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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-Q/A
Amendment No. 1
 	 	 	
(Mark One)	 	 	
þ	 	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934	
 	
 	 	For the quarterly period ended March 31, 2004	
 	
or	
 	
o	 	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  þ           No  o
     Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).     Yes  þ           No  o
     Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:
     416,047,134 shares of Common Stock, par value $.001 per share, outstanding on May 7, 2004

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EXPLANATORY NOTE
This Amendment No. 1 to the Quarterly Report on Form 10-Q for Calpine Corporation (“Calpine”) for the quarter ended March 31, 2004, as filed with the Securities and Exchange Commission (“SEC”) on May 10, 2004, is being filed in connection with the SEC’s review of Calpine’s registration statement on Form S-3, relating to the resale of 4.75% contingent convertible senior notes sold by Calpine on November 17, 2003 and January 9, 2004, and 1934 Exchange Act filings incorporated by reference thereto. As a result of this review there were no changes to the Consolidated Condensed Financial Statements. This Amendment No. 1 does provide, however, revised or expanded disclosure in Item 1 “Notes to Consolidated Condensed Financial Statements”, Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 4 “Controls and Procedures”.
Unrelated to the aforementioned review, we have made certain reclassifications to the Consolidated Condensed Balance Sheets as described in Note 2 of the Notes to the Consolidated Condensed Financial Statements under Reclassifications . 

CALPINE CORPORATION AND SUBSIDIARIES
REPORT ON FORM 10-Q
For the Quarter Ended March 31, 2004
INDEX

				Page	
				No.	
					
  PART I — FINANCIAL INFORMATION	
  Item 1.	 	  Financial Statements	 	 	 	 	
 	 	  Consolidated Condensed Balance Sheets March 31, 2004 and December 31, 2003.	 	 	2	 	
 	 	  Consolidated Condensed Statements of Operations for the Three Months Ended March 31, 2004 and 2003.	 	 	4	 	
 	 	  Consolidated Condensed Statements of Cash Flows for the Three Months Ended March 31, 2004 and 2003.	 	 	5	 	
 	 	  Notes to Consolidated Condensed Financial Statements	 	 	6	 	
  Item 2.	 	  Management’s Discussion and Analysis of Financial Condition and Results of Operations	 	 	39	 	
  Item 3.	 	  Quantitative and Qualitative Disclosures About Market Risk	 	 	69	 	
  Item 4.	 	  Controls and Procedures	 	 	69	 	
  PART II — OTHER INFORMATION	
  Item 1.	 	  Legal Proceedings	 	 	71	 	
  Item 2.	 	  Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities	 	 	77	 	
  Item 6.	 	  Exhibits and Reports on Form 8-K	 	 	78	 	
  Signatures	 	 	83	 	
  EXHIBIT 31.1	
  EXHIBIT 31.2	
  EXHIBIT 32.1	
1 

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PART I — FINANCIAL INFORMATION
Item 1.      Financial Statements.
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
March 31, 2004 and December 31, 2003
 	 	 	 	 	 	 	 	 	 	 	
		March 31,		December 31,	
		2004		2003	

		(Unaudited)	
			
		(In thousands, except share and	
		per share amounts)	
ASSETS	
Current assets:	 	 	 	 	 	 	 	 	
 	Cash and cash equivalents	 	$	582,804	 	 	$	991,806	 	
 	Accounts receivable, net	 	 	1,015,986	 	 	 	988,947	 	
 	Margin deposits and other prepaid expense	 	 	456,857	 	 	 	385,348	 	
 	Inventories	 	 	127,998	 	 	 	139,654	 	
 	Restricted cash	 	 	401,187	 	 	 	383,788	 	
 	Current derivative assets	 	 	579,564	 	 	 	496,967	 	
 	Current assets held for sale	 	 	—	 	 	 	651	 	
 	Other current assets	 	 	184,057	 	 	 	89,593	 	
 	 	 		 	 	 		 	
 	 	Total current assets	 	 	3,348,453	 	 	 	3,476,754	 	
 	 	 		 	 	 		 	
Restricted cash, net of current portion	 	 	215,137	 	 	 	575,027	 	
Notes receivable, net of current portion	 	 	211,759	 	 	 	213,629	 	
Project development costs	 	 	146,393	 	 	 	139,953	 	
Investments in power projects and oil and gas properties	 	 	417,978	 	 	 	472,749	 	
Deferred financing costs	 	 	439,941	 	 	 	400,732	 	
Prepaid lease, net of current portion	 	 	425,846	 	 	 	414,058	 	
Property, plant and equipment, net	 	 	20,736,669	 	 	 	20,081,052	 	
Goodwill, net	 	 	45,160	 	 	 	45,160	 	
Other intangible assets, net	 	 	89,753	 	 	 	89,924	 	
Long-term derivative assets	 	 	753,124	 	 	 	673,979	 	
Long-term assets held for sale	 	 	—	 	 	 	112,148	 	
Other assets	 	 	531,825	 	 	 	608,767	 	
 	 	 		 	 	 		 	
 	 	Total assets	 	$	27,362,038	 	 	$	27,303,932	 	
 	 	 		 	 	 		 	
2 

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		March 31,		December 31,	
		2004		2003	

		(Unaudited)	
			
		(In thousands, except share and	
		per share amounts)	
LIABILITIES & STOCKHOLDERS’ EQUITY	
Current liabilities:	 	 	 	 	 	 	 	 	
 	Accounts payable	 	$	1,007,405	 	 	$	938,644	 	
 	Accrued payroll and related expense	 	 	56,124	 	 	 	96,693	 	
 	Accrued interest payable	 	 	295,632	 	 	 	321,176	 	
 	Income taxes payable	 	 	9,563	 	 	 	18,026	 	
 	Notes payable and borrowings under lines of credit, current portion	 	 	254,067	 	 	 	254,292	 	
 	Preferred interests, current portion	 	 	11,597	 	 	 	11,220	 	
 	Capital lease obligation, current portion	 	 	4,396	 	 	 	4,008	 	
 	CCFC I financing, current portion	 	 	3,208	 	 	 	3,208	 	
 	Construction/project financing, current portion	 	 	76,332	 	 	 	61,900	 	
 	Senior notes and term loans, current portion	 	 	14,500	 	 	 	14,500	 	
 	Current derivative liabilities	 	 	551,191	 	 	 	456,688	 	
 	Other current liabilities	 	 	280,358	 	 	 	335,048	 	
 	 	 		 	 	 		 	
 	 	Total current liabilities	 	 	2,564,373	 	 	 	2,515,403	 	
 	 	 		 	 	 		 	
Notes payable and borrowings under lines of credit, net of current portion	 	 	791,700	 	 	 	873,572	 	
Notes payable to Calpine Capital Trusts	 	 	1,153,500	 	 	 	1,153,500	 	
Preferred interests, net of current portion	 	 	228,014	 	 	 	232,412	 	
Capital lease obligation, net of current portion	 	 	192,340	 	 	 	193,741	 	
CCFC I financing, net of current portion	 	 	784,258	 	 	 	785,781	 	
CalGen/ CCFC II financing	 	 	2,393,945	 	 	 	2,200,358	 	
Construction/project financing, net of current portion	 	 	1,548,262	 	 	 	1,209,505	 	
Convertible Senior Notes Due 2006	 	 	72,126	 	 	 	660,059	 	
Convertible Senior Notes Due 2023	 	 	900,000	 	 	 	650,000	 	
Senior notes and term loans, net of current portion	 	 	9,357,521	 	 	 	9,369,253	 	
Deferred income taxes, net	 	 	1,245,349	 	 	 	1,310,335	 	
Deferred lease incentive	 	 	49,352	 	 	 	50,228	 	
Deferred revenue	 	 	111,864	 	 	 	116,001	 	
Long-term derivative liabilities	 	 	750,810	 	 	 	692,088	 	
Long-term liabilities held for sale	 	 	—	 	 	 	161	 	
Other liabilities	 	 	269,908	 	 	 	259,390	 	
 	 	 		 	 	 		 	
 	 	Total liabilities	 	 	22,413,322	 	 	 	22,271,787	 	
 	 	 		 	 	 		 	
Minority interests	 	 	365,354	 	 	 	410,892	 	
 	 	 		 	 	 		 	
Stockholders’ equity:	 	 	 	 	 	 	 	 	
 	Preferred stock, $.001 par value per share; authorized 10,000,000 shares; none issued and outstanding in 2004 and 2003	 	 	—	 	 	 	—	 	
 	Common stock, $.001 par value per share; authorized 1,000,000,000 shares; issued and outstanding 415,736,644 shares in 2004 and 415,010,125 shares in 2003	 	 	416	 	 	 	415	 	
 	Additional paid-in capital	 	 	3,002,075	 	 	 	2,995,735	 	
 	Retained earnings	 	 	1,497,317	 	 	 	1,568,509	 	
 	Accumulated other comprehensive income	 	 	83,554	 	 	 	56,594	 	
 	 	 		 	 	 		 	
 	 	Total stockholders’ equity	 	$	4,583,362	 	 	$	4,621,253	 	
 	 	 		 	 	 		 	
 	 	Total liabilities and stockholders’ equity	 	$	27,362,038	 	 	$	27,303,932	 	
 	 	 		 	 	 		 	
The accompanying notes are an integral part of these Consolidated Condensed Financial Statements.
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CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS
For the Three Months Ended March 31, 2004 and 2003

		Three Months Ended	
		March 31,	
			
		2004		2003	

		(In thousands, except	
		per share amounts)	
		(Unaudited)	
Revenue:	 	 	 	 	 	 	 	 	
 	Electric generation and marketing revenue	 	 	 	 	 	 	 	 	
 	 	Electricity and steam revenue	 	$	1,245,887	 	 	$	1,100,067	 	
 	 	Sales of purchased power for hedging and optimization	 	 	380,028	 	 	 	681,284	 	
 	 	 		 	 	 		 	
 	 	 	Total electric generation and marketing revenue	 	 	1,625,915	 	 	 	1,781,351	 	
Oil and gas production and marketing revenue	 	 	 	 	 	 	 	 	
 	 	Oil and gas sales	 	 	24,581	 	 	 	25,911	 	
 	 	Sales of purchased gas for hedging and optimization	 	 	352,737	 	 	 	327,468	 	
 	 	 		 	 	 		 	
 	 	 	Total oil and gas production and marketing revenue	 	 	377,318	 	 	 	353,379	 	
 	Mark-to-market activities, net	 	 	12,518	 	 	 	20,443	 	
 	Other revenue	 	 	26,987	 	 	 	10,760	 	
 	 	 		 	 	 		 	
 	 	 	Total revenue	 	 	2,042,738	 	 	 	2,165,933	 	
 	 	 		 	 	 		 	
Cost of revenue:	 	 	 	 	 	 	 	 	
 	Electric generation and marketing expense	 	 	 	 	 	 	 	 	
 	 	Plant operating expense	 	 	175,834	 	 	 	161,929	 	
 	 	Transmission purchase expense	 	 	16,427	 	 	 	8,825	 	
 	 	Royalty expense	 	 	5,881	 	 	 	5,357	 	
 	 	Purchased power expense for hedging and optimization	 	 	374,939	 	 	 	679,949	 	
 	 	 		 	 	 		 	
 	 	 	Total electric generation and marketing expense	 	 	573,081	 	 	 	856,060	 	
Oil and gas operating and marketing expense	 	 	 	 	 	 	 	 	
 	 	Oil and gas operating expense	 	 	22,328	 	 	 	25,661	 	
 	 	Purchased gas expense for hedging and optimization	 	 	360,486	 	 	 	316,948	 	
 	 	 		 	 	 		 	
 	 	 	Total oil and gas operating and marketing expense	 	 	382,814	 	 	 	342,609	 	
 	Fuel expense	 	 	762,705	 	 	 	635,369	 	
 	Depreciation, depletion and amortization expense	 	 	149,415	 	 	 	133,815	 	
 	Operating lease expense	 	 	27,799	 	 	 	27,692	 	
 	Other cost of revenue	 	 	26,380	 	 	 	5,251	 	
 	 	 		 	 	 		 	
 	 	 	Total cost of revenue	 	 	1,922,194	 	 	 	2,000,796	 	
 	 	 		 	 	 		 	
 	 	 	 	Gross profit	 	 	120,544	 	 	 	165,137	 	
(Income) from unconsolidated investments in power projects and oil and gas properties	 	 	(2,506	)	 	 	(5,125	)	
Equipment cancellation and impairment cost	 	 	2,360	 	 	 	87	 	
Project development expense	 	 	7,717	 	 	 	5,086	 	
Research and development expense	 	 	3,815	 	 	 	2,391	 	
Sales, general and administrative expense	 	 	57,247	 	 	 	43,658	 	
 	 	 		 	 	 		 	
 	Income from operations	 	 	51,911	 	 	 	119,040	 	
Interest expense	 	 	254,792	 	 	 	142,961	 	
Distributions on trust preferred securities	 	 	—	 	 	 	15,657	 	
Interest (income)	 	 	(12,060	)	 	 	(8,035	)	
Minority interest expense	 	 	8,435	 	 	 	2,277	 	
Other expense (income)	 	 	(19,258	)	 	 	34,590	 	
 	 	 		 	 	 		 	
 	Loss before (benefit) for income taxes	 	 	(179,998	)	 	 	(68,410	)	
(Benefit) for income taxes	 	 	(85,949	)	 	 	(16,872	)	
 	 	 		 	 	 		 	
 	Loss before discontinued operations and cumulative effect of a change in accounting principle	 	 	(94,049	)	 	 	(51,538	)	
Discontinued operations, net of tax provision (benefit) of $12,325 and $(790)	 	 	22,857	 	 	 	(1,007	)	
Cumulative effect of a change in accounting principle, net of tax provision of $— and $450	 	 	—	 	 	 	529	 	
 	 	 		 	 	 		 	
 	 	 	 	Net loss	 	$	(71,192	)	 	$	(52,016	)	
 	 	 		 	 	 		 	
Basic and diluted loss per common share:	 	 	 	 	 	 	 	 	
 	Weighted average shares of common stock outstanding	 	 	415,308	 	 	 	380,960	 	
 	Loss before discontinued operations and cumulative effect of a change in accounting principle	 	$	(0.23	)	 	$	(0.14	)	
 	Discontinued operations, net of tax	 	$	0.06	 	 	$	—	 	
 	Cumulative affect of a change in accounting principle, net of tax	 	$	—	 	 	$	—	 	
 	 	 		 	 	 		 	
 	 	 	 	Net loss	 	$	(0.17	)	 	$	(0.14	)	
 	 	 		 	 	 		 	
The accompanying notes are an integral part of these Consolidated Condensed Financial Statements.
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CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
For the Three Months Ended March 31, 2004 and 2003

		Three Months Ended	
		March 31,	
			
		2004		2003	

		(In thousands)	
		(Unaudited)	
Cash flows from operating activities:	 	 	 	 	 	 	 	 	
 	Net loss	 	$	(71,192	)	 	$	(52,016	)	
 	 	Adjustments to reconcile net loss to net cash provided by operating activities:	 	 	 	 	 	 	 	 	
 	 	 	Depreciation, depletion and amortization(1)	 	 	197,183	 	 	 	164,501	 	
 	 	 	Deferred income taxes, net	 	 	(98,142	)	 	 	4,597	 	
 	 	 	Tax refund received	 	 	592	 	 	 	16,952	 	
 	 	 	(Gain) on sale of assets	 	 	(32,211	)	 	 	—	 	
 	 	 	Stock compensation expense	 	 	4,266	 	 	 	4,490	 	
 	 	 	Foreign exchange (gains) losses	 	 	(9,984	)	 	 	25,209	 	
 	 	 	Change in net derivative assets and liabilities	 	 	(36,230	)	 	 	54,290	 	
 	 	 	Income from unconsolidated investments in power projects and oil and gas properties	 	 	(2,506	)	 	 	(5,125	)	
 	 	 	Distributions from unconsolidated investments in power projects	 	 	5,140	 	 	 	9,401	 	
 	 	 	Other	 	 	7,599	 	 	 	(292	)	
 	 	 	Change in operating assets and liabilities, net of effects of acquisitions:	 	 	 	 	 	 	 	 	
 	 	 	Accounts receivable	 	 	(23,339	)	 	 	(251,833	)	
 	 	 	Other current assets	 	 	(49,708	)	 	 	(81,357	)	
 	 	 	Other assets	 	 	(6,823	)	 	 	(44,444	)	
 	 	 	Accounts payable and accrued expense	 	 	1,981	 	 	 	281,665	 	
 	 	 	Other liabilities	 	 	(59,856	)	 	 	39,329	 	
 	 	 		 	 	 		 	
 	 	 	 	Net cash (used in) provided by operating activities	 	 	(173,230	)	 	 	165,367	 	
 	 	 		 	 	 		 	
Cash flows from investing activities:	 	 	 	 	 	 	 	 	
 	Purchases of property, plant and equipment	 	 	(414,945	)	 	 	(507,250	)	
 	Disposals of property, plant and equipment	 	 	176,914	 	 	 	9,074	 	
 	Acquisitions, net of cash acquired	 	 	(187,466	)	 	 	(6,818	)	
 	Advances to joint ventures	 	 	(479	)	 	 	(2,020	)	
 	Project development costs	 	 	(6,837	)	 	 	(8,867	)	
 	Decrease in restricted cash	 	 	346,338	 	 	 	16,096	 	
 	(Increase) decrease in notes receivable	 	 	1,772	 	 	 	(4,534	)	
 	Other	 	 	13,332	 	 	 	20,690	 	
 	 	 		 	 	 		 	
 	 	Net cash used in investing activities	 	 	(71,371	)	 	 	(483,629	)	
 	 	 		 	 	 		 	
Cash flows from financing activities:	 	 	 	 	 	 	 	 	
 	Borrowings from notes payable and borrowings under lines of credit	 	 	2,394,565	 	 	 	—	 	
 	Repayments of notes payable and borrowings under lines of credit	 	 	(86,783	)	 	 	—	 	
 	Borrowings from project financing	 	 	315,142	 	 	 	19,426	 	
 	Repayments of project financing	 	 	(2,343,403	)	 	 	—	 	
 	Repayments of senior notes	 	 	(14,759	)	 	 	—	 	
 	Repurchase of 4% convertible senior notes	 	 	(586,926	)	 	 	—	 	
 	Proceeds from issuance of 4.75% convertible senior notes	 	 	250,000	 	 	 	—	 	
 	Proceeds from income trust offering	 	 	—	 	 	 	100,900	 	
 	Financing costs	 	 	(75,727	)	 	 	(6,941	)	
 	Other	 	 	(12,200	)	 	 	(842	)	
 	 	 		 	 	 		 	
 	 	Net cash (used in) provided by financing activities	 	 	(160,091	)	 	 	112,543	 	
 	 	 		 	 	 		 	
Effect of exchange rate changes on cash and cash equivalents	 	 	(4,310	)	 	 	4,290	 	
Net decrease in cash and cash equivalents	 	 	(409,002	)	 	 	(201,429	)	
Cash and cash equivalents, beginning of period	 	 	991,806	 	 	 	579,486	 	
 	 	 		 	 	 		 	
Cash and cash equivalents, end of period	 	$	582,804	 	 	$	378,057	 	
 	 	 		 	 	 		 	
Cash paid during the period for:	 	 	 	 	 	 	 	 	
 	Interest, net of amounts capitalized	 	$	238,954	 	 	$	71,297	 	
 	Income taxes	 	$	15,361	 	 	$	8,003	 	

		
(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.	
The accompanying notes are an integral part of these Consolidated Condensed Financial Statements.
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CALPINE CORPORATION AND SUBSIDIARIES 
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
March 31, 2004
(Unaudited)

1.	Organization and Operations of the Company	
      Calpine Corporation (“Calpine” or “the Company”), a Delaware corporation, and subsidiaries (collectively, also referred to as the “Company”) are engaged in the generation of electricity in the United States of America, Canada and the United Kingdom. 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. The Company has ownership interests in, and operates, gas-fired power generation and cogeneration facilities, gas fields, gathering systems and gas pipelines, geothermal steam fields and geothermal power generation facilities in the United States of America. In Canada, the Company owns oil and gas operations and has ownership interests in, and operates, power facilities. In the United Kingdom, the Company owns and operates a gas-fired power cogeneration facility. Each of the generation facilities produces and markets electricity for sale to utilities and other third party purchasers. Thermal energy produced by the gas-fired power cogeneration facilities is primarily sold to industrial users. Gas produced, and not physically delivered to the Company’s generating plants, is sold to third parties.

2.	Summary of Significant Accounting Policies	
      Basis of Interim Presentation  — The accompanying unaudited interim Consolidated Condensed Financial Statements of the Company have been prepared by the Company pursuant to the rules and regulations of the Securities and Exchange Commission. In the opinion of management, the Consolidated Condensed Financial Statements include the adjustments necessary to present fairly the information required to be set forth therein. Certain information and note disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles in the United States of America have been condensed or omitted from these statements pursuant to such rules and regulations and, accordingly, these financial statements should be read in conjunction with the audited Consolidated Financial Statements of the Company for the year ended December 31, 2003, included in the Company’s Annual Report on Form 10-K/A. 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 2004 presentation including a reclassification of transmission revenues from Electricity and steam revenue to Other revenue. Taxes on net current derivative assets and liabilities were reclassified out of Deferred income taxes, net to Other current liabilities.
      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 retirement and operation), provision for income taxes, fair value calculations of derivative instruments and associated reserves, capitalization of interest, primary beneficiary determination for the Company’s investments in variable interest entities, the outcome of pending litigation and estimates of oil and gas reserves used to calculate depletion, depreciation and impairment of natural gas and petroleum property and equipment.
      Effective Tax Rate  — For the three months ended March 31, 2004, the effective rate increased to 48% as compared to 25% for the three months ended March 31, 2003. This effective rate variance is due to the consideration of estimated year-end earnings in estimating the quarterly effective rate and due to the effect of significant permanent non-taxable items.
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      Derivative Instruments  — Financial Accounting Standards Board (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS No. 133”) as amended and interpreted by other related accounting literature, establishes accounting and reporting standards for derivative instruments (including certain derivative instruments embedded in other contracts). SFAS No. 133 requires companies to record derivatives on their balance sheets as either assets or liabilities measured at their fair value unless exempted from derivative treatment as a normal purchase and sale. All changes in the fair value of derivatives are recognized currently in earnings unless specific hedge criteria are met, which requires that a company must formally document, designate, and assess the effectiveness of transactions that receive hedge accounting.
      Accounting for derivatives at fair value requires the Company to make estimates about future prices during periods for which price quotes are not available from sources external to the Company. As a result, the Company is required to rely on internally developed price estimates when external price quotes are unavailable. The Company derives its future price estimates, during periods where external price quotes are unavailable, based on an extrapolation of prices from periods where external price quotes are available. The Company performs this extrapolation using liquid and observable market prices and extending those prices to an internally generated long-term price forecast based on a generalized equilibrium model.
      SFAS No. 133 sets forth the accounting requirements for cash flow and fair value hedges. SFAS No. 133 provides that the effective portion of the gain or loss on a derivative instrument designated and qualifying as a cash flow hedging instrument be reported as a component of other comprehensive income and be reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, must be recognized currently in earnings. SFAS No. 133 provides that the changes in fair value of derivatives designated as fair value hedges and the corresponding changes in the fair value of the hedged risk attributable to a recognized asset, liability, or unrecognized firm commitment be recorded in earnings. If the fair value hedge is effective, the amounts recorded will offset in earnings.
      With respect to cash flow hedges, if the forecasted transaction is no longer probable of occurring, the associated gain or loss recorded in other comprehensive income is recognized currently. In the case of fair value hedges, if the underlying asset, liability or firm commitment being hedged is disposed of or otherwise terminated, the gain or loss associated with the underlying hedged item is recognized currently. If the hedging instrument is terminated prior to the occurrence of the hedged forecasted transaction for cash flow hedges or the settlement of the hedged asset, liability or firm commitment for fair value hedges, the gain or loss associated with the hedge instrument remains deferred.
      Where the Company’s derivative instruments are subject to a master netting agreement and the criteria of FASB Interpretation (“FIN”) 39 “Offsetting of Amounts Related to Certain Contracts (An Interpretation of APB Opinion No. 10 and SFAS No. 105)” are met, the Company presents its derivative assets and liabilities on a net basis in its balance sheet. The Company has chosen this method of presentation because it is consistent with the way related mark-to-market gains and losses on derivatives are recorded in its Consolidated Statements of Operations and within Other Comprehensive Income (“OCI”).
      Mark-to-Market Activity, Net  — This includes realized settlements of and unrealized mark-to-market gains and losses on both power and gas derivative instruments undesignated as cash flow hedges, including those held for trading purposes. Gains and losses due to ineffectiveness on hedging instruments are also included in unrealized mark-to-market gains and losses. Trading activity is presented net in accordance with Emerging Issues Task Force (“EITF”) Issue No. 02-3, “Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (“EITF Issue No. 02-3”).
      Presentation of Revenue Under 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” (“EITF Issue
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No. 03-11”)  — 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 as a matter of scheduling convenience to eliminate the need to schedule actual power delivery or “book out” the physical power flows. 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 $370.5 million of purchased power expense against sales of purchased power during the three months ended March 31, 2004.
      New Accounting Pronouncements
      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” (“SFAS No. 123”) as amended by SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure” (“SFAS No. 148”). SFAS No. 148 amends 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 Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees” 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 provides two additional transition options to report the change in accounting principle — the modified prospective method and the retroactive restatement method. Additionally, SFAS No. 148 amends 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 has 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 earnings per share as if SFAS No. 123 accounting had been applied to all prior periods presented within its financial statements. As shown below, the 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 income and earnings per share for the three months ended March 31, 2004 and 2003,
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had the Company applied the accounting provisions of SFAS No. 123 to its prior years’ financial statements (in thousands, except per share amounts):

			
		Three Months Ended	
		March 31,	
			
		2004		2003	
					
Net income	 	 	 	 	 	 	 	 	
 	As reported	 	$	(71,192	)	 	$	(52,016	)	
 	Pro Forma	 	 	(72,839	)	 	 	(58,452	)	
Earnings per share data:	 	 	 	 	 	 	 	 	
 	Basic earnings per share	 	 	 	 	 	 	 	 	
 	 	As reported	 	$	(0.17	)	 	$	(0.14	)	
 	 	Pro Forma	 	 	(0.18	)	 	 	(0.15	)	
 	Diluted earnings per share	 	 	 	 	 	 	 	 	
 	 	As reported	 	$	(0.17	)	 	$	(0.14	)	
 	 	Pro Forma	 	 	(0.18	)	 	 	(0.15	)	
Stock-based compensation cost, net of tax, included in net income, as reported	 	$	2,581	 	 	$	3,367	 	
Stock-based compensation cost, net of tax, included in net income, pro forma	 	 	4,228	 	 	 	9,803	 	
      The range of fair values of the Company’s stock options granted for the three months ended March 31, 2004 and 2003, respectively, was as follows, based on varying historical stock option exercise patterns by different levels of Calpine employees: $3.37-$4.45 in 2004, $1.60-$3.43 in 2003, on the date of grant using the Black-Scholes option pricing model with the following weighted-average assumptions: expected dividend yields of 0%, expected volatility of 69.78%-97.99% and 70.44%-97.19% for the three months ended March 31, 2004 and 2003, respectively, risk-free interest rates of 2.35%-4.14% and 1.76%-4.04% for the three months ended March 31, 2004 and 2003, respectively, and expected option terms of 4-9 1/2 years and 2 1/2-9 1/2 years for the three months ended March 31, 2004 and 2003, respectively.
      In January 2003 FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities, an interpretation of ARB 51” (“FIN 46”). FIN 46 requires the consolidation of an entity by an enterprise that absorbs a majority of the entity’s expected losses, receives a majority of the entity’s expected residual returns, or both, as a result of ownership, contractual or other financial interest in the entity. Historically, entities have generally been consolidated by an enterprise when it has a controlling financial interest through ownership of a majority voting interest in the entity. The objectives of FIN 46 are to provide guidance on the identification of Variable Interest Entities (“VIEs”) for which control is achieved through means other than ownership of a majority of the voting interest of the entity, and how to determine which business enterprise (if any), as the Primary Beneficiary, should consolidate the Variable Interest Entity (“VIE”). This new model for consolidation applies to an entity in which either (1) the at-risk equity is insufficient to absorb expected losses without additional subordinated financial support or (2) its at-risk equity holders as a group are not able to make decisions that have a significant impact on the success or failure of the entity’s ongoing activities. A variable interest in a VIE, by definition, is an asset, liability, equity, contractual arrangement or other economic interest that absorbs the entity’s variability.
      In December 2003 FASB modified FIN 46 with FIN 46-R to make certain technical corrections and to address certain implementation issues. FIN 46, as originally issued, was effective immediately for VIEs created or acquired after January 31, 2003. FIN 46-R delayed the effective date of the interpretation to no later than March 31, 2004, (for calendar-year enterprises), except for Special Purpose Entities (“SPEs”) for which the effective date was December 31, 2003. The Company has adopted FIN 46-R for its investment in SPEs, equity method joint ventures, its wholly owned subsidiaries that are subject to long-term power
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purchase agreements and tolling arrangements, operating lease arrangements containing fixed price purchase options and its wholly owned subsidiaries that have issued mandatorily redeemable non-controlling preferred interests.
      The Company evaluated its investments in joint ventures and operating lease arrangements containing fixed price purchase options and concluded that, in some instances, these entities were VIEs. However, in these instances, the Company was not the Primary Beneficiary, as the Company would not absorb a majority of these entities’ expected variability. The fixed price purchase options under the Company’s operating lease arrangements were not considered significant variable interests. However, the Company’s investments in joint ventures were considered significant. See Note 7 for more information related to these joint venture investments.
      An analysis was performed for 100% Company-owned subsidiaries with significant long-term power sales or tolling agreements. Certain of the 100% Company-owned subsidiaries were deemed to be VIEs by virtue of a power sales or tolling agreement which was longer than 10 years and for more than 50% of the entity’s capacity. However, in all cases, the Company absorbed a majority of the entity’s variability and continues to consolidate these 100% Company-owned subsidiaries. The Company qualitatively determined that power sales or tolling agreements less than 10 years in length and for less than 50% of the entity’s capacity would not cause the power purchaser to be the Primary Beneficiary, due to the length of the economic life of the underlying assets. Also, power sales and tolling agreements meeting the definition of a lease under EITF Issue No. 01-08, “Determining Whether an Arrangement Contains a Lease,” were not considered variable interests, because payments under these leasing arrangements create rather than absorb the entity’s variability.
      A similar analysis was performed for the Company’s wholly owned subsidiaries that have issued mandatorily redeemable non-controlling preferred interests. These entities were determined to be VIEs in which the Company absorbs the majority of the variability, primarily due to the debt characteristics of the preferred interest, which are classified as debt in accordance with SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” in the Company’s Consolidated Condensed Balance Sheets. Consequently, the Company continues to consolidate these wholly owned subsidiaries.
      Significant judgment was required in making an assessment of whether or not a VIE was a special purpose entity (“SPE”) for purposes of adopting and applying FIN 46-R, as of October 31, 2003. Entities that meet the definition of a business outlined in FIN 46-R and that satisfy other formation and involvement criteria are not subject to the FIN 46-R consolidation guidelines. The definitional characteristics of a business include having: inputs such as long-lived assets; the ability to obtain access to necessary materials and employees; processes such as strategic management, operational process and resource management; and the ability to obtain access to the customers that purchase the outputs of the entity. Since the current accounting literature does not provide a definition of an SPE, the Company’s assessment was primarily based on the degree to which the VIE aligned with the definition of a business. Based on this assessment, the Company determined that five VIE investments were in SPEs: Calpine Northbrook Energy Marketing, LLC (“CNEM”), Power Contract Financing, L.L.C. (“PCF”) and the Calpine Capital Trusts I, II and III, and subject to FIN 46-R as of October 1, 2003.
      On May 15, 2003, the Company’s wholly owned subsidiary, CNEM, completed the $82.8 million monetization of an existing power sales agreement with the Bonneville Power Administration (“BPA”). CNEM borrowed $82.8 million secured by the spread between the BPA contract and certain fixed power purchase contracts. CNEM was established as a bankruptcy-remote entity and the $82.8 million loan is recourse only to CNEM’s assets and is not guaranteed by the Company. CNEM was determined to be a VIE in which the Company was the Primary Beneficiary. Accordingly, the entity’s assets and liabilities were consolidated into the Company’s accounts as of June 30, 2003.
      On June 13, 2003, PCF, a wholly owned stand-alone subsidiary of Calpine Energy Services, L.P. (“CES”), completed an offering of two tranches of Senior Secured Notes Due 2006 and 2010 (collectively
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called the “PCF Notes”), totaling $802.2 million. To facilitate the transaction, the Company formed PCF as a wholly owned, bankruptcy remote entity with assets and liabilities consisting of certain transferred power purchase and sales contracts, which serve as collateral for the PCF Notes. The PCF Notes are non-recourse to the Company’s other consolidated subsidiaries. PCF was determined to be a VIE in which the Company was the Primary Beneficiary. Accordingly, the entity’s assets and liabilities were consolidated into the Company’s accounts as of June 30, 2003.
      Upon adoption of FIN 46-R for the Company’s investments in SPEs, the Company determined that its equity investment in Calpine Capital Trusts I, II and III (“the Trusts”) was not considered at-risk as defined in FIN 46-R and that the Company did not have a significant variable interest in the Trusts. Consequently, the Company deconsolidated the Trusts.

3.	Collateral Debt Securities;	
      In connection with the plans of the Calpine Power Income Fund (“CPIF”) to acquire the King City Power Plant (see Note 15 for more information regarding this transaction) and become the lessor of the facility, the Company intends to sell certain investments previously accounted for as held-to-maturity. The table below reflects the reclassification of the collateral securities from held-to-maturity to available-for-sale in accordance with SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities” (“SFAS No. 115”). The following securities were, therefore, recorded at fair market value in Other Current Assets at March 31, 2004, with the excess over amortized cost recorded in Other Comprehensive Income (in thousands): 

			
		March 31, 2004	
			
				Gross		Gross			
				Unrealized		Unrealized			
				Gains in Other		Losses in Other			
		Amortized		Comprehensive		Comprehensive			
		Cost		Income		Income		Fair Value	
									
Corporate debt securities	 	$	12,422	 	 	$	432	 	 	$	—	 	 	$	12,854	 	
U.S. Treasury Notes	 	 	1,973	 	 	 	142	 	 	 	—	 	 	 	2,115	 	
U.S. Treasury Securities (non-interest bearing)	 	 	67,871	 	 	 	17,481	 	 	 	—	 	 	 	85,352	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Debt securities	 	$	82,266	 	 	$	18,055	 	 	$	—	 	 	$	100,321	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	
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4.	Property, Plant and Equipment, Net and Capitalized Interest;	
      As of March 31, 2004 and December 31, 2003, the components of property, plant and equipment, net, are stated at cost less accumulated depreciation and depletion as follows (in thousands):

		March 31,		December 31,	
		2004		2003	
					
Buildings, machinery, and equipment	 	$	13,795,049	 	 	$	13,226,310	 	
Oil and gas properties, including pipelines	 	 	2,112,964	 	 	 	2,136,740	 	
Geothermal properties	 	 	464,795	 	 	 	460,602	 	
Other	 	 	263,197	 	 	 	234,932	 	
 	 	 		 	 	 		 	
 	 	 	16,636,005	 	 	 	16,058,584	 	
Less: accumulated depreciation and depletion	 	 	(1,948,872	)	 	 	(1,834,701	)	
 	 	 		 	 	 		 	
 	 	 	14,687,133	 	 	 	14,223,883	 	
Land	 	 	97,139	 	 	 	95,037	 	
Construction in progress	 	 	5,952,397	 	 	 	5,762,132	 	
 	 	 		 	 	 		 	
Property, plant and equipment, net	 	$	20,736,669	 	 	$	20,081,052	 	

		
	Capital Spending — Construction and Development	
      Construction and Development costs in process consisted of the following at March 31, 2004 (in thousands):

						Equipment		Project			
		# of				Included in		Development		Unassigned	
		Projects		CIP		CIP		Costs		Equipment	
											
Projects in active construction	 	 	13	 	 	$	4,684,403	 	 	$	1,537,067	 	 	$	—	 	 	$	—	 	
Projects in advanced development	 	 	15	 	 	 	754,280	 	 	 	623,696	 	 	 	128,708	 	 	 	—	 	
Projects in suspended development	 	 	5	 	 	 	463,094	 	 	 	203,185	 	 	 	8,753	 	 	 	—	 	
Projects in early development	 	 	3	 	 	 	—	 	 	 	—	 	 	 	8,932	 	 	 	12,280	 	
Other capital projects	 	 	NA	 	 	 	50,620	 	 	 	31	 	 	 	—	 	 	 	—	 	
Unassigned	 	 	NA	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	54,789	 	
 	 	 	 	 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Total construction and development costs	 	 	 	 	 	$	5,952,397	 	 	$	2,363,979	 	 	$	146,393	 	 	$	67,069	 	
 	 	 	 	 	 	 		 	 	 		 	 	 		 	 	 		 	
      Construction in Progress  — 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 13 projects in active construction are estimated to come on line from May 2004 to June 2007. These projects will bring on line approximately 6,495 MW of base load capacity (7,685 MW base load 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 March 31, 2004, the estimated funding requirements to complete these projects, net of expected project financing proceeds, is approximately $1.2 billion.
      Projects in Advanced Development  — There are 15 projects in advanced development. These projects will bring on line approximately 6,735 MW of base load capacity (7,952 MW base load with peaking capacity).
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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 two projects for which development activities are complete. The estimated cost to complete the 15 projects in advanced development is approximately $4.4 billion. The Company’s current plan is to commence construction with project financing, once power purchase agreements are arranged.
      Suspended Development Projects  — Due to current electric market conditions, the Company has ceased capitalization of additional development costs and interest expense on certain development projects on which work has been suspended. Capitalization of costs may recommence as work on these projects resumes, if certain milestones and criteria are met. These projects would bring on line approximately 2,569 MW of base load capacity(3,029 MW base load with peaking capacity). The estimated cost to complete the five projects is approximately $1.5 billion.
      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 three projects and include geothermal drilling costs and equipment purchases.
      Other Capital Projects  — Other capital projects primarily consist of enhancements to operating power plants, oil and gas and geothermal resource and facilities development as well as software developed for internal use.
      Unassigned Equipment  — As of March 31, 2004, the Company had made progress payments on 4 turbines, 1 heat recovery steam generator and other equipment with an aggregate carrying value of $67.1 million This unassigned equipment is classified on the 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. For equipment that is not assigned to development or construction projects, interest is not capitalized.
      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” (“SFAS No. 34”), 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)” (“SFAS No. 58”). The Company’s qualifying assets include construction in progress, certain oil and gas properties under development, construction costs related to unconsolidated investments in power projects under construction, and advanced stage development costs. For the three months ended March 31, 2004 and 2003, the total amount of interest capitalized was $108.5 million and $118.5 million, respectively, including $18.5 million and $19.6 million, respectively, of interest incurred on funds borrowed for specific construction projects and $90.0 million and $98.9 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 months ended March 31, 2004 reflects the completion of construction for several power plants and the result of the current suspension of certain of the Company’s development projects.
      In accordance with SFAS No. 34, the Company determines which debt instruments best represent a reasonable measure of the cost of financing construction assets in terms of interest cost incurred that otherwise could have been avoided. These debt instruments and associated interest cost are included in the calculation of the weighted average interest rate used for capitalizing interest on general funds. The primary debt instruments included in the rate calculation of interest incurred on general corporate funds, are certain of the Company’s Senior Notes and term loan facilities and the secured working capital revolving credit facility.
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      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 “Accounting for the Impairment or Disposal of Long-Lived Assets” (“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 not committed to sale is impaired.

5.	Acquisitions	
      On March 23, 2004, the Company completed the acquisition of the remaining 20% interest in Calpine Cogeneration Company (“Calpine Cogen”), which holds interests in six power facilities, from NRG Energy, Inc. (“NRG”) for approximately $2.5 million. The Company had purchased its initial 80% interest in Calpine Cogen (formerly known as Cogeneration Corporation of America) from NRG in 1999. As a result of the current transaction, the Company now has a 100% interest in the Newark, Parlin, Morris and Pryor facilities, an 83% interest in the Philadelphia Water Project, and a 50% interest in the Grays Ferry Power Plant.
      On March 26, 2004, the Company acquired the remaining 50% interest in the Aries facility from a subsidiary of Aquila, Inc. (Aquila and its subsidiaries referred to collectively as “Aquila”). At the same time, Aries terminated a tolling contract with another subsidiary of Aquila. Aquila paid $5 million and assigned certain transmission and other rights to the Company. Aquila and the Company also amended a master netting agreement between them, and as a result, the Company returned cash margin deposits totaling $10.8 million to Aquila. Contemporaneous with the closing of the acquisition, Aries’ existing construction loan was converted to two term loans totaling $178.8 million. The Company contributed $15 million of equity to Aries in connection with the term out of the construction loan.
      On March 31, 2004, the Company closed on the purchase of the 570-megawatt, natural gas-fired, Brazos Valley Power Plant (“Brazos Valley”) in Fort Bend County, Texas, for approximately $175.0 million. The Company used the net proceeds from the sale of Lost Pines 1 and cash on hand to acquire this facility in a transaction structured as a tax deferred like-kind exchange under IRS Section 1031. The consortium of banks that had provided construction financing for the power plant and had taken possession of the plant from the original developer in 2003 indirectly owned the special purpose companies that owned Brazos Valley. Brazos Valley has become part of the collateral package for the Calpine Construction Finance Company, L.P. (“CCFC I”) First Priority Secured Institutional Term Loans Due 2009 and Second Priority Senior Secured Floating Rate Notes Due 2011.

6.	Financing	
      On January 9, 2004, one of the initial purchasers of the 4 3/4% Contingent Convertible Senior Notes Due 2023 (“2023 Convertible Notes”) exercised in full its option to purchase an additional $250.0 million of these notes. The notes are convertible into cash and into shares of Calpine common stock upon the occurrence of certain contingencies at an initial conversion price of $6.50 per share, which represents a 38% premium over the New York Stock Exchange closing price of $4.71 per share on November 6, 2003, the date the notes were originally priced. Upon conversion of the notes, the Company will deliver par value in cash and any additional value in Calpine shares.
      During the three months ended March 31, 2004, the Company repurchased $178.5 million in principal amount of its outstanding 4% Convertible Senior Notes Due 2006 (“2006 Convertible Senior Notes”) that can be put to the Company in exchange for $177.5 million in cash. Additionally, on February 9, 2004, the Company made a cash tender offer, which expired on March 9, 2004, for any and all of the then still
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS — (Continued)
outstanding 2006 Convertible Senior Notes at a price of par plus accrued interest. On March 10, 2004, the Company paid an aggregate amount of $412.8 million for the tendered 2006 Convertible Senior Notes which included accrued interest of $3.4 million. At March 31, 2004, 2006 Convertible Senior Notes in the aggregate principal amount of $72.1 million remain outstanding.
      On February 18, 2004, one of the Company’s wholly owned subsidiaries closed on the sale of natural gas properties to Calpine Natural Gas Trust (“CNG Trust”). The Company received consideration of Cdn$ 40.5 million (US$30.9 million). Calpine holds 25% of the outstanding trust units of CNG Trust and accounts for the investment using the equity method. The Company recorded a $6.2 million pre-tax gain on the sale of these properties.
      On February 20, 2004, the Company completed a $250.0 million, non-recourse project financing for the 600-megawatt Rocky Mountain Energy Center. A consortium of banks financed the construction of the plant at a rate of LIBOR plus 250 basis points. Upon commercial operation of the Rocky Mountain Energy Center, the banks will provide a three-year term-loan facility.
      On March 23, 2004, the Company’s wholly owned subsidiary Calpine Generating Company, LLC (“CalGen”), formerly known as Calpine Construction Finance Company II, LLC (“CCFC II”), completed its offering of secured term loans and secured notes. As expected, the Company realized net total proceeds from the offerings (after payment of transaction fees and expenses, including the fee payable to Morgan Stanley in connection with an index hedge) in the approximate amount of $2.3 billion. The offerings included: 

Amount		Description		Interest Rate	
					
$235.0 million	 	First Priority Secured Floating Rate Notes Due 2009	 	LIBOR plus 375 basis points	
$640.0 million	 	Second Priority Secured Floating Rate Notes Due 2010	 	LIBOR plus 575 basis points	
$680.0 million	 	Third Priority Secured Floating Rate Notes Due 2011	 	LIBOR plus 900 basis points	
$150.0 million	 	Third Priority Secured Notes Due 2011	 	11.50%	
$600.0 million	 	First Priority Secured Term Loans due 2009	 	LIBOR plus 375 basis points(1)	
$100.0 million	 	Second Priority Secured Term Loans due 2010	 	LIBOR plus 575 basis points(2)	

		
(1) 	The Company may also elect a Base Rate plus 275 basis points.	
 		
(2) 	The Company may also elect a Base Rate plus 475 basis points.	
      The secured term loans and secured notes described above in each case are collateralized, through a combination of pledges of the equity interests in CalGen and its first tier subsidiary, CalGen Expansion Company, liens on the assets of CalGen’s power generating facilities (other than its Goldendale facility) and related assets located throughout the United States. The lenders’ recourse is limited to such collateral, and none of the indebtedness is guaranteed by Calpine. Net proceeds from the offerings were used to refinance amounts outstanding under the $2.5 billion CCFC II revolving construction credit facility, which was scheduled to mature in November 2004, and to pay fees and transaction costs associated with the refinancing. Concurrently with this refinancing, the Company amended and restated the CCFC II credit facility (as amended and restated, the “CalGen revolving credit facility”) to reduce the commitments under the facility to $200.0 million and extend its maturity to March 2007. Borrowings under the CalGen revolving credit facility bear interest at LIBOR plus 350 basis points (or, at the Company’s election, the Base Rate plus 250 basis points). Outstanding indebtedness and letters of credit under the CCFC II credit facility at December 31, 2003, and at the refinancing date, totaled approximately $2.3 billion and $2.4 billion, respectively.
      On March 24, 2004, the Company repurchased $9.0 million in principal amount of its outstanding 8 1/2% Senior Notes Due 2011 and $11.0 million in principal amount of its outstanding 7 3/4% Senior Notes Due
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS — (Continued)
2009, in exchange for approximately $14.8 million in cash. A gain of $5.0 million, net of deferred financing costs written off, was recognized in the first quarter of 2004.

	Annual Debt Maturities	
      The annual principal repayments or maturities of notes payable and borrowings under lines of credit, notes payable to Calpine Capital Trusts, preferred interests, construction/project financing, 2006 Convertible Senior Notes, 2023 Convertible Notes, senior notes and term loans, CCFC I financing, CalGen/ CCFC II financing and capital lease obligations as of March 31, 2004, are as follows (in thousands): 

April through December 2004	 	$	245,934	 	
2005	 	 	526,637	 	
2006	 	 	775,461	 	
2007	 	 	2,371,194	 	
2008	 	 	2,620,659	 	
Thereafter	 	 	11,245,881	 	
 	 	 		 	
 	Total	 	$	17,785,766	 	

		
7.	Investments in Power Projects and Oil and Gas Properties	
      The Company’s investments in power projects and oil and gas properties are integral to its operations. As discussed in Note 2, the Company’s joint venture investments were evaluated under FIN 46-R to determine which, if any, entities were VIEs. Based on this evaluation, the Company determined that the Acadia Energy Center, Grays Ferry Power Plant, Whitby Cogeneration facility and the Androscoggin Power Plant were VIEs, in which the Company held a significant variable interest. However, based on a qualitative and quantitative assessment of the expected variability in these entities, the Company was not the primary beneficiary. Consequently, the Company continues to account for these VIEs and its other joint venture investments in power projects in accordance with APB Opinion No. 18, “The Equity Method of Accounting For Investments in Common Stock” and FASB Interpretation No. 35, “Criteria for Applying the Equity Method of Accounting for Investments in Common Stock (An Interpretation of APB Opinion No. 18).”
      Acadia Powers Partners, LLC (“Acadia”) is the owner of a 1,160-megawatt electric wholesale generation facility 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 at March 31, 2004, is limited to the book value of its investment of approximately $224.1 million.
      Grays Ferry Cogeneration Partnership (“Grays Ferry”) is the owner of a 140-megawatt gas-fired cogeneration facility located in Pennsylvania and is 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, Cogeneration Corporation of America, Inc. (“Cogen America”) in December 1999. The Grays Ferry joint venture project was part of the portfolio of assets owned by Cogen America. The Company’s maximum potential exposure to loss at March 31, 2004, is limited to the book value of its investment of approximately $48.4 million.
      Androscoggin Energy LLC (“AELLC”) is the owner of a 160-megawatt gas-fired cogeneration facility located in Maine and is a joint venture between the Company, Wisvest Corporation and Androscoggin Energy, Inc. The Company’s involvement in this VIE began with its acquisition of the independent power producer, SkyGen Energy LLC (“SkyGen”) in October 2000. The Androscoggin joint venture project was part of the portfolio of assets owned by SkyGen. The Company’s maximum potential exposure to loss at March 31, 2004, is limited to $29.0 million, which represents the book value of its investment of approximately $14.2 million and a notes receivable balance due from AELLC of $14.8 million as described below.
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      Whitby Energy LLP (“Whitby”) is the owner of a 50-megawatt 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 Energy Inc. (“Westcoast”) in September 2001, which included the Whitby joint venture project. The Company’s maximum potential exposure to loss at March 31, 2004, is limited to the book value of its investment of approximately $35.1 million.
      The following investments are accounted for under the equity method (in thousands): 

					
		Ownership		Investment Balance at	
		Interest as of			
		March 31,		March 31,		December 31,	
		2004		2004		2003	
							
Acadia Energy Center	 	 	50.0	%	 	$	224,080	 	 	$	221,038	 	
Valladolid III IPP	 	 	45.0	%	 	 	69,255	 	 	 	67,320	 	
Grays Ferry Power Plant(1)	 	 	50.0	%	 	 	48,352	 	 	 	53,272	 	
Whitby Cogeneration	 	 	20.8	%	 	 	35,083	 	 	 	31,033	 	
Calpine Natural Gas Trust	 	 	25.0	%	 	 	25,714	 	 	 	28,598	 	
Androscoggin Power Plant	 	 	32.3	%	 	 	14,174	 	 	 	11,823	 	
Aries Power Plant(2)	 	 	100.0	%	 	 	—	 	 	 	58,205	 	
Other	 	 	—	 	 	 	1,320	 	 	 	1,460	 	
 	 	 	 	 	 	 		 	 	 		 	
 	Total investments in power projects and oil and gas properties	 	 	 	 	 	$	417,978	 	 	$	472,749	 	

		
(1) 	On March 23, 2004, the Company completed the acquisition of the remaining 20% interest in Calpine Cogen. As a result of the acquisition, the Company’s ownership percentage in the Grays Ferry Power Plant increased to 50%. See Note 5 for information on the acquisition.	
 		
(2) 	On March 26, 2004, the Company acquired the remaining 50 percent interest in Aries Power Plant. Accordingly, this plant is consolidated as of March 31, 2004. See Note 5 for information on the acquisition.	
      The debt on the books of the unconsolidated power projects is not reflected on the Company’s Consolidated Condensed Balance Sheets. At March 31, 2004, investee debt is approximately $289.6 million. Based on the Company’s pro rata ownership share of each of the investments, the Company’s share would be approximately $61.5 million. However, all such debt is non-recourse to the Company.
      The Company owns a 32.3% interest in the unconsolidated equity method investee AELLC. AELLC owns the 160-MW Androscoggin Energy Center located in Maine and has construction debt of $60.1 million outstanding as of March 31, 2004. The debt is non-recourse to Calpine Corporation (the “AELLC Non-Recourse Financing”). On March 31, 2004, and December 31, 2003, the Company’s investment balance was $14.2 million and $11.8 million, respectively, and its notes receivable balance due from AELLC was $14.8 million and $13.3 million, respectively. On and after August 8, 2003, AELLC received letters from the lenders claiming that certain events of default have occurred under the credit agreement for the AELLC Non-Recourse Financing, including, among other things, that the project has been and remains in default under its debt agreement because the lending syndication had declined to extend the dates for the conversion of the construction loan to a term loan by a certain date. AELLC disputes the purported defaults. Also, the steam host for the AELLC project, International Paper Company (“IP”), filed a complaint against AELLC in October 2000, which is disclosed in Note 12. IP’s complaint has been a complicating factor in converting the construction debt to long term financing. As a result of these events, the Company has reviewed its investment and notes receivable balances and believes that the assets are not impaired. The Company further believes that AELLC will eventually be able to convert the construction loan to a term loan.
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS — (Continued)
      The following details the Company’s income and distributions from investments in unconsolidated power projects and oil and gas properties (in thousands):

							
		Income (Loss) from					
		Unconsolidated					
		Investments in Power					
		Projects and Oil and			
		Gas Properties		Distributions	

		For the Three Months Ended March 31,	
			
		2004		2003		2004		2003	
									
Acadia Energy Center	 	$	5,217	 	 	$	7,618	 	 	$	2,193	 	 	$	9,396	 	
Aries Power Plant	 	 	(1,589	)	 	 	(2,225	)	 	 	—	 	 	 	—	 	
Grays Ferry Power Plant	 	 	(1,851	)	 	 	26	 	 	 	—	 	 	 	—	 	
Whitby Cogeneration	 	 	317	 	 	 	638	 	 	 	565	 	 	 	—	 	
Calpine Natural Gas Trust	 	 	1,321	 	 	 	—	 	 	 	2,313	 	 	 	—	 	
Androscoggin Power Plant	 	 	(1,252	)	 	 	(2,876	)	 	 	—	 	 	 	—	 	
Gordonsville Power Plant(1)	 	 	—	 	 	 	1,910	 	 	 	—	 	 	 	—	 	
Other	 	 	109	 	 	 	5	 	 	 	69	 	 	 	5	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Total	 	$	2,272	 	 	$	5,096	 	 	$	5,140	 	 	$	9,401	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	
Interest income on notes receivable from power projects(2)	 	$	234	 	 	$	29	 	 	 	 	 	 	 	 	 	
 	 	 		 	 	 		 	 	 	 	 	 	 	 	 	
 	Total	 	$	2,506	 	 	$	5,125	 	 	 	 	 	 	 	 	 	

      The Company provides for deferred taxes on its share of earnings.

		
(1) 	On November 26, 2003, the Company completed the sale of its 50 percent interest in the Gordonsville Power Plant.	
 		
(2) 	At March 31, 2004, and December 31, 2003, notes receivable from power projects represented an outstanding loan to the Company’s investment, Androscoggin Energy Center LLC, in the amounts of $14.8 million and $13.3 million, respectively.	

	Related-Party Transactions	
      The Company and certain of its equity 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:

		
 	      Operation and Maintenance Agreements  — The Company operates and maintains the Acadia Power Plant and Androscoggin Power Plant. 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.	
 		
 	      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 the Company’s Androscoggin Power Plant, 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.	
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 	      Gas Supply Agreement  — CES can be directed to supply gas to the Androscoggin Power Plant 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.
      All of the other power marketing and gas supply contracts are accounted for as purchases and sales.
      The related party balances as of March 31, 2004 and December 31, 2003, reflected in the accompanying Consolidated Condensed Balance Sheets, and the related party transactions for the three months ended March 31, 2004, and 2003, reflected in the accompanying Consolidated Condensed Statements of Operations are summarized as follows (in thousands): 

		March 31,		December 31,	
		2004		2003	
					
Accounts receivable	 	$	6,821	 	 	$	1,156	 	
Accounts payable	 	 	9,985	 	 	 	12,172	 	
Interest receivable	 	 	1,656	 	 	 	2,074	 	
Note Receivable	 	 	14,802	 	 	 	13,262	 	
Other receivables	 	 	9,489	 	 	 	8,794	 	
 	 	 	 	 	 	 	 	 	
		2004		2003	
For the Three Months Ended March 31,					
Revenue	 	$	647	 	 	$	455	 	
Cost of Revenue	 	 	32,746	 	 	 	13,387	 	
Maintenance fee revenue	 	 	139	 	 	 	143	 	
Interest income	 	 	234	 	 	 	29	 	
Gain on sale of assets	 	 	6,240	 	 	 	—	 	

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 March 31, 2004 and December 31, 2003:

	Corporate and Other	
      On July 31, 2003, the Company completed the sale of its specialty data center engineering business and recorded a pre-tax loss on the sale of $11.6 million.

	Oil and Gas Production and Marketing	
      On November 20, 2003, the Company completed the sale of its Alvin South Field oil and gas assets located near Alvin, Texas for approximately $0.06 million to Cornerstone Energy, Inc. As a result of the sale, the Company recognized a pre-tax loss of $0.2 million.

	Electric Generation and Marketing	
      On January 15, 2004, the Company completed the sale of its 50-percent undivided interest in the 545 megawatt Lost Pines 1 Power Project to GenTex Power Corporation, an affiliate of the Lower Colorado
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River Authority (LCRA). Under the terms of the agreement, Calpine received a cash payment of $146.8 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 megawatts of electricity through December 31, 2004. At December 31, 2003, the Company’s undivided interest in the Lost Pines facility was classified as “held for sale.”

	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.
      The tables below present significant components of the Company’s income from discontinued operations for the three months ended March 31, 2004, and 2003, respectively (in thousands): 

			
		Three Months Ended March 31, 2004	
			
		Electric		Oil and Gas		Corporate			
		Generation		Production		and			
		and Marketing		and Marketing		Other		Total	
									
Total revenue	 	$	2,679	 	 	$	—	 	 	$	—	 	 	$	2,679	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	
Gain on disposal before taxes	 	$	35,327	 	 	$	—	 	 	$	—	 	 	$	35,327	 	
Operating loss from discontinued operations before taxes	 	 	(145	)	 	 	—	 	 	 	—	 	 	 	(145	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	
Income from discontinued operations before taxes	 	$	35,182	 	 	$	—	 	 	$	—	 	 	 	35,182	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	
Gain on disposal, net of tax	 	$	22,951	 	 	$	—	 	 	$	—	 	 	$	22,951	 	
Operating loss from discontinued operations, net of tax	 	 	(94	)	 	 	—	 	 	 	—	 	 	 	(94	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	
Income from discontinued operations, net of tax	 	$	22,857	 	 	$	—	 	 	$	—	 	 	$	22,857	 	

			
		Three Months Ended March 31, 2003	
			
		Electric		Oil and Gas		Corporate			
		Generation		Production		and			
		and Marketing		and Marketing		Other		Total	
									
Total revenue	 	$	18,503	 	 	$	78	 	 	$	1,763	 	 	$	20,344	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	
Gain on disposal before taxes	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	
Operating income (loss) from discontinued operations before taxes	 	 	878	 	 	 	30	 	 	 	(2,705	)	 	 	(1,797	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	
Income (loss) from discontinued operations before taxes	 	$	878	 	 	$	30	 	 	$	(2,705	)	 	$	(1,797	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	
Gain on disposal, net of tax	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	
Operating income (loss) from discontinued operations, net of tax	 	 	570	 	 	 	19	 	 	 	(1,596	)	 	 	(1,007	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	
Income (loss) from discontinued operations, net of tax	 	$	570	 	 	$	19	 	 	$	(1,596	)	 	$	(1,007	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	
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9.	Derivative Instruments	

	Commodity Derivative Instruments	
      As an independent power producer primarily focused on generation of electricity using gas-fired turbines, the Company’s natural physical commodity position is “short” fuel (i.e., natural gas consumer) and “long” power (i.e., electricity seller). To manage forward exposure to price fluctuation in these commodities, the Company enters into derivative commodity instruments. The Company enters into commodity instruments to convert floating or indexed electricity and gas prices to fixed prices in order to lessen its vulnerability to reductions in electric prices for the electricity it generates, to reductions in gas prices for the gas it produces, and to increases in gas prices for the fuel it consumes in its power plants. The Company seeks to “self-hedge” its gas consumption exposure to an extent with its own gas production position. The hedging, balancing, or optimization activities that the Company engages in are directly related to the Company’s asset-based business model of owning and operating gas-fired electric power plants and are designed to protect the Company’s “spark spread” (the difference between the Company’s fuel cost and the revenue it receives for its electric generation). The Company hedges exposures that arise from the ownership and operation of power plants and related sales of electricity and purchases of natural gas, and the Company utilizes derivatives to optimize the returns the Company is able to achieve from these assets for the Company’s shareholders. From time to time the Company has entered into contracts considered energy trading contracts under EITF Issue No. 02-3. However, the Company’s traders have low capital at risk and value at risk limits for energy trading, and its risk management policy limits, at any given time, its net sales of power to its generation capacity and limits its net purchases of gas to its fuel consumption requirements on a total portfolio basis. This model is markedly different from that of companies that engage in significant commodity trading operations that are unrelated to underlying physical assets. Derivative commodity instruments are accounted for under the requirements of SFAS No. 133.
      The Company also routinely enters into physical commodity contracts for sales of its generated electricity and sales of its natural gas production to ensure favorable utilization of generation and production assets. Such contracts often meet the criteria of SFAS No. 133 as derivatives but are generally eligible for the normal purchases and sales exception. Some of those contracts that are not deemed normal purchases and sales can be designated as hedges of the underlying consumption of gas or production of electricity.

	Interest Rate and Currency Derivative Instruments	
      The Company also enters into various interest rate swap agreements to hedge against changes in floating interest rates on certain of its project financing facilities. The interest rate swap agreements effectively convert floating rates into fixed rates so that the Company can predict with greater assurance what its future interest costs will be and protect itself against increases in floating rates.
      In conjunction with its capital markets activities, the Company enters into various forward interest rate agreements to hedge against interest rate fluctuations that may occur after the Company has decided to issue long-term fixed rate debt but before the debt is actually issued. The forward interest rate agreements effectively prevent the interest rates on anticipated future long-term debt from increasing beyond a certain level, allowing the Company to predict with greater assurance what its future interest costs on fixed rate long-term debt will be.
      The Company enters into various foreign currency swap agreements to hedge against changes in exchange rates on certain of its senior notes denominated in currencies other than the U.S. dollar. The foreign currency swaps effectively convert floating exchange rates into fixed exchange rates so that the Company can predict with greater assurance what its U.S. dollar cost will be for purchasing foreign currencies to satisfy the interest and principal payments on these senior notes.
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS — (Continued)

	Summary of Derivative Values	
      The table below reflects the amounts (in thousands) that are recorded as assets and liabilities at March 31, 2004, for the Company’s derivative instruments:

				Commodity			
		Interest Rate		Derivative		Total	
		Derivative		Instruments		Derivative	
		Instruments		Net		Instruments	
							
Current derivative assets	 	$	6,539	 	 	$	573,025	 	 	$	579,564	 	
Long-term derivative assets	 	 	—	 	 	 	753,124	 	 	 	753,124	 	
 	 	 		 	 	 		 	 	 		 	
 	Total assets	 	$	6,539	 	 	$	1,326,149	 	 	$	1,332,688	 	
 	 	 		 	 	 		 	 	 		 	
Current derivative liabilities	 	$	21,802	 	 	$	529,389	 	 	$	551,191	 	
Long-term derivative liabilities	 	 	62,532	 	 	 	688,278	 	 	 	750,810	 	
 	 	 		 	 	 		 	 	 		 	
 	Total liabilities	 	$	84,334	 	 	$	1,217,667	 	 	$	1,302,001	 	
 	 	 		 	 	 		 	 	 		 	
 	 	Net derivative assets (liabilities)	 	$	(77,795	)	 	$	108,482	 	 	$	30,687	 	
 	 	 		 	 	 		 	 	 		 	
      Of the Company’s net derivative assets, $393.6 million and $76.4 million are net derivative assets of Power Contract Financing, LLC and Calpine Northbrook Energy Marketing, LLC, respectively, each of which is an entity with its existence separate from the Company and other subsidiaries of the Company, but both of which are consolidated by the Company pursuant to FIN 46.
      At any point in time, it is highly unlikely that total net derivative assets and liabilities will equal accumulated OCI, net of tax from derivatives, for three primary reasons:

			
 	• 	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.	
 		
 	• 	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.	
 		
 	• 	Termination of effective cash flow hedges prior to maturity  — Following the termination of a cash flow hedge, changes in the derivative asset or liability are no longer recorded to OCI. At this point, an accumulated OCI balance remains that is not recognized in earnings until the forecasted 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 assets to its accumulated other comprehensive loss, net of tax from derivative instruments at March 31, 2004 (in thousands): 

Net derivative assets	 	$	30,687	 	
Derivatives not designated as cash flow hedges and recognized hedge ineffectiveness	 	 	(72,727	)	
Cash flow hedges terminated prior to maturity	 	 	(160,757	)	
Deferred tax asset attributable to accumulated other comprehensive loss on cash flow hedges	 	 	63,965	 	
Accumulated OCI from unconsolidated investees	 	 	21,478	 	
 	 	 		 	
Accumulated other comprehensive loss from derivative instruments, net of tax(1)	 	$	(117,354	)	
 	 	 		 	
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS — (Continued)

		
(1) 	Amount represents one portion of the Company’s total accumulated OCI balance. See Note 10 for further information.	
      The asset and liability balances for the Company’s commodity derivative instruments represent the net totals after offsetting certain assets against certain liabilities under the criteria of FASB Interpretation No. 39, “Offsetting of Amounts Related to Certain Contracts (an Interpretation of APB Opinion No. 10 and FASB Statement No. 105)” (“FIN 39”). For a given contract, FIN 39 will allow the offsetting of assets against liabilities so long as four criteria are met: (1) each of the two parties under contract owes the other determinable amounts; (2) the party reporting under the offset method has the right to set off the amount it owes against the amount owed to it by the other party; (3) the party reporting under the offset method intends to exercise its right to set off; and; (4) the right of set-off is enforceable by law. The table below reflects both the amounts (in thousands) recorded as assets and liabilities by the Company and the amounts that would have been recorded had the Company’s commodity derivative instrument contracts not qualified for offsetting as of March 31, 2004. 

			
		March 31, 2004	
			
		Gross		Net	
					
Current derivative assets	 	$	928,478	 	 	$	573,025	 	
Long-term derivative assets	 	 	1,161,134	 	 	 	753,124	 	
 	 	 		 	 	 		 	
 	Total derivative assets	 	$	2,089,612	 	 	$	1,326,149	 	
 	 	 		 	 	 		 	
Current derivative liabilities	 	$	888,778	 	 	$	529,389	 	
Long-term derivative liabilities	 	 	1,092,352	 	 	 	688,278	 	
 	 	 		 	 	 		 	
 	Total derivative liabilities	 	$	1,981,130	 	 	$	1,217,667	 	
 	 	 		 	 	 		 	
 	 	Net commodity derivative assets	 	$	108,482	 	 	$	108,482	 	
 	 	 		 	 	 		 	
      The table above excludes the value of interest rate and currency derivative instruments.
      The tables below reflect the impact of the Company’s derivative instruments on its pre-tax earnings, both from cash flow hedge ineffectiveness and from the changes in market value of derivatives not designated as hedges of cash flows, for the three months ended March 31, 2004 and 2003, respectively (in thousands): 

			
		Three Months Ended March 31,	

		2004		2003	
					
		Hedge		Undesignated				Hedge		Undesignated			
		Ineffectiveness		Derivatives		Total		Ineffectiveness		Derivatives		Total	
													
Natural gas derivatives(1)	 	$	5,446	 	 	$	637	 	 	$	6,083	 	 	$	6,113	 	 	$	(1,977	)	 	$	4,136	 	
Power derivatives(1)	 	 	(540	)	 	 	(10,488	)	 	 	(11,028	)	 	 	(3,026	)	 	 	(1,881	)	 	 	(4,907	)	
Interest rate derivatives(2)	 	 	(398	)	 	 	96	 	 	 	(302	)	 	 	(209	)	 	 	—	 	 	 	(209	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Total	 	$	4,508	 	 	$	(9,755	)	 	$	(5,247	)	 	$	2,878	 	 	$	(3,858	)	 	$	(980	)	

		
(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 within Other Income.	
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS — (Continued)
      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 months ended March 31, 2004 and 2003, respectively (in thousands):

		2004		2003	
					
Natural gas and crude oil derivatives	 	$	193	 	 	$	35,162	 	
Power derivatives	 	 	(12,768	)	 	 	(51,326	)	
Interest rate derivatives	 	 	(2,772	)	 	 	(10,642	)	
Foreign currency derivatives	 	 	(516	)	 	 	12,557	 	
 	 	 		 	 	 		 	
 	Total derivatives	 	$	(15,863	)	 	$	(14,249	)	
 	 	 		 	 	 		 	
      As of March 31, 2004 the maximum length of time over which the Company was hedging its exposure to the variability in future cash flows for forecasted transactions was 8 and 14 years, for commodity and interest rate derivative instruments, respectively. The Company estimates that pre-tax losses of $55.9 million would be reclassified from accumulated OCI into earnings during the twelve months ended March 31, 2005, as the hedged transactions affect earnings assuming constant gas and power prices, interest rates, and exchange rates over time; however, the actual amounts that will be reclassified will likely vary based on the probability that gas and power prices as well as interest rates and exchange rates will, in fact, change. Therefore, management is unable to predict what the actual reclassification from OCI to earnings (positive or negative) will be for the next twelve months.
      The table below presents (in thousands) the pre-tax gains (losses) currently held in OCI that will be recognized annually into earnings, assuming constant gas and power prices, interest rates, and exchange rates over time. 

												2009 &			
		2004		2005		2006		2007		2008		After		Total	
															
Gas OCI	 	$	49,468	 	 	$	(893	)	 	$	30,731	 	 	$	1,181	 	 	$	1,060	 	 	$	2,541	 	 	$	84,088	 	
Power OCI	 	 	(65,443	)	 	 	(64,935	)	 	 	(46,304	)	 	 	(2,037	)	 	 	31	 	 	 	64	 	 	 	(178,624	)	
Interest rate OCI	 	 	(13,629	)	 	 	(16,769	)	 	 	(12,060	)	 	 	(8,602	)	 	 	(5,163	)	 	 	(24,021	)	 	 	(80,244	)	
Foreign currency OCI	 	 	(1,377	)	 	 	(1,879	)	 	 	(1,879	)	 	 	(1,489	)	 	 	85	 	 	 	—	 	 	 	(6,539	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Total pre-tax OCI	 	$	(30,981	)	 	$	(84,476	)	 	$	(29,512	)	 	$	(10,947	)	 	$	(3,987	)	 	$	(21,416	)	 	$	(181,319	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS — (Continued)

10.	Comprehensive Income (Loss)	
      Comprehensive income is the total of net income and all other non-owner changes in equity. Comprehensive income includes the Company’s net income, unrealized gains and losses from derivative instruments that qualify as cash flow hedges and the effects of foreign currency translation adjustments. The Company reports Accumulated Other Comprehensive Income (“AOCI”) in its Consolidated Balance Sheet. The tables below detail the changes during the three months ended March 31, 2004 and 2003, in the Company’s AOCI balance and the components of the Company’s comprehensive income (in thousands): 

								Total		Comprehensive	
								Accumulated		Income (Loss)	
				Available-		Foreign		Other		for the Three	
		Cash Flow		for-Sale		Currency		Comprehensive		Months Ended	
		Hedges		Investments		Translation		Income		March 31, 2004	
											
Accumulated other comprehensive income (loss) at January 1, 2004	 	$	(130,419	)	 	$	—	 	 	$	187,013	 	 	$	56,594	 	 	 	 	 	
Net loss	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	$	(71,192	)	
 	Cash flow hedges:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Comprehensive pre-tax gain on cash flow hedges before reclassification adjustment during the three months ended March 31, 2004	 	 	4,426	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reclassification adjustment for gain included in net loss for the three months ended March 31, 2004	 	 	15,863	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Income tax provision for the three months ended March 31, 2004	 	 	(7,224	)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 		 	 	 	 	 	 	 	 	 	 	 		 	 	 		 	
 	 	 	13,065	 	 	 	 	 	 	 	 	 	 	 	13,065	 	 	 	13,065	 	
 	Available-for-sale investments:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Pre-tax gain on available-for-sale investments for the three months ended March 31, 2004	 	 	 	 	 	 	19,526	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Income tax provision for the three months ended March 31, 2004	 	 	 	 	 	 	(7,709	)	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 		 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	11,817	 	 	 	 	 	 	 	11,817	 	 	 	11,817	 	
 	 	Foreign currency translation gain for the three months ended March 31, 2004	 	 	 	 	 	 	 	 	 	 	2,078	 	 	 	2,078	 	 	 	2,078	 	
 	 	 		 	 	 	 	 	 	 		 	 	 		 	 	 		 	
Total comprehensive loss for the three months ended March 31, 2004	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	$	(44,232	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 		 	
Accumulated other comprehensive income (loss) at March 31, 2004	 	$	(117,354	)	 	$	11,817	 	 	$	189,091	 	 	$	83,554	 	 	 	 	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 	 	 	
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS — (Continued)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
						Total			
						Accumulated		Comprehensive	
						Other		Income (Loss)	
				Foreign		Comprehensive		for the Three	
		Cash Flow		Currency		Income		Months Ended	
		Hedges		Translation		(Loss)		March 31, 2003	
									
Accumulated other comprehensive loss at January 1, 2003	 	$	(224,414	)	 	$	(13,043	)	 	$	(237,457	)	 	 	 	 	
Net loss	 	 	 	 	 	 	 	 	 	 	 	 	 	$	(52,016	)	
 	Cash flow hedges:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Comprehensive pre-tax gain on cash flow hedges before reclassification adjustment during the three months ended March 31, 2003	 	 	27,827	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reclassification adjustment for loss included in net loss for the three months ended March 31, 2003	 	 	14,249	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Income tax provision for the three months ended March 31, 2003	 	 	(10,927	)	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 		 	 	 	 	 	 	 		 	 	 	 	 	
 	 	 	31,149	 	 	 	 	 	 	 	31,149	 	 	 	31,149	 	
 	 	Foreign currency translation gain for the three months ended March 31, 2003	 	 	—	 	 	 	84,062	 	 	 	84,062	 	 	 	84,062	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	
Total comprehensive income for the three months ended March 31, 2003	 	 	 	 	 	 	 	 	 	 	 	 	 	$	63,195	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 		 	
Accumulated other comprehensive loss at March 31, 2003	 	$	(193,265	)	 	$	71,019	 	 	$	(122,246	)	 	 	 	 	

		
11.	Loss Per Share	
      Basic loss per common share were 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 loss per common share to diluted loss per share is shown in the following table (in thousands, except per share data). 

			
		Periods Ended March 31,	

		2004		2003	
					
		Net Loss		Shares		EPS		Net Loss		Shares		EPS	
													
THREE MONTHS:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Basic and diluted loss per common share:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Loss before discontinued operations and cumulative effect of a change in accounting principle	 	$	(94,049	)	 	 	415,308	 	 	$	(0.23	)	 	$	(51,538	)	 	 	380,960	 	 	$	(0.14	)	
Discontinued operations, net of tax	 	 	22,857	 	 	 	—	 	 	 	0.06	 	 	 	(1,007	)	 	 	—	 	 	 	—	 	
Cumulative effect of a change in accounting principle, net of tax	 	 	—	 	 	 	—	 	 	 	—	 	 	 	529	 	 	 	—	 	 	 	—	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Net loss	 	$	(71,192	)	 	 	415,308	 	 	$	(0.17	)	 	$	(52,016	)	 	 	380,960	 	 	$	(0.14	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS — (Continued)
      Because of the Company’s losses for the three months ended March 31, 2004 and 2003, basic shares were used in the calculations of fully diluted loss per share, under the guidelines of SFAS No. 128, “Earnings per Share,” as using the basic shares produced the more dilutive effect on the loss per share. Potentially convertible securities and unexercised employee stock options to purchase 72,565,275 and 115,332,743 shares of the Company’s common stock were not included in the computation of diluted shares outstanding during the three months ended March 31, 2004 and 2003, respectively, because such inclusion would be anti-dilutive.
      For the quarter ended March 31, 2004, approximately 23.8 million weighted common shares of the Company’s outstanding 4% convertible senior notes due 2006 were excluded from the diluted EPS calculations as the inclusion of such shares would have been antidilutive. Due to repurchases by the Company of these securities during the first quarter, at March 31, 2004, 4.0 million common shares were potentially issuable upon the conversion of 100% of these securities then outstanding. The holders have the right to require the Company to repurchase these securities on December 26, 2004, at a repurchase price equal to the issue price plus any accrued and unpaid interest, payable at the option of the Company in cash or common shares, or a combination of cash and common shares.
      In connection with the convertible notes payable to Calpine Capital Trust (“Trust I”), Calpine Capital Trust II (“Trust II”) and Calpine Capital Trust III (“Trust III”), net of repurchases, there were 16.3 million, 14.1 million and 11.9 million common shares potentially issuable, respectively. These notes are convertible at any time at the applicable holder’s option in connection with the conversion of convertible preferred securities issued by the Trusts, and may be redeemed at any time after their respective initial redemption date. The Company is required to remarket the convertible preferred securities issued by Trust I, Trust II and Trust III no later than November 1, 2004, February 1, 2005 and August 1, 2005, respectively. If the Company is not able to remarket those securities, it will result in additional interest costs and an adjusted conversion rate equal to 105% of the average closing price of our common stock for the five consecutive trading days after the failed remarketing.
      For the quarter ended March 31, 2004, there were no shares potentially issuable with respect to the Company’s 4.75% contingent convertible senior notes due 2023. Upon the occurrence of certain contingencies, these securities are convertible at the holder’s option in cash for the face amount and in shares of the Company’s common stock for the appreciated value in the Company’s common stock over $6.50 per share. Holders have the right to require the Company to repurchase these securities at various times beginning on November 15, 2009, for the face amount plus any accrued and unpaid interest and liquidated damages, if any. The repurchase price is payable at the option of the Company in cash or common shares, or a combination of both. The Company may redeem the related notes at any time on or after November 22, 2009 in cash for the face amount plus any accrued and unpaid interest and liquidated damages, if any. Approximately 138.4 million maximum potential shares are issuable upon conversion of these securities and are excluded from the diluted EPS calculations as there are currently no shares contingently issuable due to the Company’s quarter end stock price being under $6.50.

12.	Commitments and Contingencies	
      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 remaining 5 turbines to be delivered as well as payment required for the potential cancellation
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS — (Continued)
costs of the remaining 68 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 68 turbines.

				Units to Be	
Year		Total		Delivered	

		(In thousands)	
April through December 2004	 	$	76,497	 	 	 	5	 	
2005	 	 	20,122	 	 	 	—	 	
2006	 	 	2,623	 	 	 	—	 	
 	 	 		 	 	 	 	 	
Total	 	$	99,242	 	 	 	5	 	
 	 	 		 	 	 		 	
     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 Condensed Financial Statements.
      Securities Class Action Lawsuits. Since March 11, 2002, fourteen shareholder lawsuits have been filed against Calpine and certain of its officers in the United States District Court for the Northern District of California. The actions captioned Weisz v. Calpine Corp., et al. , filed March 11, 2002, and Labyrinth Technologies, Inc. v. Calpine Corp., et al. , filed March 28, 2002, are purported class actions on behalf of purchasers of Calpine stock between March 15, 2001 and December 13, 2001. Gustaferro v. Calpine Corp. , filed April 18, 2002, is a purported class action on behalf of purchasers of Calpine stock between February 6, 2001 and December 13, 2001. The eleven other actions, captioned Local 144 Nursing Home Pension Fund v. Calpine Corp., Lukowski v. Calpine Corp., Hart v. Calpine Corp., Atchison v. Calpine Corp., Laborers Local 1298 v. Calpine Corp., Bell v. Calpine Corp., Nowicki v. Calpine Corp. Pallotta v. Calpine Corp., Knepell v. Calpine Corp., Staub v. Calpine Corp. , and Rose v. Calpine Corp. were filed between March 18, 2002 and April 23, 2002. The complaints in these eleven actions are virtually identical — they are filed by three law firms, in conjunction with other law firms as co-counsel. All eleven lawsuits are purported class actions on behalf of purchasers of Calpine’s securities between January 5, 2001 and December 13, 2001.
      The complaints in these fourteen actions allege that, during the purported class periods, certain Calpine executives issued false and misleading statements about Calpine’s financial condition in violation of Sections 10(b) and 20(1) of the Securities Exchange Act of 1934, as well as Rule 10b-5. These actions seek an unspecified amount of damages, in addition to other forms of relief.
      In addition, a fifteenth securities class action, Ser v. Calpine, et al. , was filed on May 13, 2002. The underlying allegations in the Ser action are substantially the same as those in the above-referenced actions. However, the Ser action is brought on behalf of a purported class of purchasers of Calpine’s 8.5% Senior Notes Due February 15, 2011 (“2011 Notes”) and the alleged class period is October 15, 2001 through December 13, 2001. The Ser complaint alleges that, in violation of Sections 11 and 15 of the Securities Act of 1933, the Supplemental Prospectus for the 2011 Notes contained false and misleading statements regarding Calpine’s financial condition. This action names Calpine, certain of its officers and directors, and the underwriters of the 2011 Notes offering as defendants, and seeks an unspecified amount of damages, in addition to other forms of relief.
      All fifteen of these securities class action lawsuits were consolidated in the United States District Court for the Northern District of California. Plaintiffs filed a first amended complaint in October 2002. The amended complaint did not include the 1933 Act complaints raised in the bondholders’ complaint, and the
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS — (Continued)
number of defendants named was reduced. On January 16, 2003, before the Company’s response was due to this amended complaint, plaintiffs filed a further second complaint. This second amended complaint added three additional Calpine executives and Arthur Andersen LLP as defendants. The second amended complaint set forth additional alleged violations of Section 10 of the Securities Exchange Act of 1934 relating to allegedly false and misleading statements made regarding Calpine’s role in the California energy crisis, the long term power contracts with the California Department of Water Resources, and Calpine’s dealings with Enron, and additional claims under Section 11 and Section 15 of the Securities Act of 1933 relating to statements regarding the causes of the California energy crisis. The Company filed a motion to dismiss this consolidated action in early April 2003.
      On August 29, 2003, the judge issued an order dismissing, with leave to amend, all of the allegations set forth in the second amended complaint except for a claim under Section 11 of the Securities Act relating to statements relating to the causes of the California energy crisis and the related increase in wholesale prices contained in the Supplemental Prospectuses for the 2011 Notes.
      The judge instructed plaintiff, Julies Ser, to file a third amended complaint, which he did on October 17, 2003. The third amended complaint names Calpine and three executives as defendants and alleges the Section 11 claim that survived the judge’s August 29, 2003 order.
      On November 21, 2003, Calpine and the individual defendants moved to dismiss the third amended complaint on the grounds that plaintiff’s Section 11 claim was barred by the applicable one-year statute of limitations. On February 4, 2004, the judge denied the Company’s motion to dismiss but has asked the parties to be prepared to file summary judgment motions to address the statute of limitations issue. The Company filed its answer to the third amended complaint on February 28, 2004.
      In a separate order dated February 4, 2004, the court denied without prejudice Julies Ser’s motion to be appointed lead plaintiff. Mr. Ser subsequently stated he no longer desired to serve as lead plaintiff. On April 4, 2004, the Policemen and Firemen Retirement System of the City of Detroit (“P&F”) moved to be appointed lead plaintiff. The Company filed a response in opposition to this motion. The court has scheduled a hearing on this matter for May 11, 2004.
      The Company considers the lawsuit to be without merit and intends to continue to defend vigorously against these allegations.
      Hawaii Structural Ironworkers Pension Fund v. Calpine, et al. A securities class action, Hawaii Structural Ironworkers Pension Fund v. Calpine, et al. , was filed on March 11, 2003, against Calpine, its directors and certain investment banks in state superior court of San Diego County, California. The underlying allegations in the Hawaii Structural Ironworkers Pension Fund action (“Hawaii action”) are substantially the same as the federal securities class actions described above. However, the Hawaii action is brought on behalf of a purported class of purchasers of Calpine’s equity securities sold to public investors in its April 2002 equity offering. The Hawaii action alleges that the Registration Statement and Prospectus filed by Calpine which became effective on April 24, 2002, contained false and misleading statements regarding Calpine’s financial condition in violation of Sections 11, 12 and 15 of the Securities Act of 1933. The Hawaii action relies in part on Calpine’s restatement of certain past financial results, announced on March 3, 2003, to support its allegations. The Hawaii action seeks an unspecified amount of damages, in addition to other forms of relief.
      The Company removed the Hawaii action to federal court in April 2003 and filed a motion to transfer the case for consolidation with the other securities class action lawsuits in the United States District Court for the Northern District of California in May 2003. Plaintiff sought to have the action remanded to state court, and on August 27, 2003, the United States District Court for the Southern District of California granted plaintiff’s motion to remand the action to state court. In early October 2003 plaintiff agreed to dismiss the claims it has against three of the outside directors.
      On November 5, 2003, Calpine, the individual defendants and the underwriter defendants filed motions to dismiss this complaint on numerous grounds. On February 6, 2004, the court issued a tentative ruling
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sustaining the Company’s motion to dismiss on the issue of plaintiff’s standing. The court found that plaintiff had not shown that it had purchased Calpine stock “traceable” to the April 2002 equity offering. The court overruled the Company’s motion to dismiss on all other grounds. On March 12, 2004, after oral argument on the issues, the court confirmed its February 2, 2004, ruling.
      On February 20, 2004, plaintiff filed an amended complaint, and in late March 2004 the Company and the individual defendants filed answers to this complaint. On April 9, 2004, the Company and the individual defendants filed motions to transfer the lawsuit to Santa Clara County Superior Court, which motions were granted on May 7, 2004. The Company considers this lawsuit to be without merit and intends to continue to defend vigorously against it.
      Phelps v. Calpine Corporation, et al. On April 17, 2003, a participant in the Calpine Corporation Retirement Savings Plan (the “401(k) Plan”) filed a class action lawsuit in the United States District Court for the Northern District of California. The underlying allegations in this action (“Phelps action”) are substantially the same as those in the securities class actions described above. However, the Phelps action is brought on behalf of a purported class of participants in the 401(k) Plan. The Phelps action alleges that various filings and statements made by Calpine during the class period were materially false and misleading, and that defendants failed to fulfill their fiduciary obligations as fiduciaries of the 401(k) Plan by allowing the 401(k) Plan to invest in Calpine common stock. The Phelps action seeks an unspecified amount of damages, in addition to other forms of relief. In May 2003 Lennette Poor-Herena, another participant in the 401(k) Plan, filed a substantially similar class action lawsuit as the Phelps action also in the Northern District of California. Plaintiffs’ counsel is the same in both of these actions, and they have agreed to consolidate these two cases and to coordinate them with the consolidated federal securities class actions described above. On January 20, 2004, plaintiff James Phelps filed a consolidated ERISA complaint naming Calpine and numerous individual current and former Calpine Board members and employees as defendants. Pursuant to a stipulated agreement with plaintiff, Calpine’s response to the amended complaint is due June 18, 2004. The Company considers this lawsuit to be without merit and intends to vigorously defend against it.
      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 captioned Johnson v. Cartwright, et al. and is pending in state superior court of 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. In March 2003 Calpine and the individual defendants filed motions to dismiss and motions to stay this proceeding in favor of the federal securities class actions described above. In July 2003 the court granted the motions to stay this proceeding in favor of the consolidated federal securities class actions described above. The Company cannot estimate the possible loss or range of loss from this matter. The Company considers this lawsuit to be without merit and intends to vigorously defend against it.
      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 have been 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 in favor of the consolidated federal securities class action described above and to dismiss without prejudice certain director defendants. On March 4, 2003, plaintiff filed papers with the court voluntarily agreeing to dismiss without prejudice the claims he had against three of the outside directors. The Company cannot estimate the possible loss or range of loss from this matter. The Company considers this lawsuit to be without merit and intends to continue to defend vigorously against it.
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      Calpine Corporation v. Automated Credit Exchange. On March 5, 2002, Calpine sued Automated Credit Exchange (“ACE”) in state superior court of Alameda County, California for negligence and breach of contract to recover reclaim trading credits, a form of emission reduction credits that should have been held in Calpine’s account with U.S. Trust Company (“US Trust”). Calpine wrote off $17.7 million in December 2001 related to losses that it alleged were caused by ACE. Calpine and ACE entered into a Settlement Agreement on March 29, 2002, pursuant to which ACE made a payment to Calpine of $7 million and transferred to Calpine the rights to the emission reduction credits to be held by ACE. The Company recognized the $7 million as income in the second quarter of 2002. In June 2002 a complaint was filed by InterGen North America, L.P. (“InterGen”) against Anne M. Sholtz, the owner of ACE, and EonXchange, another Sholtz-controlled entity, which filed for bankruptcy protection on May 6, 2002. InterGen alleges it suffered a loss of emission reduction credits from EonXchange in a manner similar to Calpine’s loss from ACE. InterGen’s complaint alleges that Anne Sholtz co-mingled assets among ACE, EonXchange and other Sholtz entities and that ACE and other Sholtz entities should be deemed to be one economic enterprise and all retroactively included in the EonXchange bankruptcy filing as of May 6, 2002. By a judgment entered on October 30, 2002, the bankruptcy court consolidated ACE and the other Sholtz controlled entities with the bankruptcy estate of EonXchange. Subsequently, the Trustee of EonXchange filed a separate motion to substantively consolidate Anne Sholtz into the bankruptcy estate of EonXchange. Although Anne Sholtz initially opposed such motion, she entered into a settlement agreement with the Trustee consenting to her being substantively consolidated into the bankruptcy proceeding. The bankruptcy court entered an order approving Anne Sholtz’s settlement agreement with the Trustee on April 3, 2002. On July 10, 2003, Howard Grobstein, the Trustee in the EonXchange bankruptcy, filed a complaint for avoidance against Calpine, seeking recovery of the $7 million (plus interest and costs) paid to Calpine in the March 29, 2002 Settlement Agreement. The complaint claims that the $7 million received by Calpine in the Settlement Agreement was transferred within 90 days of the filing of bankruptcy and therefore should be avoided and preserved for the benefit of the bankruptcy estate. On August 28, 2003, Calpine filed its answer denying that the $7 million is an avoidable preference. On January 26, 2004, Calpine filed a motion for partial summary judgment asserting that the bankruptcy court did not properly consolidate Anne Sholtz into the bankruptcy estate of EonXchange. If the motion is granted, at least $2.9 million of the $7 million that the Trustee is seeking to recover from Calpine could not be avoided as a preferential transfer. In response, the Trustee filed a motion for summary judgment for the entire $7 million plus interest against Calpine. Although Calpine will assert various defenses to the claims asserted by the Trustee, Calpine and the Trustee have entered into stipulations to continue the various hearing dates on the pending motions for summary judgment in order to pursue settlement discussions. The Company believes that it has adequately reserved for the possible loss, if any, that it may ultimately incur as a result of this matter.
      International Paper Company v. Androscoggin Energy LLC. In October 2000 International Paper Company (“IP”) filed a complaint in the United States District Court for the Northern District of Illinois against Androscoggin Energy LLC (“AELLC”) alleging that AELLC breached certain contractual representations and warranties by failing to disclose facts surrounding the termination, effective May 8, 1998, of one of AELLC’s fixed-cost gas supply agreements. The Company acquired a 32.3% interest in AELLC as part of the SkyGen transaction which closed in October 2000. AELLC filed a counterclaim against IP that has been referred to arbitration that AELLC may commence at its discretion upon further evaluation. 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 IP on the liability aspect of a particular claim against AELLC. The court also denied a motion submitted by IP for preliminary injunction to permit IP to make payment of funds into escrow (not directly to AELLC) and require AELLC to post a significant bond.
      In mid-April of 2003 IP unilaterally availed itself to self-help in withholding amounts in excess of $2.0 million as a set-off for litigation expenses and fees incurred to date as well as an estimated portion of a rate fund to AELLC. Upon AELLC’s amended complaint and request for immediate injunctive relief against such actions, the court ordered that IP must pay the approximately $1.2 million withheld as attorneys’ fees related to the litigation as any such perceived entitlement was premature, but deferred to provide injunctive
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relief on the incomplete record concerning the offset of $799,000 as an estimated pass-through of the rate fund. IP complied with the order on April 29, 2003, and tendered payment to AELLC of the approximately $1.2 million. On June 26, 2003, the court entered an order dismissing AELLC’s amended counterclaim without prejudice to AELLC refiling the claims as breach of contract claims in a separate lawsuit. On December 11, 2003, the court denied in part IP’s summary judgment motion pertaining to damages. In short, the court: (i) determined that, as a matter of law, IP is entitled to pursue an action for damages as a result of AELLC’s breach, and (ii) ruled that sufficient questions of fact remain to deny IP summary judgment on the measure of damages as IP did not sufficiently establish causation resulting from AELLC’s breach of contract (the liability aspect of which IP obtained a summary judgment in December 2002). On February 2, 2004, the parties filed a Final Pretrial Order with the court. The case appears likely scheduled for trial in the second quarter of 2004, subject to the court’s discretion and calendar. The Company believes that it has adequately reserved for the possible loss, if any, that it may ultimately incur as a result of this matter.
      Pacific Gas and Electric Company v. Calpine Corporation, et al. On July 22, 2003, Pacific Gas and Electric Company (“PG&E”) filed with the California Public Utilities Commission (“CPUC”) a Complaint of PG&E and Request for Immediate Issuance of an Order to Show Cause (“complaint”) against Calpine Corporation, CPN Pipeline Company, Calpine Energy Services, L.P., Calpine Natural Gas Company, and Lodi Gas Storage, LLC (“LGS”). The complaint requests the CPUC to issue an order requiring defendants to show cause why they should not be ordered to cease and desist from using any direct interconnections between the facilities of CPN Pipeline and those of LGS unless LGS and Calpine first seek and obtain regulatory approval from the CPUC. The complaint also seeks an order directing defendants to pay to PG&E any underpayments of PG&E’s tariffed transportation rates and to make restitution for any profits earned from any business activity related to LGS’ direct interconnections to any entity other than PG&E. The complaint further alleges that various natural gas consumers, including Calpine affiliated generation projects within California, are engaged with defendants in the acts complained of, and that the defendants unlawfully bypass PG&E’s system and operate as an unregulated local distribution company within PG&E’s service territory. On August 27, 2003, Calpine filed its answer and a motion to dismiss. LGS also made similar filings. On October 16, 2003, the presiding administrative law judge denied the motion to dismiss and on October 24, 2003, issued a Scoping Memo and Ruling establishing a procedural schedule and set the matter for an evidentiary hearing. On January 15, 2004, Calpine, LGS and PG&E executed a Settlement Agreement to resolve all outstanding allegations and claims raised in the complaint. Certain aspects of the Settlement Agreement are effective immediately and the effectiveness of other provisions is subject to the approval of the Settlement Agreement by the CPUC. In the event the CPUC fails to approve the Settlement Agreement, its operative terms and conditions become null and void. The Settlement Agreement provides, in part, for: 1) PG&E to be paid $2.7 million; 2) the disconnection of the LGS interconnections with Calpine; 3) Calpine to obtain PG&E consent or regulatory or other governmental approval before resuming any sales or exchanges at the Ryer Island Meter Station; 4) PG&E’s withdrawal of its public utility claims against Calpine; and 5) no party admitting any wrongdoing. Accordingly, the presiding administrative law judge vacated the hearing schedule and established a new procedural schedule for the filing of the Settlement Agreement. On February 6, 2004, the Settlement Agreement was filed with the CPUC. The parties were given the opportunity to submit comments and reply comments on the Settlement Agreement. The matter is currently pending and shall be considered by the CPUC following the issuance of a recommendation by the presiding administrative law judge.
      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 Calpine and certain of its affiliates in the United States District Court for the Northern District of Texas, 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 Energy Center (“Oneta”), 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 from Oneta plant and that Calpine’s actions have reduced the profits from Oneta plant thereby undermining Panda’s ability to repay monies owed to Calpine on December 1, 2003, under a promissory note
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on which approximately $38.6 million (including interest) is currently outstanding and past due. The note is collateralized by Panda’s carried interest in the income generated from Oneta, which achieved full commercial operations in June 2003. The company filed a counterclaim against Panda Energy International, Inc. (and PLC II, LLC) based on a guaranty, and have also filed a motion to dismiss as to the causes of action alleging federal and state securities laws violations. The motion to dismiss is currently pending before the court. However, at the present time, the Company cannot estimate the potential loss, if any, that might arise from this matter. The Company considers Panda’s lawsuit to be without merit and intends to defend vigorously against it. The Company stopped accruing interest income on the promissory note due December 1, 2003, as of the due date because of Panda’s default in repayment of the note.
      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 twenty energy traders and energy companies, including CES, alleges that defendants exercised market power and manipulated prices in violation of California Business & Professions Code Section 17200 et seq., and seeks injunctive relief, restitution, and attorneys’ fees. The Company also have been named in seven other similar complaints for violations of Section 17200. All seven cases were removed from the various state courts in which they were originally filed to federal court for pretrial proceedings with other cases in which the Company is not named as a defendant. However, at the present time, the Company cannot estimate the potential loss, if any, that might arise from this matter. The Company considers the allegations to be without merit, and filed a motion to dismiss on August 28, 2003. The court granted the motion, and plaintiffs have appealed.
      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 17200 cases, but also seeks rescission of the long-term power contracts with the California Department of Water Resources.
      Upon motion from another newly added defendant, Millar was recently removed to federal court. It has now been transferred to the same judge that is presiding over the other 17200 cases described above, where it will be consolidated with such cases for pretrial purposes. The Company anticipates filing a timely motion for dismissal of Millar as well.
      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, Nevada Power Company (“NPC”) and Sierra Pacific Power Company (“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, which seeks a refund, that the prices they agreed to pay in certain of the power sales agreements, including those signed with Calpine, were negotiated during a time when the power market was dysfunctional and that they are unjust and unreasonable. 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 the relief that it was seeking. In June 2003, FERC rejected the complaint. Some plaintiffs appealed to the FERC and their request for rehearing was denied. The FERC decision is therefore final, and the matter is pending on appeal before the United States Court of Appeals for the Ninth Circuit.
      Transmission Service Agreement with Nevada Power. On March 16, 2004, NPC filed a petition for declaratory order at FERC (Docket No. EL04-90-000) asking that an order be issued requiring Calpine and Reliant Energy Services, Inc. to pay for transmission service under their Transmission Service Agreements (“TSAs”) with NPC or, if the TSAs are terminated, to pay the lesser of the transmission charges or a pro rata share of the total cost of NPC’s Centennial Project (approximately $33 million for Calpine). Calpine had previously provided security to NPC for these costs in the form of a surety bond issued by Fireman’s Fund Insurance Company (“FFIC”). The Centennial Project involves construction of various transmission facilities in two phases; Calpine’s Moapa Energy Center (“MEC”) is scheduled to receive service under its
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TSA from facilities yet to be constructed in the second phase of the Centennial Project. Calpine has filed a protest to the petition asserting that Calpine will take service under the TSA if NPC proceeds to execute a purchase power agreement (“PPA”) with MEC based on its winning bid in the Request for Proposals that NPC conducted in 2003. Calpine also has taken the position that if NPC does not execute a PPA with MEC, it will terminate the TSA and any payment by Calpine would be limited to a pro rata allocation of costs incurred to date on the second phase of the project (approximately $4.5 million in total) among the three customers to be served. At this time, Calpine is unable to predict the final outcome of this proceeding or its impact on Calpine.
      On or about April 27, 2004, NPC alleged to FFIC that Calpine had defaulted on the TSA and made demand on FFIC for the full amount of the surety bond, $33,333,333.00. On April 29, 2004, FFIC filed a complaint for declaratory order in state superior court of Marin County, California in connection with this demand.
      FFIC’s complaint asks that an order be issued declaring that it has no obligation to make payment under the bond and, if the court determines that FFIC does have an obligation to make payment, FFIC asks that an order be issued declaring that (i) Calpine has an obligation to replace it with funds equal to the amount of NPC’s demand against the bond and (ii) Calpine is obligated to indemnify and hold FFIC harmless for all loss, costs and fees incurred as a result of the issuance of the bond. Calpine is preparing to file a response to the complaint. Calpine’s position will be, among other items, that it did not default on its obligations under the TSA and therefore NPC is not entitled to make a demand upon the FFIC bond. At this time, Calpine is unable to predict the outcome of this proceeding or its impact on Calpine.
      Calpine Canada Natural Gas Partnership v. Enron Canada Corp. On February 6, 2002, Calpine Canada Natural Gas Partnership (“Calpine Canada”) filed a complaint in the Alberta Court of Queens Branch alleging that Enron Canada Corp. (“Enron Canada”) owed it approximately $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 $18 million. Discovery is currently in progress, and the Company believes that Enron Canada’s counterclaim is without merit and intends to vigorously defend against it.
      Jones 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 Darrell Jones. 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 has not occurred and the daily reduction in the payment amount has reduced the $18.0 million payment to zero. The complaint alleges 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. The complaint seeks damages in an unspecified amount in excess of $75,000. 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 have filed a motion for reconsideration of the decision, and the plaintiffs may also ultimately appeal. The Company still, however, expects to make the $6.0 million payment to the estates when the project is completed.
      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 single business strategy, it is the Company’s long-range objective to produce from its own natural gas reserves (“equity gas”)
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at a level of approximately 25% of its fuel consumption requirements. The Company’s oil and gas production and marketing activity has reached the quantitative criteria to be considered a reportable segment under SFAS No. 131, “Disclosures about Segments of an Enterprise and Related Information.” The Company’s segments are electric generation and marketing; oil and gas production and marketing; and corporate and other activities. 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. Oil and gas production includes the ownership and operation of gas fields, gathering systems and gas pipelines for internal gas consumption, third party sales and hedging, balancing, optimization, and trading activity transacted on behalf of the Company’s oil and gas operations. Corporate activities and other consists primarily of financing activities, the Company’s specialty data center engineering business, which was divested in the third quarter of 2003 and general and administrative costs. Certain costs related to company-wide functions are allocated to each segment, such as interest expense, distributions on HIGH TIDES prior to October 1, 2003, and interest income, which are allocated based on a ratio of segment assets to total assets.
      The Company evaluates performance based upon several criteria including profits before tax. The financial results for the Company’s operating segments have been prepared on a basis consistent with the manner in which the Company’s management internally disaggregates financial information for the purposes of assisting in making internal operating decisions.
      Due to the integrated nature of the business segments, estimates and judgments have been made in allocating certain revenue and expense items, and reclassifications have been made to prior periods to present the allocation consistently. 

													
		Electric Generation and		Oil and Gas Production					
		Marketing		and Marketing		Corporate and Other		Total	
									
		2004		2003		2004		2003		2004		2003		2004		2003	

		(In thousands)	
For the three months ended March 31, Total revenue from external customers	 	$	1,998,393	 	 	$	2,138,498	 	 	$	24,381	 	 	$	24,892	 	 	$	19,964	 	 	$	2,543	 	 	$	2,042,738	 	 	$	2,165,933	 	
 	Intersegment revenue	 	 	—	 	 	 	—	 	 	 	80,110	 	 	 	125,214	 	 	 	—	 	 	 	—	 	 	 	80,110	 	 	 	125,214	 	
 	Segment profit/(loss) before provision for income taxes	 	 	(243,873	)	 	 	(72,391	)	 	 	19,500	 	 	 	47,394	 	 	 	44,375	 	 	 	(43,413	)	 	 	(179,998	)	 	 	(68,410	)	
 	Equipment cancellation and impairment cost	 	 	2,360	 	 	 	87	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	2,360	 	 	 	87	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
		Electric		Oil and Gas		Corporate,			
		Generation		Production		Other and			
		and Marketing		and Marketing		Eliminations		Total	

		(In thousands)	
Total assets:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	March 31, 2004	 	$	24,754,356	 	 	$	1,667,578	 	 	$	940,104	 	 	$	27,362,038	 	
 	December 31, 2003	 	$	24,067,448	 	 	$	1,797,755	 	 	$	1,438,729	 	 	$	27,303,932	 	
      Intersegment revenues primarily relate to the use of internally procured gas for the Company’s power plants. These intersegment revenues have been included in Total Revenue and Income before taxes in the oil and gas production and marketing reporting segment and eliminated in the Corporate and other reporting segment.
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14.	California Power Market	
      California Refund Proceeding. On August 2, 2000, the California Refund Proceeding was initiated by a complaint made at FERC by San Diego Gas & Electric Company 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 (“ALJ”) 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 will increase modestly, from approximately $6.2 million to $8.4 million, after taking the appropriate set-offs for outstanding receivables owed by the CalPX and CAISO to Calpine. The Company has fully reserved the amount of refund liability that by its analysis would potentially be owed under the refund calculation clarification in the March 26 order. 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. At this time, the Company is unable to predict the timing of the completion of these proceedings or the final refund liability. Thus 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 California governmental entities on April 22, 2002. Calpine’s settlement was approved by FERC on March 26, 2004, in an order 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 other agency of the State of California.
      FERC Investigation into 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 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. FERC has stated that it may use the information gathered in connection with the investigation to determine how to proceed on any existing or future complaint brought under Section 206 of the Federal Power Act involving long-term power contracts entered into in the West since January 1, 2000, or to initiate a Federal Power Act Section 206 or Natural Gas Act Section 5 proceeding on its own initiative. 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.
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS — (Continued)
There were no findings or allegations of wrongdoing by Calpine 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 have been be in violation of the CAISO’s or CalPX’s tariff. The Final Report also recommended that FERC modify the basis for determining potential liability in the California Refund Proceeding discussed above. Calpine 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.
      Also, on June 25, 2003, FERC issued a number of orders associated with these investigations, including the issuance of two show cause orders to certain industry participants. FERC did not subject Calpine to either of the show cause orders. FERC also issued an order directing the FERC Office of Markets and Investigations to investigate further whether market participants who bid a price in excess of $250 per megawatt hour into markets operated by either the CAISO or the CalPX during the period of May 1, 2000, to October 2, 2000, 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, the Company is 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. The Company’s Qualifying Facilities (“QF”) contracts with 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 the Company’s QF facilities elected the option set forth in Section 390 of the California Public Utility Code, which provides QFs the right to elect to receive energy payments based on the CalPX market clearing price instead of the price determined by SRAC. Having elected such option, the Company was 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. The CPUC at one point issued a proposed decision to the effect that the PX Price was the appropriate price for energy payments under the California Public Utility Code but tabled it, and a final decision has not been issued to date. Therefore, it is possible that the CPUC could order a 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 requests that the CPUC set a briefing schedule under the R.99-11-022 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 allege that refund liability be determined using the methodology that has been developed thus far in the California Refund Proceeding discussed above. The Company believes 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 FERC in the California Refund Proceeding is unfounded, but there can be no assurance that this will be the outcome of the CPUC proceedings.
      Geysers Reliability Must Run Section 206 Proceeding. CAISO, California Electricity Oversight Board, Public Utilities Commission of the State of California, Pacific Gas and Electric Company, 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 Power Company, LLC, 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 ISO to meet local transmission reliability needs or to manage
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS — (Continued)
transmission constraints. The Buyers Coalition has asked FERC to find that the availability payments under these RMR Contracts are not just and reasonable. Geysers Power Company, LLC filed an answer to the complaint in November 2001. To date, FERC has not established a Section 206 proceeding. The outcome of this litigation and the impact on the Company’s business cannot be determined at the present time.

15.	Subsequent Events	
      On April 15, 2004, the Company agreed to modify the terms of its long-term operating lease for the 120-megawatt King City Power Plant located in King City, California. Upon closing of this transaction, the Company expects to: (1) extend the term of the King City Power Plant’s operating lease from 2018 to 2028; (2) restructure the lease’s rent payment schedule; (3) receive approximately $87 million in cash, net of transaction costs from the sale of securities originally pledged to the lessor to secure the lessee’s obligations under the lease; (4) receive approximately $40 million through the issuance of a 10-year promissory note by Calpine Canada Power Ltd., to a CPIF affiliate; and (5) redeem the existing preferred equity interest issued in 2003 by a Company subsidiary in connection with the King City Power Plant. Together, these transactions will result in a reduction of approximately $42 million of the Company’s debt and are expected to provide the Company with approximately $45 million in net cash proceeds. The closing is contingent upon the completion of the CPIF Subscription Receipt Offering which is expected to close on May 19, 2004. The Company expects to record a gain from this transaction.
      On April 26, 2004, the Company successfully completed its consent solicitation to effect certain amendments to the Indentures governing certain of Calpine’s public debt securities. The purpose of the amendments is to conform certain of the covenants in these Indentures to comparable provisions in the Indentures and other financing instruments governing the non-convertible debt issued by Calpine in 2003. The amended Indentures govern the Senior Notes issued by Calpine between 1996 and 1999, and are as follows:

			
 	• 	10 1/2% Senior Notes due 2006	
 		
 	• 	8 3/4% Senior Notes due 2007	
 		
 	• 	7 7/8% Senior Notes due 2008	
 		
 	• 	7 5/8% Senior Notes due 2006	
 		
 	• 	7 3/4% Senior Notes due 2009	
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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 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 exploitation of oil or gas resources, such as the geology of a resource, the total amount and costs to develop recoverable reserves, and legal title, regulatory, gas administration, marketing and operational factors relating to the extraction of natural gas, (xi) uncertainties associated with estimates of oil and gas 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) uncertainties associated with estimates of sources and uses of cash, that actual sources may be lower and actual uses may be higher than estimated, (xv) 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, (xvi) present and possible future claims, litigation and enforcement actions, (xvii) effects of the application of regulations, including changes in regulations or the interpretation thereof, and (xviii) 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, 2003. 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 450 Fifth Street, N.W., 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 450 Fifth Street, N.W., 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.
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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. 

			
		Three Months Ended March 31,	
			
		2004		2003	

		(In thousands, except	
		production and pricing data)	
Power Plants:	 	 	 	 	 	 	 	 	
Electricity and steam (“E&S”) revenues:	 	 	 	 	 	 	 	 	
 	Energy	 	$	933,369	 	 	$	814,810	 	
 	Capacity	 	 	180,593	 	 	 	157,443	 	
 	Thermal and other	 	 	131,925	 	 	 	127,814	 	
 	 	 		 	 	 		 	
 	Subtotal	 	$	1,245,887	 	 	$	1,100,067	 	
Spread on sales of purchased power(1)	 	 	5,089	 	 	 	1,335	 	
 	 	 		 	 	 		 	
Adjusted E&S revenues (non-GAAP)	 	$	1,250,976	 	 	$	1,101,402	 	
Megawatt hours produced	 	 	21,050,000	 	 	 	19,100,000	 	
All-in electricity price per megawatt hour generated	 	$	59.43	 	 	$	57.67	 	

		
(1) 	From hedging, balancing and optimization activities related to our generating assets.	
      Set forth below is a table summarizing the dollar amounts and percentages of our total revenue for the three months ended March 31, 2004 and 2003, 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	
		March 31,	
			
		2004		2003	
					
Total revenue	 	$	2,042,738	 	 	$	2,165,933	 	
Sales of purchased power for hedging and optimization(1)	 	 	380,028	 	 	 	681,284	 	
As a percentage of total revenue	 	 	18.6	%	 	 	31.5	%	
Sale of purchased gas for hedging and optimization	 	 	352,737	 	 	 	327,468	 	
As a percentage of total revenue	 	 	17.3	%	 	 	15.1	%	
Total cost of revenue (“COR”)	 	 	1,922,194	 	 	 	2,000,796	 	
Purchased power expense for hedging and optimization(1)	 	 	374,939	 	 	 	679,949	 	
As a percentage of total COR	 	 	19.5	%	 	 	34.0	%	
Purchased gas expense for hedging and optimization	 	 	360,486	 	 	 	316,948	 	
As a percentage of total COR	 	 	18.8	%	 	 	15.8	%	

		
(1) 	On October 1, 2003, we adopted on a prospective basis Emerging Issues Task Force (“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	
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	Energy Trading and Risk Management Activities” (“EITF Issue No. 03-11”) and netted purchases of power against sales of purchased power. See Note 2 of the Notes to Consolidated 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 Calpine Energy Services, L.P. (“CES”) risk management organization; (b) particularly volatile markets for electricity and natural gas, which prompted us to frequently adjust our hedge positions by buying power and gas and reselling it; (c) the accounting requirements under Staff Accounting Bulletin (“SAB”) No. 101, “Revenue Recognition in Financial Statements,” and EITF Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Asset,” under which we show many of our hedging contracts on a gross basis (as opposed to netting sales and cost of revenue); and (d) rules in effect throughout 2001 and 2002 associated with the NEPOOL market in New England, which require that all power generated in NEPOOL be sold directly to the Independent System Operator (“ISO”) in that market; we then buy from the ISO to serve our customer contracts. Generally accepted accounting principles required us to account for this activity, which applies to three of our merchant generating facilities, as the aggregate of two distinct sales and one purchase until our prospective adoption of EITF Issue No. 03-11 on October 1, 2003. This gross basis presentation increases revenues but not gross profit. The table below details the financial extent of our transactions with NEPOOL for all financial periods prior to the adoption of EITF Issue No. 03-11. Our entrance into the NEPOOL market began with our acquisition of the Dighton, Tiverton and Rumford facilities on December 15, 2000. 

		Three Months	
		Ended	
		March 31, 2003	
			
		(In thousands)	
Sales to NEPOOL from power we generated	 	$	76,898	 	
Sales to NEPOOL from hedging and other activity	 	 	83,011	 	
 	 	 		 	
 	Total sales to NEPOOL	 	$	159,909	 	
 	Total purchases from NEPOOL	 	$	134,168	 	
Overview
      Our core business and primary source of revenue is the generation and delivery of electric power. We provide power to our U.S., Canadian and U.K. customers through the development and 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 own and produce natural gas and to a lesser extent oil, which we use primarily to lower our costs of power production and provide a natural hedge of fuel costs for our electric power plants, but also to generate some revenue through sales to third parties. We protect and enhance the value of our electric and gas 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 and operating power plants.
      Our key opportunities and challenges include:

			
 	• 	preserving and enhancing our liquidity while spark spreads (the differential between power revenues and fuel costs) are depressed,	
 		
 	• 	selectively adding new load-serving entities and power users to our satisfied customer list as we increase our power contract portfolio, and	
 		
 	• 	continuing to add value through prudent risk management and optimization activities.	
      Since the latter half of 2001, there has been a significant contraction in the availability of capital for participants in the energy sector. This has been due to a range of factors, including uncertainty arising from the collapse of Enron Corp. and a perceived near-term surplus supply of electric generating capacity. These factors
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have continued through 2003 and into 2004, during which decreased spark spreads have adversely impacted our liquidity and earnings. While we have been able to continue to access the capital and bank credit markets on attractive terms, we recognize that the terms of financing available to us in the future may not be attractive. To protect against this possibility and due to current market conditions, we scaled back our capital expenditure program to enable us to conserve our available capital resources. We have recently completed the refinancing of Calpine Generating Company (“CalGen”), formerly Calpine Construction Finance Company II, LLC (“CCFC II”) revolving construction facility indebtedness of approximately $2.3 billion as further discussed in Note 6 of the Notes to Consolidated Condensed Financial Statements.
      Set forth below are the Results of Operations for the three months ended March 31, 2004 and 2003.
Results of Operations
           Three Months Ended March 31, 2004, Compared to Three Months Ended March 31, 2003
     (in millions, except for unit pricing information, percentages and MW volumes).
     Revenue

							
		Three Months					
		Ended					
		March 31,					
							
		2004		2003		$ Change		% Change	
									
Total revenue	 	$	2,042.7	 	 	$	2,165.9	 	 	$	(123.2	)	 	 	(5.7	)%	
      The change in total revenue is explained by category below. 

							
		Three Months					
		Ended					
		March 31,					
							
		2004		2003		$ Change		% Change	
									
Electricity and steam revenue	 	$	1,245.9	 	 	$	1,100.1	 	 	$	145.8	 	 	 	13.3	%	
Sales of purchased power for hedging and optimization	 	 	380.0	 	 	 	681.3	 	 	 	(301.3	)	 	 	(44.2	)%	
 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Total electric generation and marketing revenue	 	$	1,625.9	 	 	$	1,781.4	 	 	$	(155.5	)	 	 	(8.7	)%	
 	 	 		 	 	 		 	 	 		 	 	 		 	
      Electricity and steam revenue increased as we completed construction and brought into operation 5 new baseload power plants, 2 new peaker facilities and 4 expansion projects completed subsequent to March 31, 2003. Average megawatts in operation of our consolidated plants increased by 21% to 21,852 MW while generation increased by 10%. The increase in generation lagged behind the increase in average MW in operation as our baseload capacity factor dropped to 50.3% in the three months ended March 31, 2004 from 55.2% in the three months ended March 31, 2003 primarily due to the increased occurrence of unattractive off-peak market spark spreads in certain areas reflecting mild weather in the first quarter of 2004 and oversupply conditions which are expected to gradually work off over the next several years. This caused us to cycle off certain of our merchant plants without contracts in off-peak hours. Average realized electric price, before the effects of hedging, balancing and optimization, increased from $57.60/ MWh in 2003 to $59.19/ MWh in 2004.
      Sales of purchased power for hedging and optimization decreased in the three months ended March 31, 2004, due primarily to netting approximately $370.5 of sales of purchased power with purchase power expense in the quarter ended March 31, 2004, from the adoption of EITF Issue No. 03-11 on a prospective basis in the
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fourth quarter of 2003 partly offset by higher volumes and higher realized prices on hedging, balancing and optimization activities. Without this netting, sales of purchased power would have increased by $69.2 or 10%.

		Three Months					
		Ended					
		March 31,					
							
		2004		2003		$ Change		% Change	
									
Oil and gas sales	 	$	24.6	 	 	$	25.9	 	 	$	(1.3	)	 	 	(5.0	)%	
Sales of purchased gas for hedging and optimization	 	 	352.7	 	 	 	327.5	 	 	 	25.2	 	 	 	7.7	%	
 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Total oil and gas production and marketing revenue	 	$	377.3	 	 	$	353.4	 	 	$	23.9	 	 	 	6.8	%	
 	 	 		 	 	 		 	 	 		 	 	 		 	
      Oil and gas sales are net of internal consumption, which is eliminated in consolidation. Internal consumption decreased primarily as a result of asset sales from $125.2 to $80.1 in 2004. Before intercompany eliminations, oil and gas sales decreased by 31% or $46.4 to $104.7 in 2004 from $151.1 in 2003 due primarily to 27% lower production following asset sales in 2003 and due to 5.2% lower average realized oil and natural gas pricing in 2004.
      Sales of purchased gas for hedging and optimization increased during 2004 due to higher volumes as compared to the same period in 2003. 

							
		Three Months					
		Ended					
		March 31,					
							
		2004		2003		$ Change		% Change	
									
Realized gain on power and gas trading transactions, net	 	$	17.4	 	 	$	21.2	 	 	$	(3.8	)	 	 	(17.9	)%	
Unrealized loss on power and gas transactions, net	 	 	(4.9	)	 	 	(0.8	)	 	 	(4.1	)	 	 	512.5	%	
 	 	 		 	 	 		 	 	 		 	 	 	 	 	
 	Mark-to-market activities, net	 	$	12.5	 	 	$	20.4	 	 	$	(7.9	)	 	 	(38.7	)%	
 	 	 		 	 	 		 	 	 		 	 	 	 	 	
      Mark-to-market activities, which are shown on a net basis, result from general market price movements against our open commodity derivative positions, including positions accounted for as trading under EITF Issue No. 02-3, “Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (“EITF Issue No. 02-3”) and other mark-to-market activities. These commodity positions represent a small portion of our overall commodity contract position. Realized revenue represents the portion of contracts actually settled, while unrealized revenue represents changes in the fair value of open contracts, and the ineffective portion of cash flow hedges.
      The decrease in mark-to-market activities revenue in the three months ended March 31, 2004, as compared to the same period in 2003 is due primarily to $9.0 in mark-to-market losses incurred on transactions executed as part of the Calpine Construction Finance Company L.P. (“CCFC I”) refinancing in 2003. Although these transactions were executed to support the cash flows of the CCFC I entity, they are required to be accounted for on a mark-to-market basis under GAAP. Losses on the CCFC I transactions were offset by increased mark-to-market gains on other positions. 

							
		Three Months					
		Ended					
		March 31,					
							
		2004		2003		$ Change		% Change	
									
Other revenue	 	$	27.0	 	 	$	10.8	 	 	$	16.2	 	 	 	150.0	%	
      Other revenue increased during the three months ended March 31, 2004, primarily due to an increase of $12.2 of revenue from Thomassen Turbine Systems, (“TTS”), which we acquired in February 2003.
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     Cost of Revenue

							
		Three Months					
		Ended					
		March 31,					
							
		2004		2003		$ Change		% Change	
									
Cost of revenue	 	$	1,922.2	 	 	$	2,000.8	 	 	$	(78.6	)	 	 	(3.9	)%	
      The decrease in total cost of revenue is explained by category below. 

							
		Three Months					
		Ended					
		March 31,					
							
		2004		2003		$ Change		% Change	
									
Plant operating expense	 	$	175.8	 	 	$	161.9	 	 	$	13.9	 	 	 	8.6	%	
Transmission purchase expense	 	 	16.4	 	 	 	8.8	 	 	 	7.6	 	 	 	86.4	%	
Royalty expense	 	 	5.9	 	 	 	5.4	 	 	 	0.5	 	 	 	9.3	%	
Purchased power expense for hedging and optimization	 	 	374.9	 	 	 	679.9	 	 	 	(305.0	)	 	 	(44.9	)%	
 	 	 		 	 	 		 	 	 		 	 	 	 	 	
 	Total electric generation and marketing expense	 	$	573.0	 	 	$	856.0	 	 	$	(283.0	)	 	 	33.1	%	
 	 	 		 	 	 		 	 	 		 	 	 	 	 	
      Plant operating expense increased due to 5 new baseload power plants, 4 new peaker facilities and 2 expansion projects completed subsequent to March 31, 2003. The addition of these units resulted in a 21% increase in consolidated operating capacity.
      Transmission purchase expense increased primarily due to additional power plants achieving commercial operation subsequent to March 31, 2003.
      Approximately 71% of the first quarter 2004 royalty expense is attributable to royalties paid to geothermal property owners at The Geysers, mostly as a percentage of geothermal electricity revenues. The increase in royalty expense in the first quarter of 2004 was due to an increase in the accrual of contingent purchase price payments to the previous owners of the Texas City and Clear Lake Power Plants based on a percentage of gross revenues at these two plants.
      Purchased power expense for hedging and optimization decreased during the three months ended March 31, 2004, as compared to the same period in 2003 due primarily to netting $370.5 of purchased power expense against sales of purchased power in the quarter ended March 31, 2004, from the adoption of EITF Issue No. 03-11 in the fourth quarter of 2003, partly offset by higher volumes and higher realized prices on hedging, balancing and optimization activities. 

							
		Three Months					
		Ended					
		March 31,					
							
		2004		2003		$ Change		% Change	
									
Oil and gas production expense	 	$	20.6	 	 	$	23.3	 	 	$	(2.7	)	 	 	(11.6	)%	
Oil and gas exploration expense	 	 	1.7	 	 	 	2.4	 	 	 	(0.7	)	 	 	(29.2	)%	
 	Oil and gas operating expense	 	 	22.3	 	 	 	25.7	 	 	 	(3.4	)	 	 	(13.2	)%	
Purchased gas expense for hedging and optimization	 	 	360.5	 	 	 	316.9	 	 	 	43.6	 	 	 	13.8	%	
 	 	 		 	 	 		 	 	 		 	 	 	 	 	
 	 	Total oil and gas operating and marketing expense	 	$	382.8	 	 	$	342.6	 	 	$	40.2	 	 	 	11.7	%	
 	 	 		 	 	 		 	 	 		 	 	 	 	 	
      Oil and gas production expense decreased during the three months ended March 31, 2004, as compared to the same period in 2003 primarily due to lower production taxes as the result of lower oil and gas revenues and tight sands formation tax refund plus lower lease operating expense primarily due to the sale of properties in the fourth quarter of 2003.
      Oil and gas exploration expense decreased primarily as a result of a decrease in exploration activity.
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      Purchased gas expense for hedging and optimization increased during the three months ended March 31, 2004, due to higher volumes as compared to the same period in 2003. 

							
		Three Months					
		Ended					
		March 31,					
							
		2004		2003		$ Change		% Change	
									
Fuel Expense	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Cost of oil and gas burned by power plants	 	$	762.2	 	 	$	643.4	 	 	$	118.8	 	 	 	18.5	%	
 	Recognized (gain) loss on gas hedges	 	 	0.5	 	 	 	(8.0	)	 	 	8.5	 	 	 	(106.3	)%	
 	 	 		 	 	 		 	 	 		 	 	 	 	 	
 	 	Total fuel expense	 	$	762.7	 	 	$	635.4	 	 	$	127.3	 	 	 	20.0	%	
 	 	 		 	 	 		 	 	 		 	 	 	 	 	
      Cost of oil and gas burned by power plants increased during the three months ended March 31, 2004, as compared to the same period in 2003 due to an 11% increase in gas-fired megawatt hours generated and 2% higher prices excluding the effects of hedging, balancing and optimization.
      Recognized (gain) loss on gas hedges decreased during the three months ended March 31, 2004, as compared to the same period in 2003 due to unfavorable gas price movements against our gas financial instrument positions. 

							
		Three Months					
		Ended					
		March 31,					
							
		2004		2003		$ Change		% Change	
									
Depreciation, depletion and amortization expense	 	$	149.4	 	 	$	133.8	 	 	$	15.6	 	 	 	11.7	%	
      Depreciation, depletion and amortization expense increased primarily due to the additional power facilities in consolidated operations subsequent to March 31, 2003. 

							
		Three Months					
		Ended					
		March 31,					
							
		2004		2003		$ Change		% Change	
									
Operating lease expense	 	$	27.8	 	 	$	27.7	 	 	$	0.1	 	 	 	0.4	%	
      Operating lease expense was consistent with the prior year as the number of operating leases did not change in 2004 as compared to 2003. 

							
		Three Months					
		Ended					
		March 31,					
							
		2004		2003		$ Change		% Change	
									
Other cost of revenue	 	$	26.4	 	 	$	5.3	 	 	$	21.1	 	 	 	398.1	%	
      Other cost of revenue increased during the three months ended March 31, 2004, as compared to the same period in 2003 due primarily to $10.6 of additional expense from TTS and $8.8 of amortization expense incurred from the adoption of Derivatives Implementation Group (“DIG”) Issue No. C20, “Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature.” In the fourth quarter of 2003, we recorded a pre-tax mark-to-market gain of $293.4 as the cumulative effect of a change in accounting principle. This gain is amortized as expense over the respective lives of the two power sales contracts from which the mark-to-market gains arose.
     (Income)/ Expenses 

							
		Three Months					
		Ended					
		March 31,					
							
		2004		2003		$ Change		% Change	
									
(Income) from unconsolidated investments in power projects	 	$	(2.5	)	 	$	(5.1	)	 	$	2.6	 	 	 	(51.0	)%	
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      (Income) from unconsolidated investments in power projects decreased during the three months ended March 31, 2004, as compared to the same period in 2003 primarily as a result of the sale of our 50 percent interest in the Gordonsville Power Plant which occurred on November 26, 2003. During the three months ended March 31, 2003, we realized $1.9 in income from our 50 percent interest in the Gordonsville Power Plant. 

							
		Three Months					
		Ended					
		March 31,					
							
		2004		2003		$ Change		% Change	
									
Equipment cancellation and asset impairment charge	 	$	2.4	 	 	$	0.1	 	 	$	2.3	 	 	 	2,300.0	%	
      Equipment cancellation and asset impairment charge increased during the three months ended March 31, 2004, as compared to the same period in 2003 as a result of a $2.3 termination fee recorded in connection with the termination of a purchase contract for heat recovery steam generators components. 

							
		Three Months					
		Ended					
		March 31,					
							
		2004		2003		$ Change		% Change	
									
Project development expense	 	$	7.7	 	 	$	5.1	 	 	$	2.6	 	 	 	51.0	%	
      Project development expense increased during the three months ended March 31, 2004, primarily due to costs associated with a new project for which a power sales contract is being sought. 

							
		Three Months					
		Ended					
		March 31,					
							
		2004		2003		$ Change		% Change	
									
Research and development expense	 	$	3.8	 	 	$	2.4	 	 	$	1.4	 	 	 	58.3	%	
      Research and development expense increased during the three months ended March 31, 2004, as compared to the same period in 2003 primarily due to increased personnel expenses related to new research and development programs at our Power Systems Mfg., LLC (“PSM”) subsidiary. 

							
		Three Months					
		Ended					
		March 31,					
							
		2004		2003		$ Change		% Change	
									
Sales, general and administrative expense	 	$	57.2	 	 	$	43.7	 	 	$	13.5	 	 	 	30.9	%	
      Sales, general and administrative expense increased during the three months ended March 31, 2004, primarily due to an increase in employee, consulting, rent, insurance and other professional fees. 

							
		Three Months					
		Ended					
		March 31,					
							
		2004		2003		$ Change		% Change	
									
Interest expense	 	$	254.8	 	 	$	143.0	 	 	$	111.8	 	 	 	78.2	%	
      Interest expense increased partially as a result of new plants that entered commercial operations (at which point capitalization of interest expense ceases). Interest capitalized decreased from $118.5 for the three months ended March 31, 2003, to $108.5 for the three months ended March 31, 2004. Additionally, we incurred approximately $12.5 in accelerated amortization of deferred financing costs due to the early refinancing of the CCFC II debt on March 23, 2004. The remaining increase relates to a 15% increase in average indebtedness, an increase in the amortization of terminated interest rate swaps and the recording of interest expense on debt to the three Calpine Capital Trusts due to the adoption of FASB Interpretation No. 46, “Consolidation of Variable Interest Entities, an interpretation of ARB 51” (“FIN 46”) prospectively on October 1, 2003. See Note 2 of the Notes to Consolidated Condensed Financial Statements for a
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discussion of our adoption of FIN 46. We expect that interest expense will continue to increase and the amount of interest capitalized will decrease in future periods as our plants in construction are completed.

		Three Months					
		Ended					
		March 31,					
							
		2004		2003		$ Change		% Change	
									
Distributions on Trust Preferred Securities	 	$	—	 	 	$	15.7	 	 	$	(15.7	)	 	 	(100.0	)%	
      As a result of the deconsolidation of the three Calpine Capital Trusts upon adoption of FIN 46 as of October 1, 2003, the distributions paid on the Trust Preferred Securities during the three months ended March 31, 2004, were no longer recorded on our books and were replaced by interest expense on our debt to the Calpine Capital Trusts. 

							
		Three Months					
		Ended					
		March 31,					
							
		2004		2003		$ Change		% Change	
									
Interest (income)	 	$	(12.1	)	 	$	(8.0	)	 	$	(4.1	)	 	 	51.3	%	
      Interest (income) increased during the three months ended March 31, 2004, due to an increase in cash and equivalents and restricted cash balances as compared to the same period in 2003. 

							
		Three Months					
		Ended					
		March 31,					
							
		2004		2003		$ Change		% Change	
									
Minority interest expense	 	$	8.4	 	 	$	2.3	 	 	$	6.1	 	 	 	265.2	%	
      Minority interest expense increased during the three months ended March 31, 2004, as compared to the same period in 2003 primarily due to an increase of $6.5 of minority interest expense associated with the Calpine Power Income Fund (“CPIF”), which had an initial public offering in August 2002. During 2003 as a result of a secondary offering of Calpine’s interests in CPIF, Calpine decreased its ownership interests to 30%, thus increasing minority interest expense. 

							
		Three Months					
		Ended					
		March 31,					
							
		2004		2003		$ Change		% Change	
									
Other expense (income)	 	$	(19.3	)	 	$	34.6	 	 	$	(53.9	)	 	 	(155.8	)%	
      Other expense (income) was $53.9 higher in the quarter ended March 31, 2004, due primarily to a foreign currency transaction gain of $10.0, a gain on the sale of a variety of oil and gas properties of $6.2 and a favorable warranty settlement in the amount of $5.1. This compares to a $25.2 foreign currency transaction loss and $4.4 in letter of credit fees in the corresponding period in 2003. 

							
		Three Months					
		Ended					
		March 31,					
							
		2004		2003		$ Change		% Change	
									
Benefit for income taxes	 	$	(85.9	)	 	$	(16.9	)	 	$	(69.0	)	 	 	408.3%	 	
      For the three months ended March 31, 2004, the effective rate increased to 48% as compared to 25% for the three months ended March 31, 2003. This effective rate variance is due to the consideration of estimated year-end earnings in estimating the quarterly effective rate and due to the effect of significant permanent items. 

							
		Three Months					
		Ended					
		March 31,					
							
		2004		2003		$ Change		% Change	
									
Discontinued operations, net of tax	 	$	22.9	 	 	$	(1.0	)	 	$	23.9	 	 	 	2,390.0	%	
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      In the first quarter of 2004, our discontinued operations was comprised primarily of the gain from the sale of our Lost Pines 1 Power Project. There were no assets held for sale as of March 31, 2003. 

							
		Three Months					
		Ended					
		March 31,					
							
		2004		2003		$ Change		% Change	
									
Cumulative effect of a change in accounting principle, net of tax	 	$	—	 	 	$	0.5	 	 	$	(0.5	)	 	 	(100.0	)%	
      The cumulative effect of a change in accounting principle, net of tax effect in 2003 resulted from adopting SFAS No. 143, “Accounting for Asset Retirement Obligations.” 

							
		Three Months					
		Ended					
		March 31,					
							
		2004		2003		$ Change		% Change	
									
Net loss	 	$	(71.2	)	 	$	(52.0	)	 	$	(19.2	)	 	 	36.9	%	
      We recorded a net loss of $71.2 for the first quarter of 2004, compared to a net loss of $52.0 for the same period last year. During the three months ended March 31, 2004, gross profit decreased by $44.6, or 27%, to $120.5, compared to the first quarter last year. This decrease is the result of lower spark spreads realized during the quarter and additional costs associated with new power plants coming on line. For the first quarter of 2004, we generated 21.1 million megawatt-hours, which equated to a capacity factor of 50.3%, and realized an average spark spread of $21.05 per megawatt-hour. For the same period in 2003, we generated 19.1 million megawatt-hours, which equated to a capacity factor of 55.2%, and realized an average spark spread of $22.91 per megawatt-hour. In the first quarter of 2004, as compared to the same period in 2003, generation did not increase commensurately with new average capacity coming on line (lower baseload capacity factor). Because of that and due to lower spark spreads per MWh, our spark spread margins did not keep pace with the additional operating and depreciation costs associated with the new capacity. Additional power plant costs include a $15.6 increase in depreciation expense, a $13.9 increase in plant operating expense and a $7.6 increase in transmission purchase expense. Also, in the first quarter of 2004, financial results were affected by a $96.2 increase in interest expense and distributions on trust preferred securities due to higher debt balances, and by the expensing of deferred financing costs in connection with the CalGen refinancing. We recorded $8.8 of amortization expense in other cost of revenue in the first quarter of 2004 related to a mark-to-market gain recognized in the fourth quarter of 2003 pursuant to adoption of Derivatives Implementation Group (“DIG”) Issue No. C20, “Scope Exceptions: Interpretation of the Meaning of Not Clearly and Closely Related in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature.”
      Other income was $53.9 higher in the quarter ended March 31, 2004, compared to the prior year due primarily to a foreign currency transaction gain of $10.0 in the current period. This compares to a $25.2 foreign currency transaction loss in the corresponding period in 2003. Additionally, in the first quarter of 2004, we recognized a $23.0 after-tax gain in discontinued operations from the sale of the Lost Pines 1 Power Project.
Liquidity and Capital Resources
      Our business is capital intensive. Our ability to capitalize on growth opportunities is dependent on the availability of capital on attractive terms. The availability of such capital in today’s environment is uncertain. To date, we have obtained cash from our operations; borrowings under our term loan and revolving credit facilities; issuance of debt, equity, trust preferred securities and convertible debentures; proceeds from sale/leaseback transactions; sale or partial sale of certain assets; contract monetizations and project financing. We have utilized this cash to fund our operations, service or prepay debt obligations, fund acquisitions, develop and construct power generation facilities, finance capital expenditures, support our hedging, balancing, optimization and trading activities at CES, and meet our other cash and liquidity needs. Our strategy is also to reinvest our cash from operations into our business development and construction program or to use it to reduce debt, rather than to pay cash dividends. As discussed below, we have a liquidity-enhancing program
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underway to fund the completion of our current construction portfolio, for refinancing and for general corporate purposes.
      In November 2004 our $2.5 billion secured revolving construction financing facility through our wholly owned subsidiary CCFC II (renamed “CalGen”) was scheduled to mature, requiring us to refinance this indebtedness. As of December 31, 2003, there was $2.3 billion outstanding under this facility including $53.2 million of letters of credit. On March 23, 2004, CalGen completed its offering of secured institutional term loans and secured notes, which refinanced the CalGen facility. We realized total proceeds from the offering in the amount of $2.4 billion, before transaction costs and fees. See Note 6 of the Notes to Consolidated Condensed Financial Statements for more information regarding this offering.
      The holders of our 4% Convertible Senior Notes Due 2006 (“2006 Convertible Senior Notes”) have a right to require us to repurchase them at 100% of their principal amount plus any accrued and unpaid interest on December 26, 2004. We can effect such a repurchase with cash, shares of Calpine stock or a combination of the two. In 2003 and 2004 we repurchased in open market and privately negotiated transactions totaling approximately $1,127.9 million of the outstanding principal amount of 2006 Convertible Senior Notes, primarily with proceeds of the July 2003 offerings and through equity swaps and with the proceeds of our 4.75% Contingent Convertible Senior Notes Due 2023 (“2023 Convertible Notes”) offering, and the February 9, 2004, tender offer, in which we initiated a cash tender offer for all of the outstanding 2006 Convertible Senior Notes for a price of par plus accrued interest. Approximately $409.4 million aggregate principal amount of the 2006 Convertible Senior Notes were tendered pursuant to the tender offer, for which we paid a total of $412.8 million (including accrued interest of $3.4 million). At March 31, 2004, 2006 Convertible Senior Notes in the aggregate principal amount of $72.1 million remain outstanding.
      On November 6, 2003, we priced our separate offerings of 2023 Convertible Notes and Second Priority Senior Secured Notes. The latter offering was for $400.0 million of 9.875% Second Priority Senior Secured Notes Due 2011, offered at 98.01% of par. This offering closed on November 18, 2003. We used the net proceeds from this offering to purchase outstanding senior notes. The other offering consisted of $650.0 million of 4.75% Contingent Convertible Senior Notes Due 2023, which included the exercise of $50.0 million of an option to purchase additional 2023 Convertible Notes granted to one of the initial purchasers. The 2023 Convertible Notes are convertible into cash and shares of Calpine common stock at an initial conversion price of $6.50 per share, which represents a 38% premium on the November 6, 2003 New York Stock Exchange closing price of $4.71 per Calpine common share. This offering closed on November 14, 2003. Net proceeds from this offering were used to repurchase our outstanding 2006 Convertible Senior Notes. In addition, on January 9, 2004, we received funding on an additional $250.0 million aggregate principal amount of the 2023 Convertible Notes pursuant to the exercise in full by one of the initial purchasers of its remaining option to purchase additional 2023 Convertible Notes, the net proceeds of which were also used to repurchase our outstanding 2006 Convertible Senior Notes pursuant to the tender offer described above.
      In addition, $276.0 million of our outstanding HIGH TIDES are scheduled to be remarketed no later than November 1, 2004, $360.0 million of our HIGH TIDES are scheduled to be remarketed no later than February 1, 2005 and $517.5 million of our HIGH TIDES are scheduled to be remarketed no later than August 1, 2005. In the event of a failed remarketing, the relevant HIGH TIDES will remain outstanding as convertible securities at a term rate equal to the treasury rate plus 6% per annum and with a term conversion price equal to 105% of the average closing price of our common stock for the five consecutive trading days after the applicable final failed remarketing termination date. While a failed remarketing of our HIGH TIDES would not have a material effect on our liquidity position, it would impact our calculation of diluted earnings per share and increase our interest expense.
      We expect to have sufficient liquidity from cash flow from operations, borrowings available under lines of credit, access to sale/leaseback and project financing markets, sale or monetization of certain assets and cash balances to satisfy all obligations under our outstanding indebtedness, and to fund anticipated capital expenditures and working capital requirements for the next twelve months. On March 31, 2004, our liquidity totaled approximately $1.4 billion. This included cash and cash equivalents on hand of $0.6 billion, current
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portion of restricted cash and cash escrowed for debt repurchases of approximately $0.4 billion and approximately $0.4 billion of borrowing capacity under our various credit facilities.
      Cash Flow Activities  — The following table summarizes our cash flow activities for the periods indicated: 

			
		Three Months Ended	
		March 31,	
			
		2004		2003	

		(In thousands)	
Beginning cash and cash equivalents	 	$	991,806	 	 	$	579,486	 	
Net cash provided by (used in):	 	 	 	 	 	 	 	 	
 	Operating activities	 	 	(173,230	)	 	 	165,367	 	
 	Investing activities	 	 	(71,371	)	 	 	(483,629	)	
 	Financing activities	 	 	(160,091	)	 	 	112,543	 	
 	Effect of exchange rates changes on cash and cash equivalents	 	 	(4,310	)	 	 	4,290	 	
 	 	 		 	 	 		 	
 	Net decrease in cash and cash equivalents	 	 	(409,002	)	 	 	(201,429	)	
 	 	 		 	 	 		 	
Ending cash and cash equivalents	 	$	582,804	 	 	$	378,057	 	
 	 	 		 	 	 		 	
      Operating activities for the three months ended March 31, 2004, used net cash of $173.2 million, compared to having provided $165.4 million for the same period in 2003. In the first quarter of 2004, there was a $137.7 million use of funds from net changes in operating assets and liabilities, comprised of an increase of $61 million in net margin deposits posted to support CES contracting activity, an increase of $23 million in accounts receivable, a use of funds of $35 million related to higher payments and pre-payments of property tax and $19 million in higher prepaid long-term service agreement payments.
      In the first quarter of 2003, there was a $56.6 million use of funds from net changes in operating assets and liabilities. Adjustments to reconcile net income to net cash provided by operating activities had the effect of lowering operating cash flow by $238.3 million between years. The increase in the tax benefit (decrease in deferred taxes) during 2004 contributed to $102.7 million of this difference. Additionally, an increase in 2004 of $67.4 million in gains from foreign exchange transactions and asset sales further contributed to the decrease in operating cash flow between periods. Finally, the change in net derivative liability comprised primarily of mark-to-market activity constitutes the majority of the remaining difference.
      Investing activities for the three months ended March 31, 2004, consumed net cash of $71.4 million, as compared to $483.6 million in the same period of 2003. Capital expenditures for the completion of our power facilities decreased in 2004, as there were fewer projects under construction. Investing activities in 2004 reflect the receipt of $176.9 million from the sale our Lost Pines Power Plant and certain oil and gas properties, as compared to $9.1 million of proceeds from other disposals in the prior year. We also reported a $187.5 million increase in cash used for acquisitions, as we used the proceeds from the Lost Pines sale and cash on hand to purchase the Los Brazos Power Plant, the remaining 50% interest in the Aries Power Plant, and the remaining 20% interest in Calpine Cogeneration Company’s fleet of plants. Finally, the $346.3 million decrease in restricted cash served as an investing activity inflow in 2004. The balance decreased in connection with the repurchase of debt with restricted cash (primarily the Convertible Senior Notes Due 2006.)
      Financing activities for the three months ended March 31, 2004, used $160.1 million, compared to having provided $112.5 million for the same period in 2003. We continued our refinancing program in the first quarter of 2004, by raising $2.4 billion to repay $2.3 billion of CCFC II project financing. In the first quarter of 2004, we also raised $250 million from the issuance of Convertible Senior Notes Due 2023 pursuant to an option exercise, and $315.1 million from various project financings, and we used $586.9 million of proceeds from convertible senior notes offerings to repurchase the majority of outstanding Convertible Senior Notes Due 2006 that come due in December.
      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
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are in bankruptcy or have below investment grade credit ratings. We believe that our current credit exposure to other companies in the energy industry is not significant either by individual company or in the aggregate.
      Letter of Credit Facilities  — At March 31, 2004 and December 31, 2003, we had approximately $512.1 million and $410.8 million, respectively, in letters of credit outstanding under various credit facilities to support CES risk management and other operational and construction activities. Of the total letters of credit outstanding, $323.0 million and $272.1 million were in aggregate issued under our cash collateralized letter of credit facility and the corporate revolving credit facility at March 31, 2004 and December 31, 2003, respectively.
      CES Margin Deposits and Other Credit Support  — As of March 31, 2004 and December 31, 2003, CES had deposited net amounts of $249.2 million and $188.0 million, respectively, in cash as margin deposits with third parties and had letters of credit outstanding of $14.5 million and $14.5 million, respectively. CES uses these margin deposits and letters of credit as credit support for the gas procurement and risk management activities it conducts on Calpine’s behalf. Future cash collateral requirements may increase based on the extent of our involvement in derivative activities and movements in commodity prices and also based on our credit ratings and general perception of creditworthiness in this market. While we believe that we have adequate liquidity to support CES’s operations at this time, it is difficult to predict future developments and the amount of credit support that we may need to provide as part of our business operations.
      Capital Availability  — Access to capital for many in the energy sector, including us, has been restricted since late 2001. While we have been able to access the capital and bank credit markets in this new environment, it has been on significantly different terms than in the past. In particular, our senior working capital facility and term loan financings and the majority of our debt securities offered and sold in this period, have been secured by certain of our assets and equity interests. While we believe we will be successful in refinancing all debt before maturity, the terms of financing available to us now and in the future may not be attractive to us and the timing of the availability of capital is uncertain and is dependent, in part, on market conditions that are difficult to predict and are outside of our control.
      During the three months ended March 31, 2004:

			
 	• 	We completed the $250 million, non-recourse project financing facility to fund the construction of our 600-megawatt Rocky Mountain Energy Center.	
 		
 	• 	Our wholly owned subsidiary Calpine Generating Company, LLC (“CalGen”), formerly Calpine Construction Finance Company II, LLC (“CCFC II”) completed its offering of secured institutional term loans and secured notes, totaling $2.4 billion before transaction costs and fees. Net proceeds from the offering were used to refinance amounts outstanding under the $2.5 billion CCFC II revolving construction credit facility, which was scheduled to mature in November 2004, and to pay fees and transaction costs associated with the refinancing.	
 		
 	• 	One of the initial purchasers of the 2023 Convertible Notes exercised in full its option to purchase an additional $250.0 million of these notes.	
 		
 	• 	We repurchased approximately $178.5 million in principal amount of the 2006 Convertible Senior Notes in exchange for approximately $177.5 million in cash. Additionally, on February 9, 2004, we made a cash tender offer, which expired on March 9, 2004, for any and all of the then still outstanding 2006 Convertible Senior Notes at a price of par plus accrued interest. On March 10, 2004, we paid an aggregate amount of $412.8 million for the tendered 2006 Convertible Senior Notes which included accrued interest of $3.4 million. At March 31, 2004, 2006 Convertible Senior Notes in the aggregate principal amount of $72.1 million remained outstanding.	
      Asset Sales  — As a result of the significant contraction in the availability of capital for participants in the energy sector, we have adopted a strategy of conserving our core strategic assets and disposing of certain less
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strategically important assets, which serves partially to strengthen our balance sheet through repayment of debt. Set forth below are the completed asset disposals during the period:
      On January 15, 2004, we completed the sale of our 50-percent undivided interest in the 545 megawatt Lost Pines 1 Power Project to GenTex Power Corporation, an affiliate of the Lower Colorado River Authority (“LCRA”). Under the terms of the agreement, we received a cash payment of $146.8 million and recorded a gain before taxes of $35.3 million. In addition, CES entered into a tolling agreement with LCRA to purchase 250 megawatts of electricity through December 31, 2004. At December 31, 2003, our undivided interest in the Lost Pines facility was classified as “held for sale” and all current and historical results reclassified to discontinued operations (See Note 8 of the Notes to Consolidated Condensed Financial Statements).
      On February 18, 2004, one of our wholly owned subsidiaries closed on the sale of natural gas properties to Calpine Natural Gas Trust (“CNG Trust”). We received consideration of Cdn$40.5 million (US$30.9 million). We hold 25% of the outstanding trust units of CNG Trust and account for the investment using the equity method.
      We believe that our completion of the financing and asset sales liquidity transactions described above in difficult conditions affecting the market, and our sector in general, demonstrate our probable ability to have access to the capital markets on acceptable terms in the future, although availability of capital has tightened significantly throughout the power generation industry and, therefore, there can be no assurance that we will have access to capital in the future as and when we may desire.
      Off-Balance Sheet Commitments  — In accordance with Accounting Principles Board (“APB”) Opinion No. 18, “The Equity Method of Accounting For Investments in Common Stock” and FASB Interpretation No. 35, “Criteria for Applying the Equity Method of Accounting for Investments in Common Stock (An Interpretation of APB Opinion No. 18),” the debt on the books of our unconsolidated investments in power projects is not reflected on our Consolidated Condensed Balance Sheet. At March 31, 2004, investee debt was approximately $289.6 million. Based on our pro rata ownership share of each of the investments, our share would be approximately $61.5 million. However, all such debt is non-recourse to us. See Note 7 of the Notes to Consolidated Condensed Financial Statements for additional information on our equity method investments in power projects and oil and gas properties.
      We own a 32.3% interest in the unconsolidated equity method investee Androscoggin Energy LLC (“AELLC”). AELLC owns the 160-MW Androscoggin Energy Center located in Maine and has construction debt of $60.1 million outstanding as of March 31, 2004. The debt is non-recourse to Calpine Corporation (the “AELLC Non-Recourse Financing”). On March 31, 2004, and December 31, 2003, our investment balance was $14.2 million and $11.8 million, respectively, and our notes receivable balance due from AELLC was $14.8 million and $13.3 million, respectively. On and after August 8, 2003, AELLC received letters from the lenders claiming that certain events of default have occurred under the credit agreement for the AELLC Non-Recourse Financing, including, among other things, that the project has been and remains in default under its debt agreement because the lending syndication had declined to extend the date for the conversion of the construction loan to a term loan. AELLC disputes the purported defaults. Also, the steam host for the AELLC project, International Paper Company (“IP”), filed a complaint against AELLC in October 2000, which is discussed in Note 12 of the Notes to Consolidated Condensed Financial Statements. IP’s complaint has been a complicating factor in converting the construction debt to long term financing. As a result of these events, we have reviewed our investment and notes receivable balances and believe that the assets are not impaired. We further believe that AELLC will be able to convert the construction loan to a term loan.
      Credit Considerations  — On March 22, 2004, S&P assigned its B corporate credit rating (with negative outlook) to our wholly owned subsidiary CalGen. Concurrently, S&P assigned its B+ rating and its 1 recovery rating to CalGen’s $235.0 million First Priority Secured Floating Rate Notes Due 2009 and the $600.0 million First Priority Secured Term Loans due 2009. S&P assigned its B rating and its 2 recovery rating to CalGen’s $640.0 million Second Priority Secured Floating Rate Notes Due 2010 and the $100.0 million Second Priority Secured Term Loans due 2010. S&P also assigned its CCC+ rating and its 5 recovery rating to CalGen’s
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$680.0 million Third Priority Secured Floating Rate Notes Due 2011 and the $150.0 million Third Priority Secured Notes Due 2011.
      Capital Spending — Development and Construction
      Construction and development costs in process consisted of the following at March 31, 2004 (dollars in thousands):

						Equipment		Project			
		# of				Included in		Development		Unassigned	
		Projects		CIP(1)		CIP		Costs		Equipment	
											
Projects in active construction	 	 	13	 	 	$	4,684,403	 	 	$	1,537,067	 	 	$	—	 	 	$	—	 	
Projects in advanced development	 	 	15	 	 	 	754,280	 	 	 	623,696	 	 	 	128,708	 	 	 	—	 	
Projects in suspended development	 	 	5	 	 	 	463,094	 	 	 	203,185	 	 	 	8,753	 	 	 	—	 	
Projects in early development	 	 	3	 	 	 	—	 	 	 	—	 	 	 	8,932	 	 	 	12,280	 	
Other capital projects	 	 	NA	 	 	 	50,620	 	 	 	31	 	 	 	—	 	 	 	—	 	
Unassigned equipment	 	 	NA	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	54,789	 	
 	 	 	 	 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Total construction and development costs	 	 	 	 	 	$	5,952,397	 	 	$	2,363,979	 	 	$	146,393	 	 	$	67,069	 	

		
(1) 	Construction in Progress (“CIP”).	
      Projects in Active Construction  — The 13 projects in active construction are estimated to come on line from May 2004 to June 2007. These projects will bring on line approximately 6,495 MW of base load capacity (7,685 MW base load 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 March 31, 2004, the estimated funding requirements to complete these projects, net of expected project financing proceeds, is approximately $1.2 billion.
      Projects in Advanced Development  — There are 15 projects in advanced development. These projects will bring on line approximately 6,735 MW of base load capacity (7,952 MW base load with peaking capacity). 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 two projects for which development activities are complete but construction will not commence until a power purchase agreement and financing are obtained. The estimated cost to complete the 15 projects in advanced development is approximately $4.4 billion. Our current plan is to project finance these costs as power purchase agreements are arranged.
      Suspended Development Projects  — Due to current electric market conditions, we have ceased capitalization of additional development costs and interest expense on certain development projects on which work has been suspended. Capitalization of costs may recommence as work on these projects resumes, if certain milestones and criteria are met. These projects would bring on line approximately 2,569 MW of base load capacity (3,029 MW base load with peaking capacity). The estimated cost to complete the five projects is approximately $1.5 billion.
      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 three projects and include geothermal drilling costs and equipment purchases.
      Other Capital Projects  — Other capital projects primarily consist of enhancements to operating power plants, oil and gas and geothermal resource and facilities development as well as software developed for internal use.
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      Unassigned Equipment  — As of March 31, 2004, we had made progress payments on 4 turbines, 1 heat recovery steam generator, and other equipment with an aggregate carrying value of $67.1 million. This unassigned equipment is classified on the balance sheet as other assets because it is not assigned to specific development and construction projects. We are 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 our engineering and construction services. For equipment that is not assigned to development or construction projects, interest is not capitalized.
      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. We review our unassigned equipment for potential impairment based on probability-weighted alternatives of utilizing the equipment for future projects versus selling the equipment. Utilizing this methodology, we do not believe that the equipment not committed to sale is impaired.
Performance Metrics
      In understanding our business, we believe that certain non-GAAP operating performance metrics are particularly important. These are described below:

			
 	• 	Total deliveries of power. We both generate power that we sell to third parties and purchase power for sale to third parties in hedging, balancing and optimization (“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, 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.	
 		
 	• 	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.	
 		
 	• 	Average heat rate for gas-fired fleet of power plants expressed in British Thermal Units (“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.	
 		
 	• 	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	
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 		generated by dividing (a) adjusted electricity and steam revenue, which includes capacity revenues, energy revenues, thermal revenues and the spread on sales of purchased power for hedging, balancing, and optimization activity, by (b) total generated MWh’s in the period.	
 		
 	• 	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 “equity” gas from Calpine Natural Gas, which is eliminated in consolidation), and the spread on sales of purchased gas for hedging, balancing, and optimization activity by (b) the heat content in millions of Btu’s of the fuel we consumed in our power plants for the period.	
 		
 	• 	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.	
 		
 	• 	Average plant operating expense per normalized MWh. To assess trends in electric power plant operating expense (“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’s. 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.	
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      The table below presents, the operating performance metrics discussed above. 

			
		Three Months Ended	
		March 31,	
			
		2004		2003	

		(In thousands)	
Operating Performance Metrics:	 	 	 	 	 	 	 	 	
 	Total deliveries of power:	 	 	 	 	 	 	 	 	
 	 	MWh generated	 	 	21,050	 	 	 	19,100	 	
 	 	HBO and trading MWh sold	 	 	19,598	 	 	 	17,520	 	
 	 	 		 	 	 		 	
 	 	MWh delivered	 	 	40,648	 	 	 	36,620	 	
 	 	 		 	 	 		 	
 	Average availability	 	 	92	%	 	 	88	%	
 	Average baseload capacity factor:	 	 	 	 	 	 	 	 	
 	 	Average total MW in operation	 	 	21,852	 	 	 	18,108	 	
 	 	Less: Average MW of pure peakers	 	 	2,951	 	 	 	2,219	 	
 	 	 		 	 	 		 	
 	 	Average baseload MW in operation	 	 	18,901	 	 	 	15,889	 	
 	 	Hours in the period	 	 	2,184	 	 	 	2,160	 	
 	 	Potential baseload generation	 	 	41,280	 	 	 	34,320	 	
 	 	Actual total generation	 	 	21,050	 	 	 	19,100	 	
 	 	Less: Actual pure peakers’ generation	 	 	273	 	 	 	171	 	
 	 	 		 	 	 		 	
 	 	Actual baseload generation	 	 	20,777	 	 	 	18,929	 	
 	 	Average baseload capacity factor	 	 	50.3	%	 	 	55.2	%	
 	Average heat rate for gas-fired power plants (excluding peakers) (Btu’s/ KWh):	 	 	 	 	 	 	 	 	
 	 	Not steam adjusted	 	 	8,167	 	 	 	7,968	 	
 	 	Steam adjusted	 	 	7,115	 	 	 	7,229	 	
 	Average all-in realized electric price:	 	 	 	 	 	 	 	 	
 	 	Electricity and steam revenue	 	$	1,245,887	 	 	$	1,100,067	 	
 	 	Spread on sales of purchased power for hedging and optimization	 	 	5,089	 	 	 	1,335	 	
 	 	 		 	 	 		 	
 	 	Adjusted electricity and steam revenue (in thousands)	 	$	1,250,976	 	 	$	1,101,402	 	
 	 	MWh generated (in thousands)	 	 	21,050	 	 	 	19,100	 	
 	 	Average all-in realized electric price per MWh	 	$	59.43	 	 	$	57.67	 	
 	Average cost of natural gas:	 	 	 	 	 	 	 	 	
 	 	Cost of oil and natural gas burned by power plants (in thousands)	 	$	770,454	 	 	$	624,849	 	
 	 	Fuel cost elimination	 	 	80,110	 	 	 	110,334	 	
 	 	 		 	 	 		 	
 	 	Adjusted fuel expense	 	$	850,564	 	 	$	735,183	 	
 	 	Million Btu’s (“MMBtu”) of fuel consumed by generating plants (in thousands)	 	 	150,357	 	 	 	122,936	 	
 	 	Average cost of natural gas per MMBtu	 	$	5.66	 	 	$	5.98	 	
 	 	MWh generated (in thousands)	 	 	21,050	 	 	 	19,100	 	
 	 	Average cost of adjusted fuel expense per MWh	 	$	40.41	 	 	$	38.49	 	
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		Three Months Ended	
		March 31,	
			
		2004		2003	

		(In thousands)	
Average spark spread:	 	 	 	 	 	 	 	 	
 	Adjusted electricity and steam revenue (in thousands)	 	$	1,250,976	 	 	$	1,101,402	 	
 	Less: Adjusted fuel expense (in thousands)	 	 	850,564	 	 	 	735,183	 	
 	 	 		 	 	 		 	
 	Spark spread (in thousands)	 	$	400,412	 	 	$	366,219	 	
 	MWh generated (in thousands)	 	 	21,050	 	 	 	19,100	 	
 	Average spark spread per MWh	 	$	19.02	 	 	$	19.17	 	
 	Add: Equity gas contribution(1)	 	$	42,684	 	 	$	71,275	 	
 	Spark spread with equity gas benefits (in thousands)	 	$	443,096	 	 	$	437,494	 	
 	Average spark spread with equity gas benefits per MWh	 	$	21.05	 	 	$	22.91	 	
Average plant operating expense (“POX”) per normalized MWh (for comparison purposes we also include POX per actual MWh):	 	 	 	 	 	 	 	 	
 	Average total consolidated MW in operations	 	 	21,852	 	 	 	18,108	 	
 	Hours in the period	 	 	2,184	 	 	 	2,160	 	
 	Total potential MWh	 	 	47,725	 	 	 	39,113	 	
 	Normalized MWh (at 70% capacity factor)	 	 	33,408	 	 	 	27,379	 	
 	Plant operating expense (POX)	 	$	175,834	 	 	$	161,929	 	
 	POX per normalized MWh	 	$	5.26	 	 	$	5.91	 	
 	Actual MWh generated (in thousands)	 	 	21,050	 	 	 	19,100	 	
 	 	 		 	 	 		 	
 	POX per actual MWh	 	$	8.35	 	 	$	8.48	 	

		
(1) 	Equity gas contribution margin:	

		Three Months Ended	
		March 31,	
			
		2004		2003	

		(In thousands)	
Oil and gas sales	 	$	24,581	 	 	$	25,911	 	
Add: Fuel cost eliminated in consolidation	 	 	80,110	 	 	 	110,334	 	
 	 	 		 	 	 		 	
 	Subtotal	 	$	104,691	 	 	$	136,245	 	
Less: Oil and gas operating expense	 	 	22,328	 	 	 	25,661	 	
Less: Depletion, depreciation and amortization	 	 	39,679	 	 	 	39,309	 	
 	 	 		 	 	 		 	
Equity gas contribution margin	 	$	42,684	 	 	 	71,275	 	
MWh generated (in thousands)	 	 	21,050	 	 	 	19,100	 	
Equity gas contribution margin per MWh	 	$	2.03	 	 	$	3.73	 	
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      The table below provides additional detail of total mark-to-market activity. For the three months ended March 31, 2004 and 2003, mark-to-market activity, net consisted of (dollars in thousands): 

		2004		2003	
					
Mark-to-market activity, net	 	 	 	 	 	 	 	 	
 	 	Realized: Power activity	 	 	 	 	 	 	 	 	
 	 	“Trading Activity” as defined in EITF No. 02-03	 	$	18,708	 	 	$	14,836	 	
 	 	Other mark-to-market activity(1)	 	 	(1,171	)	 	 	—	 	
 	 	 		 	 	 		 	
 	 	 	Total realized power activity	 	$	17,537	 	 	$	14,836	 	
 	 	 		 	 	 		 	
 	Gas activity	 	 	 	 	 	 	 	 	
 	 	“Trading Activity” as defined in EITF No. 02-03	 	$	(74	)	 	$	6,378	 	
 	 	Other mark-to-market activity(1)	 	 	—	 	 	 	—	 	
 	 	 		 	 	 		 	
 	 	 	Total realized gas activity	 	$	(74	)	 	$	6,378	 	
 	 	 		 	 	 		 	
Total realized activity:	 	 	 	 	 	 	 	 	
 	 	“Trading Activity” as defined in EITF No. 02-03	 	$	18,634	 	 	$	21,214	 	
 	 	Other mark-to-market activity(1)	 	 	(1,171	)	 	 	—	 	
 	 	 		 	 	 		 	
 	 	 	Total realized activity	 	$	17,463	 	 	$	21,214	 	
 	 	 		 	 	 		 	
Unrealized:	 	 	 	 	 	 	 	 	
 	 	Power activity	 	 	 	 	 	 	 	 	
 	 	“Trading Activity” as defined in EITF No. 02-03	 	$	(693	)	 	$	(1,881	)	
 	 	Ineffectiveness related to cash flow hedges	 	 	(540	)	 	 	(3,026	)	
 	 	Other mark-to-market activity(1)	 	 	(9,795	)	 	 	—	 	
 	 	 		 	 	 		 	
 	 	 	Total unrealized power activity	 	$	(11,028	)	 	$	(4,907	)	
 	 	 		 	 	 		 	
 	Gas activity	 	 	 	 	 	 	 	 	
 	 	“Trading Activity” as defined in EITF No. 02-03	 	$	637	 	 	$	(1,977	)	
 	 	Ineffectiveness related to cash flow hedges	 	 	5,446	 	 	 	6,113	 	
 	 	Other mark-to-market activity(1)	 	 	—	 	 	 	—	 	
 	 	 		 	 	 		 	
 	 	Total unrealized gas activity	 	$	6,083	 	 	$	4,136	 	
 	 	 		 	 	 		 	
Total unrealized activity:	 	 	 	 	 	 	 	 	
 	“Trading Activity” as defined in EITF No. 02-03	 	$	(56	)	 	$	(3,858	)	
 	Ineffectiveness related to cash flow hedges	 	 	4,906	 	 	 	3,087	 	
 	Other mark-to-market activity(1)	 	 	(9,795	)	 	 	—	 	
 	 	 		 	 	 		 	
 	 	Total unrealized activity	 	$	(4,945	)	 	$	(771	)	
 	 	 		 	 	 		 	
Total mark-to-market activity:	 	 	 	 	 	 	 	 	
 	“Trading Activity” as defined in EITF No. 02-03	 	$	18,578	 	 	$	17,356	 	
 	Ineffectiveness related to cash flow hedges	 	 	4,906	 	 	 	3,087	 	
 	Other mark-to-market activity(1)	 	 	(10,966	)	 	 	 	 	
 	 	 		 	 	 		 	
 	 	Total mark-to-market activity	 	$	12,518	 	 	$	20,443	 	

		
(1) 	Activity related to our assets but does not qualify for hedge accounting.	
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Overview

	Summary of Key Activities	

	Finance — New Issuances	
 	 	 	 	 	
Date		Amount		Description	
					
1/9/04	 	$250.0 million	 	Initial purchasers of the 2023 Convertible Notes exercised in full their purchase option	
2/20/04	 	$250.0 million	 	Completed a non-recourse project financing for Rocky Mountain Energy Center at a rate of LIBOR plus 250 basis points	
3/23/04	 	$2.4 billion	 	CalGen, formerly CCFC II, completed its offering of secured term loans and secured notes	
     Finance — Repurchases

Date		Amount		Description	
					
1/04-3/04	 	$178.5 million	 	Repurchased $178.5 million in principal of our outstanding 2006 Convertible Senior Notes that can be put to the Company in exchange for $177.5 million in cash	
3/10/04	 	$412.8 million	 	Paid an aggregate of $412.8 million for the cash tender offer of the 2006 Convertible Senior Notes	
3/24/04	 	$9.0 million	 	Repurchased $9.0 million in principal of 8 1/2% Senior Notes Due 2011 and $11.0 million in principal of 7 3/4% Senior Notes Due 2009 for cash of $14.8 million	
     Other:

Date				Description	
					
1/2004	 	Completed sale of 50-percent interest in Lost Pines 1 Power Project for a cash payment of $146.8 million	
1/2004	 	CES concluded a settlement with the Commodity Futures Trading Commission and paid a civil monetary penalty in the amount of $1.5 million	
2/2004	 	Closed on the sale of natural gas properties to CNG Trust for consideration of Cdn$40.5 million (US$30.9 million)	
2/2004	 	Entered into a one-year agreement with Cleco Power LLC to supply up to 500 megawatts of power	
2/2004	 	Entered into five power sales contracts to supply approximately 350 megawatts of electricity to five New England-based electric distribution companies for delivery in 2004	
3/2004	 	Entered into a 20-year purchased power agreement to provide 365 megawatts of electric power to Xcel Energy	
3/2004	 	Acquired the remaining 50-percent interest in the Aries Power Plant from Aquila, Inc.	
3/2004	 	Completed the acquisition of the remaining 20 percent interest in Calpine Cogeneration Company for approximately $2.5 million	
3/2004	 	Entered into a three-year power sales agreement with Safeway Inc. to supply approximately 100 megawatts to Safeway facilities throughout California	
3/2004	 	Closed on the purchase of Brazos Valley Power Plant for approximately $175.0 million	
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     Power Plant Development and Construction:

Date		Project		Description	
					
1/2004	 	Morgan Energy Center Expansion	 	Commercial Operation	
California Power Market
      We may be required to make refund payments to the CalPX and CAISO as a result of the California Refund Proceeding. On August 2, 2000, the California Refund Proceeding was initiated by a complaint made at FERC by San Diego Gas & Electric Company 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 (“ALJ”) 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. We believe, based on the available information, that any refund liability that may be attributable to us will increase modestly, from approximately $6.2 million to $8.4 million, after taking the appropriate set-offs for outstanding receivables owed by the CalPX and CAISO to us. We have fully reserved the amount of refund liability that by our analysis would potentially be owed under the refund calculation clarification in the March 26 order. 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. At this time, we are unable to predict the timing of the completion of these proceedings or the final refund liability. Thus the impact on our 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 we entered into with the California governmental entities on April 22, 2002. Our settlement was approved by FERC on March 26, 2004, in an order which partially dismissed us from the California Refund Proceeding to the extent that any refunds are owed for power sold by us to CDWR or any other agency of the State of California.
      FERC Investigation into 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 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. FERC has stated that it may use the information gathered in connection with the investigation to determine how to proceed on any existing or future complaint brought under Section 206 of the Federal Power Act involving long-term power contracts entered into in the West since January 1, 2000, or to initiate a Federal Power Act Section 206 or Natural Gas
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Act Section 5 proceeding on its own initiative. 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 us 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 us, regarding certain power scheduling practices that may have been be in violation of the CAISO’s or CalPX’s tariff. The Final Report also recommended that FERC modify the basis for determining potential liability in the California Refund Proceeding discussed above. We believe that we did not violate these tariffs and that, to the extent that such a finding could be made, any potential liability would not be material.
      Also, on June 25, 2003, FERC issued a number of orders associated with these investigations, including the issuance of two show cause orders to certain industry participants. FERC did not subject us to either of the show cause orders. FERC also issued an order directing the FERC Office of Markets and Investigations to investigate further whether market participants who bid a price in excess of $250 per megawatt hour into markets operated by either the CAISO or the CalPX during the period of May 1, 2000, to October 2, 2000, may have violated CAISO and CalPX tariff prohibitions. No individual market participant was identified. We believe that we 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 us.
      CPUC Proceeding Regarding QF Contract Pricing for Past Periods. Our Qualifying Facilities (“QF”) contracts with 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 Utility Code, which provides QFs the right to elect to receive energy payments based on the CalPX 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. The CPUC at one point issued a proposed decision to the effect that the PX Price was the appropriate price for energy payments under the California Public Utility Code but tabled it, and a final decision has not been issued to date. Therefore, it is possible that the CPUC could order a 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 requests that the CPUC set a briefing schedule under the R.99-11-022 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 allege that refund liability be determined using the methodology that has been developed thus far in the California Refund Proceeding discussed above. 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 FERC in the California Refund Proceeding is unfounded, but there can be no assurance that this will be the outcome of the CPUC proceedings.
      Geysers Reliability Must Run Section 206 Proceeding. CAISO, California Electricity Oversight Board, Public Utilities Commission of the State of California, Pacific Gas and Electric Company, 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 Power Company, LLC, 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 ISO to meet local transmission reliability needs or to manage transmission constraints. The Buyers Coalition has asked FERC to find that the availability payments under
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these RMR Contracts are not just and reasonable. Geysers Power Company, LLC filed an answer to the complaint in November 2001. To date, FERC has not established a Section 206 proceeding. The outcome of this litigation and the impact on our business cannot be determined at the present time.
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, 2004 through March 31, 2004, is summarized in the table below (in thousands): 

Fair value of contracts outstanding at January 1, 2004	 	$	76,541	 	
Gains recognized or otherwise settled during the period(1)	 	 	(11,239	)	
Changes in fair value attributable to new contracts	 	 	(3,748	)	
Changes in fair value attributable to price movements	 	 	46,928	 	
 	 	 		 	
 	Fair value of contracts outstanding at March 31, 2004(2)	 	$	108,482	 	

		
(1) 	Consists of (a) recognized losses from commodity cash flow hedges of $(6.2) million (represents realized value of cash flow hedge activity of $(12.6) million as disclosed in Note 9 of the Notes to Consolidated Condensed Financial Statements, net of terminated derivatives of $(8.9) million and equity method hedges of $2.5 million) and (b) $17.5 million realized gain on mark-to-market activity, which is reported in the Consolidated Condensed Statements of Operations under mark-to-market activities, net.	
 		
(2) 	Net commodity derivative assets reported in Note 9 of the Notes to Consolidated Condensed Financial Statements.	
      The fair value of outstanding derivative commodity instruments at March 31, 2004, based on price source and the period during which the instruments will mature, are summarized in the table below (in thousands): 

Fair Value Source		2004		2005-2006		2007-2008		After 2008		Total	
											
Prices actively quoted	 	$	71,947	 	 	$	45,917	 	 	$	—	 	 	$	 —	 	 	$	117,864	 	
Prices provided by other external sources	 	 	(43,747	)	 	 	47,628	 	 	 	6,298	 	 	 	(22,354	)	 	 	(12,175	)	
Prices based on models and other valuation methods	 	 	—	 	 	 	776	 	 	 	7,976	 	 	 	(5,959	)	 	 	2,793	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Total fair value	 	$	28,200	 	 	$	94,321	 	 	$	14,274	 	 	$	(28,313	)	 	$	108,482	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
      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.
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      The counterparty credit quality associated with the fair value of outstanding derivative commodity instruments at March 31, 2004, and the period during which the instruments will mature are summarized in the table below (in thousands): 

Credit Quality		2004		2005-2006		2007-2008		After 2008		Total	

(Based on Standard & Poor’s Ratings as of April 5, 2004)									
Investment grade	 	$	(15,166	)	 	$	67,206	 	 	$	14,620	 	 	$	(28,313	)	 	$	38,347	 	
Non-investment grade	 	 	50,260	 	 	 	27,842	 	 	 	—	 	 	 	—	 	 	 	78,102	 	
No external ratings	 	 	(6,894	)	 	 	(727	)	 	 	(346	)	 	 	—	 	 	 	(7,967	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Total fair value	 	$	28,200	 	 	$	94,321	 	 	$	14,274	 	 	$	(28,313	)	 	$	108,482	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
      The fair value of outstanding derivative commodity instruments and the fair value that would be expected after a 10% adverse price change are shown in the table below (in thousands): 

				Fair Value	
				After 10%	
				Adverse	
		Fair Value		Price Change	
					
At March 31, 2004:	 	 	 	 	 	 	 	 	
 	Electricity	 	$	(78,424	)	 	$	(213,771	)	
 	Natural gas	 	 	186,906	 	 	 	110,683	 	
 	 	 		 	 	 		 	
 	 	Total	 	$	108,482	 	 	$	(103,088	)	
      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 ten percent adverse price change regardless of term or historical relationship between the contract price of an instrument and the underlying commodity price. In the event of an actual ten percent change in prices, the fair value of our derivative portfolio would typically change by more than ten percent for earlier forward months and less than ten percent for later forward months because of the higher volatilities in the near term and the effects of discounting expected future cash flows.
      The primary factors affecting the fair value of our derivatives at any point in time are (1) the volume of open derivative positions (MMBtu and MWh), and (2) changing commodity market prices, principally for electricity and natural gas. The total volume of open gas derivative positions increased 91% from December 31, 2003, to March 31, 2004, while the total volume of open power derivative positions decreased 20% for the same period. In that prices for electricity and natural gas are among the most volatile of all commodity prices, there may be material changes in the fair value of our derivatives over time, driven both by price volatility and the changes in volume of open derivative transactions. Under SFAS No. 133, the change since the last balance sheet date in the total value of the derivatives (both assets and liabilities) is reflected either in Other Comprehensive Income (“OCI”), net of tax, or in the statement of operations as an item (gain or loss) of current earnings. As of March 31, 2004, the majority of the balance in accumulated OCI represented the unrealized net loss associated with commodity cash flow hedging transactions. As noted above, there is a substantial amount of volatility inherent in accounting for the fair value of these derivatives, and our results during the three months ended March 31, 2004, have reflected this. See Note 9 of the Notes to Consolidated Condensed Financial Statements for additional information on derivative activity and OCI.
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      Collateral Debt Securities  — In connection with the decision of the Calpine Power Income Fund (“CPIF”) to acquire the King City Power Plant and become the lessor of the facility, we intend to sell certain investments previously accounted for as held-to-maturity. As of March 31, 2004, the securities are classified as available-for-sale and recorded at fair market value in Other Current Assets. The following table presents the face value of our different classes of collateral debt securities by expected maturity date as of March 31, 2004, (dollars in thousands): 

		Weighted															
		Average															
		Interest															
		Rate		2004		2005		2006		2007		2008		Thereafter		Total	
																	
Corporate Debt Securities	 	 	7.3	%	 	$	4,575	 	 	$	7,825	 	 	$	—	 	 	$	 —	 	 	$	—	 	 	$	 —	 	 	$	12,400	 	
U.S. Treasury Notes	 	 	6.5	%	 	 	—	 	 	 	1,975	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	1,975	 	
U.S. Treasury Securities (non-interest bearing)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	9,700	 	 	 	9,100	 	 	 	9,050	 	 	 	87,100	 	 	 	114,950	 	
 	 	 	 	 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Total	 	 	 	 	 	$	4,575	 	 	$	9,800	 	 	$	9,700	 	 	$	9,100	 	 	$	9,050	 	 	$	87,100	 	 	$	129,325	 	
 	 	 	 	 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
      The following table presents the fair value of our collateral debt securities as of March 31, 2004, (dollars in thousands): 

		Fair Value	
			
Corporate Debt Securities	 	$	12,854	 	
U.S. Treasury Notes	 	 	2,115	 	
U.S. Treasury Securities (non-interest bearing)	 	 	85,352	 	
 	 	 		 	
 	Total	 	$	100,321	 	
 	 	 		 	
      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. 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 March 31, 2004, (dollars in thousands): 
      Variable to Fixed Swaps

				Weighted Average					
		Notional		Interest Rate		Weighted Average Interest		Fair Market	
Maturity Date		Principal Amount		(Pay)		Rate (Receive)		Value	
									
2007	 	$	38,000	 	 	 	3.8	%	 	3-month US $	LIBOR	 	 	$	(1,307	)	
2007	 	 	38,333	 	 	 	3.8	%	 	3-month US $	LIBOR	 	 	 	(1,318	)	
2007	 	 	38,667	 	 	 	3.8	%	 	3-month US $	LIBOR	 	 	 	(1,330	)	
2011	 	 	41,879	 	 	 	6.9	%	 	3-month US $	LIBOR	 	 	 	(6,332	)	
2012	 	 	109,998	 	 	 	6.5	%	 	3-month US $	LIBOR	 	 	 	(17,293	)	
2014	 	 	58,682	 	 	 	6.7	%	 	3-month US $	LIBOR	 	 	 	(8,599	)	
2016	 	 	21,750	 	 	 	7.3	%	 	3-month US $	LIBOR	 	 	 	(4,807	)	
2016	 	 	14,500	 	 	 	7.3	%	 	3-month US $	LIBOR	 	 	 	(3,204	)	
2016	 	 	43,500	 	 	 	7.3	%	 	3-month US $	LIBOR	 	 	 	(9,613	)	
2016	 	 	29,000	 	 	 	7.3	%	 	3-month US $	LIBOR	 	 	 	(6,409	)	
2016	 	 	36,250	 	 	 	6.7	%	 	3-month US $	LIBOR	 	 	 	(8,011	)	
 	 	 		 	 	 		 	 	 	 	 	 	 		 	
 	Total	 	$	470,559	 	 	 	6.1	%	 	 	 	 	 	$	(68,223	)	
 	 	 		 	 	 		 	 	 	 	 	 	 		 	
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      Fixed to Variable Swaps

						Weighted Average			
		Notional		Weighted Average Interest		Interest Rate		Fair Market	
Maturity Date		Principal Amount		Rate (Pay)		(Receive)		Value	
									
2011	 	$	100,000	 	 	6-month US $	LIBOR	 	 	 	8.5	%	 	$	(3,716	)	
2011	 	 	100,000	 	 	6-month US $	LIBOR	 	 	 	8.5	%	 	 	(1,861	)	
2011	 	 	200,000	 	 	6-month US $	LIBOR	 	 	 	8.5	%	 	 	(4,091	)	
2018	 	 	106,000	 	 	3-month US $	LIBOR	 	 	 	4.0	%	 	 	96	 	
 	 	 		 	 	 	 	 	 	 		 	 	 		 	
 	Total	 	$	506,000	 	 	 	 	 	 	 	7.6	%	 	$	(9,572	)	
 	 	 		 	 	 	 	 	 	 		 	 	 		 	
      The fair value of outstanding interest rate swaps and the fair value that would be expected after a one percent adverse interest rate change are shown in the table below (in thousands): 
      Variable to Fixed Swaps

		Fair Value After a 1.0%	
		(100 Basis Point) Adverse	
Fair Value as of March 31, 2004		Interest Rate Change	
			
$(68,223)	 	$	(92,338	)	
 	 	 		 	
      Fixed to Variable Swaps

		Fair Value After a 1.0%	
		(100 Basis Point) Adverse	
Fair Value as of March 31, 2004		Interest Rate Change	
			
$(9,572)	 	$	(27,530	)	
 	 	 		 	
      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”, 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 March 31, 2004, 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: 

Currency Exposure		Impact to Pre-tax Net Income	
			
GBP-Euro	 	$	(22,063	)	
$C-$US	 	 	(5,966	)	
$C-Euro	 	 	(1,494	)	
      Significant changes in exchange rates will also impact our Cumulative Translation Adjustment (“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 2003. During 2003, CTA increased by approximately $200 million primarily due to a weakening of the U.S. dollar of approximately 18% and 10% against the Canadian dollar and Great British Pound, respectively.
      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
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could have a negative impact on our future interest expense. Our variable-rate construction/project financing is primarily through CalGen. Borrowings under this credit agreement are used exclusively to fund the construction of our power plants. 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.
      The following table summarizes our variable-rate debt exposed to interest rate risk as of March 31, 2004. All fair market values are shown net of applicable premium or discount, if any (dollars in thousands): 

														Fair Value	
		2004(6)		2005		2006		2007		2008		Thereafter		3/31/2004	
															
3-month US$LIBOR weighted average interest rate basis(4)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
First Priority Senior Secured Term Loan B Notes Due 2007	 	$	1,500	 	 	$	2,000	 	 	$	2,000	 	 	$	193,500	 	 	$	—	 	 	$	 —	 	 	$	199,000	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
MEP Pleasant Hill Term Loan, Tranche A	 	 	3,413	 	 	 	6,700	 	 	 	7,482	 	 	 	8,132	 	 	 	9,271	 	 	 	95,235	 	 	 	130,233	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Riverside Energy Center Project Financing	 	 	5,111	 	 	 	7,603	 	 	 	8,011	 	 	 	163,927	 	 	 	—	 	 	 	1	 	 	 	184,653	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Total of 3-month US$LIBOR rate debt	 	 	10,024	 	 	 	16,303	 	 	 	17,493	 	 	 	365,559	 	 	 	9,271	 	 	 	95,236	 	 	 	513,886	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
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)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Rocky Mountain Energy Center project financing	 	 	2,636	 	 	 	4,856	 	 	 	5,526	 	 	 	168,175	 	 	 	—	 	 	 	1	 	 	 	181,194	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
First Priority Secured Floating Rate Notes Due 2009 (CalGen)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	1,175	 	 	 	2,350	 	 	 	231,475	 	 	 	235,000	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Total of 1-Month US$LIBOR rate debt	 	 	2,363	 	 	 	4,856	 	 	 	5,526	 	 	 	169,350	 	 	 	2,350	 	 	 	231,476	 	 	 	416,194	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 		 	 	 		 	
6-month US$LIBOR weighted average interest rate basis(4)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Third Priority Secured Floating Rate Notes Due 2011 (CalGen)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	680,000	 	 	 	680,000	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Total of 6-Month US$LIBOR rate debt	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	680,000	 	 	 	680,000	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 		 	 	 		 	
(1)(4)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
First Priority Secured Institutional Term Loan Due 2009 (CCFC I)	 	 	1,604	 	 	 	3,208	 	 	 	3,208	 	 	 	3,208	 	 	 	3,208	 	 	 	365,190	 	 	 	379,626	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 		 	 	 		 	
Second Priority Senior Secured Floating Rate Notes Due 2011 (CCFC I)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	407,840	 	 	 	407,840	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Total of variable rate debt as defined at (1) below	 	 	1,604	 	 	 	3,208	 	 	 	3,208	 	 	 	3,208	 	 	 	3,208	 	 	 	773,030	 	 	 	787,466	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 		 	 	 		 	
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														Fair Value	
		2004(6)		2005		2006		2007		2008		Thereafter		3/31/2004	
															
(2)(4)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Second Priority Senior Secured Term Loan B Notes Due 2007	 	 	5,625	 	 	 	7,500	 	 	 	7,500	 	 	 	725,625	 	 	 	—	 	 	 	—	 	 	 	746,250	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Total of variable rate debt as defined at (2) below	 	 	5,625	 	 	 	7,500	 	 	 	7,500	 	 	 	725,625	 	 	 	—	 	 	 	—	 	 	 	746,250	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 		 	 	 		 	
(3)(4)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Second Priority Senior Secured Floating Rate Notes Due
2007	 	 	3,750	 	 	 	5,000	 	 	 	5,000	 	 	 	483,750	 	 	 	—	 	 	 	—	 	 	 	497,500	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 		 	 	 		 	
Blue Spruce Energy Center project financing	 	 	—	 	 	 	1,875	 	 	 	3,750	 	 	 	3,750	 	 	 	3,750	 	 	 	126,875	 	 	 	140,000	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Total of variable rate debt as defined at (3) below	 	 	3,750	 	 	 	6,875	 	 	 	8,750	 	 	 	487,500	 	 	 	3,750	 	 	 	126,875	 	 	 	637,500	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
(5)(4)	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
First Priority Secured Term Loans Due 2009 (CalGen)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	3,000	 	 	 	6,000	 	 	 	591,000	 	 	 	600,000	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Second Priority Secured Floating Rate Notes Due 2010 (CalGen)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	3,200	 	 	 	627,239	 	 	 	630,439	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Second Priority Secured Term Loans Due 2010 (CalGen)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	500	 	 	 	98,006	 	 	 	98,506	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Total of variable rate debt as defined at (5) below	 	 	—	 	 	 	—	 	 	 	—	 	 	 	3,000	 	 	 	9,700	 	 	 	1,316,245	 	 	 	1,328,945	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Total variable-rate construction/project financing and other variable-rate instruments	 	$	23,639	 	 	$	38,742	 	 	$	42,477	 	 	$	1,754,242	 	 	$	28,279	 	 	$	3,222,862	 	 	$	5,110,241	 	

		
(1) 	British Bankers Association LIBOR Rate for deposit in US dollars for a period of six months.	
 		
(2) 	U.S. prime rate in combination with the Federal Funds Effective Rate.	
 		
(3) 	British Bankers Association LIBOR Rate for deposit in US dollars for a 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) 	For the nine months remaining in 2004.	
      Construction/project financing facility  — In November 2004 the $2.5 billion secured construction financing revolving facility for our wholly owned subsidiary CCFC II (or CalGen) was scheduled to mature. On March 23, 2004, CalGen completed its offering of secured institutional term loans and secured notes, which refinanced the CalGen facility. We realized total proceeds from the offering in the amount of $2.4 billion, before transaction costs and fees. See Note 6 of the Notes to Consolidated Condensed Financial Statements for more information regarding this offering.
      On February 20, 2004, we completed a $250.0 million, non-recourse project financing for the 600-megawatt Rocky Mountain Energy Center. A consortium of banks financed the construction of the plant at a rate of LIBOR plus 250 basis points. Upon commercial operation of the Rocky Mountain Energy Center in the summer of 2004, the banks will provide a three-year term-loan facility.
      On March 26, 2004, we acquired the remaining 50% interest in the Aries facility from a subsidiary of Aquila, Inc. (Aquila and its subsidiaries referred to collectively as “Aquila”). At the same time, Aries terminated a tolling contract with another subsidiary of Aquila. Aquila paid $5 million in cash and assigned to
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us certain transmission and other rights. Aquila and Calpine also amended a master netting agreement between them, and as a result, we returned cash margin deposits totaling $10.8 million to Aquila. Contemporaneous with the closing of the acquisition, Aries’ existing construction loan was converted to two term loans totaling $178.8 million, of which $130.2 is variable-rate debt. We contributed $15 million of equity to Aries in connection with the term out of the construction loan.
New Accounting Pronouncements
      On January 1, 2003, we 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 amends 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 Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees” 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 provides two additional transition options to report the change in accounting principle — the modified prospective method and the retroactive restatement method. Additionally, SFAS No. 148 amends 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. We elected to adopt the provisions of SFAS No. 123 on a prospective basis; consequently, we are required to provide a pro-forma disclosure of net income and earnings per share as if SFAS No. 123 accounting had been applied to all prior periods presented within its financial statements. See Note 2 of the Notes to Consolidated Condensed Financial Statements for more information.
      In January 2003 FASB issued FIN 46. FIN 46 requires the consolidation of an entity by an enterprise that absorbs a majority of the entity’s expected losses, receives a majority of the entity’s expected residual returns, or both, as a result of ownership, contractual or other financial interest in the entity. Historically, entities have generally been consolidated by an enterprise when it has a controlling financial interest through ownership of a majority voting interest in the entity. The objectives of FIN 46 are to provide guidance on the identification of Variable Interest Entities (“VIEs”) for which control is achieved through means other than ownership of a majority of the voting interest of the entity, and how to determine which business enterprise (if any), as the Primary Beneficiary, should consolidate the Variable Interest Entity (“VIE”). This new model for consolidation applies to an entity in which either (1) the at-risk equity is insufficient to absorb expected losses without additional subordinated financial support or (2) its at-risk equity holders as a group are not able to make decisions that have a significant impact on the success or failure of the entity’s ongoing activities. A variable interest in a VIE, by definition, is an asset, liability, equity, contractual arrangement or other economic interest that absorbs the entity’s variability.
      In December 2003 FASB modified FIN 46 with FIN 46-R to make certain technical corrections and to address certain implementation issues. FIN 46, as originally issued, was effective immediately for VIEs created or acquired after January 31, 2003. FIN 46-R delayed the effective date of the interpretation to no later than March 31, 2004, (for calendar-year enterprises), except for Special Purpose Entities (“SPEs”) for which the effective date was December 31, 2003. We have adopted FIN 46-R for our investment in SPEs, equity method joint ventures, our wholly owned subsidiaries that are subject to long-term power purchase agreements and tolling arrangements, operating lease arrangements containing fixed price purchase options and our wholly owned subsidiaries that have issued mandatorily redeemable non-controlling preferred interests.
      We evaluated our investments in joint ventures and operating lease arrangements containing fixed price purchase options and concluded that, in some instances, these entities were VIEs. However,in these instances, we were not the Primary Beneficiary, as we would not absorb a majority of these entities’ expected variability. The fixed price purchase options under our operating lease arrangements were not considered significant
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variable interests. However, our investments in joint ventures were considered significant. See Note 7 of the Notes to Consolidated Condensed Financial Statements for more information related to these joint venture investments.
      An analysis was performed for 100% Company-owned subsidiaries with significant long-term power sales or tolling agreements. Certain of the 100% Company-owned subsidiaries were deemed to be VIEs by virtue of a power sales or tolling agreement which was longer than 10 years and for more than 50% of the entity’s capacity. However, in all cases, we absorbed a majority of the entity’s variability and continue to consolidate these 100% Company-owned subsidiaries. We qualitatively determined that power sales or tolling agreements less than 10 years in length and for less than 50% of the entity’s capacity would not cause the power purchaser to be the Primary Beneficiary, due to the length of the economic life of the underlying assets. Also, power sales and tolling agreements meeting the definition of a lease under EITF Issue No. 01-08, “Determining Whether an Arrangement Contains a Lease,” were not considered variable interests, because payments under these leasing arrangements create rather than absorb the entity’s variability.
      A similar analysis was performed for our wholly owned subsidiaries that have issued mandatorily redeemable non-controlling preferred interests. These entities were determined to be VIEs in which we absorb the majority of the variability, primarily due to the debt characteristics of the preferred interest, which are classified as debt in accordance with SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” in our Consolidated Condensed Balance Sheets. Consequently, we continue to consolidate these wholly owned subsidiaries. See Note 2 of the Notes to Consolidated Condensed Financial Statements for more information.

Item 3.	Quantitative and Qualitative Disclosures About Market Risk.	
      See “Financial Market Risks” in Item 2.

Item 4.	Controls and Procedures.	
      As reported in the Company’s Form 10-K filing for the year ended December 31, 2003, in connection with the audit of the Company’s financial statements for the fiscal year ended December 31, 2003, its independent registered public accounting firm reviewed the Company’s information systems control framework and identified to the Company certain significant deficiencies in the design of such systems. These design deficiencies generally related to the number of persons having access to certain of the Company’s information systems databases, as well as the segregation of duties of persons with such access. The Company has concluded that, in the aggregate, these deficiencies constituted a material weakness in its internal control over financial reporting, and the Company has performed substantial analytical and post-closing procedures as a result of these design deficiencies. Based on the Company’s compensating controls and testing, it has concluded that these design deficiencies did not result in any material errors in its financial statements. Additionally, the Company has completed the process of correcting these design deficiencies by taking the following steps:

			
 	• 	manual procedures have been replaced with system-based controls to ensure proper segregation of duties and documentation of approval for the Journal Entry and Vendor Maintenance processes; and	
 		
 	• 	system access rights for financial system software updates have been re-defined and restricted to segregate incompatible activities and allow user activities to be monitored.	
      The Company continues to test the effectiveness of these changes.
      Other than correcting the material control weakness identified above, there were no other changes in the Company’s internal controls over financial reporting identified in connection with the evaluation required by paragraph (d) of Rule 13a-15 or Rule 15d-15 that have materially affected, or are reasonably likely to materially affect, the Company’s internal controls over financial reporting.
      The Company’s Chief Executive Officer and Chief Financial Officer supervised the evaluation of the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities
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Exchange Act of 1934, as amended) required by paragraph (b) of Rule 13a-15 or Rule 15d-15, as of December 31, 2003, and based on such evaluation concluded that, despite the material weakness described above, the Company’s disclosure controls and procedures overall were effective to ensure the timely collection, evaluation and disclosure of information relating to the Company that would potentially be subject to disclosure under the Securities Exchange Act of 1934, as amended, and the rules and regulations promulgated thereunder.
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PART II — OTHER INFORMATION

Item 1.	Legal Proceedings.	
      We are 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 we 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 our Consolidated Condensed Financial Statements.
      Securities Class Action Lawsuits. Since March 11, 2002, fourteen shareholder lawsuits have been filed against Calpine and certain of its officers in the United States District Court for the Northern District of California. The actions captioned Weisz v. Calpine Corp., et al. , filed March 11, 2002, and Labyrinth Technologies, Inc. v. Calpine Corp., et al. , filed March 28, 2002, are purported class actions on behalf of purchasers of Calpine stock between March 15, 2001 and December 13, 2001. Gustaferro v. Calpine Corp. , filed April 18, 2002, is a purported class action on behalf of purchasers of Calpine stock between February 6, 2001 and December 13, 2001. The eleven other actions, captioned Local 144 Nursing Home Pension Fund v. Calpine Corp., Lukowski v. Calpine Corp., Hart v. Calpine Corp., Atchison v. Calpine Corp., Laborers Local 1298 v. Calpine Corp., Bell v. Calpine Corp., Nowicki v. Calpine Corp. Pallotta v. Calpine Corp., Knepell v. Calpine Corp., Staub v. Calpine Corp. , and Rose v. Calpine Corp. were filed between March 18, 2002 and April 23, 2002. The complaints in these eleven actions are virtually identical  — they are filed by three law firms, in conjunction with other law firms as co-counsel. All eleven lawsuits are purported class actions on behalf of purchasers of Calpine’s securities between January 5, 2001 and December 13, 2001.
      The complaints in these fourteen actions allege that, during the purported class periods, certain Calpine executives issued false and misleading statements about Calpine’s financial condition in violation of Sections 10(b) and 20(1) of the Securities Exchange Act of 1934, as well as Rule 10b-5. These actions seek an unspecified amount of damages, in addition to other forms of relief.
      In addition, a fifteenth securities class action, Ser v. Calpine, et al. , was filed on May 13, 2002. The underlying allegations in the Ser action are substantially the same as those in the above-referenced actions. However, the Ser action is brought on behalf of a purported class of purchasers of Calpine’s 8.5% Senior Notes Due February 15, 2011 (“2011 Notes”) and the alleged class period is October 15, 2001 through December 13, 2001. The Ser complaint alleges that, in violation of Sections 11 and 15 of the Securities Act of 1933, the Supplemental Prospectus for the 2011 Notes contained false and misleading statements regarding Calpine’s financial condition. This action names Calpine, certain of its officers and directors, and the underwriters of the 2011 Notes offering as defendants, and seeks an unspecified amount of damages, in addition to other forms of relief.
      All fifteen of these securities class action lawsuits were consolidated in the United States District Court for the Northern District of California. Plaintiffs filed a first amended complaint in October 2002. The amended complaint did not include the 1933 Act complaints raised in the bondholders’ complaint, and the number of defendants named was reduced. On January 16, 2003, before our response was due to this amended complaint, plaintiffs filed a further second complaint. This second amended complaint added three additional Calpine executives and Arthur Andersen LLP as defendants. The second amended complaint set forth additional alleged violations of Section 10 of the Securities Exchange Act of 1934 relating to allegedly false and misleading statements made regarding Calpine’s role in the California energy crisis, the long term power contracts with the California Department of Water Resources, and Calpine’s dealings with Enron, and additional claims under Section 11 and Section 15 of the Securities Act of 1933 relating to statements regarding the causes of the California energy crisis. We filed a motion to dismiss this consolidated action in early April 2003.
      On August 29, 2003, the judge issued an order dismissing, with leave to amend, all of the allegations set forth in the second amended complaint except for a claim under Section 11 of the Securities Act relating to
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statements relating to the causes of the California energy crisis and the related increase in wholesale prices contained in the Supplemental Prospectuses for the 2011 Notes.
      The judge instructed plaintiff, Julies Ser, to file a third amended complaint, which he did on October 17, 2003. The third amended complaint names Calpine and three executives as defendants and alleges the Section 11 claim that survived the judge’s August 29, 2003 order.
      On November 21, 2003, Calpine and the individual defendants moved to dismiss the third amended complaint on the grounds that plaintiff’s Section 11 claim was barred by the applicable one-year statute of limitations.
      On February 4, 2004, the judge denied our motion to dismiss but has asked the parties to be prepared to file summary judgment motions to address the statute of limitations issue. We filed our answer to the third amended complaint on February 28, 2004.
      In a separate order dated February 4, 2004, the court denied without prejudice Julies Ser’s motion to be appointed lead plaintiff. Mr. Ser subsequently stated he no longer desired to serve as lead plaintiff. On April 4, 2004, the Policemen and Firemen Retirement System of the City of Detroit (“P&F”) moved to be appointed lead plaintiff. Calpine filed a response in opposition to this motion. The court has scheduled a hearing on this matter for May 11, 2004.
      We consider the lawsuit to be without merit and we intend to continue to defend vigorously against these allegations.
      Hawaii Structural Ironworkers Pension Fund v. Calpine, et al. A securities class action, Hawaii Structural Ironworkers Pension Fund v. Calpine, et al. , was filed on March 11, 2003, against Calpine, its directors and certain investment banks in state superior court of San Diego County, California. The underlying allegations in the Hawaii Structural Ironworkers Pension Fund action (“Hawaii action”) are substantially the same as the federal securities class actions described above. However, the Hawaii action is brought on behalf of a purported class of purchasers of Calpine’s equity securities sold to public investors in its April 2002 equity offering. The Hawaii action alleges that the Registration Statement and Prospectus filed by Calpine which became effective on April 24, 2002, contained false and misleading statements regarding Calpine’s financial condition in violation of Sections 11, 12 and 15 of the Securities Act of 1933. The Hawaii action relies in part on Calpine’s restatement of certain past financial results, announced on March 3, 2003, to support its allegations. The Hawaii action seeks an unspecified amount of damages, in addition to other forms of relief.
      We removed the Hawaii action to federal court in April 2003 and filed a motion to transfer the case for consolidation with the other securities class action lawsuits in the United States District Court for the Northern District of California in May 2003. Plaintiff sought to have the action remanded to state court, and on August 27, 2003, the United States District Court for the Southern District of California granted plaintiff’s motion to remand the action to state court. In early October 2003 plaintiff agreed to dismiss the claims it has against three of the outside directors.
      On November 5, 2003, Calpine, the individual defendants and the underwriter defendants filed motions to dismiss this complaint on numerous grounds. On February 6, 2004, the court issued a tentative ruling sustaining our motion to dismiss on the issue of plaintiff’s standing. The court found that plaintiff had not shown that it had purchased Calpine stock “traceable” to the April 2002 equity offering. The court overruled our motion to dismiss on all other grounds. On March 12, 2004, after oral argument on the issues, the court confirmed its February 2, 2004, ruling.
      On February 20, 2004, plaintiff filed an amended complaint, and in late March 2004 Calpine and the individual defendants filed answers to this complaint. On April 9, 2004, we and the individual defendants filed motions to transfer the lawsuit to Santa Clara County Superior Court, which motions were granted on May 7, 2004. We consider this lawsuit to be without merit and intend to continue to defend vigorously against it.
      Phelps v. Calpine Corporation, et al. On April 17, 2003, a participant in the Calpine Corporation Retirement Savings Plan (the “401(k) Plan”) filed a class action lawsuit in the United States District Court for the Northern District of California. The underlying allegations in this action (“Phelps action”) are
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substantially the same as those in the securities class actions described above. However, the Phelps action is brought on behalf of a purported class of participants in the 401(k) Plan. The Phelps action alleges that various filings and statements made by Calpine during the class period were materially false and misleading, and that defendants failed to fulfill their fiduciary obligations as fiduciaries of the 401(k) Plan by allowing the 401(k) Plan to invest in Calpine common stock. The Phelps action seeks an unspecified amount of damages, in addition to other forms of relief. In May 2003 Lennette Poor-Herena, another participant in the 401(k) Plan, filed a substantially similar class action lawsuit as the Phelps action also in the Northern District of California. Plaintiffs’ counsel is the same in both of these actions, and they have agreed to consolidate these two cases and to coordinate them with the consolidated federal securities class actions described above. On January 20, 2004, plaintiff James Phelps filed a consolidated ERISA complaint naming Calpine and numerous individual current and former Calpine Board members and employees as defendants. Pursuant to a stipulated agreement with plaintiff, Calpine’s response to the amended complaint is due June 18, 2004. We consider this lawsuit to be without merit and intend to vigorously defend against it.
      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 captioned Johnson v. Cartwright, et al. and is pending in state superior court of 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. In March 2003 Calpine and the individual defendants filed motions to dismiss and motions to stay this proceeding in favor of the federal securities class actions described above. In July 2003 the court granted the motions to stay this proceeding in favor of the consolidated federal securities class actions described above. We cannot estimate the possible loss or range of possible loss from this matter. We consider this lawsuit to be without merit and intend to vigorously defend against it.
      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 have been 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 in favor of the consolidated federal securities class action described above and to dismiss without prejudice certain director defendants. On March 4, 2003, plaintiff filed papers with the court voluntarily agreeing to dismiss without prejudice the claims he had against three of the outside directors. We cannot estimate the possible loss or range of possible loss from this matter. We consider this lawsuit to be without merit and intend to continue to defend vigorously against it.
      Calpine Corporation v. Automated Credit Exchange. On March 5, 2002, Calpine sued Automated Credit Exchange (“ACE”) in state superior court of Alameda County, California for negligence and breach of contract to recover reclaim trading credits, a form of emission reduction credits that should have been held in Calpine’s account with U.S. Trust Company (“US Trust”). Calpine wrote off $17.7 million in December 2001 related to losses that it alleged were caused by ACE. Calpine and ACE entered into a Settlement Agreement on March 29, 2002, pursuant to which ACE made a payment to Calpine of $7 million and transferred to Calpine the rights to the emission reduction credits to be held by ACE. We recognized the $7 million as income in the second quarter of 2002. In June 2002 a complaint was filed by InterGen North America, L.P. (“InterGen”) against Anne M. Sholtz, the owner of ACE, and EonXchange, another Sholtz-controlled entity, which filed for bankruptcy protection on May 6, 2002. InterGen alleges it suffered a loss of emission reduction credits from EonXchange in a manner similar to Calpine’s loss from ACE. InterGen’s complaint alleges that Anne Sholtz co-mingled assets among ACE, EonXchange and other Sholtz entities and that ACE and other Sholtz entities should be deemed to be one economic enterprise and all retroactively included in the EonXchange bankruptcy filing as of May 6, 2002. By a judgment entered on October 30, 2002, the bankruptcy court consolidated ACE and the other Sholtz controlled entities with the bankruptcy estate of EonXchange. Subsequently, the Trustee of EonXchange filed a separate motion to substantively consolidate
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Anne Sholtz into the bankruptcy estate of EonXchange. Although Anne Sholtz initially opposed such motion, she entered into a settlement agreement with the Trustee consenting to her being substantively consolidated into the bankruptcy proceeding. The bankruptcy court entered an order approving Anne Sholtz’s settlement agreement with the Trustee on April 3, 2002. On July 10, 2003, Howard Grobstein, the Trustee in the EonXchange bankruptcy, filed a complaint for avoidance against Calpine, seeking recovery of the $7 million (plus interest and costs) paid to Calpine in the March 29, 2002 Settlement Agreement. The complaint claims that the $7 million received by Calpine in the Settlement Agreement was transferred within 90 days of the filing of bankruptcy and therefore should be avoided and preserved for the benefit of the bankruptcy estate. On August 28, 2003, Calpine filed its answer denying that the $7 million is an avoidable preference. On January 26, 2004, Calpine filed a motion for partial summary judgment asserting that the bankruptcy court did not properly consolidate Anne Sholtz into the bankruptcy estate of EonXchange. If the motion is granted, at least $2.9 million of the $7 million that the Trustee is seeking to recover from Calpine could not be avoided as a preferential transfer. In response, the Trustee filed a motion for summary judgment for the entire $7 million plus interest against Calpine. Although Calpine will assert various defenses to the claims asserted by the Trustee, Calpine and the Trustee have entered into stipulations to continue the various hearing dates on the pending motions for summary judgment in order to pursue settlement discussions. We believe we have adequately reserved for the possible loss, if any, we may ultimately incur as a result of this matter.
      International Paper Company v. Androscoggin Energy LLC. In October 2000 International Paper Company (“IP”) filed a complaint in the United States District Court for the Northern District of Illinois against Androscoggin Energy LLC (“AELLC”) alleging that AELLC breached certain contractual representations and warranties by failing to disclose facts surrounding the termination, effective May 8, 1998, of one of AELLC’s fixed-cost gas supply agreements. We had acquired a 32.3% interest in AELLC as part of the SkyGen transaction which closed in October 2000. AELLC filed a counterclaim against IP that has been referred to arbitration that AELLC may commence at its discretion upon further evaluation. 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 IP on the liability aspect of a particular claim against AELLC. The court also denied a motion submitted by IP for preliminary injunction to permit IP to make payment of funds into escrow (not directly to AELLC) and require AELLC to post a significant bond.
      In mid-April of 2003 IP unilaterally availed itself to self-help in withholding amounts in excess of $2.0 million as a set-off for litigation expenses and fees incurred to date as well as an estimated portion of a rate fund to AELLC. Upon AELLC’s amended complaint and request for immediate injunctive relief against such actions, the court ordered that IP must pay the approximately $1.2 million withheld as attorneys’ fees related to the litigation as any such perceived entitlement was premature, but deferred to provide injunctive relief on the incomplete record concerning the offset of $799,000 as an estimated pass-through of the rate fund. IP complied with the order on April 29, 2003, and tendered payment to AELLC of the approximately $1.2 million. On June 26, 2003, the court entered an order dismissing AELLC’s amended counterclaim without prejudice to AELLC refiling the claims as breach of contract claims in a separate lawsuit. On December 11, 2003, the court denied in part IP’s summary judgment motion pertaining to damages. In short, the court: (i) determined that, as a matter of law, IP is entitled to pursue an action for damages as a result of AELLC’s breach, and (ii) ruled that sufficient questions of fact remain to deny IP summary judgment on the measure of damages as IP did not sufficiently establish causation resulting from AELLC’s breach of contract (the liability aspect of which IP obtained a summary judgment in December 2002). On February 2, 2004, the parties filed a Final Pretrial Order with the court. The case appears likely scheduled for trial in the second quarter of 2004, subject to the court’s discretion and calendar. We believe we have adequately reserved for the possible loss, if any, we may ultimately incur as a result of this matter.
      Pacific Gas and Electric Company v. Calpine Corporation, et al. On July 22, 2003, Pacific Gas and Electric Company (“PG&E”) filed with the California Public Utilities Commission (“CPUC”) a Complaint of PG&E and Request for Immediate Issuance of an Order to Show Cause (“complaint”) against Calpine Corporation, CPN Pipeline Company, Calpine Energy Services, L.P., Calpine Natural Gas Company, and Lodi Gas Storage, LLC (“LGS”). The complaint requests the CPUC to issue an order requiring defendants to show cause why they should not be ordered to cease and desist from using any direct interconnections
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between the facilities of CPN Pipeline and those of LGS unless LGS and Calpine first seek and obtain regulatory approval from the CPUC. The complaint also seeks an order directing defendants to pay to PG&E any underpayments of PG&E’s tariffed transportation rates and to make restitution for any profits earned from any business activity related to LGS’ direct interconnections to any entity other than PG&E. The complaint further alleges that various natural gas consumers, including Calpine affiliated generation projects within California, are engaged with defendants in the acts complained of, and that the defendants unlawfully bypass PG&E’s system and operate as an unregulated local distribution company within PG&E’s service territory. On August 27, 2003, Calpine filed its answer and a motion to dismiss. LGS also made similar filings. On October 16, 2003, the presiding administrative law judge denied the motion to dismiss and on October 24, 2003, issued a Scoping Memo and Ruling establishing a procedural schedule and set the matter for an evidentiary hearing. On January 15, 2004, Calpine, LGS and PG&E executed a Settlement Agreement to resolve all outstanding allegations and claims raised in the complaint. Certain aspects of the Settlement Agreement are effective immediately and the effectiveness of other provisions is subject to the approval of the Settlement Agreement by the CPUC. In the event the CPUC fails to approve the Settlement Agreement, its operative terms and conditions become null and void. The Settlement Agreement provides, in part, for: 1) PG&E to be paid $2.7 million; 2) the disconnection of the LGS interconnections with Calpine; 3) Calpine to obtain PG&E consent or regulatory or other governmental approval before resuming any sales or exchanges at the Ryer Island Meter Station; 4) PG&E’s withdrawal of its public utility claims against Calpine; and 5) no party admitting any wrongdoing. Accordingly, the presiding administrative law judge vacated the hearing schedule and established a new procedural schedule for the filing of the Settlement Agreement. On February 6, 2004, the Settlement Agreement was filed with the CPUC. The parties were given the opportunity to submit comments and reply comments on the Settlement Agreement. The matter is currently pending and shall be considered by the CPUC following the issuance of a recommendation by the presiding administrative law judge.
      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 Calpine and certain of its affiliates in the United States District Court for the Northern District of Texas, alleging, among other things, that we breached duties of care and loyalty allegedly owed to Panda by failing to correctly construct and operate the Oneta Energy Center (“Oneta”), which we acquired from Panda, in accordance with Panda’s original plans. Panda alleges that it is entitled to a portion of the profits from Oneta plant and that Calpine’s actions have reduced the profits from Oneta plant thereby undermining Panda’s ability to repay monies owed to Calpine on December 1, 2003, under a promissory note on which approximately $38.6 million (including interest) is currently outstanding and past due. The note is collateralized by Panda’s carried interest in the income generated from Oneta, which achieved full commercial operations in June 2003. We have filed a counterclaim against Panda Energy International, Inc. (and PLC II, LLC) based on a guaranty, and have also filed a motion to dismiss as to the causes of action alleging federal and state securities laws violations. The motion to dismiss is currently pending before the court. However, at the present time, we cannot estimate the potential loss, if any, that might arise from this matter. We consider Panda’s lawsuit to be without merit and intend to defend vigorously against it. We stopped accruing interest income on the promissory note due December 1, 2003, as of the due date because of Panda’s default in repayment of the note.
      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 twenty energy traders and energy companies, including CES, alleges that defendants exercised market power and manipulated prices in violation of California Business & Professions Code Section 17200 et seq., and seeks injunctive relief, restitution, and attorneys’ fees. We also have been named in seven other similar complaints for violations of Section 17200. All seven cases were removed from the various state courts in which they were originally filed to federal court for pretrial proceedings with other cases in which we are not named as a defendant. However, at the present time, we cannot estimate the potential loss, if any, that might arise from this matter. We consider the allegations to be without merit, and filed a motion to dismiss on August 28, 2003. The court granted the motion, and plaintiffs have appealed.
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      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 17200 cases, but also seeks rescission of the long-term power contracts with the California Department of Water Resources.
      Upon motion from another newly added defendant, Millar was recently removed to federal court. It has now been transferred to the same judge that is presiding over the other 17200 cases described above, where it will be consolidated with such cases for pretrial purposes. We anticipate filing a timely motion for dismissal of Millar as well.
      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, Nevada Power Company (“NPC”) and Sierra Pacific Power Company (“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, which seeks a refund, that the prices they agreed to pay in certain of the power sales agreements, including those signed with Calpine, were negotiated during a time when the power market was dysfunctional and that they are unjust and unreasonable. 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 the relief that it was seeking. In June 2003, FERC rejected the complaint. Some plaintiffs appealed to the FERC and their request for rehearing was denied. The FERC decision is therefore final, and the matter is pending on appeal before the United States Court of Appeals for the Ninth Circuit.
      Transmission Service Agreement with Nevada Power. On March 16, 2004, NPC filed a petition for declaratory order at FERC (Docket No. EL04-90-000) asking that an order be issued requiring Calpine and Reliant Energy Services, Inc. to pay for transmission service under their Transmission Service Agreements (“TSAs”) with NPC or, if the TSAs are terminated, to pay the lesser of the transmission charges or a pro rata share of the total cost of NPC’s Centennial Project (approximately $33 million for Calpine). Calpine had previously provided security to NPC for these costs in the form of a surety bond issued by Fireman’s Fund Insurance Company (“FFIC”). The Centennial Project involves construction of various transmission facilities in two phases; Calpine’s Moapa Energy Center (“MEC”) is scheduled to receive service under its TSA from facilities yet to be constructed in the second phase of the Centennial Project. Calpine has filed a protest to the petition asserting that Calpine will take service under the TSA if NPC proceeds to execute a purchase power agreement (“PPA”) with MEC based on its winning bid in the Request for Proposals that NPC conducted in 2003. Calpine also has taken the position that if NPC does not execute a PPA with MEC, it will terminate the TSA and any payment by Calpine would be limited to a pro rata allocation of costs incurred to date on the second phase of the project (approximately $4.5 million in total) among the three customers to be served. At this time, we are unable to predict the final outcome of this proceeding or its impact on us.
      On or about April 27, 2004, NPC alleged to FFIC that Calpine had defaulted on the TSA and made demand on FFIC for the full amount of the surety bond, $33,333,333.00. On April 29, 2004, FFIC filed a complaint for declaratory order in state superior court of Marin County, California in connection with this demand.
      FFIC’s complaint asks that an order be issued declaring that it has no obligation to make payment under the bond and, if the court determines that FFIC does have an obligation to make payment, FFIC asks that an order be issued declaring that (i) Calpine has an obligation to replace it with funds equal to the amount of NPC’s demand against the bond and (ii) Calpine is obligated to indemnify and hold FFIC harmless for all loss, costs and fees incurred as a result of the issuance of the bond. Calpine is preparing to file a response to the complaint. Calpine’s position will be, among other items, that it did not default on its obligations under the TSA and therefore NPC is not entitled to make a demand upon the FFIC bond. At this time, we are unable to predict the outcome of this proceeding or its impact on us.
      Calpine Canada Natural Gas Partnership v. Enron Canada Corp. On February 6, 2002, Calpine Canada Natural Gas Partnership (“Calpine Canada”) filed a complaint in the Alberta Court of Queens
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Branch alleging that Enron Canada Corp. (“Enron Canada”) owed it approximately $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 $18 million. Discovery is currently in progress, and we believe that Enron Canada’s counterclaim is without merit and intend to vigorously defend against it.
      Jones 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 Darrell Jones. 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 has not occurred and the daily reduction in the payment amount has reduced the $18.0 million payment to zero. The complaint alleges 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. The complaint seeks damages in an unspecified amount in excess of $75,000. 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 have filed a motion for reconsideration of the decision, and the plaintiffs may also ultimately appeal. Calpine still, however, expects to make the $6.0 million payment to the estates when the project is completed.
      In addition, we are involved in various other claims and legal actions arising out of the normal course of our business. We do not expect that the outcome of these proceedings will have a material adverse effect on our financial position or results of operations.

Item 2.	Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities.	
Convertible Senior Notes
      4% Convertible Senior Notes Due 2006. On December 26, 2001, we completed a private placement of $1.0 billion aggregate principal amount of our 4% Convertible Senior Notes Due 2006 (“2006 Convertible Senior Notes”). The initial purchaser of the 2006 Convertible Senior Notes was Deutsche Bank Alex. Brown Inc. Deutsche Bank exercised its option to acquire an additional $200.0 million aggregate principal amount of the 2006 Convertible Senior Notes by purchasing an additional $100.0 million aggregate principal amount of the 2006 Convertible Senior Notes on each of December 31, 2001, and January 3, 2002. The offering price of the 2006 Convertible Senior Notes was 100% of the principal amount, less an aggregate underwriting discount of $30.0 million. Each sale of the 2006 Convertible Senior Notes to Deutsche Bank was exempt from registration in reliance on Section 4(2) under the Securities Act of 1933, as amended, as a transaction not involving a public offering. The 2006 Convertible Senior Notes were re-offered by Deutsche Bank to qualified institutional buyers in reliance on Rule 144A under the Securities Act.
      We subsequently filed with the SEC a registration statement with respect to resales of the 2006 Convertible Senior Notes, which was declared effective by the SEC on June 21, 2002.
      The 2006 Convertible Senior Notes are convertible into shares of our common stock at a conversion price of $18.07 per share which represents a 13.0% premium over the New York Stock Exchange closing price of $15.99 per share on December 26, 2001. The conversion price is subject to adjustment in certain circumstances. We have reserved 66,408,411 shares of our authorized common stock for issuance upon conversion of the 2006 Convertible Senior Notes, which are convertible at any time on or before the close of business on the day that is two business days prior to the maturity date, December 26, 2006, unless we have previously repurchased the 2006 Convertible Senior Notes. Holders of the 2006 Convertible Senior Notes have the right to require us to repurchase their notes on at par plus accrued interest December 26, 2004. We may choose to pay the repurchase price in cash or shares of common stock, or a combination thereof.
      During the three months ended March 31, 2004, we repurchased $178.5 million in principal amount of our outstanding 2006 Convertible Senior Notes that can be put to us in exchange for $177.5 million in cash.
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Additionally, on February 9, 2004, we made a cash tender offer, which expired on March 9, 2004, for any and all of the then still outstanding 2006 Convertible Senior Notes at a price of par plus accrued interest. On March 10, 2004, we paid an aggregate amount of $412.8 million for the tendered 2006 Convertible Senior Notes, which included accrued interest of $3.4 million. At March 31, 2004, 2006 Convertible Senior Notes in the aggregate principal amount of $72.1 million remain outstanding.
      4 3/4% Contingent Convertible Senior Notes Due 2023. On November 17, 2003, we completed the issuance of $650 million aggregate principal amount of our 43/4% Contingent Convertible Senior Notes Due 2023 (“2023 Convertible Notes”). The initial purchasers of the 2023 Convertible Notes were Deutsche Bank Securities Inc., Credit Lyonnais Securities (USA) Inc., Harris Nesbitt Corp. and Williams Capital Group LP (the “initial purchasers”). One of the initial purchasers, Deutsche Bank Securities Inc., exercised its option to acquire an additional $250.0 million aggregate principal amount of the 2023 Convertible Notes on January 9, 2004. The offering price of the 2023 Convertible Notes was 100% of the principal amount of the 2023 Convertible Senior Notes, less an aggregate underwriting discount of $24.75 million. Each sale of the 2023 Convertible Notes to an initial purchaser was exempt from registration in reliance on Section 4(2) under the Securities Act of 1933, as amended, as a transaction not involving a public offering. The 2023 Convertible Notes were offered by each initial purchaser to qualified institutional buyers in reliance on Rule 144A under the Securities Act.
      Upon the occurrence of certain contingencies, the 2023 Convertible Notes are convertible, at the option of holder, into cash and shares of our common stock at an initial conversion price of $6.50 per share, which represents a 38% premium over The New York Stock Exchange closing price of $4.71 per share on November 6, 2003. The number of shares of our common stock a holder ultimately receives upon conversion is determined by a formula based on the closing price of our common stock on The New York Stock Exchange over a period of five consecutive trading days during a specified period. We have initially reserved 69,230,000 shares of our authorized common stock for issuance upon conversion of the 2023 Convertible Notes, and have undertaken to reserve additional shares as may be necessary to satisfy our obligation to deliver shares upon conversion if our stock price increases such that the numbers of shares reserved is inadequate. Upon conversion of the 2023 Convertible Notes, we will deliver par value in cash and any additional value in shares of our common stock. The 2023 Contingent Notes will mature on November 15, 2023. We may redeem some or all of the notes at any time on or after November 22, 2009, at a redemption price, payable in cash, of 100% of the principal amount of the notes, plus accrued and unpaid interest and additional interest, if any, up to but not including the date of redemption. Holders have the right to require us to repurchase all or a portion of the 2023 Convertible Notes on November 22, 2009, 2013 and 2018, at 100% of their principal amount plus any accrued and unpaid interest. We have the right to repurchase the 2023 Convertible Senior Notes with cash, shares of our common stock, or a combination of cash and our common stock.

Item 6.	Exhibits and Reports on Form 8-K.	
      (a) Exhibits
      The following exhibits are filed herewith unless otherwise indicated: 
EXHIBIT INDEX 

Exhibit			
Number		Description	
			
 	*3	.1	 	Amended and Restated Certificate of Incorporation of Calpine Corporation, as amended through June 2, 2004.(a)	
 	*3	.2	 	Amended and Restated By-laws of Calpine Corporation.(b)	
 	*4	.1.1	 	Indenture, dated as of May 16, 1996, between the Company and U.S. Bank(as successor trustee to Fleet National Bank), as Trustee, including form of Notes.(c)	
 	*4	.1.2	 	First Supplemental Indenture, dated as of August 1, 2000, between the Company and U.S. Bank National Association (as successor trustee to Fleet National Bank), as Trustee.(d)	
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Exhibit			
Number		Description	
			
 	*4	.1.3	 	Second Supplemental Indenture, dated as of April 26, 2004, between the Company and U.S. Bank National Association (as successor trustee to Fleet National Bank), as Trustee.(e)	
 	*4	.2.1	 	Indenture, dated as of July 8, 1997, between the Company and The Bank of New York, as Trustee, including form of Notes.(f)	
 	*4	.2.2	 	Supplemental Indenture, dated as of September 10, 1997, between the Company and The Bank of New York, as Trustee.(g)	
 	*4	.2.3	 	Second Supplemental Indenture, dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(d)	
 	*4	.2.4	 	Third Supplemental Indenture, dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee.(e)	
 	*4	.3.1	 	Indenture, dated as of March 31, 1998, between the Company and The Bank of New York, as Trustee, including form of Notes.(h)	
 	*4	.3.2	 	Supplemental Indenture, dated as of July 24, 1998, between the Company and The Bank of New York, as Trustee.(h)	
 	*4	.3.3	 	Second Supplemental Indenture, dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(d)	
 	*4	.3.4	 	Third Supplemental Indenture, dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee.(e)	
 	*4	.4.1	 	Indenture, dated as of March 29, 1999, between the Company and The Bank of New York, as Trustee, including form of Notes.(i)	
 	*4	.4.2	 	First Supplemental Indenture, dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(d)	
 	*4	.4.3	 	Second Supplemental Indenture, dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee.(e)	
 	*4	.5.1	 	Indenture, dated as of March 29, 1999, between the Company and The Bank of New York, as Trustee, including form of Notes.(i)	
 	*4	.5.2	 	First Supplemental Indenture, dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(d)	
 	*4	.5.3	 	Second Supplemental Indenture, dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee.(e)	
 	*4	.6.1	 	Indenture, dated as of August 14, 2003, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust Company, as Trustee, including form of Notes.(j)	
 	*4	.6.2	 	Supplemental Indenture, dated as of September 18, 2003, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust Company, as Trustee.(j)	
 	*4	.6.3	 	Second Supplemental Indenture, dated as of January 14, 2004, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust Company, as Trustee.(k)	
 	*4	.6.4	 	Third Supplemental Indenture, dated as of March 5, 2004, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust Company, as Trustee.(k)	
 	*4	.7	 	Amended and Restated Indenture, dated as of March 12, 2004, between the Company and Wilmington Trust Company, including form of Notes.(k)	
 	*4	.8	 	First Priority Indenture, dated as of March 23, 2004, among Calpine Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust FSB, as Trustee, including form of Notes.(k)	
 	*4	.9	 	Second Priority Indenture, dated as of March 23, 2004, among Calpine Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust FSB, as Trustee, including form of Notes.(k)	
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Exhibit			
Number		Description	
			
 	*4	.10	 	Third Priority Indenture, dated as of March 23, 2004, among Calpine Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust FSB, as Trustee, including form of Notes.(k)	
 	*10	.1.1	 	Amended and Restated Credit Agreement, dated as of March 23, 2004, among Calpine Generating Company, LLC, the Guarantors named therein, the Lenders named therein, The Bank of Nova Scotia, as Administrative Agent, LC Bank, Lead Arranger and Sole Bookrunner, Bayerische Landesbank Cayman Islands Branch, as Arranger and Co-Syndication Agent, Credit Lyonnais New York Branch, as Arranger and Co-Syndication Agent, ING Capital LLC, as Arranger and Co-Syndication Agent, Toronto-Dominion (Texas) Inc., as Arranger and Co-Syndication Agent, and Union Bank of California, N.A., as Arranger and Co-Syndication Agent.(k)	
 	*10	.2.1	 	Amended and Restated Credit Agreement, dated as of July 16, 2003 (“Amended and Restated Credit Agreement”), among the Company, the Lenders named therein, The Bank of Nova Scotia, as Administrative Agent, Funding Agent, Lead Arranger and Bookrunner, Bayerische Landesbank, Cayman Islands Branch, as Lead Arranger, as Co-Bookrunner and Documentation Agent, and ING Capital LLC and Toronto Dominion (Texas) Inc., as Lead Arrangers, Co-Bookrunners and Syndication Agents.(l)	
 	*10	.2.2	 	First Amendment to Amended and Restated Credit Agreement, dated as of August 7, 2003, among the Company, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent and Funding Agent.(l)	
 	*10	.2.3	 	Amendment and Waiver to Amended and Restated Credit Agreement, dated as of August 28, 2003, among the Company, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent and Funding Agent.(j)	
 	*10	.2.4	 	Letter Agreement regarding Technical Correction to Amendment and Waiver to Amended and Restated Credit Agreement, dated as of September 5, 2003, among the Company, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent and Funding Agent.(j)	
 	*10	.2.5	 	Third Amendment to Amended and Restated Credit Agreement, dated as of November 6, 2003, among the Company, each of Quintana Minerals (USA) Inc., JOQ Canada, Inc., and Quintana Canada Holdings, LLC, as a Guarantor, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent and Funding Agent.(j)	
 	*10	.2.6	 	Fourth Amendment and Waiver to Amended and Restated Credit Agreement, dated as of November 19, 2003, among the Company, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent and Funding Agent.(k)	
 	*10	.2.7	 	Fifth Amendment and Waiver to Amended and Restated Credit Agreement, dated as of December 30, 2003, among the Company, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent and Funding Agent.(k)	
 	*10	.2.8	 	Technical Correction to Fifth Amendment and Waiver to Amended and Restated Credit Agreement, dated as of December 31, 2003, among the Company, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent and Funding Agent.(k)	
 	*10	.2.9	 	Waiver to Amended and Restated Credit Agreement, dated as of March 5, 2003, among the Company, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent and Funding Agent.(k)	
 	*10	.3.1	 	Credit and Guarantee Agreement, dated as of August 14, 2003, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(j)	
 	*10	.3.2	 	Amendment No. 1 to the Credit and Guarantee Agreement, dated as of September 12, 2003, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(j)	
 	*10	.3.3	 	Amendment No. 2 to the Credit and Guarantee Agreement, dated as of January 13, 2004, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(k)	
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Exhibit			
Number		Description	
			
 	*10	.3.4	 	Amendment No. 3 to the Credit and Guarantee Agreement, dated as of March 5, 2004, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(k)	
 	*10	.4	 	Credit and Guarantee Agreement, dated as of March 23, 2004, among Calpine Generating Company, LLC, the Guarantors named therein, the Lenders named therein, Morgan Stanley Senior Funding, Inc., as Administrative Agent, and Morgan Stanley Senior Funding, Inc., as Sole Lead Arranger and Sole Bookrunner.(k)	
 	*10	.5	 	Credit and Guarantee Agreement, dated as of March 23, 2004, among Calpine Generating Company, LLC, the Guarantors named therein, the Lenders named therein, Morgan Stanley Senior Funding, Inc., as Administrative Agent, and Morgan Stanley Senior Funding, Inc., as Sole Lead Arranger and Sole Bookrunner.(k)	
 	*10	.6	 	Consulting Contract, dated as of January 1, 2004, between Calpine Corporation and Mr. George J. Stathakis.(k)(m)	
 	†31	.1	 	Certification of the Chairman, 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.	

			
 	*	Incorporated by reference.	

			
 	†	Filed herewith.	

(a)		Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated June 30, 2004, filed with the SEC on August 9, 2004.	
 		
(b)		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.	
 		
(c)		Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-4 (Registration No. 333-06259) filed with the SEC on June 19, 1996.	
 		
(d)		Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2000, filed with the SEC on March 15, 2001.	
 		
(e)		Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated March 31, 2004, filed with the SEC on May 10, 2004.	
 		
(f)		Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated June 30, 1997, filed with the SEC on August 14, 1997.	
 		
(g)		Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-4 (Registration No. 333-41261) filed with the SEC on November 28, 1997.	
 		
(h)		Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-4 (Registration No. 333-61047) filed with the SEC on August 10, 1998.	
 		
(i)		Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3/ A (Registration No. 333-72583) filed with the SEC on March 8, 1999.	
 		
(j)		Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated September 30, 2003, filed with the SEC on November 13, 2003.	
 		
(k)		Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K dated December 31, 2003, filed with the SEC on March 25, 2004.	
81 

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(l)		Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated June 30, 2003, filed with the SEC on August 14, 2003.	
 		
(m)		Management contract or compensatory plan or arrangement.	
      (b) Reports on Form 8-K
      The registrant filed the following reports on Form 8-K during the quarter ended March 31, 2004: 

Date of Report		Date Filed		Item Reported	
					
 	January 6, 2004	 	 	 	January 6, 2004	 	 	 	5	 	
 	January 9, 2004	 	 	 	January 9, 2004	 	 	 	5	 	
 	January 9, 2004	 	 	 	January 9, 2004	 	 	 	5	 	
 	January 16, 2004	 	 	 	January 20, 2004	 	 	 	5	 	
 	January 28, 2004	 	 	 	January 29, 2004	 	 	 	5	 	
 	February 3, 2004	 	 	 	February 3, 2004	 	 	 	5	 	
 	February 4, 2004	 	 	 	February 4, 2004	 	 	 	5	 	
 	February 6, 2004	 	 	 	February 6, 2004	 	 	 	12	 	
 	February 9, 2004	 	 	 	February 9, 2004	 	 	 	5	 	
 	February 20, 2004	 	 	 	February 24, 2004	 	 	 	5	 	
 	February 24, 2004	 	 	 	February 24, 2004	 	 	 	5	 	
 	February 26, 2004	 	 	 	March 1, 2004	 	 	 	12	 	
 	March 10, 2004	 	 	 	March 10, 2004	 	 	 	5	 	
 	March 11, 2004	 	 	 	March 12, 2004	 	 	 	5	 	
 	March 12, 2004	 	 	 	March 16, 2004	 	 	 	5	 	
 	March 23, 2004	 	 	 	March 23, 2004	 	 	 	5	 	
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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: September 13, 2004

			
 	By: 	/s/ CHARLES B. CLARK, JR.	

 	Charles B. Clark, Jr.	
 	Senior Vice President and Corporate	
 	Controller (Principal Accounting Officer)	
Date: September 13, 2004
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      The following exhibits are filed herewith unless otherwise indicated: 
EXHIBIT INDEX

Exhibit			
Number		Description	
			
 	*3	.1	 	Amended and Restated Certificate of Incorporation of Calpine Corporation, as amended through June 2, 2004.(a)	
 	*3	.2	 	Amended and Restated By-laws of Calpine Corporation.(b)	
 	*4	.1.1	 	Indenture, dated as of May 16, 1996, between the Company and U.S. Bank(as successor trustee to Fleet National Bank), as Trustee, including form of Notes.(c)	
 	*4	.1.2	 	First Supplemental Indenture, dated as of August 1, 2000, between the Company and U.S. Bank National Association (as successor trustee to Fleet National Bank), as Trustee.(d)	
 	*4	.1.3	 	Second Supplemental Indenture, dated as of April 26, 2004, between the Company and U.S. Bank National Association (as successor trustee to Fleet National Bank), as Trustee.(e)	
 	*4	.2.1	 	Indenture, dated as of July 8, 1997, between the Company and The Bank of New York, as Trustee, including form of Notes.(f)	
 	*4	.2.2	 	Supplemental Indenture, dated as of September 10, 1997, between the Company and The Bank of New York, as Trustee.(g)	
 	*4	.2.3	 	Second Supplemental Indenture, dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(d)	
 	*4	.2.4	 	Third Supplemental Indenture, dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee.(e)	
 	*4	.3.1	 	Indenture, dated as of March 31, 1998, between the Company and The Bank of New York, as Trustee, including form of Notes.(h)	
 	*4	.3.2	 	Supplemental Indenture, dated as of July 24, 1998, between the Company and The Bank of New York, as Trustee.(h)	
 	*4	.3.3	 	Second Supplemental Indenture, dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(d)	
 	*4	.3.4	 	Third Supplemental Indenture, dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee.(e)	
 	*4	.4.1	 	Indenture, dated as of March 29, 1999, between the Company and The Bank of New York, as Trustee, including form of Notes.(i)	
 	*4	.4.2	 	First Supplemental Indenture, dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(d)	
 	*4	.4.3	 	Second Supplemental Indenture, dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee.(e)	
 	*4	.5.1	 	Indenture, dated as of March 29, 1999, between the Company and The Bank of New York, as Trustee, including form of Notes.(i)	
 	*4	.5.2	 	First Supplemental Indenture, dated as of July 31, 2000, between the Company and The Bank of New York, as Trustee.(d)	
 	*4	.5.3	 	Second Supplemental Indenture, dated as of April 26, 2004, between the Company and The Bank of New York, as Trustee.(e)	
 	*4	.6.1	 	Indenture, dated as of August 14, 2003, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust Company, as Trustee, including form of Notes.(j)	

Table of Contents

Exhibit			
Number		Description	
			
 	*4	.6.2	 	Supplemental Indenture, dated as of September 18, 2003, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust Company, as Trustee.(j)	
 	*4	.6.3	 	Second Supplemental Indenture, dated as of January 14, 2004, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust Company, as Trustee.(k)	
 	*4	.6.4	 	Third Supplemental Indenture, dated as of March 5, 2004, among Calpine Construction Finance Company, L.P., CCFC Finance Corp., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, and Wilmington Trust Company, as Trustee.(k)	
 	*4	.7	 	Amended and Restated Indenture, dated as of March 12, 2004, between the Company and Wilmington Trust Company, including form of Notes.(k)	
 	*4	.8	 	First Priority Indenture, dated as of March 23, 2004, among Calpine Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust FSB, as Trustee, including form of Notes.(k)	
 	*4	.9	 	Second Priority Indenture, dated as of March 23, 2004, among Calpine Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust FSB, as Trustee, including form of Notes.(k)	
 	*4	.10	 	Third Priority Indenture, dated as of March 23, 2004, among Calpine Generating Company, LLC, CalGen Finance Corp. and Wilmington Trust FSB, as Trustee, including form of Notes.(k)	
 	*10	.1.1	 	Amended and Restated Credit Agreement, dated as of March 23, 2004, among Calpine Generating Company, LLC, the Guarantors named therein, the Lenders named therein, The Bank of Nova Scotia, as Administrative Agent, LC Bank, Lead Arranger and Sole Bookrunner, Bayerische Landesbank Cayman Islands Branch, as Arranger and Co-Syndication Agent, Credit Lyonnais New York Branch, as Arranger and Co-Syndication Agent, ING Capital LLC, as Arranger and Co-Syndication Agent, Toronto-Dominion (Texas) Inc., as Arranger and Co-Syndication Agent, and Union Bank of California, N.A., as Arranger and Co-Syndication Agent.(k)	
 	*10	.2.1	 	Amended and Restated Credit Agreement, dated as of July 16, 2003 (“Amended and Restated Credit Agreement”), among the Company, the Lenders named therein, The Bank of Nova Scotia, as Administrative Agent, Funding Agent, Lead Arranger and Bookrunner, Bayerische Landesbank, Cayman Islands Branch, as Lead Arranger, as Co-Bookrunner and Documentation Agent, and ING Capital LLC and Toronto Dominion (Texas) Inc., as Lead Arrangers, Co-Bookrunners and Syndication Agents.(l)	
 	*10	.2.2	 	First Amendment to Amended and Restated Credit Agreement, dated as of August 7, 2003, among the Company, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent and Funding Agent.(l)	
 	*10	.2.3	 	Amendment and Waiver to Amended and Restated Credit Agreement, dated as of August 28, 2003, among the Company, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent and Funding Agent.(j)	
 	*10	.2.4	 	Letter Agreement regarding Technical Correction to Amendment and Waiver to Amended and Restated Credit Agreement, dated as of September 5, 2003, among the Company, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent and Funding Agent.(j)	
 	*10	.2.5	 	Third Amendment to Amended and Restated Credit Agreement, dated as of November 6, 2003, among the Company, each of Quintana Minerals (USA) Inc., JOQ Canada, Inc., and Quintana Canada Holdings, LLC, as a Guarantor, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent and Funding Agent.(j)	

Table of Contents

Exhibit			
Number		Description	
			
 	*10	.2.6	 	Fourth Amendment and Waiver to Amended and Restated Credit Agreement, dated as of November 19, 2003, among the Company, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent and Funding Agent.(k)	
 	*10	.2.7	 	Fifth Amendment and Waiver to Amended and Restated Credit Agreement, dated as of December 30, 2003, among the Company, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent and Funding Agent.(k)	
 	*10	.2.8	 	Technical Correction to Fifth Amendment and Waiver to Amended and Restated Credit Agreement, dated as of December 31, 2003, among the Company, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent and Funding Agent.(k)	
 	*10	.2.9	 	Waiver to Amended and Restated Credit Agreement, dated as of March 5, 2003, among the Company, the Lenders named therein, and The Bank of Nova Scotia, as Administrative Agent and Funding Agent.(k)	
 	*10	.3.1	 	Credit and Guarantee Agreement, dated as of August 14, 2003, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(j)	
 	*10	.3.2	 	Amendment No. 1 to the Credit and Guarantee Agreement, dated as of September 12, 2003, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(j)	
 	*10	.3.3	 	Amendment No. 2 to the Credit and Guarantee Agreement, dated as of January 13, 2004, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(k)	
 	*10	.3.4	 	Amendment No. 3 to the Credit and Guarantee Agreement, dated as of March 5, 2004, among Calpine Construction Finance Company, L.P., each of Calpine Hermiston, LLC, CPN Hermiston, LLC and Hermiston Power Partnership, as Guarantors, the Lenders named therein, and Goldman Sachs Credit Partners L.P., as Administrative Agent and Sole Lead Arranger.(k)	
 	*10	.4	 	Credit and Guarantee Agreement, dated as of March 23, 2004, among Calpine Generating Company, LLC, the Guarantors named therein, the Lenders named therein, Morgan Stanley Senior Funding, Inc., as Administrative Agent, and Morgan Stanley Senior Funding, Inc., as Sole Lead Arranger and Sole Bookrunner.(k)	
 	*10	.5	 	Credit and Guarantee Agreement, dated as of March 23, 2004, among Calpine Generating Company, LLC, the Guarantors named therein, the Lenders named therein, Morgan Stanley Senior Funding, Inc., as Administrative Agent, and Morgan Stanley Senior Funding, Inc., as Sole Lead Arranger and Sole Bookrunner.(k)	
 	*10	.6	 	Consulting Contract, dated as of January 1, 2004, between Calpine Corporation and Mr. George J. Stathakis.(k)(m)	
 	†31	.1	 	Certification of the Chairman, 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.	

		
*	Incorporated by reference.	

			
 	† 	Filed herewith.	

Table of Contents

			
(a)		Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated June 30, 2004, filed with the SEC on August 9, 2004.	
 		
(b)		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.	
 		
(c)		Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-4 (Registration No. 333-06259) filed with the SEC on June 19, 1996.	
 		
(d)		Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2000, filed with the SEC on March 15, 2001.	
 		
(e)		Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated March 31, 2004, filed with the SEC on May 10, 2004.	
 		
(f)		Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated June 30, 1997, filed with the SEC on August 14, 1997.	
 		
(g)		Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-4 (Registration No. 333-41261) filed with the SEC on November 28, 1997.	
 		
(h)		Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-4 (Registration No. 333-61047) filed with the SEC on August 10, 1998.	
 		
(i)		Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3/ A (Registration No. 333-72583) filed with the SEC on March 8, 1999.	
 		
(j)		Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated September 30, 2003, filed with the SEC on November 13, 2003.	
 		
(k)		Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K dated December 31, 2003, filed with the SEC on March 25, 2004.	
 		
(l)		Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated June 30, 2003, filed with the SEC on August 14, 2003.	
 		
(m)		Management contract or compensatory plan or arrangement.	

Exhibit 31.1
CERTIFICATIONS
I, Peter Cartwright, certify that:
1. I have reviewed this quarterly report on Form 10-Q/A 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)) 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) 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
c) 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 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:  September 13, 2004

                              /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/A 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)) 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) 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
c) 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 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:  September 13, 2004

                              /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/A for the period ending March 31, 2004, 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. ss. 1350, as adopted pursuant to ss. 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                         /s/ ROBERT D. KELLY
--------------------------                   -------------------------------
Peter Cartwright                             Robert D. Kelly
Chairman, President and                      Executive Vice President and
Chief Executive Officer                      Chief Financial Officer
Calpine Corporation                          Calpine Corporation

Dated:  September 13, 2004	

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.