006, and (b) on each February 28 (or February 29, in the event of a leap year), May 31, August 31 and November 30 thereafter (each three (3) Month period ending on each such date, a "Renewal Period"), unless, in each case, this Agreement is renewed or otherwise stays in effect in accordance with Section 16.2 below. This Agreement shall terminate immediately upon completion of Liquidation (the "Termination Date"). 16.2 Renewal. (a) (i) If any Party wishes to renew this Agreement so that it shall continue after the end of the Initial Term through the end of the Renewal Period commencing on December 1, 2006, Calpine or any Calpine Transaction Party, on the 60 one hand, or Bear Stearns or CalBear, on the other hand, shall deliver a notice setting forth the intention of such Party and its Affiliates that are Parties to renew this Agreement (the "Renewal Notice") through the Renewal Period ending February 28, 2007, which Renewal Notice shall be delivered on or before August 31, 2006. (ii) If this Agreement has been renewed so that it continues after the end of the Initial Term, and if any Party wishes to renew this Agreement so that it shall continue after the end of the latest Renewal Period for which this Agreement has previously been renewed (the "Latest Renewal Period"), then Calpine or any Calpine Transaction Party, on the one hand, or Bear Stearns or CalBear, on the other hand, shall deliver a Renewal Notice setting forth the intention of such Party and its Affiliates that are Parties to renew this Agreement through the end of the Renewal Period immediately following the Latest Renewal Period, which notice shall be given on or before the day immediately preceding the first day of the Latest Renewal Period. (iii) A Renewal Notice may set forth the intention of Calpine or any Calpine Transaction Party, on the one hand, or Bear Stearns or CalBear, on the other hand, to renew this Agreement for any number of Renewal Periods following the end of the Initial Term or the end of the Latest Renewal Period, as applicable (and, in such case, such Renewal Notice shall serve as the Renewal Notice for each such Renewal Period, unless such Renewal Notice is withdrawn with respect to any Renewal Period (and all subsequent Renewal Periods contained in such Renewal Notice, if any) on or prior to the date such Renewal Notice would otherwise be due for such Renewal Period, except as set forth in Section 16.3(a) below), as determined by the Party delivering such notice in its sole discretion. A form of Renewal Notice is attached hereto as Exhibit F. Each Renewal Notice shall be delivered in any manner provided in Section 18.2. (b) If both Calpine or any Calpine Transaction Party, on the one hand, and Bear Stearns or CalBear, on the other hand, deliver a Renewal Notice with respect to an Applicable Renewal Period as specified in Section 16.2(a), this Agreement shall continue in full force and effect at least until the end of such Applicable Renewal Period, unless otherwise terminated pursuant to the terms hereof. (c) If none of Calpine, any Calpine Transaction Party, Bear Stearns or CalBear delivers a Renewal Notice with respect to an Applicable Renewal Period as specified in Section 16.2(a), the Liquidation Date shall occur at the end of the Initial Term or the end of the Renewal Period immediately preceding such Applicable Renewal Period, as applicable, in accordance with Section 16.6(b)(i). (d) If either Calpine or any Calpine Transaction Party, on the one hand, or Bear Stearns or CalBear, on the other hand, delivers a Renewal Notice with respect to an Applicable Renewal Period as specified in Section 16.2(a) (such Party, together with its Affiliates, the "Renewing Parties") but neither of Bear Stearns nor CalBear, on the one hand, or none of Calpine or the Calpine Transaction Parties, on the other hand, respectively, delivers a Renewal Notice with respect to such Applicable Renewal Period (such Parties, together with their Affiliates, the "Non-Renewing Parties"), the Liquidation Date shall occur 61 at the end of the Initial Term or the end of the Renewal Period immediately preceding such Applicable Renewal Period, as applicable, in accordance with Section 16.6(b)(ii). 16.3 Certain Matters with Respect to Renewal. (a) Notwithstanding anything herein to the contrary, if a Bankruptcy Event has occurred with respect to any Party, neither such Party nor any of its Affiliates that are Parties shall have a right to send any Renewal Notice with respect to any Applicable Renewal Period, unless such Party and all of its Affiliates that are Parties have (i) "assumed", within the meaning of the Bankruptcy Law, this Agreement and the other Transaction Documents prior to such time and (ii) complied with all of their obligations hereunder and under the other Transaction Documents prior to such time. (b) Notwithstanding anything herein to the contrary, in no event shall delivery of a Renewal Notice or a renewal of this Agreement in accordance with Section 16.2 result in, or be deemed to, or cause, the waiver of any rights of the Renewing Parties under this Agreement, the Transaction Documents, or otherwise. 16.4 Calpine Events of Default. The occurrence of any one or more of the following events shall constitute a Calpine Event of Default ("Calpine Event of Default") under this Agreement and the other Transaction Documents: (a) the failure by any Calpine Transaction Party to make any Payment required under this Agreement or any of the other Transaction Documents which failure continues unremedied (i) if notice of such failure was given in accordance with the applicable notice provisions by Bear Stearns or CalBear to Calpine or any such Calpine Transaction Party prior to 4:30 p.m. New York City time on a Business Day, at the end of the Business Day following the day such notice was given, or (ii) if notice of such default was given by Bear Stearns or CalBear after 4:30 p.m. New York City time on any Business Day, or on any day that is not a Business Day, at the end of the second (2nd) Business Day following the day such notice was given; (b) the failure by Calpine or any Calpine Transaction Party to perform any covenant or agreement of Calpine or such Calpine Transaction Party, respectively, set forth in this Agreement or any other Transaction Document (other than as described in Sections 16.4(a), 16.4(c) and 16.4(d)), which failure constitutes a material breach of this Agreement or such other Transaction Document or would have a Material Adverse Effect on the Transaction, and which failure is not cured within (i) any applicable cure period with respect to such failure set forth in this Agreement or any other Transaction Document, if any, or, (ii) in the event that there is no such applicable cure period with respect to such failure, ten (10) Business Days after notice thereof is given to Calpine or such Calpine Transaction Party, respectively, by Bear Stearns or CalBear in accordance with Section 18.2; (c) a Bankruptcy Event shall have occurred with respect to Calpine, a Calpine Transaction Party or a Significant Subsidiary of Calpine; or 62 (d) any representation or warranty of Calpine or any Calpine Transaction Party hereunder proves to have been incorrect in any material respect as of the date such representation or warranty was made; provided that a Calpine Event of Default shall not arise under this Section 16.4(d) following the expiration of the survival period with respect to such representation or warranty set forth in Section 14.1. 16.5 Bear Stearns Events of Default. The occurrence of any one or more of the following events shall constitute a Bear Stearns Event of Default ("Bear Stearns Event of Default") under this Agreement and the other Transaction Documents: (a) the failure by CalBear to make any Payment required under this Agreement or any of the other Transaction Documents which failure continues unremedied (i) if notice of such failure was given in accordance with the applicable notice provisions by Calpine or a Calpine Transaction Party to Bear Stearns or CalBear prior to 4:30 p.m. New York City time on a Business Day, at the end of the Business Day following the day such notice was given, or (ii) if notice of such default was given by Calpine or a Calpine Transaction Party after 4:30 p.m. New York City time on any Business Day, or on any day that is not a Business Day, at the end of the second (2nd) Business Day following the day such notice was given; (b) the failure by Bear Stearns or CalBear to perform any covenant or agreement of Bear Stearns or CalBear, respectively, set forth in this Agreement or any other Transaction Document (other than as described in Sections 16.5(a), 16.5(c) and 16.5(d)), which failure constitutes a material breach of this Agreement or such other Transaction Document or would have a Material Adverse Effect on the Transaction, and which failure is not cured within (i) any applicable cure period with respect to such failure set forth in this Agreement or any other Transaction Document, if any, or (ii) in the event that there is no such applicable cure period with respect to such failure, ten (10) Business Days after notice thereof is given to Bear Stearns or CalBear, respectively, by Calpine or a Calpine Transaction Party in accordance with Section 18.2; (c) a Bankruptcy Event shall have occurred with respect to Bear Stearns, CalBear or a Significant Subsidiary of Bear Stearns; or (d) any representation or warranty of Bear Stearns or CalBear hereunder proves to have been incorrect in any material respect as of the date such representation or warranty was made; provided that a Bear Stearns Event of Default shall not arise under this Section 16.5(d) following the expiration of the survival period with respect to such representation or warranty set forth in Section 14.1. 16.6 Termination; Liquidation Date; Transfer of Final Third Party Master Agreements. (a) Termination Prior to the Effective Date. This Agreement may be terminated, and the transactions contemplated hereby abandoned, prior to the Effective Date as follows: 63 (i) by mutual consent of the Parties at any time; (ii) by Bear Stearns or CalBear, on the one hand, or Calpine or the Calpine Transaction Parties, on the other hand, upon notice, if the Effective Date shall not have occurred on or before December 31, 2005, except that neither Bear Stearns or CalBear, on the one hand, nor Calpine or the Calpine Transaction Parties, on the other hand, may terminate this Agreement if the failure of the Effective Date to occur is due to the failure of any such Party or its Affiliates to perform in all material respects each of its obligations required to be performed under this Agreement at or prior to the Effective Date; (iii) by Bear Stearns or CalBear, upon notice to Calpine or the Calpine Transaction Parties, if an event or events shall occur which render compliance with one or more of the conditions set forth in Article XIII impossible and such condition (or conditions) is not waived by Bear Stearns or CalBear; provided that neither Bear Stearns nor CalBear is in breach in any material respect of its representations, warranties, covenants or agreements contained in this Agreement; or (iv) by Calpine or the Calpine Transaction Parties, upon notice to Bear Stearns or CalBear, if an event or events shall occur which render compliance with one or more of the conditions set forth in Article XII impossible, and such condition (or conditions) is not waived by Calpine or the Calpine Transaction Parties, provided that none of Calpine or the Calpine Transaction Parties is in breach in any material respect of its representations, warranties, covenants or agreements contained in this Agreement. (b) Liquidation Date and Termination Following the Effective Date. Following the occurrence of the Effective Date, and, subject to the other provisions of this Agreement, this Agreement and the other Transaction Documents shall be automatically terminated, without any further action by any Party, and the transactions contemplated hereby and thereby abandoned, immediately upon completion of Liquidation. The Liquidation Date shall occur and the Liquidation shall commence: (i) as determined by mutual consent of the Parties at any time (provided that if none of the Parties delivers a Renewal Notice in accordance with Section 16.2(a) of this Agreement, the Parties shall be deemed to have mutually consented to a Liquidation Date immediately following the end of the Initial Term or the applicable Renewal Period, as applicable); (ii) in accordance with Section 16.2(d) of this Agreement, automatically upon the end of the Initial Term or the applicable Renewal Period, as applicable, if only Bear Stearns or CalBear, on the one hand, or Calpine or any Calpine Transaction Party, on the other hand, but not both, delivers a Renewal Notice with respect to the end of the Initial Term or such Renewal Period, as applicable; (iii) following the end of the Initial Term, ninety (90) days after the delivery of a Termination Notice by any Party (or, in the event of a delivery of a Termination Notice by Calpine following a breach of Section 3.14(b) by Bear Stearns, on the one hand, or by Bear Stearns following a breach 64 of Section 3.14(a) by Calpine, on the other hand, fifty (50) days after delivery of such Termination Notice); provided that a Termination Notice may not be delivered by any Party if the Liquidation Date has occurred or will occur as a result of non-renewal of this Agreement or an Event of Default, or otherwise in accordance with this Section 16.6(b) (and, for the avoidance of doubt, if a Liquidation Date occurs before the end of the ninety (90) day period following the delivery of a Termination Notice in accordance with this Section 16.6(b), Liquidation shall commence and this Agreement shall terminate in accordance with such Liquidation Date and the applicable Termination Notice shall be of no further force and effect); provided, further, that, in the event of a breach of Section 3.1 or Section 3.14 by Calpine or a Calpine Transaction Party, on the one hand, or Bear Stearns or CalBear, on the other hand, Bear Stearns or CalBear, on the one hand, or Calpine or any Calpine Transaction Party, on the other hand, may deliver a Termination Notice pursuant to this Section 16.6(b)(iii) at any time following the Effective Date; and provided, further, that if Calpine or any Calpine Transaction Party, on the one hand, and Bear Stearns and CalBear, on the other hand, deliver Termination Notices to each other nearly simultaneously (and in such a manner that it is reasonably unlikely that either Termination Notice was sent following receipt of the other Termination Notice), the Liquidation Date shall occur ninety (90) days after the delivery of such Termination Notices pursuant to Section 16.6(b)(i) and the Parties shall be deemed to have mutually consented to the occurrence of such Liquidation Date; (iv) upon a Calpine Event of Default, if so elected by Bear Stearns or CalBear; (v) upon a Bear Stearns Event of Default, if so elected by Calpine or a Calpine Transaction Party; (vi) automatically, following a termination of any Transaction Document (other than this Agreement) by Calpine or a Calpine Transaction Party in accordance with the terms thereof, unless otherwise agreed by Calpine or a Calpine Transaction Party prior to such time; (vii) automatically, following a termination of any Transaction Document (other than this Agreement) by Bear Stearns or CalBear in accordance with the terms thereof, unless otherwise agreed by Bear Stearns or CalBear prior to such time; (viii) following a downgrade of the credit rating assigned to Bear Stearns by (i) Standard & Poors Ratings Group below BBB+ or (ii) Moody's Investor Services below Baa1, if terminated in writing by Calpine or a Calpine Transaction Party; or (ix) by Bear Stearns or CalBear, following the end of the Initial Term, ninety (90) days after the delivery of a Termination Notice, if the Trading Volume for a calendar year during the term of this Agreement is less than [*]MWh. (c) Conduct Of Business Following Liquidation Date; Termination; Survival Following Termination. 65 (i) Conduct of Business Following Liquidation Date and Termination. Immediately following the occurrence of a Liquidation Date, (1) the Liquidation shall commence and (2) pending completion of the Liquidation and subject to Section 7.1(b) of the Agency and Services Agreement, the Parties shall continue to have the benefit of, and be bound by, their applicable rights and obligations under the Transaction Documents. Following the Termination Date, (i) Bear Stearns and CalBear shall, or shall cause their Affiliates to, change the name of CalBear to another name not including the phrase "CalBear" and (ii) the Parties shall not, and shall cause their Affiliates not to, transact business under the name "CalBear Energy LP", "CalBear", or any other name containing the word "CalBear" (the "CalBear Name"). Without limitation of the foregoing, as soon as practicable following the Termination Date, but not later than ninety (90) days after such date, the Parties shall, and shall cause their respective Affiliates to, remove and change signage, change and substitute promotional or advertising material in whatever medium, change stationery and packaging and take all such other steps as may be required or appropriate to cease use of the CalBear Name; provided, however, that no Party shall be deemed to have violated this Section 16.6(c)(i) by reason of (i) the appearance of the CalBear Name in or on any equipment, manuals, work sheets, risk policies, operating procedures, other written materials or other Assets of such Party or its Affiliates that are used for internal purposes only in connection with the Transaction or CalBear's business; provided that the such Party and its Affiliates shall endeavor to remove such appearances of the CalBear Name as soon as reasonably practicable in the ordinary course of business, (ii) the appearance of the CalBear Name in or on any Third Party's publications, marketing materials, brochures, instruction sheets, equipment or products that any Party or its Affiliates distributed in the ordinary course of business or in connection with the Transaction or CalBear's business prior to the Termination Date, and that generally are in the public domain, or any other similar uses by any such Third Party over which such Party has no control, or (iii) the use by any Party or its Affiliates of the CalBear Name for purposes of conveying to customers or the general public that the name of CalBear has changed or the change in ownership or historical origins or historical business of CalBear, including the use by any Party or its Affiliates of the CalBear Name in (A) any legally required disclosure, (B) response to any disclosure request made by any Governmental Authority, (C) connection with the defense or prosecution of any Action, (D) connection with any reporting requirements of such Party or its Affiliates under any Applicable Law, and (E) any financial statements, schedules or information. (ii) Survival of Certain Obligations Following Termination. Following the Termination Date, all rights and obligations of the Parties under this Agreement shall terminate, except for (i) rights and obligations accrued prior to the Termination Date, including rights and obligations with respect to a breach or violation of or default under any provision of this Agreement that occurred prior to the Termination Date (unless the survival period for such right or obligation has otherwise expired pursuant to Section 14.1), (ii) rights and obligations under Articles IV, Article V, Article XV and Article XVII and Sections 3.2, 3.5, 3.7, 3.8, 3.9, 3.10, 3.11, 3.16, 7.2, 7.4(a), 7.4(b), 14.1, 14.8, this Section 16.6(c), Section 16.6(d) and Sections 18.1 through 18.4 and 18.6 through 18.20, (iii) rights and obligations under other provisions of this Agreement to the extent the same expressly survive termination of this Agreement, and (iv) rights and obligations under provisions of this Agreement necessary for the operation of effective provisions of the other Transaction Documents that reference such provisions in this Agreement. 66 (d) Transfer of Final Third Party Master Agreements Following Termination Date. (i) Transfer of Final Third Party Master Agreements Following Non-Renewal. In the event that the Liquidation Date occurs pursuant to 16.6(b)(ii) and Calpine and the Calpine Transaction Parties are the Renewing Parties, subject to clause (iv) below, the Renewing Parties shall have the right (but not the obligation), exercisable within two (2) Business Days following the date that the applicable Renewal Notice was due from CalBear, to acquire, or cause any of their respective Affiliates to acquire, for a purchase price of [*], the Third Party Master Agreements to which CalBear is a party at such time (collectively, the "Final Third Party Master Agreements"), in accordance with Section 16.6(d)(v) (including the last sentence thereof), following completion of Liquidation (the "Non-Renewal Purchase Right"). Calpine or any of the Calpine Transaction Parties may exercise the Non-Renewal Purchase Right by delivering a notice (the "Non-Renewal Purchase Notice") to Bear Stearns or CalBear within such two (2) Business Day period, in any applicable manner provided in Section 18.2, setting forth Calpine's or such Calpine Transaction Party's election to exercise its Non-Renewal Purchase Right. For the avoidance of doubt, in the event that the Liquidation Date occurs pursuant to Section 16.6(b)(ii) after the Non-Renewing Parties fail to deliver a Renewal Notice and if Bear Stearns and CalBear are the Renewing Parties, Bear Stearns and CalBear shall retain the Final Third Party Master Agreements following completion of Liquidation and Calpine and the Calpine Transaction Parties shall not have any right to purchase, or any other right with respect to, the Final Third Party Master Agreements. (ii) Transfer of Final Third Party Master Agreements Following Elective Termination. In the event that the Liquidation Date occurs pursuant to Section 16.6(b)(iii) or Section 16.6(b)(ix), following delivery of the Termination Notice by an Elective Terminating Party, subject to clause (iv) below, the Elective Non-Terminating Parties shall have the right and the obligation (the "CalBear Termination Option"), exercisable within two (2) Business Days following such delivery of a Termination Notice, to (A) if the Elective Non-Terminating Parties are Calpine and the Calpine Transaction Parties, either (1) elect to acquire the Final Third Party Master Agreements, in accordance with Section 16.6(d)(v) (including the last sentence thereof), for the amount set forth in the applicable Termination Notice (the "Termination Amount") or (2) elect to receive a termination fee in an amount equal to the Termination Amount from CalBear (the "Termination Fee"), or (B) if the Elective Non-Terminating Parties are Bear Stearns and CalBear, to either (1) sell the Final Third Party Master Agreements, in accordance with Section 16.6(d)(v) (including the last sentence thereof), to the Elective Terminating Parties for the Termination Amount or (2) elect to pay the Termination Fee to Elective Terminating Parties (either of clause (A)(1) or (B)(2), a "Termination Purchase Right" and either of clause (A)(2) or (B)(1), a "Termination Sale Right"), in each case following completion of Liquidation. Any Elective Non-Terminating Party shall exercise the CalBear Termination Option by delivering a notice, in any manner provided in Section 18.2, setting forth such Elective Non-Terminating Party's election to exercise either its Termination Purchase Right or its Termination Sale Right within the applicable two (2) Business Day period. (iii) Transfer of Final Third Party Master Agreements Following Event of Default or Termination. In the event that the Liquidation Date occurs pursuant to Section 16.6(b)(iv) through (viii), subject to clause (iv) below, 67 the Defaulting Termination Parties shall deliver to the Non-Defaulting Termination Parties, within two (2) Business Days following the occurrence of the Liquidation Date and in any manner provided in Section 18.2, an irrevocable notice (the "Default Termination Notice") setting forth (A) a Termination Amount and (B) a binding offer, irrevocable by its terms for two (2) Business Days following receipt of the Default Termination Notice by the Non-Defaulting Termination Parties (the "CalBear Default Option"), (1) if the Defaulting Termination Parties are Calpine and the Calpine Transaction Parties, to either (x) purchase the Final Third Party Master Agreements, in accordance with Section 16.6(d)(v) (including the last sentence thereof), from Bear Stearns and CalBear for the Termination Amount or (y) receive from Bear Stearns and CalBear the Termination Fee, or (2) if the Defaulting Termination Parties are Bear Stearns and CalBear, to either (x) sell the Final Third Party Master Agreements, in accordance with Section 16.6(d)(v) (including the last sentence thereof), to Calpine and the Calpine Transaction Parties for the Termination Amount or (y) pay to Calpine and the Calpine Transaction Parties the Termination Fee (either of clause (1)(x) or (2)(y), a "Default Purchase Right" and either of clause (1)(y) or (2)(x), a "Default Sale Right"), in each case following completion of Liquidation. Any of the Non-Defaulting Termination Parties shall exercise the CalBear Default Option by delivering a notice, in the manner provided in Section 18.2, setting forth such Non-Defaulting Termination Party's election to exercise either its Default Purchase Right or its Default Sale Right within such two (2) Business Day period. If the Defaulting Termination Parties are Calpine and the Calpine Transaction Parties and the Defaulting Termination Parties fail to (A) deliver the Default Termination Notice or (B) comply with their obligation to purchase Final Third Party Master Agreements following exercise of the Default Sale Right by the Non-Defaulting Termination Parties, CalBear shall retain the Final Third Party Master Agreements following completion of Liquidation and Calpine and the Calpine Transaction Parties shall not have any right to purchase, or any other right with respect to, the Final Third Party Master Agreements. If the Defaulting Termination Parties are Bear Stearns and CalBear and the Defaulting Termination Parties fail to (A) deliver the Default Termination Notice, (B) comply with their obligation to sell Final Third Party Master Agreements following exercise of the Default Purchase Right by the Non-Defaulting Termination Parties, or (C) comply with their obligation to pay the Termination Fee following exercise of the Default Sale Right by the Non-Defaulting Termination Parties, Calpine and the Calpine Transaction Parties shall have the right (but not the obligation), exercisable within ten (10) days following such failure to comply, to purchase for [*], the Final Third Party Master Agreements, in accordance with Section 16.6(d)(v) (including the last sentence thereof), following the completion of Liquidation. (iv) Payment of Termination Amount. Promptly following exercise of the Termination Purchase Right, the Termination Sale Right, the Default Purchase Right or the Default Sale Right, as applicable, the Parties responsible for payment of the Termination Amount with respect to such exercise shall pay the Termination Amount in cash by wire transfer of immediately available funds to an account designated by (A) Calpine or a Calpine Transaction Party, in the case of a payment of the Termination Amount by Bear Stearns or CalBear, or (B) Bear Stearns or CalBear, in the case of a payment of the Termination Amount by Calpine or a Calpine Transaction Party. 68 (v) Obligation to Transfer Final Third Party Master Agreements. The Parties shall cooperate with each other and take any actions reasonably necessary to cause the consummation of the Non-Renewal Purchase Right and, in the event that the Termination Purchase Right, the Termination Sale Right, the Default Purchase Right or the Default Sale Right requires a transfer of the Final Third Party Master Agreements, the consummation of the Termination Purchase Right, the Termination Sale Right, the Default Purchase Right or the Default Sale Right, as applicable, including by cooperating in obtaining any applicable Regulatory Approvals and any Third Party consents or releases. Notwithstanding anything to the contrary contained in this Section 16.6(d), CalBear shall not be required to transfer any Third Party Master Agreement pursuant to this Section 16.6(d) (A) if and until Calpine or a Calpine Transaction Party has paid the Termination Amount in accordance with Section 16.6(d)(iv) or (B) if such Third Party Master Agreement (1) requires consent to transfer from a Third Party and such consent has not been received by Bear Stearns within one hundred eight (180) days following the exercise by Calpine or any of the Calpine Transaction Parties of their right to purchase, or the exercise by Bear Stearns or CalBear of their right to sell, as applicable, the Final Third Party Master Agreements pursuant to this Section 16.6(d) or (2) does not provide for the unconditional release of Bear Stearns and its Affiliates from any obligation to guarantee or otherwise provide credit support for any transaction under such Third Party Master Agreement, unless such unconditional release of such obligation is received by Bear Stearns within one hundred eight (180) days following the exercise by Calpine or any of the Calpine Transaction Parties of their right to purchase, or the exercise by Bear Stearns or CalBear of their right to sell, as applicable, the Final Third Party Master Agreements pursuant to this Section 16.6(d). If CalBear is not required to transfer any Third Party Master Agreement as a result of clause (B) in the immediately preceding sentence, (x) each of Bear Stearns and CalBear shall not, and Bear Stearns shall cause its Affiliates not to, following the Termination Date, transact any business pursuant to such Third Party Master Agreement, (y) CalBear shall, following the expiration of any applicable consent and/or release period set forth in the immediately preceding sentence, reasonably promptly terminate such Third Party Master Agreement in accordance with the terms thereof (provided that CalBear shall not be required to terminate any such Third Party Master Agreement in a manner that results in Damages owed by CalBear to a Third Party under such Third Party Master Agreement), and (z) CalBear shall deliver written evidence of such termination to Calpine. (vi) Closing of Transfer of Final Third Party Master Agreements. The purchase and sale of the Final Third Party Master Agreements, if any, in accordance with this Section 16.6(d) pursuant to any exercised Non-Renewal Purchase Right, Termination Purchase Right, Termination Sale Right, Default Purchase Right or Default Sale Right, as applicable, shall take place as soon as reasonably practicable, but in any event following the completion of Liquidation and the receipt of any applicable Regulatory Approvals and Third Party consents and releases. ARTICLE XVII. LIMITATION OF LIABILITY 17.1 Limitation of Remedies. 69 NOTWITHSTANDING ANY PROVISION OF THE TRANSACTION DOCUMENTS TO THE CONTRARY, THE RIGHTS, REMEDIES, CLAIMS AND DAMAGES OF CALPINE, THE CALPINE TRANSACTION PARTIES AND THE OTHER CALPINE PARTIES, AND BEAR STEARNS, CALBEAR AND THE OTHER BEAR STEARNS PARTIES (COLLECTIVELY, FOR THE PURPOSES OF THIS ARTICLE XVII, THE "REMEDIAL PARTIES"), IN CONNECTION WITH, ARISING OUT OF, RESULTING FROM OR RELATING OR INCIDENT TO, WHETHER DIRECTLY OR INDIRECTLY, THE TRANSACTION DOCUMENTS, PERFORMANCE OR NONPERFORMANCE UNDER THE TRANSACTION DOCUMENTS, ANY CALPINE EVENT OF DEFAULT OR BEAR STEARNS EVENT OF DEFAULT, ANY MATTER DESCRIBED IN SECTION 15.1, OR ANY OTHER RIGHT OR DUTY RELATED TO ANY OF THE FOREGOING, WHETHER ARISING UNDER CONTACT, TORT, COMMON LAW, STATUTE OR AT LAW OR IN EQUITY, OR RELATED TO ANY FAULT, NEGLIGENCE, GROSS NEGLIGENCE, STRICT LIABILITY, FRAUD OR MISCONDUCT, SHALL BE LIMITED TO THE EXTENT SET FORTH IN THIS ARTICLE XVII (IN ADDITION TO ANY OTHER APPLICABLE LIMITATIONS IN THE TRANSACTION DOCUMENTS). 17.2 Limitation of Monetary Damages. (A) THE INDEMNIFICATION RIGHTS PROVIDED TO THE REMEDIAL PARTIES PURSUANT TO ARTICLE XV OF THIS AGREEMENT AND SECTION 6.3 OF THE TRADING MASTER AGREEMENT, (B) ANY LIQUIDATED DAMAGES EXPRESSLY PROVIDED FOR IN THE TRANSACTION DOCUMENTS, AND (C) ANY OTHER EXPRESS RIGHTS TO RECEIVE PAYMENT OR INTEREST IN THE TRANSACTION DOCUMENTS; SHALL BE THE SOLE AND EXCLUSIVE MONETARY REMEDIES OF THE REMEDIAL PARTIES, IN LIEU OF ANY OTHER RIGHT TO MONETARY DAMAGES. 17.3 Limitation of Non-Monetary Damages. IN THE EVENT THAT MONETARY REMEDIES FOR ANY APPLICABLE BREACH, VIOLATION OR DAMAGE ARE NOT PROVIDED FOR IN SECTION 17.2, THE SOLE AND EXCLUSIVE REMEDIES OF THE REMEDIAL PARTIES SHALL BE (A) TERMINATION OF THIS AGREEMENT AND THE TRANSACTION DOCUMENTS PURSUANT TO THE APPLICABLE PROVISIONS OF SECTION 16.6 OF THIS AGREEMENT OR (B) EQUITABLE REMEDIES TO THE EXTENT AVAILABLE TO THE APPLICABLE REMEDIAL PARTY UNDER THE CIRCUMSTANCES UNDER SECTION 18.15. 17.4 Limitation of Consequential Damages, Etc. EXCEPT WITH RESPECT TO THIRD PARTY CLAIMS IN SECTION 15.1(a)(ii) AND SECTION 15.1(b)(ii) OF THIS AGREEMENT AND THE LAST SENTENCE OF SECTION 6.3 OF THE TRADING MASTER AGREEMENT, NONE OF THE REMEDIAL PARTIES SHALL BE LIABLE FOR OR ENTITLED TO ANY CONSEQUENTIAL, INDIRECT, SPECIAL, PUNITIVE, EXEMPLARY OR INCIDENTAL DAMAGES. 70 17.5 Liability for Acts or Omissions of Other Persons. BEAR STEARNS OR CALBEAR SHALL NOT BE DEEMED TO HAVE VIOLATED OR BE IN BREACH OF ANY REPRESENTATION, WARRANTY, COVENANT OR AGREEMENT CONTAINED IN THIS AGREEMENT OR IN ANY OF THE OTHER TRANSACTION DOCUMENTS TO THE EXTENT SUCH VIOLATION OR BREACH RESULTS FROM OR ARISES OUT OF ANY ACT OF CALPINE OR ANY CALPINE TRANSACTION PARTY OR OMISSION BY CALPINE OR ANY CALPINE TRANSACTION PARTY, IN EACH CASE CONSTITUTING A VIOLATION OR BREACH OF THE TRANSACTION DOCUMENTS. CALPINE OR ANY CALPINE TRANSACTION PARTY SHALL NOT BE DEEMED TO HAVE VIOLATED OR BE IN BREACH OF ANY REPRESENTATION, WARRANTY, COVENANT OR AGREEMENT CONTAINED IN THIS AGREEMENT OR IN ANY OF THE OTHER TRANSACTION DOCUMENTS IF SUCH VIOLATION OR BREACH RESULTS FROM OR ARISES OUT OF ANY ACT OF BEAR STEARNS OR CALBEAR OR OMISSION BY BEAR STEARNS OR CALBEAR, IN EACH CASE CONSTITUTING A VIOLATION OR BREACH OF THE TRANSACTION DOCUMENTS. 17.6 Survival of Limitations. THE LIMITATIONS, RELEASES, WAIVERS AND DISCLAIMERS OF REMEDIES AND LIABILITIES EXPRESSED IN THIS AGREEMENT SHALL SURVIVE TERMINATION OR EXPIRATION OF THE TRANSACTION DOCUMENTS. ARTICLE XVIII. MISCELLANEOUS 8.1 Assignment. Except as provided in Section 3.3 or Section 3.4, as applicable, neither this Agreement nor any of the rights or obligations hereunder may be assigned by Calpine or any Calpine Transaction Party without the prior consent of Bear Stearns and CalBear, or by Bear Stearns or CalBear without the prior consent of Calpine and each Calpine Transaction Party; provided that in the event of an assignment by a Party of this Agreement and all of its rights and obligations hereunder to an Affiliate of such Party, such consent shall not be unreasonably withheld. Except as provided in Section 3.3 or Section 3.4, as applicable, none of the Transaction Documents other than this Agreement, nor any of the rights or obligations thereunder, may be assigned by any Calpine Transaction Party without the prior consent of Bear Stearns, or by CalBear without the prior consent of Calpine; provided that in the event of an assignment by a Transaction Party of a Transaction Document other than this Agreement and all of its rights and obligations thereunder to an Affiliate of such Party, such consent shall not be unreasonably withheld. This Agreement shall be binding upon and inure to the benefit of the Parties hereto and their respective successors and assigns, and no other Person shall have any right, benefit or obligation hereunder, except as specifically set forth in Section 18.18 hereof. 18.2 Notices. 71 All notices, consents, waivers, requests, demands and other communications which are required or may be given under this Agreement and: (a) concern (i) modifications of this Agreement, including pursuant to Section 18.8, or (ii) Article XV, Article XVI (other than Section 16.4(a) and Section 16.5(a)), or Section 18.4, shall be in writing and shall be deemed to have been duly given in writing when received if personally delivered, or, if sent to the mailing address set forth below with respect to notices delivered pursuant to this Section 18.2(a) for any Party, the Business Day after it is sent, if sent for next day delivery to a domestic address by recognized overnight delivery service (e.g., Federal Express); (b) concern Payments (other than communications that are given pursuant to Section 18.2(a) and also concern Payments), including Section 16.4(a) or Section 16.5(a), shall be in writing and shall be deemed to have been duly given in writing when transmitted if transmitted (A) to CalBear by telecopy to the notice address set forth below for Bear Stearns or CalBear with respect to notices delivered pursuant to this Section 18.2(b) or (B) to CMSC by electronic mail (including in portable document format by electronic mail) to the notice address set forth below for Calpine or a Calpine Transaction Party with respect to notices delivered pursuant to this Section 18.2(b); and (c) concern any matter not specifically addressed in Section 18.2(a) or Section 18.2(b) shall be in writing and shall be deemed to have been duly given in writing when received if personally delivered, or, if sent to the notice address set forth below with respect to notices delivered pursuant to this Section 18.2(c) for any Party, when transmitted if transmitted by electronic mail (including in portable document format by electronic mail); provided, that, in the case of Section 18.2(b) and Section 18.2(c), if any such communication is transmitted by telecopy or electronic mail, as applicable, after 4:30 p.m. New York City time on any day, or at any time on a day that is not a Business Day, such communication shall be deemed to have been transmitted at 9:00 a.m. New York City time on the following Business Day; and provided, further, that, in the case of Section 18.2(b), if the sender of the electronic mails with respect to such communication receives an "out-of-office" or similar notice with respect thereto from each addressee thereof, such communication shall nonetheless be deemed to be duly given in writing; and provided, further, that, in the case of Section 18.2(b) (except as provided in the immediately preceding proviso) and Section 18.2(c), if all telecopies or electronic mails with respect to such communication are returned to the sender as undeliverable or the sender receives an "out-of-office" or similar notice with respect thereto, such transmission shall not be deemed to be duly given in writing until (i) delivered to an alternate recipient in compliance with the provisions of Section 18.2(b) or Section 18.2(c), as applicable, or (ii) received if personally delivered, or, if sent to the applicable mailing address set forth below with respect to notices delivered pursuant Section 18.2(b) or Section 18.2(c), as applicable, for any Party, the Business Day after it is sent, if sent for next day delivery to a domestic address by recognized overnight delivery service (e.g., Federal Express). Communications to Calpine or a Calpine Transaction Party pursuant to Section 18.2(a) shall be addressed to: 72 Calpine Corporation 717 Texas Avenue Houston, TX 77002 Tel: (713) 830-8649 Fax: (713) 570-4725 Attention: Andrew Slocum E-mail: [email protected] In each case, with a copy to: Calpine Corporation 50 West San Fernando Street San Jose, CA 95113 Tel: (408) 792-1226 Fax: (408) 794-2434 Attention: Lisa Bodensteiner, Executive Vice President and General Counsel E-mail: [email protected] and with a copy to: -------------------------------------------------------------------------------Paul Posoli Rodney Malcolm Executive Vice President Senior Vice President Calpine Corporation Calpine Corporation 717 Texas Avenue 717 Texas Avenue Houston, TX 77002 Houston, TX 77002 Tel: (713) 830-8663 Tel: (713) 570-4816 Fax: (713) 570-4725 Fax: (713) 570-4725 E-mail: [email protected] E-mail: [email protected] -------------------------------------------------------------------------------- Communications to Calpine or a Calpine Transaction Party pursuant to Section 18.2(b) shall be addressed to: 73 -------------------------------------------------------------------------------Andrew Slocum Janet Dixon Vice President Risk Operations Calpine Merchant Services Company, Inc. Calpine Merchant Services Company, Inc. 717 Texas Avenue 717 Texas Avenue Houston, TX 77002 Houston, TX 77002 Tel: (713) 830-8835 Tel: (713) 830-8649 Fax: (713) 570-4725 Fax: (713) 570-4725 E-mail: [email protected] E-mail: [email protected] -------------------------------------------------------------------------------Randy Kruger Josh Pesikoff Calpine Merchant Services Company, Inc. Calpine Merchant Services Company, Inc. 717 Texas Avenue 717 Texas Avenue Houston, TX 77002 Houston, TX 77002 Tel: (713) 570-4811 Tel: (713) 570-4782 Fax: (713) 570-4725 Fax: (713) 570-4725 E-mail: [email protected] E-mail: [email protected] -------------------------------------------------------------------------------- Communications to Calpine or a Calpine Transaction Party pursuant to Section 18.2(c) shall be addressed to: -------------------------------------------------------------------------------Paul Posoli Rodney Malcolm Executive Vice President Senior Vice President Calpine Corporation Calpine Corporation 717 Texas Avenue 717 Texas Avenue Houston, TX 77002 Houston, TX 77002 Tel: (713) 830-8663 Tel: (713) 570-4816 Fax: (713) 570-4725 Fax: (713) 570-4725 E-mail: [email protected] E-mail: [email protected] -------------------------------------------------------------------------------Lisa Bodensteiner Executive Vice President and General Counsel Calpine Corporation 50 West San Fernando Street San Jose, CA 95113 Tel: (408) 792-1226 Fax: (408) 794-2434 E-mail: [email protected] -------------------------------------------------------------------------------- Communications to Bear Stearns or CalBear pursuant to Section 18.2(a) shall be addressed to: The Bear Stearns Companies Inc. 383 Madison Avenue 74 New York, NY 10179 Tel: (212) 272-4653 Fax: (212) 272-8976 Attention: Andrew Kittell E-mail: [email protected] and with a copy to: The Bear Stearns Companies Inc. 383 Madison Avenue New York, NY 10179 Tel: (212) 272-7850 Fax: (917) 849-1072 Attention: Michael Solender, General Counsel E-mail: [email protected] and with a copy to: Latham & Watkins LLP 885 Third Avenue Suite 1000 New York, NY 10022 Tel:(212) 906-1200 Fax:(212) 751-4864 Attention: Steven Della Rocca E-mail: [email protected] and with a copy to: -------------------------------------------------------------------------------Francis Dunleavy Eli Wachtel Senior Managing Director Senior Managing Director Bear, Stearns & Co. Inc. Bear, Stearns & Co. Inc. 383 Madison Avenue 383 Madison Avenue New York, NY 10179 New York, NY 10179 Tel: (212) 272-5141 Tel: (212) 272-4808 Fax: (212) 272-8976 Fax: (212) 272-5681 E-mail: [email protected] E-mail: [email protected] -------------------------------------------------------------------------------- Communications to Bear Stearns or CalBear pursuant to Section 18.2(b) shall be addressed to: -------------------------------------------------------------------------------Bill Hamilton Chip Steppacher Bear, Stearns & Co. Inc. Bear, Stearns & Co. Inc. 383 Madison Avenue 383 Madison Avenue New York, NY 10179 New York, NY 10179 75 Tel: (212) 272-6918 Tel: (212) 272-2050 Fax: (212) 272-5921 Fax: (212) 272-5921 E-mail: [email protected] E-mail: [email protected] -------------------------------------------------------------------------------Andrew Kittell Brian Anast Bear, Stearns & Co. Inc. Bear, Stearns & Co. Inc. 383 Madison Avenue 383 Madison Avenue New York, NY 10179 New York, NY 10179 Tel: (212) 272-4653 Tel: (212) 272-4654 Fax: (212) 272-8976 Fax: (212) 272-8976 E-mail: [email protected] E-mail: [email protected] -------------------------------------------------------------------------------Kristen Reifsnyder Bear, Stearns & Co. Inc. 383 Madison Avenue New York, NY 10179 Tel: (212) 272-6417 Fax: (212) 272-8888 E-mail: [email protected] -------------------------------------------------------------------------------- Communications to Bear Stearns or CalBear pursuant to Section 18.2(c) shall be addressed to: -------------------------------------------------------------------------------Francis Dunleavy Eli Wachtel Senior Managing Director Senior Managing Director Bear, Stearns & Co. Inc. Bear, Stearns & Co. Inc. 383 Madison Avenue 383 Madison Avenue New York, NY 10179 New York, NY 10179 Tel: (212) 272-5141 Tel: (212) 272-4808 Fax: (212) 272-8976 Fax: (212) 272-5681 E-mail: [email protected] E-mail: [email protected] or, in each case, to such other place and with such other copies as any Party may designate as to itself and its Representatives by notice to the other Parties that are not Affiliates of such Party. 18.3 Choice of Law; Service of Process; Venue; Jury Trial Waiver. (a) Each of the Parties agrees that this Agreement and each of the other Transaction Documents to which it is a party (including any claim or controversy arising out of or relating to this Agreement or such other Transaction Document) shall be construed and interpreted and the rights of the Parties determined in accordance with the internal laws of the State of New York without giving effect to any choice or conflict of law provision, principle or rule (whether of the State of New York or any other jurisdiction) that would cause the application of the laws of any jurisdiction other than the State of New York. Each of the Parties irrevocably consents to the service of any and all 76 process in any Action arising out of or relating to this Agreement, the other Transaction Documents to which it is a party or the transactions contemplated hereby or thereby by the registered or certified mailing of copies of such process to the addresses of such Party specified in Section 18.2. Each of the Parties consents and voluntarily submits to personal jurisdiction in the State of New York and in the courts in such state located in New York County and the United States District Court for the Southern District of New York in any proceedings arising out of or relating to this Agreement, the other Transaction Documents to which it is a party and the transactions contemplated hereby and thereby and, subject to the arbitration provisions set out in Section 18.4, agrees that all claims in respect of any such proceeding may be heard and determined in any such court and that all claims shall, in respect of any such proceeding, be brought, prior to appeal beyond such courts, in such courts. Each Party irrevocably and unconditionally waives and agrees not to plead, to the fullest extent permitted by law, any objection that they may now or hereafter have to the laying of venue or the convenience of the forum of any Action with respect to this Agreement, the other Transaction Documents to which it is a party and the transactions contemplated hereby and thereby, in the United States District Court for the Southern District of New York and the courts of the State of New York located in New York County. Each Party agrees that a final judgment, subject to appeal rights, in any proceeding so brought shall be conclusive and may be enforced by suit on the judgment in any court or in any other manner provided by law or in equity. (b) Subject to the arbitration provisions set out in Section 18.4, each of the Parties agrees to commence any proceeding arising out of or relating to this Agreement, the other Transaction Documents to which it is a party or the transactions contemplated hereby or thereby in the United States District Court for the Southern District of New York or the courts of the State of New York located in New York County and that any claims shall, in respect of any such proceeding, initially be brought in such courts. (c) EACH OF THE PARTIES HERETO HEREBY IRREVOCABLY WAIVES ANY AND ALL RIGHT TO TRIAL BY JURY IN ANY LEGAL PROCEEDING ARISING OUT OF OR RELATED TO THIS AGREEMENT, THE OTHER TRANSACTION DOCUMENTS TO WHICH IT IS A PARTY, OR THE TRANSACTIONS CONTEMPLATED HEREBY OR THEREBY. 18.4 Dispute Resolution; Arbitration. (a) In an effort to resolve informally and amicably any dispute or Action that might arise between the Parties or their respective Affiliates hereunder or under any of the other Transaction Documents, Calpine or Bear Stearns may by providing notice to the other refer any matter in dispute for resolution to Paul J. Posoli and Francis Dunleavy, respectively. Calpine or Bear Stearns may change the designation of the applicable aforementioned individual established by the previous sentence by notice to Bear Stearns or Calpine, respectively. If settlement is not thereafter reached through their efforts within twenty (20) days following such referral, or such longer time period as the Parties may agree, then any Party may initiate arbitration proceedings as set forth below to resolve the matter. 77 (b) Each of the Parties agrees that, notwithstanding anything herein to the contrary, any dispute or Action not otherwise resolved pursuant to Section 18.4(a) shall be resolved by binding arbitration proceedings in accordance with this Section 18.4. Any dispute not otherwise resolved may be submitted for arbitration hereunder by any Party delivering to the other Parties that are not its Affiliates a notice demanding arbitration of the dispute in accordance with the commercial arbitration rules of the American Arbitration Association ("AAA") then in effect. To the extent that such provisions are not inconsistent with such rules, the remaining provisions of this Section 18.4 shall also apply to such proceedings. (c) Each of Calpine and Bear Stearns, within thirty (30) days of delivery of the notice demanding arbitration, shall select an arbitrator (each, a "Party Arbitrator"). The Party Arbitrators shall select, within ten (10) days, one neutral arbitrator, who shall serve as the Chairman ("Chairman") (together with the Party Arbitrators, the "Arbitration Panel"). In the absence of agreement between the Party Arbitrators on selection of the Chairman, the Chairman shall be selected by the AAA. (d) No member of the Arbitration Panel may have a direct or indirect interest in any Party or the subject of the arbitration; provided however that each of Calpine and Bear Stearns may communicate ex parte with its respective Party Arbitrator, but not the Chairman. (e) The place of the arbitration shall be a place mutually agreed upon by the Parties at a site chosen by the Arbitration Panel or, in the absence of agreement among the Arbitration Panel, at a site chosen by the Chairman; provided, however, that if the Parties are not able to mutually agree upon the place of arbitration, such place shall be New York, New York. (f) The Arbitration Panel shall determine the rules of procedure or, in the absence of agreement among the Arbitration Panel, the Federal Rules of Civil Procedure shall govern the procedure for discovery as well as presentation of the evidence. In any event, the Arbitration Panel or, in the absence of agreement among the Arbitration Panel, the Chairman, shall have the right to impose reasonable restrictions on the taking of discovery, including limitations on the number of and length of depositions of witnesses. (g) The Arbitration Panel shall render a reasoned decision in writing within thirty (30) days of the close of evidence. Any award issued as a result of such arbitration shall be final and binding between the parties thereto and judgment upon the award rendered by the arbitration panel may be entered, and shall be enforceable, by any Governmental Authority having jurisdiction over the party against whom enforcement is sought. (h) During the course of the arbitration, each Party shall pay its and its Affiliates' own fees, costs and expenses (including attorneys' fees) and Calpine, on the one hand, and Bear Stearns, on the other hand, shall each pay one-half of any fees, costs and expenses of the Arbitration Panel; provided, however that the Arbitration Panel shall in no way award damages for any Claim of a type that are not permitted for such Claim under New York law and the provisions of the Transaction Documents or that exceed the limits, if any, on damages afforded by New York law and the provisions of the Transaction Documents, particularly Article XVII. 78 (i) Calpine and Bear Stearns may mutually agree, each in their sole discretion, to reduce any time periods specified in this Section 18.4 to resolve any dispute or controversy on an expedited basis. 18.5 Continued Performance. Each of the Parties agrees that it shall, and shall cause each of its Affiliates that is a Party to, continue to perform under this Agreement and the other Transaction Documents to which it is a party during the pendency of any dispute, arbitration or other Action hereunder or thereunder. For the avoidance of doubt, this Section 18.5 shall not prevent or restrict the termination of, or limit the right of any Party to terminate or the effect of the termination of, this Agreement or any other Transaction Document in accordance with the terms hereof or thereof. 18.6 Regulatory Event. Any provision of this Agreement or the other Transaction Documents declared or rendered unlawful by any Governmental Authority or deemed unlawful because of a statutory or regulatory change or interpretation (individually or collectively, such events referred to as a "Regulatory Event") will not otherwise affect the remaining lawful obligations that arise under this Agreement and the other Transaction Documents. Further, if a Regulatory Event occurs, the Parties shall use their commercially reasonable efforts to modify this Agreement and the other Transaction Documents, as applicable, in order to give effect to the original intention of the Parties in a manner consistent with the Regulatory Event. 18.7 Forward Contracts. The Parties acknowledge and agree that all CalBear Trades, other than CalBear Trades with a maturity date less than two days after the date the CalBear Trade is executed, constitute "forward contracts" within the meaning of the United States Bankruptcy Code. The Parties acknowledge and agree that CalBear is a "forward contract merchant" within the meaning of the United States Bankruptcy Code. 18.8 Effectiveness; Entire Agreement; Amendments and Waivers. This Agreement shall become binding upon each Party hereto when such Party has executed and delivered this Agreement. This Agreement, and all exhibits and schedules hereto, constitutes the entire agreement among the Parties pertaining to the subject matter hereof and supersedes all prior agreements, understandings, negotiations and discussions, whether oral or written, of the Parties; provided that the forms of agreements attached hereto as exhibits shall be superseded by the copies of such agreements executed and delivered by the respective parties thereto, the execution and delivery of such agreements by the parties thereto to be conclusive evidence of such parties' approval of any modification therein. Except as otherwise expressly set forth in this Agreement, no amendment, supplement, waiver or other modification of this Agreement shall be binding unless agreed in writing by each Party hereto indicating its intention to modify this Agreement; provided that any waiver of a right under this Agreement shall be binding if agreed in writing by the Party against whom enforcement of such waiver is sought. Neither the failure nor any delay by any Party in exercising any right, power or privilege under this Agreement or the other Transaction Documents will operate as a waiver of any right, power or privilege under this Agreement or the other Transaction Documents, and no waiver of any of the provisions of this Agreement or the other Transaction Documents shall be deemed or shall constitute a waiver of any other provision hereof or thereof (whether or not similar), nor shall such waiver constitute a continuing waiver unless otherwise expressly provided in such waiver. In addition, no 79 notice to or demand on one Party will be deemed a waiver of any obligation of such Party or of the right of the Party giving such notice or demand to take further action without notice or demand as provided in this Agreement or the other Transaction Documents. Notwithstanding the foregoing, (a) Bear Stearns, in its sole discretion, may modify Schedule 3.7(a) in accordance with Section 3.7(a), and (b) Calpine, in its sole discretion, may modify Schedule 3.8(a) in accordance with Section 3.8(a). 8.9 Multiple Counterparts. This Agreement may be executed in one or more counterparts, each of which shall be deemed an original, but all of which together shall constitute one and the same instrument. This Agreement and the signature pages hereto may be delivered by telecopy or other electronic or digital transmission method. 18.10 Invalidity. In addition to, and not in limitation of, Section 18.6, in the event that any one or more of the provisions contained in this Agreement or in any other instrument referred to herein, shall, for any reason, be held to be invalid, illegal or unenforceable in any respect, then to the maximum extent permitted by law, such invalidity, illegality or unenforceability shall not affect any other provision of this Agreement or any other such instrument. 8.11 Titles; Currency; Schedules. The titles, captions or headings of the Articles and Sections herein are inserted for convenience of reference only and are not intended to be a part of or to affect the meaning or interpretation of this Agreement. Unless otherwise specified, all references contained in this Agreement or in any other Transaction Document to dollars or "$" will mean United States Dollars. Disclosure of any item in any section or part of this Agreement or the schedules hereto will not constitute disclosure of such item in any other section or part of this Agreement or the schedules hereto, whether or not the existence of the item or its contents should be or is relevant to any other section or part of this Agreement or the schedules, unless such relevance is reasonably apparent on its face. 18.12 Payments. Unless otherwise specified, all Payment due pursuant to the terms of this Agreement shall be due by 4:00 p.m. New York City time on the date they are due pursuant to the terms hereof. 18.13 Publicity. No Party shall, and each Party shall cause its Affiliates and their Representatives not to, issue any press release regarding the transactions contemplated hereby or by the other Transaction Documents or consummated hereunder or thereunder without the prior approval of, in the case of Calpine or any Calpine Transaction Party, Bear Stearns, and in the case of Bear Stearns or CalBear, Calpine, in each case such approval not to be unreasonably withheld. Notwithstanding the foregoing, nothing herein shall be deemed to prohibit any Party from making any disclosure which its counsel deems reasonably necessary in order to fulfill such Party's disclosure obligations imposed by Applicable Law; provided that each such Party shall, to the extent reasonably practicable, afford, in the case of Calpine or any Calpine Transaction Party, Bear Stearns, or in the case of Bear Stearns or CalBear, Calpine, the opportunity to review and comment on the proposed disclosure in advance of such issuance; provided, further, that in the event that it is not reasonably practicable, such Party shall provide Bear Stearns or Calpine, as 80 applicable, a copy promptly thereafter. Reference is made to Section 3.5(b) for other agreements with respect to press releases. 18.14 Fees and Expenses. (a) Calpine. Subject to the provisions of Article XV and Section 18.4 hereof, unless otherwise specifically provided in this Agreement or in any other Transaction Document, Calpine and the Calpine Transaction Parties shall pay all of the fees, costs and expenses incurred by Calpine or any Calpine Transaction Party incident to or in connection with the negotiation, preparation, execution and delivery of this Agreement. (b) Bear Stearns. Subject to the provisions of Article XV and Section 18.4 hereof, unless otherwise specifically provided in this Agreement or in any other Transaction Document, Bear Stearns and CalBear shall pay all of the fees, costs and expenses incurred by Bear Stearns or CalBear incident to or in connection with the negotiation, preparation, execution and delivery of this Agreement. 18.15 Specific Performance; Remedies Cumulative. In the event of any actual or threatened default in, or breach of, any of the terms, conditions and provisions of this Agreement or the other Transaction Documents (other than Soft Covenants), any Party who is or is to be thereby aggrieved will have the right of specific performance and injunctive relief giving effect to its rights under this Agreement and the other Transaction Documents to the extent permitted by Applicable Law. Except as otherwise set forth herein, all rights and remedies under this Agreement and the other Transaction Documents will be cumulative, and the exercise of one or more rights or remedies shall not prejudice or impair the concurrent or subsequent exercise of other rights or remedies. 18.16 Representation of Counsel; Mutual Negotiation. Each Party has been represented by counsel of its choice in negotiating this Agreement. This Agreement shall therefore be deemed to have been negotiated and prepared at the request, direction and construction of each of the Parties, at arm's length, with the advice and participation of counsel, and will be interpreted in accordance with its terms without favor to any Party. 18.17 Knowledge. Whenever used in this Agreement or any Transaction Documents, "to the knowledge of" or a similar phrase shall mean the actual knowledge of (i) if a specified individual or individuals are referred to in any provision of this Agreement or any Transaction Documents, such individual or individuals, or (ii) if no such individual or individuals are specified, any of the individual Representatives of the applicable Party or its Affiliates listed on Schedule 18.17, in each case after such individuals undertook a reasonable investigation. 18.18 No Third Party Beneficiaries. This Agreement shall be binding upon and inure solely to the benefit of each Party, and nothing in this Agreement, express or implied, is intended to or shall confer upon any other Person any legal or equitable right, benefit or remedy of any nature whatsoever under or by reason of this Agreement, including by way of subrogation, except as specifically set forth in Article XV hereof. 81 18.19 Time of Essence. With regard to all dates and time periods set forth or referred to in this Agreement, time is of the essence. 18.20 Force Majeure. In the event of a Force Majeure with respect to a Party, if such Party gives notice and details of the Force Majeure to the other Party or Parties to whom performance is owed as soon as practicable, then the Party claiming the Force Majeure shall be excused from the performance of its obligations to the extent and for the period affected by the Force Majeure. The Party claiming the Force Majeure shall remedy the Force Majeure in a commercially reasonable manner as promptly as possible. [signature page follows] 82 IN WITNESS WHEREOF, the Parties have caused this Agreement to be duly executed on their respective behalf, by their respective officers thereunto duly authorized, all as of the day and year first above written. CALPINE CORPORATION By: /s/ ERIC PRYOR Name: Eric Pryor -----------------------------------------Title: Executive Vice President ------------------------------------------ CALPINE ENERGY SERVICES, L.P. By: /s/ PAUL POSOLI Name: Paul Posoli -----------------------------------------Title: President ------------------------------------------ THE BEAR STEARNS COMPANIES INC. By: Name: /s/ WARREN J. SPECTOR Warren J. Spector -----------------------------------------Title: President, Co-Chief Operating Officer and Director ------------------------------------------ EXHIBITS TO THE MASTER TRANSACTION AGREEMENT Exhibit A Form of Agency and Services Agreement Exhibit B Form of Trading Master Agreement Exhibit C Organizational Documents of CMSC Exhibit D Organizational Documents of CalBear Exhibit E Form of CMSC and CalBear Signature Page SIGNATURE PAGE TO THE MASTER TRANSACTION AGREEMENT By execution of this signature page, each of Calpine Merchant Services Company, Inc., a Delaware corporation ("CMSC") and CalBear Energy LP, a Delaware limited partnership ("CalBear"), in accordance with the terms of the Master Transaction Agreement (as defined below), in consideration of the premises, mutual covenants and promises contained in the Master Transaction Agreement, and for other good and valuable consideration, the receipt and adequacy of which are hereby acknowledged, hereby agrees to become party to, to be bound by the obligations of, and to receive the benefits of, that certain Master Transaction Agreement, dated as of September 7, 2005, by and among Calpine Corporation, a Delaware corporation, Calpine Energy Services, L.P., a Delaware limited partnership, and The Bear Stearns Companies Inc., a Delaware corporation, as modified from time to time thereafter (the "Master Transaction Agreement"), and each of CMSC and CalBear acknowledges and agrees that it shall be "CMSC" or "CalBear", respectively, and a "Party", in each case as defined in the Master Transaction Agreement, for all purposes thereunder. Dated: [________], 2005 [signature page follows] CALPINE MERCHANT SERVICES COMPANY, INC., a Delaware corporation By:_______________________________ Name: Title: CALBEAR ENERGY LP, a Delaware limited partnership By: [________] Its: General Partner By: [________] Its: Managing Member By:_______________________________ Name: Title: Exhibit F Form of Renewal Notice RENEWAL NOTICE PURSUANT TO SECTION 16.2(A) OF THE MASTER TRANSACTION AGREEMENT [NAME OF PARTY], together with its Affiliates that are Parties to that certain Master Transaction Agreement (as defined below) hereby deliver this Renewal Notice to [BEAR STEARNS OR CALPINE, AS APPLICABLE] and renew the Master Transaction Agreement pursuant to Section 16.2(a) of the Master Transaction Agreement, for [each of] the Renewal Period(s) commencing: [August 31, [____], [____] and [____];] [November 30, [____], [____] and [____];] [February 28 (or February 29, in the event of a leap year), [____], [____] and [____]; and] [May 31, [____], [____] and [____].] until the end of [the last] such Renewal Period. Capitalized terms used but not defined in this Renewal Notice shall have the meaning given to them in that certain Master Transaction Agreement, dated as of September 7, 2005, by and among Calpine Corporation, a Delaware corporation, Calpine Energy Services, L.P., a Delaware limited partnership, and The Bear Stearns Companies Inc., a Delaware corporation, as modified from time to time thereafter (the "Master Transaction Agreement"). Dated: [________] [NAME OF PARTY], a [TYPE OF ENTITY] By:_______________________________ Name: Title: SCHEDULES TO THE MASTER TRANSACTION AGREEMENT Schedule 1.1(a) Calpine Existing Indentures 1. Indenture, dated as of May 16, 1996, as supplemented by the First Supplemental Indenture, dated as of August 1, 2000, and the Second Supplemental Indenture, dated as of April 26, 2004, between the Company and State Street Bank and Trust Company (as successor to Fleet National Bank), as Trustee, relating to $180,000,000 in aggregate principal amount of the Company's 10-1/2% Senior Notes due 2006. 2. Indenture, dated as of July 8, 1997, as supplemented by the First Supplemental Indenture, dated as of September 10, 1997, the Second Supplemental Indenture, dated as of July 31, 2000, and the Third Supplemental Indenture, dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee, relating to $275,000,000 in aggregate principal amount of the Company's 8-3/4% Senior Notes due 2007. 3. Indenture, dated as of March 31, 1998, as supplemented by the First Supplemental Indenture, dated as of July 24, 1998, the Second Supplemental Indenture, dated as of July 31, 2000, and the Third Supplemental Indenture, dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee, relating to $400,000,000 in aggregate principal amount of the Company's 7-7/8% Senior Notes due 2008. 4. Indenture, dated as of March 29, 1999, as supplemented by the First Supplemental Indenture, dated as of July 31, 2000, and the Second Supplemental Indenture, dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee, relating to $250,000,000 in aggregate principal amount of the Company's 7-5/8% Senior Notes due 2006. 5. Indenture, dated as of March 29, 1999, as supplemented by the First Supplemental Indenture, dated as of July 31, 2000, and the Second Supplemental Indenture, dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee, relating to $350,000,000 in aggregate principal amount of the Company's 7-3/4% Senior Notes due 2009. 6. Indenture, dated as of August 10, 2000, as supplemented by the First Supplemental Indenture, dated as of September 28, 2000 and the Second Supplemental Indenture, dated as of September 30, 2004, between the Company and Wilmington Trust Company, as Trustee, relating to $250,000,000 in aggregate principal amount of the Company's 8-1/4% Senior Notes due 2005, $750,000,000 in aggregate principal amount of the Company's 8-5/8% Senior Notes due 2010, $2,000,000,000 in aggregate principal amount of the Company's 8-1/2% Senior Notes due 2011, $1,200,000,000 in aggregate principal amount of the Company's 4% Convertible Senior Notes due 2006 and $725,000,000 in aggregate principal amount of the Company's Contingent Convertible Notes due 2014. 7. Amended and Restated Indenture, dated as of March 12, 2004, between the Company and Wilmington Trust Company, as Trustee, relating to $900,000,000 in aggregate principal amount of the Company's 4.75% Contingent Senior Notes due 2023. 8. Indenture, dated as of July 16, 2003, between the Company and Wilmington Trust Company, as Trustee, relating to $500,000,000 in aggregate principal amount of the Company's Second Priority Senior Secured Floating Rate Notes due 2007. 9. Indenture, dated as of July 16, 2003, between the Company and Wilmington Trust Company, as Trustee, relating to $1,150,000,000 in aggregate principal amount of the Company's 8.500% Second Priority Senior Secured Notes due 2010. 10. Indenture, dated as of July 16, 2003, between the Company and Wilmington Trust Company, as Trustee, relating to $1,150,000,000 in aggregate principal amount of the Company's 8.750% Second Priority Senior Secured Notes due 2013. 11. Indenture, dated as of November 18, 2003, between the Company and Wilmington Trust Company, as Trustee, relating to $400,000,000 in aggregate principal amount of the Company's 9.875% Second Priority Senior Secured Notes due 2011. 12. Indenture, dated as of September 30, 2004, between the Company and Wilmington Trust Company, as Trustee, relating to $785,000,000 in aggregate principal amount of the Company's 9.625% First Priority Senior Secured Notes due 2014. Schedule 1.1(b) Calpine Restricted Transferees [*] and their respective Affiliates. Schedule 1.1(c) Bear Stearns Restricted Transferees [*] and their respective Affiliates. Schedule 1.1(d) Calpine Significant Subsidiaries Calpine Generating Company, LLC Calpine Power Company Calpine Central, Inc. Bear Stearns Significant Subsidiaries Bear, Stearns & Co. Inc. Bear, Stearns Securities International Limited Bear, Stearns International Limited Schedule 3.7(a) Employees of Bear Stearns [*] Schedule 3.8(a) Employees of Calpine [*] Schedule 9.1 Calpine and Calpine Transaction Parties Name Calpine Corporation CES Marketing VII, LLC (to be known as Calpine Merchant Services Company, Inc.) Type of Entity Corporation Limited Liability Company Calpine Energy Services, L.P. Limited Partnership Delaware Jurisdiction of Organization Delaware Delaware Schedule 9.2 Calpine Conflicts, Violations and Consents Any notice filings or other approvals, as needed under the FPA, for CMSC to receive FERC approval under Section 203 of the FPA for the performance of the Services by CMSC in accordance with CalBear's FERC-jurisdictional rate schedules, for the provision of energy related services by CMSC to CES, for the transfer of interests in CMSC's predecessor, CES Marketing VII, LLC, among Affiliates of Calpine, and for the name change from CES Marketing VII, LLC to Calpine Merchant Services Company, Inc. and any other notice filings or other approvals required under the FPA. Any material consent, waiver, agreement, Permit or approval or authorization of, or material declaration, filing, notice or registration to or with, or material assignment by, any Person or Governmental Authority, that may be required in connection with any specific CalBear Trade, including any RTO registrations. Schedule 10.1 Bear Stearns and CalBear Name The Bear Stearns Companies Inc. Type of Entity Jurisdiction of Organization Corporation Delaware Arroyo Energy LP Limited partnership Delaware (to be known as CalBear Energy LP) Schedule 10.2 Bear Stearns Conflicts, Violations and Consents Any notice filings or other approvals, as needed under the FPA, for CalBear to receive FERC approval under Section 203 of the FPA for the performance of the Services by CMSC in accordance with CalBear's FERC-jurisdictional rate schedules, for the transfer of interests in CalBear's predecessor, Arroyo Energy LP, among Affiliates of Bear Stearns, and for the name change from Arroyo Energy LP to CalBear Energy LP and any other notice filings or other approvals required under the FPA. Any material consent, waiver, agreement, Permit or approval or authorization of, or material declaration, filing, notice or registration to or with, or material assignment by, any Person or Governmental Authority, that may be required in connection with any specific CalBear Trade, including any RTO registrations. Schedule 12.9 Opinions of Counsel to Bear Stearns [*] Schedule 13.9 Opinions of Counsel to Calpine [*] Schedule 18.17 Knowledge Representatives of Bear Stearns and CalBear [*] Representatives of Calpine, CMSC and CES [*] EXHIBIT 31.1 CERTIFICATIONS I, Peter Cartwright, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Calpine Corporation (the "registrant"); 2. Based on my knowledge, this 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 report; 3. Based on my knowledge, the financial statements, and other financial information included in this 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 report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, 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 report is being prepared; b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: November ___, 2005 /s/ PETER CARTWRIGHT -------------------Peter Cartwright CHAIRMAN, PRESIDENT AND CHIEF EXECUTIVE OFFICER CALPINE CORPORATION EXHIBIT 31.2 CERTIFICATIONS I, Robert D. Kelly, certify that: 1. I have reviewed this quarterly report on Form 10-Q of Calpine Corporation (the "registrant"); 2. Based on my knowledge, this 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 report; 3. Based on my knowledge, the financial statements, and other financial information included in this 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 report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, 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 report is being prepared; b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: November ___, 2005 /s/ ROBERT D. KELLY ------------------Robert D. Kelly EXECUTIVE VICE PRESIDENT AND CHIEF FINANCIAL OFFICER CALPINE CORPORATION EXHIBIT 32.1 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, 2005, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), each of the undersigned does hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of his 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. /s/ PETER CARTWRIGHT ---------------------------------Peter Cartwright Chairman, President and Chief Executive Officer Calpine Corporation /s/ ROBERT D. KELLY ---------------------------------------Robert D. Kelly Executive Vice President and Chief Financial Officer Calpine Corporation Dated: November ___, 2005 A signed original of this written statement required by Section 906 has been provided to Calpine Corporation and will be retained by Calpine Corporation and furnished to the Securities and Exchange Commission or its staff upon request.

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