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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q

þ	 	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934	
 	
 	 	For the quarterly period ended March 31, 2003	
 	
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:
      381,260,990 shares of Common Stock, par value $.001 per share, outstanding on June 27, 2003

TABLE OF CONTENTS

									
PART I -- FINANCIAL INFORMATION	
	Item 1. Financial Statements.	
	CONSOLIDATED CONDENSED BALANCE SHEETS	
	CONSOLIDATED CONDENSED STATEMENTS OF OPERATIONS	
	CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS	
	NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS	
	Item 2. Management’s Discussion and Analysis (“MD&A”) of Financial Condition and Results of Operations.	
	Item 3. Quantitative and Qualitative Disclosures About Market Risk.	
	Item 4. Controls and Procedures	
PART II -- OTHER INFORMATION	
	Item 1. Legal Proceedings.	
	Item 6. Exhibits and Reports on Form 8-K.	
SIGNATURES	
CERTIFICATE OF THE CHAIRMAN, PRESIDENT AND CHIEF EXECUTIVE OFFICER	
CERTIFICATE OF THE EXECUTIVE VICE PRESIDENT AND CHIEF FINANCIAL OFFICER	
EXHIBIT 10.7	
EXHIBIT 10.8	
EXHIBIT 10.12	
EXHIBIT 10.13	
EXHIBIT 99.1	

Table of Contents

CALPINE CORPORATION AND SUBSIDIARIES
REPORT ON FORM 10-Q
For the Quarter Ended March 31, 2003
INDEX

				Page No.	
					
PART I — FINANCIAL INFORMATION	
Item 1.	 	Financial Statements	 	 	 	 	
 	 	   Consolidated Condensed Balance Sheets March 31, 2003 and December 31, 2002	 	 	2	 	
 	 	   Consolidated Condensed Statements of Operations for the Three Months Ended March 31, 2003 and 2002 (Restated)	 	 	3	 	
 	 	   Consolidated Condensed Statements of Cash Flows for the Three Months Ended March 31, 2003 and 2002 (Restated)	 	 	4	 	
 	 	   Notes to Consolidated Condensed Financial Statements.	 	 	5	 	
Item 2.	 	Management’s Discussion and Analysis of Financial Condition and Results of Operations	 	 	31	 	
Item 3.	 	Quantitative and Qualitative Disclosures About Market Risk	 	 	58	 	
Item 4.	 	Controls and Procedures	 	 	58	 	
PART II — OTHER INFORMATION	
Item 1.	 	Legal Proceedings	 	 	59	 	
Item 6.	 	Exhibits and Reports on Form 8-K	 	 	61	 	
Signatures	 	 	65	 	
Certifications	 	 	66	 	
1 

Table of Contents
PART I — FINANCIAL INFORMATION 

Item 1.	Financial Statements.	
CALPINE CORPORATION AND SUBSIDIARIES
CONSOLIDATED CONDENSED BALANCE SHEETS
March 31, 2003 and December 31, 2002
(in thousands, except share and per share amounts)
 	 	 	 	 	 	 	 	 	 	 	
		March 31,		December 31,	
		2003		2002	
					
		(unaudited)			
ASSETS	
Current assets:	 	 	 	 	 	 	 	 	
 	Cash and cash equivalents	 	$	378,057	 	 	$	579,486	 	
 	Accounts receivable, net	 	 	1,004,088	 	 	 	747,004	 	
 	Margin deposits and other prepaid expense	 	 	222,996	 	 	 	152,726	 	
 	Inventories	 	 	114,260	 	 	 	106,536	 	
 	Restricted cash	 	 	146,343	 	 	 	176,716	 	
 	Current derivative assets	 	 	633,864	 	 	 	330,244	 	
 	Other current assets	 	 	156,192	 	 	 	143,318	 	
 	 	 		 	 	 		 	
 	 	Total current assets	 	 	2,655,800	 	 	 	2,236,030	 	
 	 	 		 	 	 		 	
Restricted cash, net of current portion	 	 	23,481	 	 	 	9,203	 	
Notes receivable, net of current portion	 	 	199,932	 	 	 	195,398	 	
Project development costs	 	 	125,618	 	 	 	118,513	 	
Investments in power projects	 	 	403,454	 	 	 	421,402	 	
Deferred financing costs	 	 	171,063	 	 	 	185,026	 	
Prepaid lease, net of current portion	 	 	318,623	 	 	 	301,603	 	
Property, plant and equipment, net	 	 	19,326,320	 	 	 	18,850,967	 	
Goodwill	 	 	34,589	 	 	 	34,589	 	
Other intangible assets, net	 	 	96,107	 	 	 	93,066	 	
Long-term derivative assets	 	 	497,029	 	 	 	496,028	 	
Other assets	 	 	310,776	 	 	 	285,167	 	
 	 	 		 	 	 		 	
 	 	Total assets	 	$	24,162,792	 	 	$	23,226,992	 	
 	 	 		 	 	 		 	
LIABILITIES & STOCKHOLDERS’ EQUITY	
Current liabilities:	 	 	 	 	 	 	 	 	
 	Accounts payable	 	$	1,484,967	 	 	$	1,238,647	 	
 	Accrued payroll and related expense	 	 	42,271	 	 	 	48,322	 	
 	Accrued interest payable	 	 	227,731	 	 	 	189,336	 	
 	Income taxes payable	 	 	3,323	 	 	 	3,640	 	
 	Notes payable and borrowings under lines of credit, current portion	 	 	340,388	 	 	 	340,703	 	
 	Capital lease obligation, current portion	 	 	3,866	 	 	 	3,502	 	
 	Construction/project financing, current portion	 	 	1,325,002	 	 	 	1,307,291	 	
 	Current derivative liabilities	 	 	558,025	 	 	 	189,356	 	
 	Other current liabilities	 	 	310,244	 	 	 	246,334	 	
 	 	 		 	 	 		 	
 	 	Total current liabilities	 	 	4,295,817	 	 	 	3,567,131	 	
 	 	 		 	 	 		 	
Term loan	 	 	949,565	 	 	 	949,565	 	
Notes payable and borrowings under lines of credit, net of current portion	 	 	8,483	 	 	 	8,249	 	
Capital lease obligation, net of current portion	 	 	196,706	 	 	 	197,672	 	
Construction/project financing, net of current portion	 	 	3,213,737	 	 	 	3,212,022	 	
Convertible Senior Notes Due 2006.	 	 	1,200,000	 	 	 	1,200,000	 	
Senior notes	 	 	6,905,854	 	 	 	6,894,801	 	
Deferred income taxes, net	 	 	1,160,773	 	 	 	1,123,729	 	
Deferred lease incentive	 	 	52,856	 	 	 	53,732	 	
Deferred revenue	 	 	135,161	 	 	 	154,969	 	
Long-term derivative liabilities	 	 	505,842	 	 	 	528,400	 	
Other liabilities	 	 	214,533	 	 	 	175,636	 	
 	 	 		 	 	 		 	
 	 	Total liabilities	 	 	18,839,327	 	 	 	18,065,906	 	
 	 	 		 	 	 		 	
Company-obligated mandatorily redeemable convertible preferred securities of subsidiary trusts	 	 	1,124,227	 	 	 	1,123,969	 	
Minority interests	 	 	278,870	 	 	 	185,203	 	
 	 	 		 	 	 		 	
Stockholders’ equity:	 	 	 	 	 	 	 	 	
 	Preferred stock, $.001 par value per share; authorized 10,000,000 shares; issued and outstanding one share in 2003 and 2002	 	 	—	 	 	 	—	 	
 	Common stock, $.001 par value per share; authorized 1,000,000,000 shares; issued and outstanding 381,168,410 shares in 2003 and 380,816,132 shares in 2002	 	 	381	 	 	 	381	 	
 	Additional paid-in capital	 	 	2,807,762	 	 	 	2,802,503	 	
 	Retained earnings	 	 	1,234,471	 	 	 	1,286,487	 	
 	Accumulated other comprehensive loss	 	 	(122,246	)	 	 	(237,457	)	
 	 	 		 	 	 		 	
 	 	Total stockholders’ equity	 	$	3,920,368	 	 	$	3,851,914	 	
 	 	 		 	 	 		 	
 	 	Total liabilities and stockholders’ equity	 	$	24,162,792	 	 	$	23,226,992	 	
 	 	 		 	 	 		 	
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, 2003 and 2002

		Three Months Ended	
		March 31,	
			
		2003		2002	
					
				Restated(1)	
			
		(In thousands, except	
		per share amounts)	
		(Unaudited)	
Revenue:	 	 	 	 	 	 	 	 	
 	Electric generation and marketing revenue	 	 	 	 	 	 	 	 	
 	 	Electricity and steam revenue	 	$	1,122,038	 	 	$	622,400	 	
 	 	Sales of purchased power for hedging and optimization	 	 	681,284	 	 	 	520,051	 	
 	 	 		 	 	 		 	
 	Total electric generation and marketing revenue	 	 	1,803,322	 	 	 	1,142,451	 	
 	Oil and gas production and marketing revenue	 	 	 	 	 	 	 	 	
 	 	Oil and gas sales	 	 	25,989	 	 	 	53,076	 	
 	 	Sales of purchased gas for hedging and optimization	 	 	327,468	 	 	 	123,404	 	
 	 	 		 	 	 		 	
 	Total oil and gas production and marketing revenue	 	 	353,457	 	 	 	176,480	 	
 	Trading revenue, net	 	 	 	 	 	 	 	 	
 	 	Realized revenue on power and gas trading transactions, net	 	 	21,214	 	 	 	6,229	 	
 	 	Unrealized mark-to-market gain (loss) on power and gas transactions, net	 	 	(771	)	 	 	2,817	 	
 	 	 		 	 	 		 	
 	Total trading revenue, net	 	 	20,443	 	 	 	9,046	 	
 	Other revenue	 	 	9,055	 	 	 	4,558	 	
 	 	 		 	 	 		 	
 	 	 	Total revenue	 	 	2,186,277	 	 	 	1,332,535	 	
 	 	 		 	 	 		 	
Cost of revenue:	 	 	 	 	 	 	 	 	
 	Electric generation and marketing expense	 	 	 	 	 	 	 	 	
 	 	Plant operating expense	 	 	164,980	 	 	 	116,474	 	
 	 	Royalty expense	 	 	5,357	 	 	 	4,155	 	
 	 	Purchased power expense for hedging and optimization	 	 	679,949	 	 	 	429,235	 	
 	 	 		 	 	 		 	
 	Total electric generation and marketing expense	 	 	850,286	 	 	 	549,864	 	
 	Oil and gas production and marketing expense	 	 	 	 	 	 	 	 	
 	 	Oil and gas production expense	 	 	25,691	 	 	 	21,639	 	
 	 	Purchased gas expense for hedging and optimization	 	 	316,948	 	 	 	121,361	 	
 	 	 		 	 	 		 	
 	Total oil and gas production and marketing expense	 	 	342,639	 	 	 	143,000	 	
 	Fuel expense	 	 	650,236	 	 	 	332,534	 	
 	Depreciation, depletion and amortization expense	 	 	134,710	 	 	 	94,969	 	
 	Operating lease expense	 	 	27,692	 	 	 	28,141	 	
 	Other expense	 	 	6,976	 	 	 	2,591	 	
 	 	 		 	 	 		 	
 	 	 	Total cost of revenue	 	 	2,012,539	 	 	 	1,151,099	 	
 	 	 		 	 	 		 	
 	Gross profit	 	 	173,738	 	 	 	181,436	 	
Income from unconsolidated investments in power projects	 	 	(5,123	)	 	 	(1,497	)	
Equipment cancellation cost	 	 	—	 	 	 	168,471	 	
Project development expense	 	 	5,214	 	 	 	11,338	 	
General and administrative expense	 	 	56,404	 	 	 	59,118	 	
 	 	 		 	 	 		 	
 	Income (loss) from operations	 	 	117,243	 	 	 	(55,994	)	
Interest expense	 	 	142,962	 	 	 	73,710	 	
Distributions on trust preferred securities	 	 	15,657	 	 	 	15,654	 	
Interest income	 	 	(8,039	)	 	 	(12,176	)	
Other expense (income)	 	 	36,869	 	 	 	(12,853	)	
 	 	 		 	 	 		 	
 	Loss before benefit for income taxes	 	 	(70,206	)	 	 	(120,329	)	
Benefit for income taxes	 	 	(17,661	)	 	 	(42,611	)	
 	 	 		 	 	 		 	
 	Loss before discontinued operations and cumulative effect of a change in accounting principle	 	 	(52,545	)	 	 	(77,718	)	
Discontinued operations, net of tax provision of $— and $1,040.	 	 	—	 	 	 	2,045	 	
Cumulative effect of a change in accounting principle, net of tax provision of $450 and $—	 	 	529	 	 	 	—	 	
 	 	 		 	 	 		 	
 	Net loss	 	$	(52,016	)	 	$	(75,673	)	
 	 	 		 	 	 		 	
Basic and diluted loss per common share:	 	 	 	 	 	 	 	 	
 	Weighted average shares of common stock outstanding	 	 	380,960	 	 	 	307,332	 	
 	Loss before discontinued operations and cumulative effect of a change in accounting principle	 	$	(0.14	)	 	$	(0.25	)	
 	Discontinued operations, net of tax	 	$	—	 	 	$	—	 	
 	Cumulative affect of a change in accounting principle	 	$	—	 	 	$	—	 	
 	 	 		 	 	 		 	
 	Net loss	 	$	(0.14	)	 	$	(0.25	)	

		
(1) 	See Note 2 to Consolidated Condensed Financial Statements regarding the restatement of financial statements.	
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, 2003 and 2002
(in thousands)
(unaudited)

		Three Months	
		Ended	
		March 31,	
			
		2003		2002	
					
				Restated(1)	
Cash flows from operating activities:	 	 	 	 	 	 	 	 	
 	Net loss	 	$	(52,016	)	 	$	(75,673	)	
 	 	Adjustments to reconcile net loss to net cash provided by operating activities:	 	 	 	 	 	 	 	 	
 	 	Depreciation, depletion and amortization	 	 	164,501	 	 	 	110,939	 	
 	 	Equipment cancellation cost	 	 	—	 	 	 	168,471	 	
 	 	Deferred income taxes, net	 	 	42,811	 	 	 	(93,687	)	
 	 	Gain on sale of assets	 	 	—	 	 	 	(9,667	)	
 	 	Foreign currency translation loss	 	 	25,209	 	 	 	—	 	
 	 	Income from unconsolidated investments in power projects	 	 	(5,740	)	 	 	(1,497	)	
 	 	Distributions from unconsolidated investments in power projects	 	 	9,401	 	 	 	10	 	
 	 	Stock compensation expense	 	 	4,490	 	 	 	—	 	
 	 	Other	 	 	323	 	 	 	(5,202	)	
 	 	Change in operating assets and liabilities, net of effects of acquisitions:	 	 	 	 	 	 	 	 	
 	 	 	Accounts receivable	 	 	(251,833	)	 	 	158,255	 	
 	 	 	Change in net derivative liability	 	 	54,290	 	 	 	(184,073	)	
 	 	 	Other current assets	 	 	(81,357	)	 	 	226,765	 	
 	 	 	Other assets	 	 	(44,444	)	 	 	5,385	 	
 	 	 	Accounts payable and accrued expense	 	 	281,665	 	 	 	9,710	 	
 	 	 	Other liabilities	 	 	18,067	 	 	 	45,337	 	
 	 	 		 	 	 		 	
 	 	 	 	Net cash provided by operating activities	 	 	165,367	 	 	 	355,073	 	
 	 	 		 	 	 		 	
Cash flows from investing activities:	 	 	 	 	 	 	 	 	
 	Purchases of property, plant and equipment	 	 	(507,250	)	 	 	(1,301,986	)	
 	Acquisitions, net of cash acquired	 	 	(6,818	)	 	 	—	 	
 	Disposals of property, plant and equipment	 	 	9,074	 	 	 	1,739	 	
 	Advances to joint ventures	 	 	(2,020	)	 	 	(23,121	)	
 	Decrease (increase) in notes receivable	 	 	(4,534	)	 	 	11,543	 	
 	Maturities of collateral securities	 	 	2,794	 	 	 	3,325	 	
 	Project development costs	 	 	(8,867	)	 	 	(23,784	)	
 	Decrease in restricted cash	 	 	16,096	 	 	 	17,269	 	
 	Other	 	 	17,896	 	 	 	1,004	 	
 	 	 		 	 	 		 	
 	 	Net cash used in investing activities	 	 	(483,629	)	 	 	(1,314,011	)	
 	 	 		 	 	 		 	
Cash flows from financing activities:	 	 	 	 	 	 	 	 	
 	Repurchase of Zero-Coupon Convertible Debentures Due 2021.	 	 	—	 	 	 	(187,727	)	
 	Repayments of notes payable and borrowings under lines of credit	 	 	—	 	 	 	(73,652	)	
 	Borrowings from project financing	 	 	19,426	 	 	 	126,488	 	
 	Repayments of project financing	 	 	—	 	 	 	(92,198	)	
 	Proceeds from issuance of Convertible Senior Notes Due 2006.	 	 	—	 	 	 	100,000	 	
 	Proceeds from income trust secondary offering	 	 	100,900	 	 	 	—	 	
 	Financing costs	 	 	(6,941	)	 	 	(32,029	)	
 	Other	 	 	(842	)	 	 	2,195	 	
 	 	 		 	 	 		 	
 	 	Net cash provided by (used in) financing activities	 	 	112,543	 	 	 	(156,923	)	
 	 	 		 	 	 		 	
Effect of exchange rate changes on cash and cash equivalents	 	 	4,290	 	 	 	(491	)	
Net decrease in cash and cash equivalents	 	 	(201,429	)	 	 	(1,116,352	)	
Cash and cash equivalents, beginning of period	 	 	579,486	 	 	 	1,594,144	 	
 	 	 		 	 	 		 	
Cash and cash equivalents, end of period	 	$	378,057	 	 	$	477,792	 	
 	 	 		 	 	 		 	
Cash paid during the period for:	 	 	 	 	 	 	 	 	
 	Interest, net of amounts capitalized	 	$	71,677	 	 	$	29,359	 	
 	Income taxes	 	$	8,003	 	 	$	12,065	 	

		
(1) 	See Note 2 to Consolidated Condensed Financial Statements regarding the restatement of financial statements.	
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, 2003
(unaudited)

1.	Organization and Operation of the Company	
      Calpine Corporation (“Calpine”), a Delaware corporation, and subsidiaries (collectively, the “Company”) is engaged in the generation of electricity in the United States 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	
      Restatement of Prior Period Financial Statements  — The accompanying financial statements reflect certain restatements of first quarter 2002 amounts, which were included in and described in the Company’s Annual Report on Form 10-K (“Annual Report” or “Form 10-K”) for the year ended December 31, 2002. Subsequent to the issuance of the Company’s Consolidated Condensed Financial Statements as of March 31, 2002, the Company determined that the sale/leaseback transactions for its Pasadena and Broad River facilities should have been accounted for as financing transactions, rather than as sales with operating leases as had been the accounting previously afforded such transactions. Accordingly, these two transactions were restated as financing transactions and the proceeds were classified as debt and the operating lease payments were recharacterized as debt service payments in the accompanying Consolidated Condensed Financial Statements. The Company is therefore now accounting for the assets as if they had not been sold. The assets were added back to the Company’s property, plant and equipment, and depreciation has been recorded thereon.
      In addition the Company has reclassified certain amounts in the accompanying Consolidated Condensed Financial Statements for the three months ended March 31, 2002, to reflect the adoption of new accounting standards. The reclassifications include (a) treatment as discontinued operations pursuant to SFAS No. 144 “Accounting for the Impairment or Disposal of Long-Lived Assets” of the 2002 sales of certain oil and gas properties and the DePere Energy Center, (b) the reclassification of revenues and costs associated with certain energy trading contracts to trading revenues, net, pursuant to Emerging Issues Task Force (“EITF”) Issue No. 02-3, “Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities” and (c) the adoption of SFAS No. 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections” to reclassify gains or losses from extinguishment of debt from extraordinary gain or loss to other income or loss.
      In October 2002 the EITF released EITF Issue No. 02-3, which precludes mark-to-market accounting for all energy trading contracts not within the scope of SFAS No. 133 and mandates that gains and losses on derivative instruments within the scope of SFAS No. 133 should be shown net in the income statement if the derivative instruments are held for trading purposes. EITF Issue No. 02-3 has had no impact on the Company’s net income but did affect the presentation of the prior period Consolidated Financial Statements. Accordingly, the Company reclassified certain prior period revenue amounts and cost of revenue in its Consolidated Statements of Operations. The reclassification of the financial information in accordance with
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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS — (Continued)
SFAS No. 144, SFAS No. 145 and EITF Issue No. 02-3 discussed above relates exclusively to the presentation and classification of such amounts and has no effect on net income.
      To properly account for the two sale/leaseback transactions as financing transactions, to record certain other adjustments, and to reflect the adoption of new accounting standards as described above, the accompanying Consolidated Condensed Financial Statements for the three months ended March 31, 2002, have been restated and differ from amounts previously reported in the Company’s Quarterly Report on Form 10Q for the quarter ended March 31, 2002.
      A summary of the significant effects of restatement, along with certain reclassification adjustments, to the consolidated condensed statement of operations for the three months ended March 31, 2002 is as follows: 

		As previously			
		reported		As restated	
					
Sales of purchased power	 	$	908,301	 	 	$	520,051	 	
Sales of purchased gas	 	 	132,158	 	 	 	123,404	 	
Total revenue	 	 	1,738,347	 	 	 	1,332,535	 	
Purchase power expense	 	 	815,005	 	 	 	429,235	 	
Purchased gas expense	 	 	123,694	 	 	 	121,361	 	
Depreciation, depletion and amortization expense	 	 	103,873	 	 	 	94,969	 	
Operating lease expense	 	 	36,134	 	 	 	28,141	 	
Gross profit	 	 	177,964	 	 	 	181,436	 	
Interest expense	 	 	61,311	 	 	 	73,710	 	
Loss before discontinued operations and extraordinary items	 	 	(76,397	)	 	 	(77,718	)	
Net loss	 	 	(74,267	)	 	 	(75,673	)	
Loss per share — basic and diluted	 	 	(0.24	)	 	 	(0.25	)	
      For further information on prior period restatement items, please see Note 2 to the Consolidated Financial Statements included in the Company’s Annual report on Form 10-K for the year ended December 31, 2002.
      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, 2002, included in the Company’s Annual Report on Form 10-K. The results for interim periods are not necessarily indicative of the results for the entire year.
      Use of Estimates in Preparation of Financial Statements  — The preparation of financial statements in conformity with generally accepted accounting principles in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expense during the reporting period. Actual results could differ from those estimates. The most significant estimates with regard to these financial statements relate to useful lives and carrying values of assets (including the carrying value of projects in development, construction and operation), provision for income taxes, fair value calculations of derivative instruments and associated reserves, capitalization of interest and depletion, depreciation and impairment of natural gas and petroleum property and equipment.
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS — (Continued)
      Revenue Recognition  — The Company is primarily an electric generation company, operating a portfolio of mostly wholly owned plants but also some plants in which its ownership interest is 50% or less and which are accounted for under the equity method. In conjunction with its electric generation business, the Company also produces, as a by-product, thermal energy for sale to customers, principally steam hosts at the Company’s cogeneration sites. In addition, the Company acquires and produces natural gas for its own consumption and sells the balance and oil produced to third parties. Where applicable, revenues are recognized under EITF No. 91-6, “Revenue Recognition of Long Term Power Sales Contracts,” ratably over the terms of the related contracts. To protect and enhance the profit potential of its electric generation plants, the Company, through its subsidiary, Calpine Energy Services (“CES”), enters into electric and gas hedging, balancing, and optimization transactions, subject to market conditions, and CES has also, from time to time, entered into contracts considered energy trading contracts under EITF Issue No. 02-3. CES executes these transactions primarily through the use of physical forward commodity purchases and sales and financial commodity swaps and options. With respect to its physical forward contracts, CES generally acts as a principal, takes title to the commodities, and assumes the risks and rewards of ownership. Therefore, when CES does not hold these contracts for trading purposes and, in accordance with SAB No. 101 and EITF Issue No. 99-19, the Company records settlement of its non-trading physical forward contracts on a gross basis. Effective July 1, 2002, the Company changed its method of reporting gains and losses from derivatives held for trading purposes to a net basis. Prior to July 1, 2002, physical trading contracts were recorded on a gross basis but have been reclassified to a net basis to conform to the current presentation. The Company settles its financial swap and option transactions net and does not take title to the underlying commodity. Accordingly, the Company records gains and losses from settlement of financial swaps and options net within net income. Managed risks typically include commodity price risk associated with fuel purchases and power sales.
      The Company, through its wholly owned subsidiary, Power Systems Mfg., LLC (“PSM”), designs and manufactures certain spare parts for gas turbines, and through its Thomassen Turbine Systems (“TTS”) subsidiary provides turbine maintenance services to third parties. The Company also generates revenue by occasionally loaning funds to power projects, by providing operation and maintenance (“O&M”) services to third parties and to certain unconsolidated power projects, and by performing engineering services for data centers and other facilities requiring highly reliable power. The Company also has begun to sell engineering and construction services to third parties for power projects. Further details of the Company’s revenue recognition policy for each type of revenue transaction are provided below:
      Electric Generation and Marketing Revenue  — This includes electricity and steam sales and sales of purchased power for hedging, balancing and optimization. Subject to market and other conditions, the Company manages the revenue stream for its portfolio of electric generating facilities. The Company markets on a system basis both power generated by its plants in excess of amounts under direct contract between the plant and a third party, and power purchased from third parties, through hedging, balancing and optimization transactions. The Company records revenues from generation sold under long-term contracts and generation liquidated into the market as electricity and steam sales. The Company records revenues from sales of power not sourced from the Company’s generation as sales of purchased power.
      Oil and Gas Production and Marketing Revenue  — This includes sales to third parties of oil, gas and related products that are produced by the Company’s Calpine Natural Gas and Calpine Canada Natural Gas subsidiaries and, subject to market and other conditions, sales of purchased gas arising from hedging, balancing and optimization transactions. Oil and gas sales for produced products are recognized pursuant to the sales method, net of royalties. If the Company has recorded gas sales on a particular well or field in excess of its share of remaining estimated reserves, then the excessive gas sale imbalance is recognized as a liability. If the Company is under-produced on a particular well or field, and it is determined that an over-produced partner’s share of remaining reserves is insufficient to settle the gas imbalance, the Company will recognize a receivable, to the extent collectible, from the over-produced partner.
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS — (Continued)
      Trading Revenue, Net  — This includes realized settlements of, and unrealized mark-to-market gains and losses on, both power and gas derivative instruments held for trading purposes or not designated as a hedge related to the Company’s generating assets in accordance with EITF 02-03, “Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities.” Gains and losses due to ineffectiveness on hedging instruments are also included in unrealized mark-to-market gains and losses.
      Other Revenue  — This includes O&M contract revenue, PSM and TTS revenue from sales to third parties, engineering revenue and miscellaneous revenue.
      Purchased Power and Purchased Gas Expense  — The cost of power purchased from third parties for hedging, balancing and optimization activities is recorded as purchased power expense, a component of electric generation and marketing expense. The Company records the cost of gas purchased from third parties for the purposes of consumption in its power plants as fuel expense, while gas purchased from third parties for hedging, balancing, and optimization activities is recorded as purchased gas expense for hedging and optimization, a component of oil and gas production and marketing expense.
      Derivative Instruments  — SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” 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.
      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 (“OCI”) and be reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument, if any, must be recognized currently in earnings. SFAS No. 133 provides that the changes in fair value of both 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.
      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 Condensed Statements of Operations and within OCI.

	New Accounting Pronouncements	
      In June 2001 the Financial Accounting Standards Board (“FASB”) issued SFAS No. 143, “Accounting for Asset Retirement Obligations”. SFAS No. 143 applies to fiscal years beginning after June 15, 2002, and amends SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies.” This standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development or normal use of the assets and requires that a liability for an asset retirement obligation be recognized when incurred, recorded at fair value and classified as a liability in the balance sheet. When the liability is initially recorded, the entity will capitalize the cost and increase the
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS — (Continued)
carrying value of the related long-lived asset. Asset retirement obligations represent future liabilities, and, as a result, accretion expense will be accrued on this liability until the obligation is satisfied. At the same time, the capitalized cost will be depreciated over the estimated useful life of the related asset. At the settlement date, the entity will settle the obligation for its recorded amount or recognize a gain or loss upon settlement.
      The Company adopted the new rules on asset retirement obligations on January 1, 2003. As required by the new rules, the Company recorded liabilities equal to the present value of expected future asset retirement obligations at January 1, 2003. The Company identified obligations related to operating gas-fired power plants, geothermal power plants and oil and gas properties. The liabilities are partially offset by increases in net assets, net of accumulated depreciation, recorded as if the provisions of SFAS 143 had been in effect at the date the obligation was incurred, which for power plants is generally the start of commercial operations for the facility.
      Based on current information and assumptions, the Company recorded, as of January 1, 2003, an additional long-term liability of $25.9 million, an additional asset within Property, plant and equipment, net of accumulated depreciation, of $26.9 million, and a pre-tax gain to income due to the cumulative effect of a change in accounting principle of $1.0 million. These entries include the effects of the reversal of site dismantlement and restoration costs previously expensed in accordance with SFAS No. 19.
      In June 2002 the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities,” which addresses accounting for restructuring and similar costs. SFAS No. 146 supersedes previous accounting guidance, principally EITF Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (Including Certain Costs Incurred in a Restructuring).” The Company has adopted, effective January 1, 2003, the provisions of SFAS No. 146 for restructuring activities initiated after December 31, 2002. SFAS No. 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. Under EITF No. 94-3, a liability for an exit cost was recognized at the date of commitment to an exit plan. SFAS No. 146 also establishes that the liability should initially be measured and recorded at fair value. Accordingly, SFAS No. 146 may affect the timing of recognizing future restructuring costs as well as the amounts recognized. SFAS No. 146 has not had a material impact on the Company’s Consolidated Condensed Financial Statements.
      In November 2002 the FASB issued Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others (“FIN 45”)”. This Interpretation addresses the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees. In addition, the Interpretation clarifies the requirements related to the recognition of a liability by a guarantor at the inception of a guarantee for the obligations that the guarantor has undertaken in issuing the guarantee. The Company adopted the disclosure requirements of FIN 45 for the fiscal year ended December 31, 2002, and the recognition provisions on January 1, 2003. Adoption of this Interpretation did not have a material impact on the Company’s Consolidated Condensed Financial Statements.
      On January 1, 2003, the Company prospectively adopted the fair value method of accounting for stock-based employee compensation pursuant to SFAS No. 123, “Accounting for Stock-Based Compensation” as amended by SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure.” SFAS No. 148 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
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS — (Continued)
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 for March 31, 2003 and 2002, had the Company applied the accounting provisions of SFAS No. 123 to its prior years’ financial statements. 

			
		Three Months Ended	
		March 31,	
			
		2003		2002	
					
Net income	 	 	 	 	 	 	 	 	
 	As reported	 	$	(52,016	)	 	$	(75,673	)	
 	Pro Forma	 	 	(58,452	)	 	 	(88,843	)	
Earnings per share data:	 	 	 	 	 	 	 	 	
 	Basic earnings per share	 	 	 	 	 	 	 	 	
 	 	As reported	 	$	(0.14	)	 	$	(0.25	)	
 	 	Pro Forma	 	 	(0.15	)	 	 	(0.29	)	
 	Diluted earnings per share	 	 	 	 	 	 	 	 	
 	 	As reported	 	$	(0.14	)	 	$	(0.25	)	
 	 	Pro Forma	 	 	(0.15	)	 	 	(0.29	)	
Stock-based compensation cost, net of tax, included in net income, as reported	 	$	3,367	 	 	$	—	 	
Stock-based compensation cost, net of tax, included in net income, pro forma	 	 	9,803	 	 	 	13,170	 	
      The range of fair values of the Company’s stock options granted for the three months ended March 31, 2003 and 2002, respectively, was as follows, based on varying historical stock option exercise patterns by different levels of Calpine employees: $1.60-$3.43 in 2003, $3.83-$13.85 in 2002, 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 70.44%-97.19% and 59.30%-65.09% for the three months ended March 31, 2003 and 2002, respectively, risk-free interest rates of 1.76%-4.04% and 4.61%-5.42% for the three months ended March 31, 2003 and 2002, respectively, and expected option terms of 2 1/2-9 1/2 years and 4-9 1/2 years for the three months ended March 31, 2003 and 2002, respectively.
      In January 2003 the FASB issued FIN 46, “Consolidation of Variable Interest Entities — an Interpretation of ARB No. 51”. FIN 46 establishes accounting, reporting and disclosure requirements for companies that currently hold unconsolidated investments in Variable Interest Entities (“VIEs”). FIN 46 defines VIEs as entities that meet one or both of two criteria: 1. the entity’s total equity at risk is deemed to be insufficient to finance its ongoing business activities without additional subordinated financial support from other parties, and/or, 2. as a collective group, the entity’s owners do not have a controlling financial interest in the entity, which effectively occurs if the voting rights to, or the entitlement to future returns or risk of future losses from the investment for each of the entity’s owners is inconsistent with the ownership percentages assigned to each owner within the underlying partnership agreement. If an investment is determined to be a VIE, further analysis must be performed to determine which of the VIE’s owners qualifies as the primary beneficiary. The primary beneficiary is the owner of the VIE that is entitled or at risk to earn or absorb the majority of the entity’s expected future returns or losses. An owner that is determined to be the primary beneficiary of a VIE is required to consolidate the VIE into its financial statements, as well as to provide certain disclosures regarding the size and nature of the VIE, the purpose for the investment, and information about the assets
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS — (Continued)
being held as collateral on behalf of the VIE. Additionally, the remaining owners of a VIE that do not qualify as the primary beneficiary must determine whether or not they hold significant variable interests within the VIE. An owner with a significant variable interest in a VIE that is not the primary beneficiary is not required to consolidate the VIE but must provide certain disclosures regarding the size and nature of the VIE, the purpose for the investment, its potential exposure to the VIE’s losses, and the date it first acquired ownership in the VIE. FIN 46 applies immediately to VIEs created or acquired after January 31, 2003. It applies in the first fiscal year or interim period beginning after June 15, 2003, to VIEs that were previously created or acquired before February 1, 2003. FIN 46 has not had a material impact on the Company’s Consolidated Condensed Financial Statements, as no VIEs were created during the first quarter of 2003. The Company has not completed its assessment of the impact of FIN 46 for VIE relationships prior to December 31, 2002.
      In April 2003 the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” SFAS No. 149 amends and clarifies financial reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities under SFAS No. 133. SFAS No. 149 clarifies under what circumstances a contract with an initial net investment meets the characteristic of a derivative, clarifies when a derivative contains a financing component, amends the definition of an underlying to conform it to language used in FIN 45, and amends certain other existing pronouncements. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003, and should be applied prospectively, with the exception of certain SFAS No. 133 implementation issues that were effective for all fiscal quarters prior to June 15, 2003. Any such implementation issues should continue to be applied in accordance with their respective effective dates. The Company does not believe that SFAS No. 149 will have a material impact on its financial statements.
      In May 2003 the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity”. SFAS No. 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. SFAS No. 150 applies specifically to a number of financial instruments that companies have historically presented within their financial statements either as equity or between the liabilities section and the equity section, rather than as liabilities. SFAS 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The Company has not completed its assessment of the impact of SFAS No. 150.
      In June 2003, the FASB issued 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.” DIG Issue No. C20 superseded DIG Issue No. C11 “Interpretation of Clearly and Closely Related in Contracts That Qualify for the Normal Purchases and Normal Sales Exception,” and specified additional circumstances in which a price adjustment feature in a derivative contract would not be an impediment to qualifying for the normal purchases and normal sales scope exception under SFAS No. 133. DIG Issue No. C20 is effective as of the first day of the fiscal quarter beginning after July 10, 2003, (i.e. October 1, 2003, for the Company) with early application permitted. It should be applied prospectively for all existing contracts as of the effective date and for all future transactions. In conjunction with initially applying the implementation guidance, DIG Issue No. C20 requires the recognition of a special transition adjustment for certain contracts containing a price adjustment feature based on a broad market index for which the normal purchases and normal sales scope exception had been previously elected. In those circumstances, the derivative contract should be recognized at fair value as of the date of the initial application with a corresponding adjustment of net income as the cumulative effect of a change in accounting principle.
      Certain of the Company’s power sales contracts, which meet the definition of a derivative and for which it previously elected the normal purchases and normal sales scope exception, use a CPI or similar index to escalate the O&M charges. Accordingly, DIG Issue No. C20 will require the Company to record a special transition accounting adjustment upon adoption of the new guidance to record these contracts at fair value
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS — (Continued)
with a corresponding adjustment to net income as the effect of a change in accounting principle. The fair value of these contracts will be based in large part on the nature and extent of the key price adjustment features of the contracts and market conditions on the date of adoption, such as the forward price of power and natural gas and the expected future rate of inflation. Although the final amount of the adjustment, if any, will not be known until actual adoption of DIG Issue No. C20, based upon contract values as of June 26, 2003, the Company estimates that it will recognize derivative assets of approximately $360 million, derivative liabilities of approximately $90 million and a cumulative effect adjustment to net income of approximately $200 million, net of tax. Assuming the contracts meet the new conditions for qualifying for the normal purchases and normal sales exception and the Company makes that election, the recorded balance for these contracts would reverse through charges to income over the life of the long term contracts, which extend out as far as the year 2020, as deliveries of power are made. To the extent any contract fails to meet the new requirements in DIG Issue No. C20 or the Company does not elect the scope exception, it would be required to recognize subsequent changes in the fair value of those contracts in earnings each period. The Company anticipates that it will adopt DIG Issue No. C20 on October 1, 2003. Upon adoption of DIG Issue No. C20, the Company expects, subject to further analysis, that most of its structured power sales contracts will meet the criteria for the normal purchases and sales exception under SFAS No. 133 and that it will make that election.
This amount would reverse over the life of the long term contracts, which extend out as far as the year 2020, as deliveries of power are made. Upon adoption of DIG Issue C20, the Company expects, subject to further analysis, that most of its structured power sales contracts will meet the criteria for the normal purchases and sales exception under SFAS No. 133.
      Reclassifications  — Prior period amounts in the Consolidated Condensed Financial Statements have been reclassified where necessary to conform to the 2003 presentation.

3.	Property, Plant and Equipment, Net; Capitalized Interest; Project Development Costs; and Equipment for Future Use in Other Assets	
      Property, plant and equipment, net, consisted of the following (in thousands): 

		March 31,		December 31,	
		2003		2002	
					
Buildings, machinery, and equipment	 	$	10,926,995	 	 	$	10,290,931	 	
Oil and gas properties, including pipelines	 	 	2,122,685	 	 	 	2,031,026	 	
Geothermal properties	 	 	407,639	 	 	 	402,643	 	
Other	 	 	216,608	 	 	 	183,742	 	
 	 	 		 	 	 		 	
 	 	 	13,673,927	 	 	 	12,908,342	 	
Less: accumulated depreciation, depletion and amortization	 	 	(1,379,421	)	 	 	(1,220,425	)	
 	 	 		 	 	 		 	
 	 	 	12,294,506	 	 	 	11,687,917	 	
Land	 	 	79,560	 	 	 	82,158	 	
Construction in progress	 	 	6,952,254	 	 	 	7,080,892	 	
 	 	 		 	 	 		 	
Property, plant and equipment, net	 	$	19,326,320	 	 	$	18,850,967	 	
 	 	 		 	 	 		 	
      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. Further detail of CIP is presented below under Capital Spending — Development and Construction.
      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
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS — (Continued)
of Interest Cost,” as amended by SFAS No. 58, “Capitalization of Interest Cost in Financial Statements That Include Investments Accounted for by the Equity Method (an Amendment of FASB Statement No. 34).” The Company’s qualifying assets include construction in progress, certain oil and gas properties under development, construction costs related to unconsolidated investments in power projects under construction, and advanced stage development costs. For the three months ended March 31, 2003 and 2002, the total amount of interest capitalized was $118.5 million and $163.1 million, respectively, including $19.6 million and $35.1 million, respectively, of interest incurred on funds borrowed for specific construction projects and $98.9 million and $128.0 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, 2003 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 the Company’s Senior Notes, the Company’s term loan facility and the $950 million secured working capital revolving credit facilities.

	Capital Spending — Development and Construction	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
						Equipment		Project		Equipment for	
		# of				Included in		Development		Future Use in	
		Projects		CIP		CIP		Costs		Other Assets	
											
Projects in active construction	 	 	21	 	 	$	5,556,050	 	 	$	2,075,692	 	 	$	—	 	 	$	—	 	
Projects in advanced development	 	 	11	 	 	 	710,642	 	 	 	642,332	 	 	 	107,554	 	 	 	—	 	
Projects in suspended development	 	 	5	 	 	 	577,431	 	 	 	308,631	 	 	 	8,753	 	 	 	—	 	
Projects in early development	 	 	3	 	 	 	3,824	 	 	 	—	 	 	 	7,768	 	 	 	—	 	
Other capital projects	 	 	NA	 	 	 	104,307	 	 	 	—	 	 	 	1,543	 	 	 	 	 	
Unassigned turbines	 	 	 	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	147,946	 	
 	 	 	 	 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Total construction and development costs	 	 	 	 	 	$	6,952,254	 	 	$	3,026,655	 	 	$	125,618	 	 	$	147,946	 	
 	 	 	 	 	 	 		 	 	 		 	 	 		 	 	 		 	
      Projects in Active Construction  — The 21 projects in active construction are estimated to come on line from April 2003 to December 2005. These projects will bring on line approximately 8,900 and 10,700 MW of base load and base load with peaking capacity, respectively. Interest and other costs related to the construction activities necessary to bring these projects to their intended use are being capitalized. The estimated cost to complete these projects, net of expected project financing proceeds, is approximately $2.0 billion.
      Projects in Advanced Development  — There are 11 projects in advanced development. Of the total amount capitalized approximately $642.3 million relates to equipment, primarily turbine progress payments. These projects will bring on line approximately 5,816 and 7,014 MW of base load and base load with peaking capacity, respectively. 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 one project 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 these projects is approximately $3.5 billion. The Company’s current plan is to project finance these costs as power purchase agreements are arranged.
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS — (Continued)
      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 indicating that it is again highly probable that the costs will be recovered through future operations. As is true for all projects, the suspended projects are reviewed for impairment whenever there is an indication of potential reduction in a project’s fair value. Further, if it is determined that it is no longer probable that the projects will be completed and all capitalized costs recovered through future operations, the carrying values of the projects would be written down to the recoverable value. These projects would bring on line approximately 2,858 and 3,338 MW of base load and base load with peaking capacity, respectively. The estimated cost to complete these projects is approximately $1.4 billion. Of the amount capitalized approximately $308.6 million relates to equipment cost, primarily turbine progress payments.
      Projects in 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, 2003, the Company had made progress payments on 9 turbines, 14 heat recovery steam generators, and other equipment with an aggregate carrying value of $147.9 million, that are not assigned to specific development and construction projects and which the Company is holding 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. The Company reviews the equipment for potential impairment by allocating a factor based on the probability that it will utilize it for future projects versus selling it. Then the Company reviews for impairment in the context of the equipment’s use in a future power facility. Utilizing this methodology, the Company does not believe that the equipment is impaired. However, during the second quarter of 2003, the Company recorded approximately $17.2 million in losses in connection with the sale of two turbines, and it may incur further losses should it decide to sell more equipment in the future.
      Impairment Evaluation  — All active, construction and development projects, including unassigned turbines are reviewed for impairment whenever there is an indication of potential reduction in a project’s 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 FASB 144 “Accounting for Impairment or Disposal of Long-Lived Assets.”
4.     Acquisitions
      On February 26, 2003, the Company, through its wholly owned subsidiary, Calpine European Finance, purchased 100% of the outstanding stock of Babcock Borsig Power Turbine Services (“BBPTS”) from its parent company, Babcock Borsig. Immediately following the acquisition, the BBPTS name was changed to Thomassen Turbine Systems (“TTS”). The Company’s total cost of the acquisition was $12.0 million and was comprised of two pieces. The first was a $7.0 million cash payment to Babcock Borsig to acquire the outstanding stock of TTS. Included in this payment was the right to a note receivable valued at 11.9 million Euro (approximately US$12.9 million on the acquisition date) due from TTS, which the Company acquired
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS — (Continued)
from Babcock Borsig for $1. Additionally, as of the date of the acquisition, TTS owed $5.0 million in payments to another of the Company’s wholly owned subsidiaries, PSM, under a pre-existing license agreement. Because of the acquisition, TTS ceased to exist as a third party debtor to the Company, thereby resulting in a reduction of third party receivables of $5.0 million from the Company’s consolidated perspective.
5.     Goodwill and Other Intangible Assets
      On January 1, 2002, the Company adopted SFAS No. 142, “Goodwill and Other Intangible Assets,” which requires that all intangible assets with finite useful lives be amortized and that goodwill and intangible assets with indefinite lives not be amortized, but rather tested upon adoption and at least annually for impairment. The Company was required to complete the initial step of a transitional impairment test within six months of adoption of SFAS No. 142 and to complete the final step of the transitional impairment test by the end of the fiscal year. The Company completed both the transitional goodwill impairment test and the first annual goodwill impairment test as required during 2002 and determined that the fair value of the reporting units with goodwill exceeded their net carrying values. Therefore, the Company did not record any impairment expense during 2002. Consistent with the requirements of SFAS No. 142, the Company will perform an annual impairment test for 2003 during December, in conjunction with its annual reporting process.
      In accordance with the standard, the Company discontinued the amortization of its recorded goodwill as of January 1, 2002, and identified reporting units based on its current segment reporting structure and allocated all recorded goodwill, as well as other assets and liabilities, to the reporting units.
      Recorded goodwill, by segment, was (in thousands): 

		As of		As of	
		March 31,		December 31,	
		2003		2002	
					
Electric Generation and Marketing	 	$	—	 	 	$	—	 	
Oil and Gas Production and Marketing	 	 	—	 	 	 	—	 	
Corporate, Other and Eliminations	 	 	34,589	 	 	 	34,589	 	
 	 	 		 	 	 		 	
 	Total	 	$	34,589	 	 	$	34,589	 	
 	 	 		 	 	 		 	
      The Company also reassessed the useful lives and the classification of its identifiable intangible assets and determined that they continue to be appropriate. The components of the amortizable intangible assets consist of the following (in thousands): 

		Weighted					
		Average		As of March 31, 2003		As of December 31, 2002	
		Useful					
		Life/Contract		Carrying		Accumulated		Carrying		Accumulated	
		Life		Amount		Amortization		Amount		Amortization	
											
Patents	 	 	5	 	 	$	485	 	 	$	(255	)	 	$	485	 	 	$	(231	)	
Power sales agreements	 	 	14	 	 	 	156,814	 	 	 	(107,574	)	 	 	156,814	 	 	 	(106,227	)	
Fuel supply and fuel management contracts	 	 	26	 	 	 	22,198	 	 	 	(4,327	)	 	 	22,198	 	 	 	(4,105	)	
Geothermal lease rights	 	 	20	 	 	 	19,518	 	 	 	(375	)	 	 	19,518	 	 	 	(350	)	
Steam purchase agreement	 	 	14	 	 	 	5,102	 	 	 	(567	)	 	 	5,201	 	 	 	(486	)	
Other	 	 	8	 	 	 	5,170	 	 	 	(82	)	 	 	320	 	 	 	(71	)	
 	 	 	 	 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Total	 	 	 	 	 	$	209,287	 	 	$	(113,180	)	 	$	204,536	 	 	$	(111,470	)	
 	 	 	 	 	 	 		 	 	 		 	 	 		 	 	 		 	
      Amortization expense of other intangible assets was $1.7 million and $6.0 million in the three months ended March 31, 2003 and 2002, respectively. Assuming no future impairments of these assets or additions as
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS — (Continued)
the result of acquisitions, amortization expense for the twelve months ended December 31 will be $5.4 million in 2003, $5.0 million in 2004, $4.9 million in 2005, $4.8 million in 2006 and $4.8 million in 2007.
6.     Financing
      On February 13, 2003, the Company completed a secondary offering of 17,034,234 Warranted Units of the Calpine Power Income Fund for gross proceeds of Cdn$153.3 million (US$100.9 million). The Warranted Units were sold to a syndicate of underwriters at a price of Cdn$9.00. Each Warranted Unit consists of one Trust Unit and one-half of one Trust Unit purchase warrant. Each Warrant entitles the holder to purchase one Trust Unit at a price of Cdn$9.00 per Trust Unit at any time on or prior to December 30, 2003, after which time the Warrant will be null and void. Assuming the exercise in full of the Warrants, Calpine will not own or control any of the outstanding Trust Units. However, Calpine will retain its 30% subordinated interest in the Canadian power generating assets and will continue to operate and manage the Calpine Power Income Fund and the Fund assets.
7.     Discontinued Operations
      As a result of the significant contraction in the availability of capital for participants in the energy sector, the Company has adopted a strategy of conserving its core strategic assets and selectively disposing of certain less strategically important assets, which serves primarily to raise cash for general corporate purposes and strengthen the Company’s balance sheet through repayment of debt. Set forth below are all of the Company’s asset disposals by reportable segment that impacted the Company’s Consolidated Condensed Financial Statements for the three months ended March 31, 2003:

	Oil and Gas Production and Marketing	
      On August 29, 2002, the Company completed the sale of certain oil and gas properties (“Medicine River properties”) located in central Alberta to NAL Oil and Gas Trust and another institutional investor for Cdn$125.0 million (US$80.1 million). As a result of the sale, the Company recorded a pre-tax gain of $21.9 million in the third quarter 2002.
      On October 1, 2002, the Company completed the sale of substantially all of its British Columbia oil and gas properties to Calgary, Alberta-based Pengrowth Corporation for gross proceeds of approximately Cdn$387.5 million (US$244.3 million). Of the total consideration, the Company received US$155.9 million in cash. The remaining US$88.4 million of consideration was paid by Pengrowth Corporation’s purchase in the open market of US$203.2 million in aggregate principal amount of the Company’s debt securities. As a result of the transaction, the Company recorded a US$37.4 million pre-tax gain on the sale of the properties and a gain on the extinguishment of debt of US$114.8 million in the third quarter 2002. The Company used approximately US$50.4 million of cash proceeds to repay amounts outstanding under its US$1.0 billion term loan.
      On October 31, 2002, the Company sold all of its oil and gas properties in Drake Bay Field located in Plaquemines Parish, Louisiana for approximately $3 million to Goldking Energy Corporation. As a result of the sale, the Company recognized a pre-tax loss of $0.02 million in the third quarter 2002.

	Electric Generation and Marketing	
      On December 16, 2002, the Company completed the sale of the 180-megawatt DePere Energy Center in DePere, Wisconsin. The facility was sold to Wisconsin Public Service for $120.4 million, which included $72.0 million in cash at closing and a $48.4 million payment due in December 2003. As a result of the sale, the Company recognized a pre-tax gain of $35.8 million. On December 17, 2002, the Company sold its right to the December 2003 payment to a third party for $46.3 million, and recognized a pre-tax loss of $2.1 million.
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS — (Continued)

	Summary	
      All of the asset disposals above were completed by December 31, 2002, and the Company did not have any additional material disposals during the three months ended March 31, 2003. As a result, the Company did not have any assets designated as “held for sale” on its Consolidated Condensed Balance Sheet at March 31, 2003, and December 31, 2002, respectively, and the Company did not record any income from discontinued operations for the three months ended March 31, 2003.
      The table below presents significant components of the Company’s income from discontinued operations for the three months ended March 31, 2002 (in thousands): 

			
		Three Months Ended March 31, 2002	
			
		Electric		Oil and Gas			
		Generation		Production			
		and Marketing		and Marketing		Total	
							
Total revenue	 	$	2,493	 	 	$	18,124	 	 	$	20,617	 	
Income from discontinued operations before taxes	 	 	1,234	 	 	 	1,851	 	 	 	3,085	 	
Income from discontinued operations, net of tax	 	$	842	 	 	$	1,203	 	 	$	2,045	 	
      The Company allocates interest expense associated with consolidated non-specific debt to its discontinued operations based on a ratio of the net assets of its discontinued operations to the Company’s total consolidated net assets, in accordance with EITF Issue No. 87-24, “Allocation of Interest to Discontinued Operations” (“EITF Issue No. 87-24”). Also in accordance with EITF Issue No. 87-24, the Company allocated interest expense to its British Columbia oil and gas properties for approximately $50.4 million of debt the Company was required to repay under the terms of its $1.0 billion term loan. For the three months ended March 31, 2002, the Company allocated interest expense of $1.2 million to its discontinued operations.

8.	Derivative Instruments	

	Commodity Derivative Instruments	
      As an independent power producer primarily focused on generation of electricity using gas-fired turbines, the Company’s natural physical commodity position is “short” fuel (i.e., natural gas consumer) and “long” power (i.e., electricity seller). To manage forward exposure to price fluctuation in these and (to a lesser extent) other commodities, the Company enters into derivative commodity instruments. The Company enters into commodity instruments to convert floating or indexed electricity and gas (and to a lesser extent oil and refined product) prices to fixed prices in order to lessen its vulnerability to reductions in electric prices for the electricity it generates, to reductions in gas prices for the gas it produces, and to increases in gas prices for the fuel it consumes in its power plants. The Company seeks to “self-hedge” its gas consumption exposure to an extent with its own gas production position. Any hedging, balancing, or optimization activities that the Company engages in are directly related to the Company’s asset-based business model of owning and operating gas-fired electric power plants and are designed to protect the Company’s “spark spread” (the difference between the Company’s fuel cost and the revenue it receives for its electric generation). The Company hedges exposures that arise from the ownership and operation of power plants and related sales of electricity and purchases of natural gas, and the Company utilizes derivatives to optimize the returns it is able to achieve from these assets. 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.
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS — (Continued)
      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 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.
      The table below reflects the amounts (in thousands) that are recorded as assets and liabilities at March 31, 2003, for the Company’s derivative instruments: 

						Commodity			
		Interest Rate		Currency		Derivative		Total	
		Derivative		Derivative		Instruments		Derivative	
		Instruments		Instruments		Net		Instruments	
									
Current derivative assets	 	$	—	 	 	$	998	 	 	$	632,866	 	 	$	633,864	 	
Long-term derivative assets	 	 	—	 	 	 	181	 	 	 	496,848	 	 	 	497,029	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Total assets	 	$	—	 	 	$	1,179	 	 	$	1,129,714	 	 	$	1,130,893	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	
Current derivative liabilities	 	$	(14,915	)	 	$	—	 	 	$	(543,110	)	 	$	(558,025	)	
Long-term derivative liabilities	 	 	(27,381	)	 	 	—	 	 	 	(478,461	)	 	 	(505,842	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Total liabilities	 	$	(42,296	)	 	$	—	 	 	$	(1,021,571	)	 	$	(1,063,867	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	
Net derivative assets (liabilities)	 	$	(42,296	)	 	$	1,179	 	 	$	108,143	 	 	$	67,026	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	
      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, 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	
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS — (Continued)

			
 		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 from the Company’s net derivative assets to its accumulated other comprehensive loss, net of tax from derivative instruments at March 31, 2003 (in thousands): 

Net derivative assets	 	$	67,026	 	
Derivatives not designated as cash flow hedges and recognized hedge ineffectiveness	 	 	(168,388	)	
Cash flow hedges terminated prior to maturity	 	 	(219,981	)	
Deferred tax asset attributable to accumulated other comprehensive loss on cash flow hedges	 	 	134,368	 	
Accumulated OCI from unconsolidated investees	 	 	(5,836	)	
Other reconciling items	 	 	(454	)	
 	 	 		 	
Accumulated other comprehensive loss from derivative instruments, net of tax(1)	 	$	(193,265	)	

		
(1) 	Amount represents one portion of the Company’s total accumulated OCI balance. See Note 9 — “Comprehensive Income (Loss)” 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, 2003. 

			
		March 31, 2003	
			
		Gross		Net	
					
Current derivative assets	 	$	1,691,543	 	 	$	632,866	 	
Long-term derivative assets	 	 	661,254	 	 	 	496,848	 	
 	 	 		 	 	 		 	
 	Total derivative assets	 	$	2,352,797	 	 	$	1,129,714	 	
 	 	 		 	 	 		 	
Current derivative liabilities	 	$	(1,601,623	)	 	$	(543,110	)	
Long-term derivative liabilities	 	 	(643,031	)	 	 	(478,461	)	
 	 	 		 	 	 		 	
 	Total derivative liabilities	 	$	(2,244,654	)	 	$	(1,021,571	)	
 	 	 		 	 	 		 	
 	Net commodity derivative assets	 	$	108,143	 	 	$	108,143	 	
 	 	 		 	 	 		 	
      The table above excludes the value of interest rate and currency derivative instruments.
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS — (Continued)
      The table below reflects the impact of the Company’s derivative instruments on its pre-tax earnings, both from cash flow hedge ineffectiveness and from the changes in market value of derivatives not designated as hedges of cash flows, for the three months ended March 31, 2003 and 2002, respectively (in thousands):

			
		Three Months Ended March 31,	

		2003		2002	
					
		Hedge		Undesignated				Hedge		Undesignated			
		Ineffectiveness		Derivatives		Total		Ineffectiveness		Derivatives		Total	
													
Natural gas derivatives(1)	 	$	6,113	 	 	$	(1,977	)	 	$	4,136	 	 	$	5,485	 	 	$	(6,835	)	 	$	(1,350	)	
Power derivatives(1)	 	 	(3,026	)	 	 	(1,881	)	 	 	(4,907	)	 	 	(222	)	 	 	4,389	 	 	 	4,167	 	
Interest rate derivatives(2)	 	 	(209	)	 	 	—	 	 	 	(209	)	 	 	(152	)	 	 	—	 	 	 	(152	)	
Foreign currency derivatives	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Total	 	$	2,878	 	 	$	(3,858	)	 	$	(980	)	 	$	5,111	 	 	$	(2,446	)	 	$	2,665	 	

		
(1) 	Recorded within unrealized mark-to-market gain (loss) on power and gas transactions, net	
 		
(2) 	Recorded within Other Income	
      The table below reflects the contribution of the Company’s cash flow hedge activity to pre-tax earnings based on the reclassification adjustment from OCI to earnings for the three months ended March 31, 2003 and 2002, respectively (in thousands): 

		2003		2002	
					
Natural gas and crude oil derivatives	 	$	35,162	 	 	$	(35,766	)	
Power derivatives	 	 	(51,326	)	 	 	86,466	 	
Interest rate derivatives	 	$	(10,642	)	 	$	(1,924	)	
Foreign currency derivatives	 	 	12,557	 	 	 	(287	)	
 	 	 		 	 	 		 	
 	Total derivatives	 	$	(14,249	)	 	$	48,489	 	
 	 	 		 	 	 		 	
      As of March 31, 2003, the maximum length of time over which the Company was hedging its exposure to the variability in future cash flows for forecasted transactions was 9, 4 1/2, and 12 years, for commodity, foreign currency and interest rate derivative instruments, respectively. The company estimates that pre-tax losses of $93.9 million would be reclassified from accumulated OCI into earnings during the twelve months ended March 31, 2004, 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.
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS — (Continued)

												2008			
		2003		2004		2005		2006		2007		& After		Total	
															
Crude oil OCI	 	$	(1,333	)	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	(1,333	)	
Gas OCI	 	 	(34,175	)	 	 	(14,232	)	 	 	(46,580	)	 	 	(9,581	)	 	 	872	 	 	 	2,860	 	 	 	(100,836	)	
Power OCI	 	 	(30,578	)	 	 	(37,618	)	 	 	(21,453	)	 	 	(11,943	)	 	 	(1,034	)	 	 	—	 	 	 	(102,626	)	
Interest rates OCI	 	 	(18,253	)	 	 	(21,833	)	 	 	(17,348	)	 	 	(14,001	)	 	 	(10,724	)	 	 	(31,053	)	 	 	(113,212	)	
Foreign currency OCI	 	 	(1,235	)	 	 	(1,721	)	 	 	(1,957	)	 	 	(2,111	)	 	 	(2,482	)	 	 	(120	)	 	 	(9,626	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Total OCI	 	$	(85,574	)	 	$	(75,404	)	 	$	(87,338	)	 	$	(37,636	)	 	$	(13,368	)	 	$	(28,313	)	 	$	(327,633	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
9.     Comprehensive Income (Loss)
      Comprehensive income (loss) is the total of net income (loss) and all other non-owner changes in equity. Comprehensive income (loss) includes net income (loss) and unrealized gains and losses from derivative instruments that qualify as hedges. The Company reports accumulated other comprehensive loss in its Consolidated Balance Sheet. The tables below detail the changes in the Company’s accumulated OCI balance and the components of the Company’s comprehensive income (loss) (in thousands): 

						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 loss 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	)	 	 	 	 	
 	 	 		 	 	 		 	 	 		 	 	 	 	 	
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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, 2002	
									
Accumulated other comprehensive loss at January 1, 2002	 	$	(180,819	)	 	$	(60,061	)	 	$	(240,880	)	 	 	 	 	
Net loss	 	 	 	 	 	 	 	 	 	 	 	 	 	$	(75,673	)	
 	Cash flow hedges:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Comprehensive pre-tax loss on cash flow hedges before reclassification adjustment during the three months ended March 31, 2002	 	 	130,436	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Reclassification adjustment for gain included in net loss for the three months ended March 31, 2002	 	 	(48,489	)	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Income tax provision for the three months ended March 31, 2002	 	 	(32,035	)	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 		 	 	 	 	 	 	 		 	 	 		 	
 	 	 	49,912	 	 	 	 	 	 	 	49,912	 	 	 	49,912	 	
 	 	Foreign currency translation loss for the three months ended March 31, 2002	 	 	—	 	 	 	(25,171	)	 	 	(25,171	)	 	 	(25,171	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	
Total comprehensive loss for the three months ended March 31, 2002	 	 	 	 	 	 	 	 	 	 	 	 	 	$	(50,932	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 		 	
Accumulated other comprehensive loss at March 31, 2002	 	$	(130,907	)	 	$	(85,232	)	 	$	(216,139	)	 	 	 	 	
 	 	 		 	 	 		 	 	 		 	 	 	 	 	
10.     Customers

	NRG Power Marketing Inc.	
      The Company has open contract positions with NRG Power Marketing Inc., a subsidiary of NRG Energy, Inc., which in turn is the unregulated power-generation subsidiary of XCEL Energy Inc. Almost all of the open contracts are accounted for as cash flow hedges under SFAS No. 133. See Note 15 — “Subsequent Events” for subsequent bankruptcy filing of NRG Energy, Inc. and NRG Power Marketing Inc. The Company’s exposure to NRG Power Marketing Inc. at March 31, 2003, is summarized below (in millions): 

							
		Receivables/Payables		Open Positions			
							
				Net				Gross Fair		Net Open			
		Gross		Gross		Receivable		Gross Fair		Value		Positions			
		Receivable		Payable		(Payable)		Value (+)		(-)		Value		Total	
															
NRG Power Marketing Inc.	 	$	5.7	 	 	$	(0.3	)	 	$	5.4	 	 	$	2.5	 	 	$	(5.3	)	 	$	(2.8	)	 	$	2.6	 	

	Aquila Merchant Services, Inc.	
      The Company currently buys and sells electricity and natural gas from Aquila and AMS under a variety of contractual arrangements. The Company accounts for certain of its contractual arrangements with AMS as derivatives under SFAS No. 133 and, accordingly, records the fair value of the open positions under these contracts in the financial statements. The Company also has tolling arrangements with AMS on the Acadia
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS — (Continued)
facility and with Aquila on the Aries facility under which they deliver gas to, and purchase electricity from, the Company with 20 and 15.5 year terms, respectively. These tolling agreements are not subject to derivative accounting. While Aquila and AMS have remained current in their payments to the Company, the Company has established partial reserves totaling $2.9 million offsetting revenue and other accumulated comprehensive loss and holds $27.1 million in margin deposits as collateral. The Company will continue to closely monitor its position with Aquila and AMS and will adjust the value of the reserve as conditions dictate. See Note 15 — “Subsequent Events” for subsequent termination of the tolling arrangement with AMS on the Acadia facility. The Company’s exposure, net of the established reserve, to Aquila and AMS at March 31, 2003, is summarized below (in millions): 

							
		Receivables/Payables		Open Positions			
							
				Net				Net Open			
		Gross		Gross		Receivable		Gross Fair		Gross Fair		Positions			
		Receivable		Payable		(Payable)		Value(+)		Value(-)		Value		Total	
															
AMS and Aquila	 	$	28.2	 	 	$	(23.3	)	 	$	4.9	 	 	$	76.4	 	 	$	(35.2	)	 	$	41.2	 	 	$	46.1	 	
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 period. The dilutive effect of the potential exercise of outstanding options to purchase shares of common stock is calculated using the treasury stock method. The dilutive effect of the assumed conversion of certain convertible securities into the Company’s common stock is based on the dilutive common share equivalents and the after tax interest expense and distribution expense avoided upon conversion. The reconciliation of basic 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,	

		2003		2002	
					
		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	 	$	(52,545	)	 	 	380,960	 	 	$	(0.14	)	 	$	(77,718	)	 	 	307,332	 	 	$	(0.25	)	
Discontinued operations, net of tax	 	 	—	 	 	 	—	 	 	 	—	 	 	 	2,045	 	 	 	—	 	 	 	—	 	
Cumulative effect of a change in accounting principle, net of tax	 	 	529	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Net loss	 	$	(52,016	)	 	 	380,960	 	 	$	(0.14	)	 	$	(75,673	)	 	 	307,332	 	 	$	(0.25	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
      Because of the Company’s losses for the three months ended March 31, 2003 and 2002, 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 115,332,743 and 131,505,219 shares of the Company’s common stock were not included in the computation of diluted shares outstanding during the three months ended March 31, 2003 and 2002, respectively, because such inclusion would be anti-dilutive.
12.     Commitments and Contingencies
      Capital Expenditures — On February 11, 2003, the Company announced a significant restructuring of its turbine agreements, which enables the Company to cancel up to 131 steam and gas turbines. In the quarter
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS — (Continued)
ended December 31, 2002, the Company recorded a pre-tax charge of $207.4 million in connection with these restructurings. Additionally, in the quarter ended March 31, 2002, the Company recorded a pre-tax charge of $168.5 million for equipment cancellations, primarily consisting of 35 steam and gas turbines. The Company remains committed to take delivery of 12 gas and 9 steam turbines.
      One of the Company’s equity method investees, Merchant Energy Partners Pleasant Hill, LLC (“Aries”), which owns the 591 mw Aries Power Project located in Pleasant Hill, Missouri, in which the Company owns a 50% interest, has $270 million of debt that was due on June 26, 2003. The management of Aries is in negotiation with the lenders to extend the debt for one month while it continues to negotiate a term loan for the project. The project is technically in default of its debt agreement until the extension is signed. Calpine management believes that the project will be able to obtain long-term project financing at commercially reasonable terms. As a result of this event, the Company has reviewed its investment in the Aries project and believes that the investment is not impaired.
      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 in each case presently be reasonably estimated. 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, these matters may potentially be material to the Company’s Consolidated Condensed Financial Statements.
      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 the California Superior Court, San Diego County. The underlying allegations in the Hawaii Structural Ironworkers Pension Fund action (“Hawaii action”) are substantially the same as the federal securities class actions described in the Company’s previous filings. However, the Hawaii action is brought on behalf of a purported class of purchasers of the Company’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 the Company’s financial condition in violation of Sections 11, 12 and 15 of the Securities Act of 1933. The Hawaii action relies in part on the Company’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 considers this lawsuit to be without merit and intends to defend vigorously against it. The Company has 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 U.S. District Court Northern District Court of California in May 2003.
      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. The underlying allegations in this action (“Phelps action”) are substantially the same as those in the securities class actions described in the Form 10-K for the year ended December 31, 2002. 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 the 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 Shareholder 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 in the Northern District of California. The Company considers these lawsuits to be without merit and intends to vigorously defend against them.
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS — (Continued)
      Johnson v. Peter Cartwright, et al. On December 17, 2001, a shareholder filed a derivative lawsuit on behalf of the Company against its directors and one if its senior officers. This lawsuit is captioned Johnson v. Cartwright, et al. and is pending in the California Superior Court, Santa Clara County. The Company is a nominal defendant in this lawsuit, which alleges claims relating to purportedly misleading statements about 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 the plaintiff may appeal this ruling. In early February 2003 the plaintiff filed an amended complaint. In March 2003 the Company and the individual defendants filed demurrers. 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 lawsuit 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 the 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. The Company considers this lawsuit to be without merit and intends to vigorously defend against it.
      California Business & Professions Code Section 17200 Cases. The lead case T&E Pastorino Nursery v. Duke Energy Trading and Marketing, L.L.C., et al. 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 has been named in seven other similar complaints for violations of Section 17200. All seven cases have been 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. In addition, plaintiffs in the case have filed a motion to remand that matter to California state court. The Company considers the allegations against Calpine and its subsidiaries in each of these lawsuits to be without merit, and intends to vigorously defend against them.
      McClintock et al. v. Vikram Budhraja, et al. California Department of Water Resources Case. On May 1, 2002, California State Senator Tom McClintock and others filed a complaint against Vikram Budhraja, a consultant to the California Department of Water Resources (“DWR”), DWR itself, and more than twenty-nine energy providers and other interested parties, including Calpine. The complaint alleges that the long-term power contracts that DWR entered into with these energy providers, including Calpine, are rendered void because Budhraja, who negotiated the contracts on behalf of the DWR, allegedly had an undisclosed financial interest in the contracts due to his connection to one of the energy providers, Edison International. Among other things, the complaint seeks an injunction prohibiting further performance of the long-term contracts and restitution of any funds paid to energy providers by the State of California under the contracts. The action has been stayed by order of the Court since August 26, 2002, pending resolution of an earlier-filed state court action involving the same parties and subject matter captioned Carboneau v. State of California in which the Company is not a defendant. The Company considers the allegations against it in this lawsuit to be without merit and intends to vigorously defend against them.
      Calpine Corporation v. Automated Credit Exchange. On March 5, 2002, the Company sued Automated Credit Exchange (“ACE”) in the Superior Court of the State of California for the County of Alameda for negligence and breach of contract to recover reclaim trading credits, a form of emission reduction credits that should have been held in the Company’s account with U.S. Trust Company (“US Trust”). 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 the Company of $7 million and transferred to the Company the rights to the emission reduction credits to be held
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS — (Continued)
by ACE. The Company recognized the $7 million in the second quarter of 2002. In June 2002 a complaint was filed by InterGen North America, L.P. (“InterGen”) against Anne M. Sholtz, the owner of ACE, and EonXchange, another Sholtz-controlled entity, which filed for bankruptcy protection on May 6, 2002. InterGen alleges it suffered a loss of emission reduction credits from EonXchange in a manner similar to the Company’s loss from ACE. InterGen’s complaint alleges that Anne Sholtz co-mingled assets among ACE, EonXchange and other Sholtz entities and that ACE and other Sholtz entities should be deemed to be one economic enterprise and all retroactively included in the EonXchange bankruptcy filing as of May 6, 2002. Ann Sholtz recently stipulated to agree to the consolidation of Anne Sholtz, ACE and other Sholtz entities in the EonXchange bankruptcy proceeding. On April 25, 2003, Calpine received a demand from the trustee of the EonXchange estate to return the $7 million payment as a preferential payment. The Company is confident of its valid defenses against this demand and cannot currently assess the likelihood of the demand, or of InterGen’s complaint, being upheld at this time.
      International Paper Company v. Androscoggin Energy LLC. In October 2000 International Paper Company filed a complaint against Androscoggin Energy LLC (“AELLC”) alleging that AELLC breached certain contractual representations and warranties by failing to disclose facts surrounding the termination, effective May 8, 1998, of one of AELLC’s fixed-cost gas supply agreements. The Company had acquired a 32.3% interest in AELLC as part of the SkyGen transaction which closed in October 2000. AELLC filed a counterclaim against International Paper Company that has been referred to arbitration. AELLC may commence the arbitration counterclaim after discovery has progressed further, depending on the outcome of the discussions referred to below. On November 7, 2002, the court issued an opinion on the parties’ cross motions for summary judgment finding in AELLC’s favor on certain matters though granting summary judgment to International Paper Company on the liability aspect of a particular claim against AELLC.
      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. The Court has a set schedule for disclosure of expert witness and depositions thereof and has tentatively scheduled the case for trial in the first quarter of 2004.
      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. AELLC has submitted an amended complaint and request for immediate injunctive relief against such actions. The Court heard the motion on April 24, 2003, and ordered that IP must pay the approximate $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 approximate $1.2 million. The Company believes it has adequately reserved for the possible loss, if any, it may ultimately incur as a result of this matter.
      Nevada Power Company and Sierra Pacific Power Company v. Calpine Energy Services, L.P. before the Federal Energy Regulatory Commission (“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 the Company. NPC and SPPC allege in their complaint, which seeks a refund, that the prices they agreed to pay in certain of the power sales agreements, including those signed with 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. On June 25, 2003, FERC rejected NPC’s complaint.
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NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS — (Continued)
13.     Operating Segments
      The Company is first and foremost an electric generating company. In pursuing this single business strategy, it is the Company’s objective to provide approximately 25% of its fuel consumption from its own natural gas production (“equity gas”). Since 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 following represents reportable segments and their defining criteria. 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 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, 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 accounting policies of the operating segments are the same as those described in Note 2 to the Consolidated Condensed Financial Statements, “Summary of Significant Accounting Policies.” 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		Oil and Gas									
		Generation		Production					
		and Marketing		and Marketing		Corporate and Other		Total	
									
		2003		2002		2003		2002		2003		2002		2003		2002	

		(In thousands)	
For the three months ended March 31,	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Total Revenue	 	$	2,156,470	 	 	$	1,275,103	 	 	$	26,111	 	 	$	54,068	 	 	$	3,696	 	 	$	3,364	 	 	$	2,186,277	 	 	$	1,332,535	 	
 	Income (loss) before taxes	 	 	(48,159	)	 	 	(66,306	)	 	 	43,265	 	 	 	3,720	 	 	 	(65,312	)	 	 	(57,743	)	 	 	(70,206	)	 	 	(120,329	)	
 	Equipment cancellation cost	 	 	—	 	 	 	165,371	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	3,100	 	 	 	—	 	 	 	168,471	 	
 	Intersegment Revenue	 	 	—	 	 	 	—	 	 	 	125,214	 	 	 	17,641	 	 	 	—	 	 	 	—	 	 	 	125,214	 	 	 	17,641	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
		Electric		Oil and Gas		Corporate, Other			
		Generation		Production		and			
		and Marketing		and Marketing		Eliminations		Total	

		(In thousands)	
Total assets:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	March 31, 2003	 	$	21,929,498	 	 	$	1,639,278	 	 	$	594,016	 	 	$	24,162,792	 	
 	December 31, 2002	 	$	18,587,342	 	 	$	1,713,085	 	 	$	2,926,565	 	 	$	23,226,992	 	
      Intersegment revenues primarily relate to the use of internally procured gas for the Company’s power plants. These intersegment revenues have been included in Income before taxes in the oil and gas production and marketing reporting segment and eliminated in the oil and gas production and marketing segment.
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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS — (Continued)
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 and under Section 206 of the Federal Power Act alleging, among other things, that the markets operated by the California Independent System Operator (“CAISO”) and the California Power Exchange (“CalPX”) were dysfunctional. In addition to commencing an inquiry regarding the market structure, FERC established a refund effective period of October 2, 2000, to June 19, 2001, for sales made into those markets.
      On December 12, 2002, the Administrative Law Judge issued a Certification of Proposed Finding on California Refund Liability (“December 12 Certification”) making an initial determination of refund liability. On March 26, 2003, FERC also issued an order adopting many of the ALJ’s findings set forth in the December 12 Certification (the “March 26 Order”). In addition, as a result of certain findings by the FERC staff concerning the unreliability or misreporting of certain reported indices for gas prices in California during the refund period, FERC ordered that the basis for calculating a party’s potential refund liability be modified by substituting a gas proxy price based upon gas prices in the producing areas plus the tariff transportation rate for the California gas price indices previously adopted in the refund proceeding. The Company believes, based on the available information, that any refund liability that may be attributable to it 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. The final outcome of this proceeding and the impact on the Company’s business is uncertain at this time.
      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. 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 potentially be in violation of the CAISO’s or CalPX’ tariff. The Final Report also recommended that FERC modify the basis for determining potential liability in the California Refund Proceeding discussed above. On June 25, 2003, FERC issued a number of orders associated with these investigations. In particular, based on the FERC staff’s earlier recommendations in the Final Report, FERC issued two show cause orders each naming certain industry participants. The show cause orders have initiated proceedings wherein the named parties must demonstrate that certain market behavior did not violate either the CAISO or CalPX tariffs as prohibited market manipulative behavior. FERC did not subject the Company to either of the show cause orders. FERC also issued an order directing the FERC staff
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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS — (Continued)
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.

15.	Subsequent Events	
      On April 29, 2003, the Company completed the sale for $82.0 million to GE Structured Finance of a preferred interest, which approximates 60% based on projected cash flow distributions, in a subsidiary that leases and operates the 115-megawatt King City Power Plant. Calpine will hold the remaining interest in the subsidiary and will continue to provide O&M services.
      On May 12, 2003, the Company completed the contract monetization and a restructuring of its interest in Acadia Power Partners, LLC (“Acadia”), a 50/50 joint venture between Calpine and Cleco Corporation (“Cleco”). As part of the transaction, Acadia terminated its 580-megawatt, 20-year tolling arrangement with AMS in return for a cash payment of $105.5 million paid by a subsidiary of Aquila. Acadia will make a $105.5 million distribution to Calpine. Subsequent to this contract monetization, CES, a wholly owned subsidiary of Calpine, entered into a new 20-year, 580-megawatt tolling contract with Acadia. CES will now market all of the output from the Acadia Power Project under the terms of this new contract and an existing 20-year tolling agreement. Cleco will receive priority cash distributions as its consideration for the restructuring.
      On May 14, 2003, NRG Energy Inc. and NRG Power Marketing Inc. filed for Chapter 11 bankruptcy reorganization, that includes a commitment by parent Xcel Energy Inc. to help settle debts. The filing does not include Xcel or any other Xcel subsidiaries. See Note 10 — “Customers” for the Company’s exposure to NRG Power Marketing Inc. at March 31, 2003.
      On May 15, 2003, the Company’s wholly-owned subsidiary, Calpine Northbrook Energy Marketing, LLC (“CNEM”), completed the $82.8 million monetization of an existing power sales agreement with the Bonneville Power Administration (“BPA”).
      Under the existing 100-megawatt fixed-price contract, CNEM delivers baseload power to BPA through December 31, 2006. As a part of the monetization transaction, CNEM entered into a contract with a third party to purchase power based on spot prices and a fixed-price swap agreement with an affiliate of Deutsche Bank to lock in the price of the purchased power. The term of both agreements is through December 31, 2006. To complete the monetization, CNEM then entered into an agreement with an affiliate of Deutsche Bank and borrowed $82.8 million secured by the spread between the BPA contract and the fixed power purchases. Proceeds from the borrowing will be used to pay transaction expenses for plant construction and general corporate purposes, as well as fees and expenses associated with the monetization. CNEM will make quarterly principal and interest payments on the loan that matures on December 31, 2006. CNEM has been 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.
      On June 2, 2003, Standard & Poor’s (S&P) downgraded Calpine’s corporate credit rating to B from BB. The ratings on the Company’s senior unsecured debt, convertible preferred securities, secured corporate revolver and secured term loan were also lowered. The S&P downgrade does not trigger any defaults under the Company’s credit agreements, and the Company continues to conduct its business with its usual creditworthy counterparties.
      On June 13, 2003, Power Contract Financing, L.L.C. (“PCF”), a wholly owned stand-alone subsidiary of CES, completed an offering of approximately $340 million of 5.2% Senior Secured Notes Due 2006 and approximately $462 million of 6.256% Senior Secured Notes Due 2010 in a private placement under
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CALPINE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS — (Continued)
Rule 144A. The two tranches of Senior Secured Notes, totaling approximately $802 million of gross proceeds, are secured by fixed cash flows from one of CES’s fixed-priced, long-term power sales agreements with the State of California Department of Water Resources and a new fixed-priced, long-term power purchase agreement with a third party.
      The Company reached agreement with its bank group on a term sheet for a new, two-year, $950 million secured working capital revolver. As previously announced, this agreement provides the Company with an automatic extension of the current maturity date for its existing $950 million revolving credit facilities to July 16, 2003. This extension is expected to allow the Company and its banks sufficient time to complete definitive documentation.
      On June 26, 2003, the Company announced its intent to commence an offering of approximately $1.8 billion of second-priority senior secured notes and term loans. The final principal amount and note maturities will be determined by market conditions. The notes and term loans will be secured by substantially all of the assets owned directly by Calpine Corporation, including natural gas and power plant assets and the stock of CES and other subsidiaries.
      As discussed in Note 3, the Company recorded approximately $17.2 million in losses in connection with the sale of two turbines in the second quarter of 2003.
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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. Such statements include those concerning Calpine Corporation’s (“the Company’s”) expected financial performance and its strategic and operational plans, as well as all assumptions, expectations, predictions, intentions or beliefs about future events. You are cautioned that any such forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties that could cause actual results to differ materially from the forward-looking statements such as, but not limited to, (i) the timing and extent of deregulation of energy markets and the rules and regulations adopted on a transitional basis with respect thereto, (ii) the timing and extent of changes in commodity prices for energy, particularly natural gas and electricity, (iii) commercial operations of new plants that may be delayed or prevented because of various development and construction risks, such as a failure to obtain the necessary permits to operate, failure of third-party contractors to perform their contractual obligations or failure to obtain financing on acceptable terms, (iv) unscheduled outages of operating plants, (v) unseasonable weather patterns that produce reduced demand for power, (vi) systemic economic slowdowns, which can adversely affect consumption of power by businesses and consumers, (vii) cost estimates are preliminary and actual costs may be higher than estimated, (viii) a competitor’s development of lower-cost generating gas-fired power plants, (ix) risks associated with marketing and selling power from power plants in the evolving energy market, (x) the successful exploitation of an oil or gas resource that ultimately depends upon the geology of the resource, the total amount and costs to develop recoverable reserves, and legal title, regulatory, gas administration, marketing and operational factors relating to the extraction of natural gas, (xi) the effects on the Company’s business resulting from reduced liquidity in the trading and power industry, (xii) the Company’s ability to access the capital markets on attractive terms, (xiii) sources and uses of cash are estimates based on current expectations; actual sources may be lower and actual uses may be higher than estimated, (xiv) the direct or indirect effects on the Company’s business of a lowering of its credit rating (or actions it may take in response to changing credit rating criteria), including, increased collateral requirements, refusal by the Company’s current or potential counterparties to enter into transactions with it and its inability to obtain credit or capital in desired amounts or on favorable terms, (xv) possible future claims, litigation and enforcement actions pertaining to the foregoing or (xvi) other risks as identified herein. All information set forth in this filing is as of June 30, 2003, and Calpine undertakes no duty to update this information. Readers should carefully review the “Risk Factors” section below.
      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 rooms in Washington, D.C., Chicago, Illinois and New York, New York. You may obtain information on the operation of the SEC’s public reference facilities by calling the SEC at 1-800-SEC-0330. You can request copies of these documents, upon payment of a duplicating fee, by writing to the SEC at its principal office at 450 Fifth Street, N.W., Washington, D.C. 20549-1004. Our SEC filings are also accessible through the Internet at the SEC’s website at http://www.sec.gov.
      Our reports on Forms 10-K, 10-Q and 8-K are available for download, free of charge, as soon as reasonably practicable, at our website at www.calpine.com. The content of our website is not a part of this report. You may request a copy of our SEC filings, at no cost to you, by writing or telephoning us at: Calpine Corporation, 50 West San Fernando Street, San Jose, California 95113, attention: Lisa M. Bodensteiner, Assistant Secretary, telephone: (408) 995-5115. We will not send exhibits to the documents, unless the exhibits are specifically requested and you pay our fee for duplication and delivery.
      The information contained in this MD&A section reflects the restatements of the first quarter 2002 financial results as discussed in Note 2 of the Notes to the Consolidated Condensed Financial Statements.
Selected Operating Information
      Set forth below is certain selected operating information for our power plants for which results are consolidated in our Statements of Operations. Electricity revenue is composed of fixed capacity payments,
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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,	
			
		2003		2002	
					
				Restated(1)	
			
		(In thousands, except	
		production and pricing data)	
Power Plants:	 	 	 	 	 	 	 	 	
Electricity and steam (“E&S”) revenues:	 	 	 	 	 	 	 	 	
 	Energy	 	$	830,358	 	 	$	514,236	 	
 	Capacity	 	 	160,628	 	 	 	76,479	 	
 	Thermal and other	 	 	131,052	 	 	 	31,685	 	
 	 	 		 	 	 		 	
 	Subtotal	 	$	1,122,038	 	 	$	622,400	 	
E&S revenue from discontinued operations	 	 	—	 	 	 	2,493	 	
Spread on sales of purchased power(2)	 	 	1,335	 	 	 	90,816	 	
 	 	 		 	 	 		 	
Adjusted E&S revenues (non-GAAP)	 	$	1,123,373	 	 	$	715,709	 	
Megawatt hours produced	 	 	19,421,899	 	 	 	14,713,815	 	
All-in electricity price per megawatt hour generated	 	$	57.84	 	 	$	48.64	 	

		
(1) 	See Note 2 of the Notes to Consolidated Condensed Financial Statements regarding the restatement of financial statements.	
 		
(2) 	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, 2003 and 2002, that represent purchased power and purchased gas sales and the costs we incurred to purchase the power and gas that we resold during these periods (in thousands, except percentage data): 

			
		Three Months Ended	
		March 31,	
			
		2003		2002	
					
				Restated(1)	
Total revenue	 	$	2,186,277	 	 	$	1,332,535	 	
Sales of purchased power	 	 	681,284	 	 	 	520,051	 	
As a percentage of total revenue	 	 	31.2	%	 	 	39.0	%	
Sale of purchased gas	 	 	327,468	 	 	 	123,404	 	
As a percentage of total revenue	 	 	15.0	%	 	 	9.3	%	
Total cost of revenue (“COR”)	 	 	2,012,539	 	 	 	1,151,099	 	
Purchased power expense	 	 	679,949	 	 	 	429,235	 	
As a percentage of total COR	 	 	33.8	%	 	 	37.3	%	
Purchased gas expense	 	 	316,948	 	 	 	121,361	 	
As a percentage of total COR	 	 	15.7	%	 	 	10.5	%	

		
(1) 	See Note 2 of the Notes to Consolidated Condensed Financial Statements regarding the restatement of financial statements.	
      The primary reasons for the size of these sales and costs of revenue items include: (a) the significant level of Calpine Energy Services’ (“CES’s”) hedging, balancing and optimization activities; (b) volatile markets for electricity and natural gas, which prompted us to frequently adjust our hedge positions by buying power
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and gas and reselling it; (c) the accounting requirements under Staff Accounting Bulletin (“SAB”) No. 101, “Revenue Recognition in Financial Statements,” and Emerging Issues Task Force (“EITF”) Issue No. 99-19, “Reporting Revenue Gross as a Principal versus Net as an Asset”, which require us to show most of our hedging contracts on a gross basis (as opposed to netting sales and cost of revenue); and (d) rules in effect 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 require us to account for this activity, which applies to three of our merchant generating facilities, as the aggregate of two distinct sales and one purchase. This gross basis presentation increases revenues but not gross profit. This activity increased in 2003 compared to 2002 due primarily to an increase in electric prices. The table below details the financial extent of our transactions with NEPOOL for the period indicated.

		Three Months Ended	
		March 31,	
			
		2003		2002	
					
				Restated(1)	
			
		(In thousands)	
Sales to NEPOOL from power we generated	 	$	76,898	 	 	$	50,581	 	
Sales to NEPOOL from hedging and other activity	 	 	83,011	 	 	 	24,657	 	
 	 	 		 	 	 		 	
 	Total sales to NEPOOL	 	$	159,909	 	 	$	75,238	 	
 	Total purchases from NEPOOL	 	$	134,168	 	 	$	75,834	 	

		
(1) 	See Note 2 of the Notes to Consolidated Condensed Financial Statements regarding the restatement of financial statements.	
Results of Operations

	Three Months Ended March 31, 2003, Compared to Three Months Ended March 31, 2002 (in millions, except for unit pricing information and MW volumes).	

		Three Months Ended					
		March 31,					
							
		2003		2002		$ Change		% Change	
									
				Restated(1)					
Total Revenue	 	$	2,186.3	 	 	$	1,332.5	 	 	$	853.8	 	 	 	64.1	%	
      The increase in total revenue is explained by category below. 

							
		Three Months Ended					
		March 31,					
							
		2003		2002		$ Change		% Change	
									
				Restated(1)					
Electricity and steam revenue	 	$	1,122.0	 	 	$	622.4	 	 	$	499.6	 	 	 	80.3	%	
Sales of purchased power for hedging and optimization	 	 	681.3	 	 	 	520.1	 	 	 	161.2	 	 	 	31.0	%	
 	 	 		 	 	 		 	 	 		 	 	 	 	 	
 	Total electric generation and marketing revenue	 	$	1,803.3	 	 	$	1,142.5	 	 	$	660.8	 	 	 	57.8	%	
 	 	 		 	 	 		 	 	 		 	 	 	 	 	
      Electricity and steam revenue increased as we completed construction and brought into operation 10 new baseload power plants, 10 new peaker facilities and 2 expansion projects completed subsequent to March 31, 2002. Average megawatts in operation of our consolidated plants increased by 62% to 18,116 MW while generation increased by 32%. The increase in generation lagged behind the increase in average MW in operation as our baseload capacity factor dropped to 56% in the three months ended March 31, 2003 from 71% in the three months ended March 31, 2002 primarily due to the increased occurrence of unattractive off-peak market spark spreads in certain areas, and to a lesser extent due to unscheduled outages caused by equipment problems at certain of our plants. Average realized electric price, before the effects of hedging, balancing and optimization, increased from $42.30/ MWh in 2002 to $57.77/ MWh in 2003.
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      Sales of purchased power for hedging and optimization increased in the three months ended March 31, 2003, due primarily to higher electricity pricing in 2003. 

							
		Three Months Ended					
		March 31,					
							
		2003		2002		$ Change		% Change	
									
				Restated(1)					
Oil and gas sales	 	$	26.0	 	 	$	53.1	 	 	$	(27.1	)	 	 	(51.0	)%	
Sales of purchased gas for hedging and optimization	 	 	327.5	 	 	 	123.4	 	 	 	204.1	 	 	 	165.4	%	
 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Total oil and gas production and marketing revenue	 	$	353.5	 	 	$	176.5	 	 	$	177.0	 	 	 	100.3	%	
 	 	 		 	 	 		 	 	 		 	 	 	 	 	
      Oil and gas sales are net of internal consumption, which is eliminated in consolidation. Internal consumption increased by $107.6 to $125.2 in 2003. Before inter-company eliminations, oil and gas sales increased by $80.5 to $151.2 in 2003 from $70.7 in 2002 due primarily to 112% higher average realized natural gas pricing in 2003.
      Sales of purchased gas for hedging and optimization increased during 2003 as we brought into operation new generation and the related level of physical gas optimization and balancing activity increased to support the new generation, combined with a higher price environment. 

							
		Three Months Ended					
		March 31,					
							
		2003		2002		$ Change		% Change	
									
				Restated(1)					
Realized revenue on power and gas trading transactions, net	 	$	21.2	 	 	$	6.2	 	 	$	15.0	 	 	 	241.9	%	
Unrealized mark-to-market gain (loss) on power and gas transactions, net	 	 	(0.8	)	 	 	2.8	 	 	 	(3.6	)	 	 	(128.6	)%	
 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Total trading revenue, net	 	$	20.4	 	 	$	9.0	 	 	$	11.4	 	 	 	126.7	%	
 	 	 		 	 	 		 	 	 		 	 	 		 	
      Total trading revenue, which is shown on a net basis, increased due to favorable power and gas price movements. 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. 

							
		Three Months Ended					
		March 31,					
							
		2003		2002		$ Change		% Change	
									
				Restated(1)					
Other revenue	 	$	9.1	 	 	$	4.6	 	 	$	4.5	 	 	 	97.8	%	
      Other revenue increased during the three months ended March 31, 2003, primarily due to a $1.4 increase in revenue from Power Systems Mfg., LLC (“PSM”), our subsidiary that designs and manufactures certain spare parts for gas turbines and $2.0 of revenue from Thomassen Turbine Systems, (“TTS”), which we acquired in February 2003. Additionally our recently formed power and operating services unit contributed revenues of $1.3 in 2003. 

							
		Three Months Ended					
		March 31,					
							
		2003		2002		$ Change		% Change	
									
				Restated(1)					
Cost of revenue	 	$	2,012.5	 	 	$	1,151.1	 	 	$	861.4	 	 	 	74.8	%	
      The increase in total cost of revenue is explained by category below.
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		Three Months Ended					
		March 31,					
							
		2003		2002		$ Change		% Change	
									
				Restated(1)					
Plant operating expense	 	$	165.0	 	 	$	116.5	 	 	$	48.5	 	 	 	41.6	%	
Royalty expense	 	 	5.4	 	 	 	4.2	 	 	 	1.2	 	 	 	28.6	%	
Purchased power expense for hedging and optimization	 	 	679.9	 	 	 	429.2	 	 	 	250.7	 	 	 	58.4	%	
 	 	 		 	 	 		 	 	 		 	 	 	 	 	
 	Total electric generation and marketing expense	 	$	850.3	 	 	$	549.9	 	 	$	300.4	 	 	 	54.6	%	
 	 	 		 	 	 		 	 	 		 	 	 	 	 	
      Plant operating expense increased due to 10 new baseload power plants, 10 new peaker facilities and 2 expansion projects completed subsequent to March 31, 2002. In addition, during the three months ended March 31, 2003, we recorded reserves of $16.9 for generator and turbine combustor equipment repairs, for which the company is pursuing recovery from an equipment vendor.
      Royalty expense increased due to an increase in electric revenues at The Geysers geothermal plants.
      The increase in purchased power expense for hedging and optimization was due primarily to higher electricity prices in 2003. 

							
		Three Months Ended					
		March 31,					
							
		2003		2002		$ Change		% Change	
									
				Restated(1)					
Oil and gas production expense	 	$	25.7	 	 	$	21.6	 	 	$	4.1	 	 	 	19.0	%	
Purchased gas expense for hedging and optimization	 	 	316.9	 	 	 	121.4	 	 	 	195.5	 	 	 	161.0	%	
 	 	 		 	 	 		 	 	 		 	 	 	 	 	
 	Total oil and gas production and marketing expense	 	$	342.6	 	 	$	143.0	 	 	$	199.6	 	 	 	139.6	%	
 	 	 		 	 	 		 	 	 		 	 	 	 	 	
      Oil and gas production expense increased primarily due to higher production taxes, ad valorem taxes and treating and transportation costs which are the result of higher oil and gas revenues and increased production.
      Purchased gas expense for hedging and optimization increased in the three months ended March 31, 2003, as we brought into operation new generation, and the related level of physical gas optimization and balancing activity increased to support the new generation, combined with a higher price environment. 

							
		Three Months Ended					
		March 31,					
							
		2003		2002		$ Change		% Change	
									
				Restated(1)					
Fuel expense	 	$	650.2	 	 	$	332.5	 	 	$	317.7	 	 	 	95.5	%	
      Fuel expense increased for the three months ended March 31, 2003 due to a 32% increase in gas-fired megawatt hours generated and 66% higher gas prices excluding the effects of hedging, balancing and optimization, which was partially offset by increased usage of internally produced gas and a 2% improved average heat rate for our generation portfolio in 2003. 

							
		Three Months Ended					
		March 31,					
							
		2003		2002		$ Change		% Change	
									
				Restated(1)					
Depreciation, depletion and amortization expense	 	$	134.7	 	 	$	95.0	 	 	$	39.7	 	 	 	41.8	%	
      Depreciation, depletion and amortization expense increased primarily due to the additional power facilities in consolidated operations subsequent to March 31, 2002.
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		Three Months Ended					
		March 31,					
							
		2003		2002		$ Change		% Change	
									
				Restated(1)					
Other expense	 	$	7.0	 	 	$	2.6	 	 	$	4.4	 	 	 	169.2	%	
      The increase is primarily due to a $1.1 increase in PSM expense, $1.4 of TTS expense and a $1.1 increase in expense from WRMS engineering, our California-based engineering and architectural subsidiary. 

							
		Three Months Ended					
		March 31,					
							
		2003		2002		$ Change		% Change	
									
				Restated(1)					
(Income) from unconsolidated investments in power projects	 	$	(5.1	)	 	$	(1.5	)	 	$	(3.6	)	 	 	240.0	%	
      The increase is due primarily to the $7.6 in earnings generated by the Acadia Energy Center which went operational in August 2002. This was offset partially by a $2.2 loss generated by the Aries Power Project. These two projects were not in operation in the first quarter of 2002. 

							
		Three Months Ended					
		March 31,					
							
		2003		2002		$ Change		% Change	
									
				Restated(1)					
Equipment cancellation and asset impairment charge	 	$	—	 	 	$	168.5	 	 	$	168.5	 	 	 	—	 	
      The pre-tax equipment cancellation charge of $168.5 in the three months ended March 31, 2002 was primarily a result of the 35 steam and gas turbine order cancellations and the cancellation of certain other equipment based primarily on forfeited prepayments made in prior periods. 

							
		Three Months Ended					
		March 31,					
							
		2003		2002		$ Change		% Change	
									
				Restated(1)					
Project development expense	 	$	5.2	 	 	$	11.3	 	 	$	(6.1	)	 	 	(54.0	)%	
      Project development expense decreased as we placed certain existing development projects on hold and scaled back new development activity. 

							
		Three Months Ended					
		March 31,					
							
		2003		2002		$ Change		% Change	
									
				Restated(1)					
Interest expense	 	$	143.0	 	 	$	73.7	 	 	$	69.3	 	 	 	94.0	%	
      Interest expense increased primarily due to the new plants entering commercial operations (at which point capitalization of interest expense ceases). Interest capitalized decreased from $163.1 for the three months ended March 31, 2002, to $118.5 for the three months ended March 31, 2003. We expect that interest expense will continue to increase and the amount of interest capitalized will decrease in future periods as our plants in construction are completed, and, to a lesser extent, as a result of suspension of certain of our development projects and suspension of capitalization of interest thereon. The remaining increase relates to an approximate 7% increase in average indebtedness and an increase in the amortization of terminated interest rate swaps. 

							
		Three Months Ended					
		March 31,					
							
		2003		2002		$ Change		% Change	
									
				Restated(1)					
Interest (income)	 	$	(8.0	)	 	$	(12.2	)	 	$	4.2	 	 	 	(34.4	)%	
      The decrease is primarily due to lower cash balances and lower interest rates in 2003.
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		Three Months Ended					
		March 31,					
							
		2003		2002		$ Change		% Change	
									
				Restated(1)					
Other expense (income)	 	$	36.9	 	 	$	(12.9	)	 	$	49.8	 	 	 	(386.0	)%	
      The other expense in the three months ended March 31, 2003, is comprised primarily of $25.2 of foreign exchange translation losses, $4.4 of letter of credit fees and $2.3 of minority interest expense. The foreign exchange translation losses recognized into income were inter-company transaction-related and were due mainly to a strong Canadian dollar in the quarter. In 2002 we recorded a $9.7 gain from the sale of our interest in the Lockport facility and a gain of $3.5 from the repurchase of our Zero-Coupon Convertible Debentures Due 2021 at a discount. 

							
		Three Months Ended					
		March 31,					
							
		2003		2002		$ Change		% Change	
									
				Restated(1)					
Benefit for income taxes	 	$	(17.7	)	 	$	(42.6	)	 	$	24.9	 	 	 	(58.5	)%	
      The benefit for income taxes decreased primarily due to the increase in income from continuing operations in 2003 compared to 2002 and from a reduction in the effective tax rate from 35% to 25%. The effective rate is driven primarily by our estimate of the tax liability by year end, in addition to certain permanent items. 

							
		Three Months Ended					
		March 31,					
							
		2003		2002		$ Change		% Change	
									
				Restated(1)					
Discontinued operations, net of tax	 	$	—	 	 	$	2.0	 	 	$	(2.0	)	 	 	—	 	
      The 2002 activity represents the results of our discontinued operations, which included the DePere Energy Center and Drakes Bay Field, British Columbia and Medicine River oil and gas assets. As the sale of these assets were completed by December 31, 2002 and there were no assets held for sale as of March 31, 2003, there was no corresponding activity for 2003. 

							
		Three Months Ended					
		March 31,					
							
		2003		2002		$ Change		% Change	
									
				Restated(1)					
Cumulative effect of a change in acct. principle, net of tax	 	$	0.5	 	 	$	—	 	 	$	0.5	 	 	 	—	 	
      The cumulative effect of a change in accounting principle represents a gain, net of tax effect from adopting SFAS No. 143, “Accounting for Asset Retirement Obligations.” See Note 2 of the Notes to Consolidated Condensed Financial Statements for more information. 

							
		Three Months Ended					
		March 31,					
							
		2003		2002		$ Change		% Change	
									
				Restated(1)					
Net loss	 	$	(52.0	)	 	$	(75.7	)	 	$	23.7	 	 	 	(31.3	)%	
      Net loss of $52.0 for the three months ended March 31, 2003 improved as compared to the first quarter net loss of $75.7 last year. Both period results included significant charges. In the first quarter of 2003, financial results were affected by unscheduled outages and charges, including reserves for equipment repairs, totaling $16.9, and $25.2 of foreign exchange translation losses. Our growing portfolio of operational merchant generation facilities contributed to a 32% increase in electric generation production. Electric generation and marketing revenues increased 58% as a result of this new production and as a result of CES’s hedging, balancing and optimization activity. Market on-peak spark spreads were slightly ahead of our expectations in certain markets, and operating results for the three months ended March 31, 2003 reflect an increase in
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realized electricity prices. However, overall we experienced a decrease in average spark spreads per megawatt-hour compared with the same period in 2002, reflecting a higher mix of lower market on-peak spark spreads. Plant operating expenses and depreciation were higher due to the additional plants in operation. This was partially mitigated by an increase in oil and gas production margins compared to the prior year due to higher realized oil and gas pricing. As a result of the above, gross profit for the first quarter 2003 decreased approximately 4% compared to the same quarter in 2002. Additionally, lower general and administrative costs were offset by higher interest expense as new facilities entered commercial operation.
      (1) See Note 2 of the Notes to Consolidated Condensed Financial Statements regarding the restatement of financial statements.
Liquidity and Capital Resources
      General — Beginning in the latter half of 2001, and continuing through 2003 to date, there has been a significant contraction in the availability of capital for participants in the energy sector, although a more favorable climate for refinancings has been observed in 2003. This was due to a range of factors, including uncertainty arising from the collapse of Enron Corp. and a perceived near-term surplus supply of electric generating capacity. Contracting credit markets and decreased spark spreads have adversely impacted our liquidity and earnings. While we have been able to access the capital and bank credit markets, it has been on significantly different terms than in the past. We recognize that 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 for 2002 and 2003 to enable us to conserve our available capital resources.
      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 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 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. Our strategy is also to reinvest our cash from operations into our business development and construction program or use it to reduce debt, rather than to pay cash dividends. As discussed below, we have a liquidity-enhancing program underway to fund the completion of our current construction portfolio, for refinancing and for general corporate purposes.
      We continue to evaluate current and forecasted cash flow as a basis for funding operating requirements and capital expenditures. In November 2003 and 2004 our $1.0 billion and $2.5 billion secured revolving construction financing facilities will mature, requiring us to refinance this indebtedness. At March 31, 2003, there was $970.1 million and $2,468.8 million outstanding, respectively, under these facilities. In May 2003 our $950 million secured working capital revolving credit facilities matured; however, we reached agreement with the bank group on a term sheet for a new, two-year, $950 million secured working capital revolver. This agreement provides us with an automatic extension of the current maturity date for our existing $950 million revolving credit facilities to July 16, 2003. This extension is expected to allow us and our banks sufficient time to complete definitive documentation. Our $1.0 billion secured term credit facility will mature in May 2004 and will need to be refinanced. At March 31, 2003, we had $340.0 million in funded borrowings under the revolving credit facilities and $949.6 million in funded borrowings outstanding under the term loan facility. We believe that, we will be able to refinance these facilities, and 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 of certain assets and cash balances to satisfy all obligations under our other outstanding indebtedness, and to fund anticipated capital expenditures and working capital requirements for the next twelve months.
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      Cash Flow Activities  — The following table summarizes our cash flow activities for the periods indicated: 

			
		Three Months Ended	
		March 31,	
			
		2003		2002	
					
				Restated(1)	
			
		(In thousands)	
Beginning cash and cash equivalents	 	$	579,486	 	 	$	1,594,144	 	
Net cash provided by (used in):	 	 	 	 	 	 	 	 	
 	Operating activities	 	 	165,367	 	 	 	355,073	 	
 	Investing activities	 	 	(483,629	)	 	 	(1,314,011	)	
 	Financing activities	 	 	112,543	 	 	 	(156,923	)	
 	Effect of exchange rates changes on cash and cash equivalents	 	 	4,290	 	 	 	(491	)	
 	 	 		 	 	 		 	
 	Net increase (decrease) in cash and cash equivalents	 	 	(201,429	)	 	 	(1,116,352	)	
 	 	 		 	 	 		 	
Ending cash and cash equivalents	 	$	378,057	 	 	$	477,792	 	

		
(1) 	See Note 2 of the Notes to Consolidated Condensed Financial Statements regarding the restatement of financial statements.	
      Operating activities for the three months ended March 31, 2003, provided net cash of $165.4 million, compared to $355.1 million for the same period in 2002. The decrease in operating cash flow between periods is primarily due to the collection from escrow of approximately $222.3 million in 2002 for the PG&E past due pre-petition receivables that were sold to a third party in December 2001. Excluding the effects of working capital reflected as “Changes in operating assets and liabilities, net of effects of acquisitions,” our operating cash flow increased by approximately $97.0 million. Although average spark spreads were lower in 2003 than in 2002, increased electrical generation yielded greater gross profit. Natural gas price increases benefited our oil and gas operating results on similar production.
      Investing activities for the three months ended March 31, 2003, consumed net cash of $483.6 million, as compared to $1.3 billion in the same period of 2002. In both periods, capital expenditures represent the majority of investing cash outflows. The decrease between periods is due to the completion of construction on several facilities during 2002, and due to our revised capital expenditure program, which aggressively reduces capital investments.
      Financing activities for the three months ended March 31, 2003, provided $112.5 million, compared to having used $156.9 million in the prior year. Current year cash inflows are the result of a secondary trust unit offering from our Canadian income trust and additional borrowings under our revolvers. In the same period of 2002, we repaid $353.6 million in borrowings, which more than offset the $226.5 million we raised from a convertible senior notes offering and project financing borrowings.
      Customers  — As of March 31, 2003, we had collection exposures after established reserves from certain of our counterparties as follows: $8.4 million from the California Independent System Operator Corporation and Automated Power Exchange, Inc.; approximately $3.9 million and $0.5 million, with two subsidiaries of Sierra Pacific Resources Company, Nevada Power Company and Sierra Pacific Power Company, respectively; $2.6 million with NRG Power Marketing Inc and $46.1 million with Aquila Merchant Services, Inc. and Aquila. While we cannot predict the likelihood of default by our customers, we are continuing to closely monitor our positions and will adjust the values of the reserves as conditions dictate. Based on our legal analysis, we do not have any net collection exposure to Enron and its affiliates. See Note 10 of the Notes to Consolidated Condensed Financial Statements for more information.
      Letter of Credit Facilities  — At March 31, 2003 and December 31, 2002, we had approximately $630.4 million and $685.6 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, $519.5 million and $573.9 million, respectively, were issued under the corporate revolving credit facilities at March 31, 2003 and December 31, 2002.
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      CES Margin Deposits and Other Credit Support  — As of March 31, 2003 and December 31, 2002, CES had deposited net amounts of $26.2 million and $25.2 million, respectively, in cash as margin deposits with third parties related to its business activities and had letters of credit outstanding to support CES risk management activities of $74.6 million and $106.1 million, respectively.
      The amount of credit support required to support CES’s operations is a function primarily of the changes in fair value of commodity contracts that CES has entered into and our credit rating. Since December 31, 2001, the amount of credit support provided by us for CES transactions has declined, largely due to the reduction of CES’s activities as well as changes in commodity prices in late 2002 and early 2003, as compared with late 2001. 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.
      Working Capital  — At March 31, 2003 we had a negative working capital balance (current assets minus current liabilities) of $1,640.0 million. This was primarily caused by $1,669.3 million of debt, including balances outstanding under our $1 billion construction revolving credit facility, $950 million working capital revolving credit facility, equipment vendor financing and peaker facilities funding that we intend to refinance or extend. Until such time as the debt is refinanced or extended, we are classifying it as current. As discussed in Note 15 of Notes to Consolidated Condensed Financial Statements, on June 26, 2003, we announced our intent to commence an offering of approximately $1.8 billion of second-priority senior secured notes and term loans.
      Contractual Obligations  — Our contractual obligations as of March 31, 2003, are as follows (in thousands): 

		April													
		Through													
		December													
Contractual Obligations		2003		2004		2005		2006		2007		Thereafter		Total	
															
Notes payable and borrowings under lines of credit and term loan	 	$	340,388	 	 	$	951,841	 	 	$	4,047	 	 	$	161	 	 	$	171	 	 	$	1,828	 	 	$	1,298,436	 	
Capital lease obligation	 	 	2,969	 	 	 	3,880	 	 	 	4,416	 	 	 	5,468	 	 	 	5,980	 	 	 	177,859	 	 	 	200,572	 	
Construction/ project financing	 	 	1,317,251	 	 	 	2,492,853	 	 	 	19,192	 	 	 	22,202	 	 	 	34,152	 	 	 	653,089	 	 	 	4,538,739	 	
Convertible Senior Notes	 	 	—	 	 	 	—	 	 	 	—	 	 	 	1,200,000	 	 	 	—	 	 	 	—	 	 	 	1,200,000	 	
Senior Notes	 	 	—	 	 	 	—	 	 	 	249,476	 	 	 	421,571	 	 	 	410,434	 	 	 	5,824,373	 	 	 	6,905,854	 	
Total operating lease	 	 	208,951	 	 	 	226,914	 	 	 	209,909	 	 	 	196,069	 	 	 	193,491	 	 	 	1,927,825	 	 	 	2,963,159	 	
Turbine commitments	 	 	391,865	 	 	 	153,339	 	 	 	19,597	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	564,801	 	
HIGH TIDES	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	1,153,500	 	 	 	1,153,500	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Total	 	$	2,261,424	 	 	$	3,828,827	 	 	$	506,637	 	 	$	1,845,471	 	 	$	644,228	 	 	$	9,738,474	 	 	$	18,825,061	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
      Holders have the right to require us to repurchase all or a portion of the Convertible Senior Notes on December 26, 2004, at 100% of their principal amount plus any accrued and unpaid interest.
      Our intent is to refinance all or a portion of the borrowings outstanding under the secured term and revolving working capital credit and construction financing facilities coming due in 2003 and 2004, extend the maturity of the financing, or obtain additional financing. Our ability to refinance this indebtedness will depend, in part, on events beyond our control, including the significant contraction in the availability of capital for participants in the energy sector, and actions taken by rating agencies. If we are unable to refinance this indebtedness, we may be required to further delay our construction program, sell assets or obtain additional financing.
      Our Senior Notes indenture and our credit facilities contain financial and other restrictive covenants with which we are required to comply. Any failure to comply could give holders of debt under the relevant instrument the right to accelerate the maturity of all debt outstanding thereunder if the default was not cured or waived. In addition, holders of debt under other instruments typically would have cross-acceleration
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provisions, which would permit them also to elect to accelerate the maturity of their debt if another debt instrument was accelerated upon the occurrence of such an uncured event of default.
      We reached agreement with the bank group on a term sheet for a new, two-year, $950 million secured working capital revolver. This agreement provides us with an automatic extension of the current maturity date for our existing $950 million revolving credit facilities to July 16, 2003. This extension is expected to allow us and our banks sufficient time to complete definitive documentation.
      Revised Capital Expenditure Program — On February 11, 2003, we announced a significant restructuring of our turbine agreements, which enables us to cancel up to 131 steam and gas turbines. In the quarter ended December 31, 2002, we recorded a pre-tax charge of $207.4 million in connection with these restructurings. Additionally, in the quarter ended March 31, 2002, we recorded a pre-tax charge of $168.5 million for equipment cancellations, primarily consisting of 35 steam and gas turbines. We remain committed to take delivery of 12 gas and 9 steam turbines. We have substantial flexibility to either proceed with or cancel our turbine orders as conditions warrant.
      In 2003, 2004 and 2005 we plan to spend $1.4 billion, $0.5 billion, and $0.1 billion, respectively, net of expected project financing proceeds, to complete our projects under construction.

	Capital Spending — Development and Construction	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
						Equipment		Project		Equipment for	
		# of				Included in		Development		Future Use in	
		Projects		CIP		CIP		Costs		Other Assets	
											
Projects in active construction	 	 	21	 	 	$	5,556,050	 	 	$	2,075,692	 	 	$	—	 	 	$	—	 	
Projects in advanced development	 	 	11	 	 	 	710,642	 	 	 	642,332	 	 	 	107,554	 	 	 	—	 	
Projects in suspended development	 	 	5	 	 	 	577,431	 	 	 	308,631	 	 	 	8,753	 	 	 	—	 	
Projects in early development	 	 	3	 	 	 	3,824	 	 	 	—	 	 	 	7,768	 	 	 	—	 	
Other capital projects	 	 	NA	 	 	 	104,307	 	 	 	—	 	 	 	1,543	 	 	 	—	 	
Unassigned turbines	 	 	 	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	147,946	 	
 	 	 	 	 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Total construction and development costs	 	 	 	 	 	$	6,952,254	 	 	$	3,026,655	 	 	$	125,618	 	 	$	147,946	 	
 	 	 	 	 	 	 		 	 	 		 	 	 		 	 	 		 	
      Projects in Active Construction — The 21 projects in active construction are estimated to come on line from April 2003 to December 2005. These projects will bring on line approximately 8,900 and 10,700 MW of base load and base load with peaking capacity, respectively. Interest and other costs related to the construction activities necessary to bring these projects to their intended use are being capitalized. The estimated cost to complete these projects, net of expected project financing proceeds, is approximately $2.0 billion.
      Projects in Advanced Development — There are 11 projects in advanced development. Of the total amount capitalized approximately $642.3 million relates to equipment, primarily turbine progress payments. These projects will bring on line approximately 5,816 and 7,014 MW of base load and base load with peaking capacity, respectively. 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 one project 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 these projects is approximately $3.5 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 indicating that it is again highly probable that the costs will be recovered through future operations. As is true for all projects, the suspended projects are reviewed for impairment whenever there is an indication of potential reduction in a project’s fair value. Further, if it is determined that it is no longer probable that the projects will be completed and all capitalized costs recovered through future
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operations, the carrying values of the projects would be written down to the recoverable value. These projects would bring on line approximately 2,858 and 3,338 MW of base load and base load with peaking capacity, respectively. The estimated cost to complete these projects is approximately $1.4 billion. Of the amount capitalized approximately $308.6 million relates to equipment cost, primarily turbine progress payments.
      Projects in 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, 2003, we had made progress payments on 9 turbines, 14 heat recovery steam generators, and other equipment with an aggregate carrying value of $147.9 million, that are not assigned to specific development and construction projects and which we are holding 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. We review the equipment for potential impairment by allocating a factor based on the probability that we will utilize it for future projects versus selling it. Then we review for impairment in the context of the equipment’s use in a future power facility. Utilizing this methodology, we do not believe that the equipment is impaired. However, during the second quarter of 2003, we recorded approximately $17.2 million in losses in connection with the sale of two turbines, and we may incur further losses should we decide to sell more equipment in the future.
      Impairment Evaluation — All active, construction and development projects, including unassigned turbines are reviewed for impairment whenever there is an indication of potential reduction in a project’s 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 FASB 144 “Accounting for Impairment or Disposal of Long-Lived Assets.”
      Capital Availability and Liquidity-Enhancing Program — Access to capital for many in the energy sector, including us, has been restricted since late 2001. While we were able in the first half of 2002 to access the capital and bank credit markets, in this new environment, it was on significantly different terms than in the past. In particular, our senior working capital facility has been secured by certain of our assets and equity interests. 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.
      The key elements, and the approximate amounts currently targeted, of our 2003 liquidity-enhancing program to fund completion of our current construction portfolio, for refinancing and for general corporate purposes include: 

•	 	Monetization/securitization of power sales contracts	 	$800 million	
•	 	Asset sales	 	$600 million	
•	 	Financing for Calpine’s California peaker program	 	$350 million	
•	 	Construction financing	 	$400 million	
•	 	Secondary offering of our Canadian income fund interests	 	$135 million	
      In 2003, we have continued to make significant progress towards these liquidity goals and have:

			
 	• 	Generated $105.5 million through contract monetization and joint venture restructuring at our Acadia Power Project.	
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 	• 	Completed a secondary offering of our Calpine Power Income Fund (“CPIF”) interests, generating net proceeds of approximately $94.6 million, and issued Warranted Units as part of the CPIF secondary offering, which are expected to generate approximately $45 million by the end of 2003.	
 		
 	• 	Completed the sale of a preferred interest in the 115-megawatt King City Power Plant for $82.0 million. We are continuing to evaluate the potential sale of a number of additional Qualifying Facility assets.	
 		
 	• 	Completed the offering of approximately $802 million Senior Notes secured by fixed cash flows from one of CES’s fixed-priced, long-term power sales agreements with the State of California Department of Water Resources and a new fixed-priced, long-term power purchase agreement with a third party.	
 		
 	• 	Continued efforts on the non-recourse construction financings for two 600-megawatt projects currently in construction: the Riverside Energy Center in Wisconsin and the Rocky Mountain Energy Center in Colorado. Both financings are expected to close in the second half of 2003.	
 		
 	• 	Progressed on our plan to approach the capital markets for the $350 million, long-term financing for our 495-megawatt California peaker projects.	
 		
 	• 	Completed the $82.8 million monetization of an existing power sales agreement with the Bonneville Power Administration.	
      In addition, on June 26, 2003, we announced our intent to commence an offering of approximately $1.8 billion of second-priority senior secured notes and term loans. The final principal amount and note maturities will be determined by market conditions. The notes and term loans will be secured by substantially all of the assets owned directly by Calpine Corporation, including natural gas and power plant assets and the stock of CES and other subsidiaries.
      One of our equity method investees, Merchant Energy Partners Pleasant Hill, LLC (“Aries”), which owns the 591 mw Aries Power Project located in Pleasant Hill, Missouri, in which we own a 50% interest, has $270 million of debt that was due on June 26, 2003. The management of Aries is in negotiation with the lenders to extend the debt for one month while it continues to negotiate a term loan for the project. The project is technically in default of its debt agreement until the extension is signed. We believe that the project will be able to obtain long-term project financing at commercially reasonable terms. As a result of this event, we have reviewed our investment in the Aries project and believe that the investment is not impaired.
      Credit Considerations — On June 2, 2003, Standard & Poors (S&P) downgraded our corporate credit rating to B from BB. The ratings on our senior unsecured debt, convertible preferred securities, secured corporate revolver and secured term loan were also lowered. The S&P downgrade does not trigger any defaults under our credit agreements, and we continue to conduct our business with our usual creditworthy counterparties.
Performance Metrics
      We believe that certain non-GAAP financial measures and other performance metrics are particularly important in understanding our business. These are described below, beginning with the non-GAAP financial measures:

			
 	• 	Average gross profit margin based on non-GAAP revenue and non-GAAP cost of revenue. A high percentage of our revenue consists of CES hedging, balancing and optimization activity undertaken primarily to enhance the value of our generating assets. CES’s hedging, balancing and optimization activity is primarily accomplished by buying and selling electric power and buying and selling natural gas or by entering into gas financial instruments such as exchange-traded swaps or forward contracts. Under SAB No. 101 and EITF No. 99-19, we must show the purchases and sales of electricity and gas for hedging, balancing and optimization activities (non-trading activities) on a gross basis in our statement of operations when we act as a principal, take title to the electricity and gas we purchase for resale, and enjoy the risks and rewards of ownership. This is notwithstanding the fact that the net gain or loss on certain financial hedging instruments, such as exchange-traded natural gas price swaps, is	
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 		shown as a net item in our GAAP financials and that pursuant to EITF No. 02-3, trading activity is now shown net in our Statements of Operations under trading revenue, net, for all periods presented. Because of the inflating effect on revenue of much of our hedging, balancing and optimization activity, we believe that revenue levels and trends do not reflect our performance as accurately as gross profit, and that it is analytically useful for investors to look at our results on a non-GAAP basis with all hedging, balancing and optimization activity netted. This analytical approach nets the sales of purchased power for hedging and optimization with purchased power expense for hedging and optimization and includes that net amount as an adjustment to E&S revenue for our generation assets. Similarly, we believe that it is analytically useful for investors to net the sales of purchased gas for hedging and optimization with purchased gas expense for hedging and optimization and include that net amount as an adjustment to fuel expense. This allows us to look at all hedging, balancing and optimization activity consistently (net presentation) and better understand our performance trends. It should be noted that in this non-GAAP analytical approach, total gross profit does not change from the GAAP presentation, but the gross profit margins as a percent of revenue do differ from corresponding GAAP amounts because the inflating effects on our GAAP revenue of hedging, balancing and optimization activities are removed.	
      Other performance metrics are described below and are important to understanding the degree to which our generating assets are productively employed, how efficiently they operate, and how market forces in the electricity and gas markets and our risk management activities affect our profitability. We elaborate below on why each of these metrics is useful in understanding our business.

			
 	• 	Average availability and average capacity factor or operating rate. Availability represents the percent of total hours during the period that our plants were available to run after taking into account the downtime associated with both scheduled and unscheduled outages. The capacity factor, sometimes called operating rate, is calculated by dividing (a) total megawatt hours generated by our power plants (excluding peakers) by the product of multiplying (b) the weighted average megawatts in operation during the period by (c) the total hours in the period. The capacity factor is thus a measure of total actual generation as a percent of total potential generation. If we elect not to generate during periods when electricity pricing is too low or gas prices too high to operate profitably, the capacity factor will reflect that decision as well as both scheduled and unscheduled outages due to maintenance and repair requirements.	
 		
 	• 	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 generated by dividing (a) adjusted electricity and steam revenue, which includes capacity revenues, energy revenues, thermal revenues and the spread on sales of purchased electricity for hedging, balancing, and optimization activity, by (b) total generated MWh 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	
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 		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. We also calculate average spark spread per MWh as adjusted for the margin on equity gas production. We calculate the margin on equity gas production by adding (a) oil and gas sales plus (b) the value of equity gas eliminated from fuel expense in consolidation and subtracting from this sum both (c) oil and gas production expense and (d) the depreciation, depletion and amortization expense attributable to oil and gas production. This amount is divided by (e) total generated MWh in the period and the resultant value per MWh is added to average spark spread. Because of our strategy of partially hedging our fuel expense exposure for electric generation with our equity gas production, we believe that this equity-gas-adjusted spark spread value is the more meaningful measure of spark spread in evaluating our performance.	
      The table below presents, side-by-side, both our GAAP and non-GAAP netted revenue, costs of revenue and gross profit showing the purchases and sales of electricity and gas for hedging, balancing and optimization activity on a net basis. It also shows the other performance metrics discussed above. 

							
				Non-GAAP Netted	
		GAAP Presentation		Presentation	
		Three Months Ended		Three Months Ended	
		March 31,		March 31,	
					
		2003		2002		2003		2002	
									
				Restated(1)					
			
		(In thousands)	
Revenue, Cost of Revenue and Gross Profit	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Revenue:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Electric generation and marketing revenue	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Electricity and steam revenue(3)	 	$	1,122,038	 	 	$	622,400	 	 	$	1,123,373	 	 	$	713,216	 	
 	 	Sales of purchased power for hedging and optimization(3)	 	 	681,284	 	 	 	520,051	 	 	 	—	 	 	 	—	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Total electric generation and marketing revenue	 	 	1,803,322	 	 	 	1,142,451	 	 	 	1,123,373	 	 	 	713,216	 	
 	Oil and gas production and marketing revenue	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Oil and gas production sales	 	 	25,989	 	 	 	53,076	 	 	 	25,989	 	 	 	53,076	 	
 	 	Sales of purchased gas for hedging and optimization(3)	 	 	327,468	 	 	 	123,404	 	 	 	—	 	 	 	—	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Total oil and gas production and marketing revenue	 	 	353,457	 	 	 	176,480	 	 	 	25,989	 	 	 	53,076	 	
 	Trading revenue, net	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Realized net revenue on power and gas trading, net	 	 	21,214	 	 	 	6,229	 	 	 	21,214	 	 	 	6,229	 	
 	 	Unrealized mark-to-market gain (loss) on power and gas transactions, net	 	 	(771	)	 	 	2,817	 	 	 	(771	)	 	 	2,817	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Total trading revenue, net	 	 	20,443	 	 	 	9,046	 	 	 	20,443	 	 	 	9,046	 	
 	Other revenue	 	 	9,055	 	 	 	4,558	 	 	 	9,055	 	 	 	4,558	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	
 	 	 	Total revenue	 	 	2,186,277	 	 	 	1,332,535	 	 	 	1,178,860	 	 	 	779,896	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	
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				Non-GAAP Netted	
		GAAP Presentation		Presentation	
		Three Months Ended		Three Months Ended	
		March 31,		March 31,	
					
		2003		2002		2003		2002	
									
				Restated(1)					
			
		(In thousands)	
Cost of revenue:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	Electric generation and marketing expense	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Plant operating expense	 	 	164,980	 	 	 	116,474	 	 	 	164,980	 	 	 	116,474	 	
 	 	Royalty expense	 	 	5,357	 	 	 	4,155	 	 	 	5,357	 	 	 	4,155	 	
 	 	Purchased power expense(2)	 	 	679,949	 	 	 	429,235	 	 	 	—	 	 	 	—	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Total electric generation and marketing expense	 	 	850,286	 	 	 	549,864	 	 	 	170,337	 	 	 	120,629	 	
 	Oil and gas production and marketing expense	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Oil and gas production expense	 	 	25,691	 	 	 	21,639	 	 	 	25,691	 	 	 	21,639	 	
 	 	Purchased gas expense(2)	 	 	316,948	 	 	 	121,361	 	 	 	—	 	 	 	—	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Total oil and gas production and marketing expense	 	 	342,639	 	 	 	143,000	 	 	 	25,691	 	 	 	21,639	 	
 	Total fuel expense	 	 	650,236	 	 	 	332,534	 	 	 	639,716	 	 	 	330,491	 	
 	Depreciation, depletion and amortization expense	 	 	134,710	 	 	 	94,969	 	 	 	134,710	 	 	 	94,969	 	
 	Operating lease expense	 	 	27,692	 	 	 	28,141	 	 	 	27,692	 	 	 	28,141	 	
 	Other expense	 	 	6,976	 	 	 	2,591	 	 	 	6,976	 	 	 	2,591	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	
 	 	 	Total cost of revenue	 	 	2,012,539	 	 	 	1,151,099	 	 	 	1,005,122	 	 	 	598,460	 	
 	 	Gross profit	 	$	173,738	 	 	$	181,436	 	 	$	173,738	 	 	$	181,436	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	
 	 	Gross profit margin	 	 	8	%	 	 	14	%	 	 	15	%	 	 	23	%	

		Non-GAAP Netted	
		Presentation	
		Three Months Ended	
		March 31,	
			
		2003		2002	

		(In thousands)	
Other Non-GAAP Performance Metrics	 	 	 	 	 	 	 	 	
Average availability and capacity factor:	 	 	 	 	 	 	 	 	
 	Average availability	 	 	88	%	 	 	89	%	
 	Average capacity factor or operating rate based on total hours (excluding peakers)	 	 	56	%	 	 	71	%	
Average heat rate for gas-fired power plants (excluding peakers) (Btu’s/kWh):	 	 	 	 	 	 	 	 	
 	Not steam adjusted	 	 	7,953	 	 	 	8,173	 	
 	Steam adjusted	 	 	7,227	 	 	 	7,374	 	
Average all-in realized electric price:	 	 	 	 	 	 	 	 	
 	Adjusted Electricity and steam revenue before discontinued operations (in thousands)	 	$	1,123,373	 	 	$	713,216	 	
 	Electricity and steam revenue from discontinued operations	 	 	—	 	 	 	2,493	 	
 	 	 		 	 	 		 	
 	Adjusted electricity and steam revenue (in thousands)	 	 	1,123,373	 	 	 	715,709	 	
 	MWh generated (in thousands)	 	 	19,422	 	 	 	14,714	 	
 	Average all-in realized electric price per MWh	 	$	57.84	 	 	$	48.64	 	
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		Non-GAAP Netted	
		Presentation	
		Three Months Ended	
		March 31,	
			
		2003		2002	

		(In thousands)	
Average cost of natural gas:	 	 	 	 	 	 	 	 	
 	Cost of oil and natural gas burned by power plants (in thousands)	 	$	639,716	 	 	$	330,491	 	
 	Fuel cost elimination	 	 	110,334	 	 	 	17,641	 	
 	Fuel expense from discontinued operations	 	 	—	 	 	 	199	 	
 	 	 		 	 	 		 	
 	Adjusted fuel expense	 	$	750,050	 	 	$	348,331	 	
 	Million Btu’s (“MMBtu”) of fuel consumed by generating plants (in thousands)	 	 	125,243	 	 	 	106,524	 	
 	Average cost of natural gas per MMBtu	 	$	5.99	 	 	$	3.27	 	
 	MWh generated (in thousands)	 	 	19,422	 	 	 	14,714	 	
 	Average cost of oil and natural gas burned by power plants per MWh	 	$	38.62	 	 	$	23.67	 	
Equity gas contribution margin:	 	 	 	 	 	 	 	 	
 	Oil and gas production sales	 	 	25,989	 	 	 	53,076	 	
 	Add: Fuel cost eliminated in consolidation	 	 	110,334	 	 	 	17,641	 	
 	 	 		 	 	 		 	
 	 	Subtotal	 	 	136,323	 	 	 	70,717	 	
 	Less: Oil and gas production expense	 	 	25,691	 	 	 	21,639	 	
 	Less: Depletion, depreciation and amortization	 	 	39,326	 	 	 	35,636	 	
 	Equity gas contribution margin	 	 	71,306	 	 	 	13,442	 	
 	MWh generated (in thousands)	 	 	19,422	 	 	 	14,714	 	
 	Equity gas contribution margin per MWh	 	 	3.67	 	 	 	0.91	 	
Average spark spread:	 	 	 	 	 	 	 	 	
 	Adjusted electricity and steam revenue (in thousands)	 	$	1,123,373	 	 	$	715,709	 	
 	Less: Adjusted fuel expense (in thousands)	 	$	750,050	 	 	$	348,331	 	
 	 	 		 	 	 		 	
 	 	Spark spread (in thousands)	 	$	373,323	 	 	$	367,378	 	
 	MWh generated (in thousands)	 	 	19,422	 	 	 	14,714	 	
 	Average spark spread per MWh	 	$	19.22	 	 	$	24.97	 	
 	Add: Equity gas contribution	 	 	71,306	 	 	 	13,442	 	
 	Spark spread with equity gas benefits (in thousands)	 	 	444,629	 	 	 	380,820	 	
 	Average spark spread with equity gas benefits per MWh	 	 	22.89	 	 	 	25.88	 	
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      The non-GAAP presentation above also facilitates a look at the total “trading” activity impact on gross profit. For the three months ended March 31, 2003 and 2002, trading revenue, net consisted of (dollars in thousands): 

					
				Three Months Ended	
				March 31,	
					
				2003		2002	
		  					
						Restated(1)	
ELECTRICITY	 	 	 	 	 	 	 	 	 	 	
Realized gain (loss)	 	Realized revenue on power trading transactions, net	 	$	14,836	 	 	$	157	 	
Unrealized	 	Unrealized mark-to-market gain (loss)on power transactions, net	 	 	(4,907	)	 	 	4,167	 	
 	 	 	 	 		 	 	 		 	
Subtotal	 	$	9,929	 	 	$	4,324	 	
 	 	 		 	 	 		 	
GAS	 	 	 	 	 	 	 	 	 	 	
Realized gain (loss)	 	Realized revenue on gas trading transactions, net	 	$	6,378	 	 	$	6,072	 	
Unrealized	 	Unrealized mark-to-market gain (loss)on gas transactions, net	 	 	4,136	 	 	 	(1,350	)	
 	 	 	 	 		 	 	 		 	
Subtotal	 	$	10,514	 	 	$	4,722	 	

		Three Months				Three Months			
		Ended				Ended			
		March 31,		Percent of		March 31,		Percent of	
		2003		Gross Profit		2002		Gross Profit	
									
						Restated(1)			
Total trading activity gain (loss)	 	$	20,443	 	 	 	12	%	 	$	9,046	 	 	 	5	%	
Realized gain	 	$	21,214	 	 	 	12	%	 	$	6,229	 	 	 	3	%	
Unrealized (mark-to-market) gains (loss)(3)	 	$	(771	)	 	 	0	%	 	$	2,817	 	 	 	2	%	

		
(1) 	See Note 2 of the Notes to Consolidated Condensed Financial Statements regarding the restatement of financial statements.	
 		
(2) 	For the three months ended March 31, 2003 and 2002, the mark-to-market gains shown above as “trading” activity include hedge ineffectiveness as discussed in Note 8 of the Notes to Consolidated Condensed Financial Statements.	
 		
(3) 	Following is a reconciliation of GAAP to non-GAAP presentation further to the narrative set forth under this Performance Metrics section: ($ in thousands)	
 	 	 	 	 	 	 	 	 	 	 	 	 	
				To Net			
				Hedging,			
				Balancing &		Netted	
		GAAP		Optimization		Non-GAAP	
		Balance		Activity		Balance	
							
Three months ended March 31, 2003	 	 	 	 	 	 	 	 	 	 	 	 	
Electricity and steam revenue	 	$	1,122,038	 	 	$	1,335	 	 	$	1,123,373	 	
Sales of purchased power	 	 	681,284	 	 	 	(681,284	)	 	 	—	 	
Sales of purchased gas	 	 	327,468	 	 	 	(327,468	)	 	 	—	 	
Purchased power expense	 	 	679,949	 	 	 	(679,949	)	 	 	—	 	
Purchased gas expense	 	 	316,948	 	 	 	(316,948	)	 	 	—	 	
Fuel expense	 	 	650,236	 	 	 	(10,520	)	 	 	639,716	 	
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				To Net			
				Hedging,			
				Balancing &		Netted	
		GAAP		Optimization		Non-GAAP	
		Balance		Activity		Balance	
							
Three months ended March 31, 2002, Restated(1)	 	 	 	 	 	 	 	 	 	 	 	 	
Electricity and steam revenue	 	$	622,400	 	 	$	90,816	 	 	$	713,216	 	
Sales of purchased power	 	 	520,051	 	 	 	(520,051	)	 	 	—	 	
Sales of purchased gas	 	 	123,404	 	 	 	(123,404	)	 	 	—	 	
Purchased power expense	 	 	429,235	 	 	 	(429,235	)	 	 	—	 	
Purchased gas expense	 	 	121,361	 	 	 	(121,361	)	 	 	—	 	
Fuel expense	 	 	332,534	 	 	 	(2,043	)	 	 	330,491	 	

		
(1) 	See Note 2 of the Notes to Consolidated Condensed Financial Statements regarding the restatement of financial statements.	
Overview

	Summary of Key Activities	

	Power Plant Development and Construction:	
 	 	 	 	 	 	 	
Date		Project		Description	
					
 	1/03	 	 	Goose Haven Energy Center	 	Commercial Operation	
 	1/03	 	 	Lambie Energy Center	 	Commercial Operation	
 	1/03	 	 	Creed Energy Center	 	Commercial Operation	
 	3/03	 	 	Los Esteros Energy Center	 	Commercial Operation	
 	3/03	 	 	Wolfskill Energy Center	 	Commercial Operation	

	Finance	
 	 	 	 	 	 	 	
Date		Amount		Description	
					
 	2/13/03	 	 	Cdn$153.3 million (US$100.9 million)	 	Completion of secondary offering of 17,034,234 warranted units of the Calpine Power Income Fund.	

	Turbine Restructuring Program:	
 	 	 	 	 	 	 	
Date of					
Announcement		Reduction in Capital Spending		Earnings Effect	
					
 	2/11/03	 	 	$3.4 billion	 	Pre-tax charge of approximately $207.4 million in the quarter ended December 31, 2002	
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	Other:	
 	 	 	
Date		Description	
			
1/7/03	 	Announced that we entered into power purchase and sales agreements with the Pacific Gas and Electric Company and the State of California Department of Water Resources. The agreements call for the delivery of 110 megawatts of on-peak and up to 55 megawatts of off-peak geothermal power.	
1/21/03	 	Calpine and the Long Island Power Authority announced that they will enter into a 16-year power purchase and sale agreement related to an 80-megawatt expansion of our existing cogeneration facility located on the campus of the State University of New York at Stony Brook.	
1/27/03	 	Announced that we have entered into a three-year power purchase agreement with Nevada Power Company, a subsidiary of Sierra Pacific Resources. The arrangement calls for the delivery of 100 megawatts of on-peak and 50 megawatts of off-peak power.	
2/26/03	 	Announced that the Federal Energy Regulatory Commission (“FERC”) has approved a Reliability Must-Run (“RMR”) Settlement Agreement, which applies to 13 of our 19 geothermal power plants located at The Geysers geothermal resource area in Northern California	
3/17/03	 	Announced that we have entered into a long-term power sales agreement with Southern California Edison (“SCE”) calling for the delivery of 200 megawatts of baseload renewable energy.	
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 and under Section 206 of the Federal Power Act alleging, among other things, that the markets operated by the California Independent System Operator (“CAISO”) and the California Power Exchange (“CalPX”) were dysfunctional. In addition to commencing an inquiry regarding the market structure, FERC established a refund effective period of October 2, 2000, to June 19, 2001, for sales made into those markets.
      On December 12, 2002, the Administrative Law Judge issued a Certification of Proposed Finding on California Refund Liability (“December 12 Certification”) making an initial determination of refund liability. On March 26, 2003, FERC also issued an order adopting many of the ALJ’s findings set forth in the December 12 Certification (the “March 26 Order”). In addition, as a result of certain findings by the FERC staff concerning the unreliability or misreporting of certain reported indices for gas prices in California during the refund period, FERC ordered that the basis for calculating a party’s potential refund liability be modified by substituting a gas proxy price based upon gas prices in the producing areas plus the tariff transportation rate for the California gas price indices previously adopted in the refund proceeding. 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 Calpine. 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. The final outcome of this proceeding and the impact on our business is uncertain at this time.
      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
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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. 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 potentially be in violation of the CAISO’s or CalPX’ tariff. The Final Report also recommended that FERC modify the basis for determining potential liability in the California Refund Proceeding discussed above. On June 25, 2003, FERC issued a number of orders associated with these investigations. In particular, based on the FERC staff’s earlier recommendations in the Final Report, FERC issued two show cause orders each naming certain industry participants. The show cause orders have initiated proceedings wherein the named parties must demonstrate that certain market behavior did not violate either the CAISO or CalPX tariffs as prohibited market manipulative behavior. FERC did not subject Calpine to either of the show cause orders. FERC also issued an order directing the FERC staff to investigate further whether market participants who bid a price in excess of $250 per megawatt hour into markets operated 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.
Financial Market Risks
      Because 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, 2003 through March 31, 2003, is summarized in the table below (in thousands): 

Fair value of contracts outstanding at January 1, 2003.	 	$	150,627	 	
Gains recognized or otherwise settled during the period(1)	 	 	(46,562	)	
Changes in fair value attributable to changes in valuation techniques and assumptions	 	 	—	 	
Changes in fair value attributable to new contracts	 	 	896	 	
Changes in fair value attributable to price movements	 	 	59,011	 	
Terminated derivatives(2)	 	 	(55,829	)	
 	 	 		 	
Fair value of contracts outstanding at March 31, 2003(3)	 	$	108,143	 	

		
(1) 	Recognized gains from commodity cash flow hedges of $25.3 million, excluding recognized gains and losses from terminated hedges, consisting of realized gains on power derivatives of $60.1 million and realized losses on natural gas and crude oil derivatives of $85.4 million, are reported in Note 8 of the Notes to Consolidated Condensed Financial Statements and $21.2 million realized gain on trading activity is reported in the Statement of Operations under trading revenue, net.	
 		
(2) 	Includes the value of derivatives terminated or settled before their scheduled maturity and the value of commodity financial instruments that ceased to qualify as derivative instruments.	
 		
(3) 	Net commodity derivative assets reported in Note 8 of the Notes to Consolidated Condensed Financial Statements	
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      The fair value of outstanding derivative commodity instruments at March 31, 2003, based on price source and the period during which the instruments will mature, are summarized in the table below (in thousands): 

Fair Value Source		2003		2004-2005		2006-2007		After 2007		Total	
											
Prices actively quoted	 	$	138,313	 	 	$	21,090	 	 	$	—	 	 	$	—	 	 	$	159,403	 	
Prices provided by other external sources	 	 	(56,894	)	 	 	12,000	 	 	 	19,334	 	 	 	—	 	 	 	(25,560	)	
Prices based on models and other valuation methods	 	 	102	 	 	 	(4,651	)	 	 	(8,904	)	 	 	(12,247	)	 	 	(25,700	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Total fair value	 	$	81,521	 	 	$	28,439	 	 	$	10,430	 	 	$	(12,247	)	 	$	108,143	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
      Our risk managers maintain fair value price information derived from various sources in our risk management systems. The propriety of that information is validated by our Risk Control group. Prices actively quoted include validation with prices sourced from commodities exchanges (e.g., New York Mercantile Exchange). Prices provided by other external sources include quotes from commodity brokers and electronic trading platforms. Prices based on models and other valuation methods are validated using quantitative methods.
      The counterparty credit quality associated with the fair value of outstanding derivative commodity instruments at March 31, 2003, and the period during which the instruments will mature are summarized in the table below (in thousands): 

Credit Quality											
(based on April 18, 2003, ratings)		2003		2004-2005		2006-2007		After 2007		Total	
											
Investment grade	 	$	64,475	 	 	$	20,926	 	 	$	16,644	 	 	$	(18,514	)	 	$	83,531	 	
Non-investment grade	 	 	26,156	 	 	 	10,132	 	 	 	(5,938	)	 	 	6,333	 	 	 	36,683	 	
No external ratings	 	 	(9,110	)	 	 	(2,619	)	 	 	(276	)	 	 	(66	)	 	 	(12,071	)	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
Total fair value	 	$	81,521	 	 	$	28,439	 	 	$	10,430	 	 	$	(12,247	)	 	$	108,143	 	
 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
      The fair value of outstanding derivative commodity instruments and the fair value that would be expected after a ten percent adverse price change are shown in the table below (in thousands): 

				Fair Value	
				After 10%	
				Adverse	
		Fair Value		Price Change	
					
At March 31, 2003:	 	 	 	 	 	 	 	 	
 	Crude oil	 	$	(2,373	)	 	$	(2,706	)	
 	Electricity	 	 	(20,934	)	 	 	(116,368	)	
 	Natural gas	 	 	131,450	 	 	 	9,274	 	
 	 	 		 	 	 		 	
 	 	Total	 	$	108,143	 	 	$	(109,800	)	
 	 	 		 	 	 		 	
      Derivative commodity instruments included in the table are those included in Note 8 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
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portfolio would typically change by more than ten percent for earlier forward months and less than ten percent for later forward months because of the higher volatilities in the near term and the effects of discounting expected future cash flows.
      The primary factors affecting the fair value of our derivatives at any point in time are (1) the volume of open derivative positions (MMBtu and MWh), and (2) changing commodity market prices, principally for electricity and natural gas. The total volume of open gas derivative positions decreased 7% from December 31, 2002, to March 31, 2003, and the total volume of open power derivative positions decreased 7% 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, 2003, 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, 2003, have reflected this. See Notes 8 and 9 of the Notes to Consolidated Condensed Financial Statements for additional information on derivative activity and OCI.
      Collateral Debt Securities  — The King City operating lease commitment is supported by collateral debt securities that mature serially in amounts equal to a portion of the semi-annual lease payment. We have the ability and intent to hold these securities to maturity, and as a result, we do not expect a sudden change in market interest rates to have a material affect on the value of the securities at the maturity date. The securities are recorded at an amortized cost of $83.3 million at March 31, 2003. The following tables present our different classes of collateral debt securities by face value expected maturity date and also by fair market value as of March 31, 2003, (dollars in thousands): 

		Weighted															
		Average															
		Interest Rate		2003		2004		2005		2006		2007		Thereafter		Total	
																	
Corporate Debt Securities	 	 	7.2	%	 	$	2,015	 	 	$	6,050	 	 	$	7,825	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	15,890	 	
U.S. Treasury Notes	 	 	6.5	%	 	 	—	 	 	 	—	 	 	 	1,975	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	1,975	 	
U.S. Treasury Securities (non-interest bearing)	 	 	—	 	 	 	2,065	 	 	 	—	 	 	 	—	 	 	 	9,700	 	 	 	9,100	 	 	 	96,150	 	 	 	117,015	 	
 	 	 	 	 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	 	 		 	
 	Total	 	 	 	 	 	$	4,080	 	 	$	6,050	 	 	$	9,800	 	 	$	9,700	 	 	$	9,100	 	 	$	96,150	 	 	$	134,880	 	

		Fair Market Value	
			
Corporate Debt Securities	 	$	16,927	 	
U.S. Treasury Notes	 	 	2,197	 	
U.S. Treasury Securities (non-interest bearing)	 	 	82,755	 	
 	 	 		 	
 	Total	 	$	101,879	 	
 	 	 		 	
      Interest Rate Swaps and Cross Currency Swaps  — From time to time, we use interest rate swap and cross currency swap agreements to mitigate our exposure to interest rate and currency fluctuations associated with certain of our debt instruments. We do not use interest rate swap and currency swap agreements for speculative or trading purposes. In regards to foreign currency denominated senior notes, the swap notional amounts equal the amount of the related principal debt. The following tables summarize the fair market
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values of our existing interest rate swap and currency swap agreements as of March 31, 2003, (dollars in thousands):
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
		Weighted Average		Weighted Average					
		Notional		Interest Rate				Fair Market	
Maturity Date		Principal Amount		(Pay)		Interest Rate (Receive)		Value	
									
2008	 	$	95,866	 	 	 	4.2	%	 	 	(1)	 	 	$	(5,543	)	
2011	 	 	46,599	 	 	 	6.9	%	 	 	3-month US $LIBOR	 	 	 	(7,513	)	
2012	 	 	114,597	 	 	 	6.5	%	 	 	3-month US $LIBOR	 	 	 	(19,145	)	
2014	 	 	63,451	 	 	 	6.7	%	 	 	3-month US $LIBOR	 	 	 	(10,095	)	
 	 	 		 	 	 	 	 	 	 	 	 	 	 		 	
 	Total	 	$	320,513	 	 	 	5.9	%	 	 	 	 	 	$	(42,296	)	

		
(1) 	1-month US $ LIBOR until July 2003. 3-month US $ LIBOR thereafter.	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
						Frequency of			
				Fixed Currency		Fixed Currency		Fair Market	
Maturity Date		Notional Principal		Exchange		Exchange		Value	
									
		(Pay/Receive)		(Pay/Receive)					
2007	 	 	US $127,763/	 	 	 	US $5,545/	 	 	 	Semi-annually	 	 	$	1,179	 	
 	 	 	Cdn $200,000	 	 	 	Cdn $8,750	 	 	 	 	 	 	 	 	 	
      Debt financing  — Because of the significant capital requirements within our industry, debt financing is often needed to fund our growth. Certain debt instruments may effect 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; (2) Other variable-rate instruments. Significant LIBOR increases could have a negative impact on our future interest expense. Our variable-rate construction/ project financing is primarily through two separate credit agreements, Calpine Construction Finance Company L.P. and Calpine Construction Finance Company II, LLC. Borrowings under these credit agreements 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 different LIBOR rates.
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      The following table summarizes our variable-rate debt exposed to interest rate risk as of March 31, 2003 (dollars in thousands): 

		Outstanding		Weighted Average Interest		Fair Market	
		Balance		Rate		Value	
							
Variable-rate construction/ project financing and other variable-rate instruments:	 	 	 	 	 	 	 	 	 	 	 	 	
Short-term	 	 	 	 	 	 	 	 	 	 	 	 	
 	Calpine Construction Finance Company L.P (due 2003)	 	$	970,110	 	 	 	1-month US $LIBOR	 	 	$	970,110	 	
 	Corporate revolving line of credit	 	 	340,000	 	 	 	1-month US $LIBOR	 	 	 	340,000	 	
 	Siemens Westinghouse Power Corporation	 	 	185,569	 	 	 	6-month US $LIBOR	 	 	 	185,569	 	
 	 	 		 	 	 	 	 	 	 		 	
 	 	Total short-term	 	$	1,495,679	 	 	 	 	 	 	$	1,495,679	 	
 	 	 		 	 	 	 	 	 	 		 	
Long-term	 	 	 	 	 	 	 	 	 	 	 	 	
 	Blue Spruce Energy Center Project financing	 	$	93,620	 	 	 	1-month US $LIBOR	 	 	$	93,620	 	
 	Term loan due (due 2004)	 	 	949,565	 	 	 	3-month US $LIBOR	 	 	 	949,565	 	
 	Calpine Construction Finance Company II, LLC (due 2004)	 	 	2,468,784	 	 	 	1-month US $LIBOR	 	 	 	2,468,784	 	
 	 	 		 	 	 	 	 	 	 		 	
 	 	Total long-term	 	$	3,511,969	 	 	 	 	 	 	$	3,511,969	 	
 	 	 		 	 	 	 	 	 	 		 	
Total variable-rate construction/ project financing and other variable-rate instruments	 	$	5,007,648	 	 	 	 	 	 	$	5,007,648	 	
 	 	 		 	 	 	 	 	 	 		 	
      Construction/ project financing facilities  — In November 2003 and November 2004, respectively, our $1.0 billion and $2.5 billion, secured construction financing revolving facilities will mature, requiring us to refinance or extend this indebtedness. We remain confident that we will have the ability to refinance or extend this indebtedness as it matures, but recognize that this is dependent, in part, on market conditions that are difficult to predict.
      Revolving credit and term loan facilities  — At March 31, 2003, we had $949.6 million in funded borrowings outstanding under the term loan, which matures in May 2004. Additionally we had $340.0 million in funded borrowings outstanding and $519.5 million in outstanding letters of credit under the revolving credit facilities, of which $185.9 million of the letters of credit were issued in support of financial arrangements either reflected on the balance sheet or associated with leased assets or obligations of partially-owned subsidiaries. In May 2003 our $950 million secured working capital revolving credit facilities matured; however, we reached agreement with the bank group on a term sheet for a new, two-year, $950 million secured working capital revolver. This agreement provides us with an automatic extension of the current maturity date for our existing $950 million revolving credit facilities to July 16, 2003. This extension is expected to allow us and our banks sufficient time to complete definitive documentation. We extended the termination date of our letters of credit under the $570 million secured revolving credit facility from May 2003 through dates up to May 2004.
New Accounting Pronouncements
      In June 2001 the FASB issued SFAS No. 143 “Accounting for Asset Retirement Obligations.” SFAS No. 143 applies to fiscal years beginning after June 15, 2002, and amends SFAS No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies.” This standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development or normal use of the assets and requires that a liability for an asset retirement obligation be recognized when incurred, recorded at fair value and classified as a liability in the balance sheet. When the liability is initially recorded, the entity will capitalize the cost and increase the carrying value of the related long-lived asset. Asset retirement obligations represent future liabilities, and, as a result, accretion expense will be accrued on this liability until the obligation is satisfied. At the same time, the capitalized cost will be depreciated over the
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estimated useful life of the related asset. At the settlement date, the entity will settle the obligation for its recorded amount or recognize a gain or loss upon settlement.
      We adopted the new rules on asset retirement obligations on January 1, 2003. As required by the new rules, we recorded liabilities equal to the present value of expected future asset retirement obligations at January 1, 2003. We identified obligations related to operating gas-fired power plants, geothermal power plants and oil and gas properties. The liabilities are partially offset by increases in net assets, net of accumulated depreciation, recorded as if the provisions of the Statement had been in effect at the date the obligation was incurred, which for power plants is generally the start of commercial operations for the facility.
      Based on current information and assumptions we recorded an additional long-term liability of $25.9 million, an additional asset within Property, plant and equipment, net of accumulated depreciation, of $26.9 million, and a pre-tax gain to income due to the cumulative effect of a change in accounting principle of $1.0 million. These entries include the effects of the reversal of site dismantlement and restoration costs previously expensed in accordance with SFAS No. 19.
      In June 2002 the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities,” which addresses accounting for restructuring and similar costs. SFAS No. 146 supersedes previous accounting guidance, principally EITF Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (Including Certain Costs Incurred in a Restructuring).” We have adopted, effective January 1, 2003, the provisions of SFAS No. 146 for restructuring activities initiated after December 31, 2002. SFAS No. 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. Under EITF No. 94-3, a liability for an exit cost was recognized at the date of commitment to an exit plan. SFAS No. 146 also establishes that the liability should initially be measured and recorded at fair value. Accordingly, SFAS No. 146 may affect the timing of recognizing future restructuring costs as well as the amounts recognized. SFAS No. 146 has not had a material impact on our Consolidated Condensed Financial Statements.
      In November 2002 the FASB issued Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (“FIN 45”). This Interpretation addresses the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees. In addition, the Interpretation clarifies the requirements related to the recognition of a liability by a guarantor at the inception of a guarantee for the obligations that the guarantor has undertaken in issuing the guarantee. We adopted the disclosure requirements of FIN 45 for the fiscal year ended December 31, 2002, and the recognition provisions on January 1, 2003. Adoption of this Interpretation did not have a material impact on our Consolidated Condensed Financial Statements.
      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” (“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” (“APB 25”) 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 have 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
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statements. Adoption of SFAS No. 123 has had a material impact on our financial statements. See Note 2 of the Notes to Consolidated Condensed Financial Statements for more information.
      In January 2003 the FASB issued FIN 46, “Consolidation of Variable Interest Entities — an Interpretation of ARB No. 51.” FIN 46 establishes accounting reporting and disclosure requirements for companies that currently hold unconsolidated investments in Variable Interest Entities (“VIEs”). FIN 46 defines VIEs as entities that meet one or both of two criteria: 1. the entity’s total equity at risk is deemed to be insufficient to finance its ongoing business activities without additional subordinated financial support from other parties, and/or, 2. as a collective group, the entity’s owners do not have a controlling financial interest in the entity, which effectively occurs if the voting rights to, or the entitlement to future returns or risk of future losses from the investment for each of the entity’s owners is inconsistent with the ownership percentages assigned to each owner within the underlying partnership agreement. If an investment is determined to be a VIE, further analysis must be performed to determine which of the VIE’s owners qualifies as the primary beneficiary. The primary beneficiary is the owner of the VIE that is entitled or at risk to earn or absorb the majority of the entity’s expected future returns or losses. An owner that is determined to be the primary beneficiary of a VIE is required to consolidate the VIE into its financial statements, as well as to provide certain disclosures regarding the size and nature of the VIE, the purpose for the investment, and information about the assets being held as collateral on behalf of the VIE. Additionally, the remaining owners of a VIE that do not qualify as the primary beneficiary must determine whether or not they hold significant variable interests within the VIE. An owner with a significant variable interest in a VIE that is not the primary beneficiary is not required to consolidate the VIE but must provide certain disclosures regarding the size and nature of the VIE, the purpose for the investment, its potential exposure to the VIE’s losses, and the date it first acquired ownership in the VIE. FIN 46 applies immediately to VIEs created or acquired after January 31, 2003. It applies in the first fiscal year or interim period beginning after June 15, 2003, to VIEs that were previously created or acquired before February 1, 2003. FIN 46 has not had a material impact on our Consolidated Condensed Financial Statements, as no VIEs were created during the first quarter of 2003. We have not completed our assessment of the impact of FIN 46 for VIE relationships prior to December 31, 2002.
      Certain of our power sales contracts use a CPI or similar index for escalating the O&M, and sometimes the capacity, component of the pricing. Under SFAS No. 133: Accounting for Derivative Instruments and Hedging Activities and Derivatives Implementation Group (“DIG”) Issue No. C11, the normal purchase and sales exemption is not available if an index is used that is not clearly and closely related to the asset to be delivered under the contract. In April of 2003 the FASB proposed an amendment to DIG Issue No. C11. The intent of this proposed amendment is to clarify the application of the clearly and closely related criterion with respect to the usage of broad based indices in the pricing of long-term contracts. The proposed amendment will be effective for the first day of the first fiscal quarter beginning after July 10, 2003. We are still evaluating the impact of this proposed accounting standard.
      In April 2003 the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” SFAS No. 149 amends and clarifies financial reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities under SFAS No. 133. SFAS No. 149 clarifies under what circumstances a contract with an initial net investment meets the characteristic of a derivative, clarifies when a derivative contains a financing component, amends the definition of an underlying to conform it to language used in FIN 45, and amends certain other existing pronouncements. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003, and should be applied prospectively, with the exception of certain SFAS No. 133 implementation issues that were effective for all fiscal quarters prior to June 15, 2003. Any such implementation issues should continue to be applied in accordance with their respective effective dates. We do not believe that SFAS No. 149 will have a material impact on our financial statements.
      In May 2003 the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity”. SFAS No. 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. SFAS No. 150 applies specifically to a number of financial instruments that companies have historically presented within their financial statements either as equity or between the liabilities section and the equity
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section, rather than as liabilities. SFAS 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. We have not completed our assessment of the impact of SFAS No. 150.
      In June 2003, the FASB issued 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.” DIG Issue No. C20 superseded DIG Issue No. C11 “Interpretation of Clearly and Closely Related in Contracts That Qualify for the Normal Purchases an Normal Sales Exception” and specified additional circumstances in which a price adjustment feature in a derivative contract would not be an impediment to qualifying for the normal purchases and normal sales scope exception under SFAS No. 133. DIG Issue No. C20 is effective as of the first day of the fiscal quarter beginning after July 10, 2003, (i.e. October 1, 2003, for Calpine) with early application permitted. It should be applied prospectively for all existing contracts as of the effective date and for all future transactions. In conjunction with initially applying the implementation guidance, DIG Issue No. C20 requires the recognition of a special transition adjustment for certain contracts containing a price adjustment feature based on a broad market index for which the normal purchases and normal sales scope exception had been previously elected. In those circumstances, the derivative contract should be recognized at fair value as of the date of the initial application with a corresponding adjustment of net income as the cumulative effect of a change in accounting principle.
      Certain of our power sales contracts, which meet the definition of a derivative and for which we previously elected the normal purchases and normal sales scope exception, use a CPI or similar index to escalate the O&M charges. Accordingly, DIG Issue No. C20 will require us to record a special transition accounting adjustment upon adoption of the new guidance to record these contracts at fair value with a corresponding adjustment to net income as the effect of a change in accounting principle. The fair value of these contracts will be based in large part on the nature and extent of the key price adjustment features of the contracts and market conditions on date of adoption, such as the forward price of power and natural gas and the expected future rate of inflation. Although the final amount of the adjustment, if any, will not be known until actual adoption of DIG Issue No. C20, based upon contract values as of June 26, 2003, we estimate that we will recognize derivative assets of approximately $360 million, derivative liabilities of approximately $90 million and cumulative effect adjustment to net income of approximately $200 million, net of tax. Assuming the contracts meet the new conditions for qualifying for the normal purchases and normal sales exception and we make that election, the recorded balance for these contracts would reverse through charges to income over the life of the long term contracts, which extend out as far as the year 2020, as deliveries of power are made. To the extent any contract fails to meet the new requirements in DIG Issue No. C20 or we do not elect the scope exception, we would be required to recognize subsequent changes in the fair value of those contracts in earnings each period. We anticipate that we will adopt DIG Issue No. C20 on October 1, 2003. Upon adoption of DIG Issue No. C20, we expect, subject to further analysis, that most of our structured power sales contracts will meet the criteria for the normal purchases and sales exception under SFAS No. 133 and that we will make that election. 
Item 3.      Quantitative and Qualitative Disclosures About Market Risk.
      See “Financial Market Risks” in Item 2. 
Item 4.      Controls and Procedures
      The Company’s senior management, including the Company’s Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the Company’s disclosure controls and procedures within 90 days of the filing date of this quarterly report. Based upon this evaluation, the Company’s Chairman, President and Chief Executive Officer along with the Company’s Executive Vice President and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective in ensuring that material information required to be disclosed is included in the reports that it files with the Securities and Exchange Commission. There were no significant changes in the Company’s internal controls or, to the knowledge of the management of the Company, in other factors that could significantly affect these controls
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subsequent to the evaluation date. The certificates required by this item are filed as a part of this Form 10-Q. See Certifications.
PART II — OTHER INFORMATION 
Item 1.      Legal Proceedings.
      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 in each case presently be reasonably estimated. 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, these matters may potentially be material to the Company’s Consolidated Condensed Financial Statements.
      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 the California Superior Court, San Diego County. The underlying allegations in the Hawaii Structural Ironworkers Pension Fund action (“Hawaii action”) are substantially the same as the federal securities class actions described in the Company’s previous filings. However, the Hawaii action is brought on behalf of a purported class of purchasers of the Company’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 the Company’s financial condition in violation of Sections 11, 12 and 15 of the Securities Act of 1933. The Hawaii action relies in part on the Company’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 considers this lawsuit to be without merit and intends to defend vigorously against it. The Company has sought to have the Hawaii action removed to federal court and transferred for consolidation with the other securities class action lawsuits in the U.S. District Court Northern District Court of California.
      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. The underlying allegations in this action (“Phelps action”) are substantially the same as those in the above-referenced securities class actions. 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 the 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 Shareholder relief. 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 the Company against its directors and one if its senior officers. This lawsuit is captioned Johnson v. Cartwright, et al. and is pending in the California Superior Court, Santa Clara County. The Company is a nominal defendant in this lawsuit, which alleges claims relating to purportedly misleading statements about 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 the plaintiff may appeal this ruling. In early February 2003 the plaintiff filed an amended complaint. 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 lawsuit 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 the plaintiff agreed to stay these
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proceedings in favor of the consolidated federal securities class action described above and to dismiss without prejudice certain director defendants. The Company considers this lawsuit to be without merit and intends to vigorously defend against it.
      California Business & Professions Code Section 17200 Cases. The lead case T&E Pastorino Nursery v. Duke Energy Trading and Marketing, L.L.C., et al. 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 has been named in seven other similar complaints for violations of Section 17200. All seven cases have been 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. In addition, plaintiffs in the case have filed a motion to remand that matter to California state court. The Company considers the allegations against Calpine and its subsidiaries in each of these lawsuits to be without merit, and intends to vigorously defend against them.
      McClintock et al. v. Vikram Budhraja, et al. California Department of Water Resources Case. On May 1, 2002, California State Senator Tom McClintock and others filed a complaint against Vikram Budhraja, a consultant to the California Department of Water Resources (“DWR”), DWR itself, and more than twenty-nine energy providers and other interested parties, including Calpine. The complaint alleges that the long-term power contracts that DWR entered into with these energy providers, including Calpine, are rendered void because Budhraja, who negotiated the contracts on behalf of the DWR, allegedly had an undisclosed financial interest in the contracts due to his connection to one of the energy providers, Edison International. Among other things, the complaint seeks an injunction prohibiting further performance of the long-term contracts and restitution of any funds paid to energy providers by the State of California under the contracts. The action has been stayed by order of the Court since August 26, 2002, pending resolution of an earlier-filed state court action involving the same parties and subject matter captioned Carboneau v. State of California in which the Company is not a defendant. The Company considers the allegations against it in this lawsuit to be without merit and intends to vigorously defend against them.
      Calpine Corporation v. Automated Credit Exchange. On March 5, 2002, the Company sued Automated Credit Exchange (“ACE”) in the Superior Court of the State of California for the County of Alameda for negligence and breach of contract to recover reclaim trading credits, a form of emission reduction credits that should have been held in the Company’s account with U.S. Trust Company (“US Trust”). 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 the Company of $7 million and transferred to the Company the rights to the emission reduction credits to be held by ACE. The Company recognized the $7 million in the second quarter of 2002. In June 2002 a complaint was filed by InterGen North America, L.P. (“InterGen”) against Anne M. Sholtz, the owner of ACE, and EonXchange, another Sholtz-controlled entity, which filed for bankruptcy protection on May 6, 2002. InterGen alleges it suffered a loss of emission reduction credits from EonXchange in a manner similar to the Company’s loss from ACE. InterGen’s complaint alleges that Anne Sholtz co-mingled assets among ACE, EonXchange and other Sholtz entities and that ACE and other Sholtz entities should be deemed to be one economic enterprise and all retroactively included in the EonXchange bankruptcy filing as of May 6, 2002. Ann Sholtz recently stipulated to agree to the consolidation of Anne Sholtz, ACE and other Sholtz entities in the EonXchange bankruptcy proceeding. On April 25, 2003, Calpine received a demand from the trustee of the EonXchange estate to return the $7 million payment as a preferential payment. The Company is confident of its valid defenses against this demand and cannot currently assess the likelihood of the demand, or of InterGen’s complaint, being upheld at this time.
      International Paper Company v. Androscoggin Energy LLC. In October 2000 International Paper Company filed a complaint against Androscoggin Energy LLC (“AELLC”) alleging that AELLC breached certain contractual representations and warranties by failing to disclose facts surrounding the termination, effective May 8, 1998, of one of AELLC’s fixed-cost gas supply agreements. The Company had acquired a 32.3% interest in AELLC as part of the SkyGen transaction which closed in October 2000. AELLC filed a counterclaim against International Paper Company that has been referred to arbitration. AELLC may
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commence the arbitration counterclaim after discovery has progressed further, depending on the outcome of the discussions referred to below. On November 7, 2002, the court issued an opinion on the parties’ cross motions for summary judgment finding in AELLC’s favor on certain matters though granting summary judgment to International Paper Company on the liability aspect of a particular claim against AELLC.
      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. The Court has a set schedule for disclosure of expert witness and depositions thereof and has tentatively scheduled the case for trial in the first quarter of 2004.
      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. AELLC has submitted an amended complaint and request for immediate injunctive relief against such actions. The Court heard the motion on April 24, 2003, and ordered that IP must pay the approximate $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 approximate $1.2 million. The Company believes it has adequately reserved for the possible loss, if any, it may ultimately incur as a result of this matter.
      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 the Company. NPC and SPPC allege in their complaint, which seeks a refund, that the prices they agreed to pay in certain of the power sales agreements, including those signed with 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. On June 25, 2003, FERC rejected NPC’s complaint. 

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

Exhibit			
Number		Description	
			
 	*3.1	 	 	Amended and Restated Certificate of Incorporation of Calpine Corporation (a)	
 	*3.2	 	 	Certificate of Correction of Calpine Corporation (b)	
 	*3.3	 	 	Certificate of Amendment of Amended and Restated Certificate of Incorporation of Calpine Corporation (c)	
 	*3.4	 	 	Certificate of Designation of Series A Participating Preferred Stock of Calpine Corporation (b)	
 	*3.5	 	 	Amended Certificate of Designation of Series A Participating Preferred Stock of Calpine Corporation (b)	
 	*3.6	 	 	Amended Certificate of Designation of Series A Participating Preferred Stock of Calpine Corporation (c)	
 	*3.7	 	 	Certificate of Designation of Special Voting Preferred Stock of Calpine Corporation (d)	
 	*3.8	 	 	Certificate of Ownership and Merger Merging Calpine Natural Gas GP, Inc. into Calpine Corporation (e)	
 	*3.9	 	 	Certificate of Ownership and Merger Merging Calpine Natural Gas Company into Calpine Corporation (e)	
 	*3.10	 	 	Amended and Restated By-laws of Calpine Corporation (f)	
 	*10.1	 	 	Second Amended and Restated Credit Agreement (“Second Amended and Restated Credit Agreement”) dated as of May 23, 2000, among the Company, Bayerische Landesbank, as Co-Arranger and Syndication Agent, The Bank of Nova Scotia, as Lead Arranger and Administrative Agent, and the Lenders named therein (g)	
 	*10.2	 	 	First Amendment and Waiver to Second Amended and Restated Credit Agreement, dated as of April 19, 2001, among the Company, The Bank of Nova Scotia, as Administrative Agent, and the Lenders named therein (f)	
 	*10.3	 	 	Second Amendment to Second Amended and Restated Credit Agreement, dated as of March 8, 2002, among the Company, The Bank of Nova Scotia, as Administrative Agent, and the Lenders named therein (f)	
 	*10.4	 	 	Third Amendment to Second Amended and Restated Credit Agreement, dated as of May 9, 2002, among the Company, The Bank of Nova Scotia, as Administrative Agent, and the Lenders named therein (e)	
 	*10.5	 	 	Fourth Amendment to Second Amended and Restated Credit Agreement, dated as of September 26, 2002, among the Company, The Bank of Nova Scotia, as Administrative Agent, and the Lenders named therein (i)	
 	*10.6	 	 	Fifth Amendment to Second Amended and Restated Credit Agreement, dated as of March 12, 2003, among the Company, The Bank of Nova Scotia, as Administrative Agent, and the Lenders named therein (j)	
 	+10.7	 	 	Sixth Amendment to Second Amended and Restated Credit Agreement, dated as of May 23, 2003, among the Company, The Bank of Nova Scotia, as Administrative Agent, and the Lenders named therein	
 	+10.8	 	 	Seventh Amendment to Second Amended and Restated Credit Agreement, dated as of June 16, 2003, among the Company, The Bank of Nova Scotia, as Administrative Agent, and the Lenders named therein	
 	*10.9	 	 	Credit Agreement, dated as of March 8, 2002, among the Company, the Lenders named therein, The Bank of Nova Scotia and Bayerische Landesbank Girozentrale, as lead arrangers and bookrunners, Salomon Smith Barney Inc. and Deutsche Banc Alex. Brown Inc., as lead arrangers and bookrunners, Bank of America, National Association, and Credit Suisse First Boston, Cayman Islands Branch, as lead arrangers and syndication agents, TD Securities (USA) Inc., as lead arranger, The Bank of Nova Scotia, as joint administrative agent and funding agent, and Citicorp USA, Inc., as joint administrative agent (f)	
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Exhibit			
Number		Description	
			
 	*10.10	 	 	First Amendment to Credit Agreement, dated as of May 9, 2002, among the Company, The Bank of Nova Scotia, as Joint Administrative Agent and Funding Agent, Citicorp USA, Inc., as Joint Administrative Agent, and the Lenders named therein (e)	
 	*10.11	 	 	Increase in Term B Loan Commitment Amount Notice, effective as of May 31, 2002, by The Bank of Nova Scotia and Citicorp USA, Inc., as Administrative Agents (y)	
 	+10.12	 	 	Second Amendment to Credit Agreement, dated as of May 23, 2003, among the Company, The Bank of Nova Scotia, as Joint Administrative Agent and Funding Agent, Citicorp USA, Inc., as Joint Administrative Agent, and the Lenders named therein	
 	+10.13	 	 	Third Amendment to Credit Agreement, dated as of June 16, 2003, among the Company, The Bank of Nova Scotia, as Joint Administrative Agent and Funding Agent, Citicorp USA, Inc., as Joint Administrative Agent, and the Lenders named therein	
 	+99.1	 	 	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 Registration Statement on Form S-3 (Registration No. 333-40652), filed with the SEC on June 30, 2000.	
 		
(b) 	Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2000, filed with the SEC on March 15, 2001.	
 		
(c) 	Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3 (Registration No. 333-66078), filed with the SEC on July 27, 2001.	
 		
(d) 	Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated March 31, 2001, filed with the SEC on May 15, 2001.	
 		
(e) 	Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated March 31, 2002, filed with the SEC on May 15, 2002.	

		
(f) 	Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2001, filed with the SEC on March 29, 2002.	

		
(g) 	Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K dated July 25, 2000, filed with the SEC on August 9, 2000.	
 		
(h) 	Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3 (Registration No. 333-76880), filed with the SEC on January 17, 2002.	

		
(i) 	Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated September 30, 2002, filed with the SEC on November 14, 2002.	
 		
(j) 	Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2002, filed with the SEC on March 31, 2003.	

		
(k) 	Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated June 30, 2002, filed with the SEC on August 12, 2002.	
      (b)     Reports on Form 8-K
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      The registrant filed the following reports on Form 8-K during the quarter ended March 31, 2003: 

Date of Report		Date Filed		Item Reported	
					
January 21, 2003	 	January 23, 2003	 	5,7	
January 23, 2003	 	January 24, 2003	 	5,7	
February 11, 2003	 	February 11, 2003	 	5,7	
February 13, 2003	 	February 14, 2003	 	5,9	
March 3, 2003	 	March 4, 2003	 	5,7	
March 12, 2003	 	March 12, 2003	 	5,7	
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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: June 30, 2003

			
 	By: 	/s/ CHARLES B. CLARK, JR.	

 	Charles B. Clark, Jr.	
 	Senior Vice President and Corporate	
 	Controller (Principal Accounting Officer)	
Date: June 30, 2003
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CERTIFICATE OF THE CHAIRMAN, PRESIDENT AND CHIEF EXECUTIVE OFFICER
I, Peter Cartwright, the Chairman, President and Chief Executive Officer of Calpine Corporation, certify that:
      1.     I have reviewed this quarterly report on Form 10-Q of Calpine Corporation (the “registrant”);
      2.     Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;
      3.     Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;
      4.     The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

		
 	      a) Designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;	
 		
 	      b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and	
 		
 	      c) Presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;	
      5.     The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

		
 	      a) All significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and	
 		
 	      b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and	
      6.     The registrant’s other certifying officer and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

		
 	/s/ PETER CARTWRIGHT	
 		
 	Peter Cartwright	
 	Chairman, President and	
 	Chief Executive Officer	
 	Calpine Corporation	
Date: June 30, 2003
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CERTIFICATE OF THE EXECUTIVE VICE PRESIDENT AND CHIEF FINANCIAL OFFICER
I, Robert D. Kelly, the Executive Vice President and Chief Financial Officer of Calpine Corporation, certify that:
      1.     I have reviewed this quarterly report on Form 10-Q of Calpine Corporation (the “registrant”);
      2.     Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;
      3.     Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;
      4.     The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

		
 	      a) Designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;	
 		
 	      b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and	
 		
 	      c) Presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;	
      5.     The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent function):

		
 	      a) All significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and	
 		
 	      b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and	
      6.     The registrant’s other certifying officer and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

		
 	/s/ ROBERT D. KELLY	
 		
 	Robert D. Kelly	
 	Executive Vice President and	
 	Chief Financial Officer	
 	Calpine Corporation	
Date: June 30, 2003
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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(a)	
 	*3.2	 	 	Certificate of Correction of Calpine Corporation(b)	
 	*3.3	 	 	Certificate of Amendment of Amended and Restated Certificate of Incorporation of Calpine Corporation(c)	
 	*3.4	 	 	Certificate of Designation of Series A Participating Preferred Stock of Calpine Corporation(b)	
 	*3.5	 	 	Amended Certificate of Designation of Series A Participating Preferred Stock of Calpine Corporation(b)	
 	*3.6	 	 	Amended Certificate of Designation of Series A Participating Preferred Stock of Calpine Corporation(c)	
 	*3.7	 	 	Certificate of Designation of Special Voting Preferred Stock of Calpine Corporation(d)	
 	*3.8	 	 	Certificate of Ownership and Merger Merging Calpine Natural Gas GP, Inc. into Calpine Corporation(e)	
 	*3.9	 	 	Certificate of Ownership and Merger Merging Calpine Natural Gas Company into Calpine Corporation(e)	
 	*3.10	 	 	Amended and Restated By-laws of Calpine Corporation(f)	
 	*10.1	 	 	Second Amended and Restated Credit Agreement (“Second Amended and Restated Credit Agreement”) dated as of May 23, 2000, among the Company, Bayerische Landesbank, as Co-Arranger and Syndication Agent, The Bank of Nova Scotia, as Lead Arranger and Administrative Agent, and the Lenders named therein(g)	
 	*10.2	 	 	First Amendment and Waiver to Second Amended and Restated Credit Agreement, dated as of April 19, 2001, among the Company, The Bank of Nova Scotia, as Administrative Agent, and the Lenders named therein(f)	
 	*10.3	 	 	Second Amendment to Second Amended and Restated Credit Agreement, dated as of March 8, 2002, among the Company, The Bank of Nova Scotia, as Administrative Agent, and the Lenders named therein(f)	
 	*10.4	 	 	Third Amendment to Second Amended and Restated Credit Agreement, dated as of May 9, 2002, among the Company, The Bank of Nova Scotia, as Administrative Agent, and the Lenders named therein(e)	
 	*10.5	 	 	Fourth Amendment to Second Amended and Restated Credit Agreement, dated as of September 26, 2002, among the Company, The Bank of Nova Scotia, as Administrative Agent, and the Lenders named therein(i)	
 	*10.6	 	 	Fifth Amendment to Second Amended and Restated Credit Agreement, dated as of March 12, 2003, among the Company, The Bank of Nova Scotia, as Administrative Agent, and the Lenders named therein(j)	
 	+10.7	 	 	Sixth Amendment to Second Amended and Restated Credit Agreement, dated as of May 23, 2003, among the Company, The Bank of Nova Scotia, as Administrative Agent, and the Lenders named therein	
 	+10.8	 	 	Seventh Amendment to Second Amended and Restated Credit Agreement, dated as of June 16, 2003, among the Company, The Bank of Nova Scotia, as Administrative Agent, and the Lenders named therein	
68 

Table of Contents

Exhibit			
Number		Description	
			
 	*10.9	 	 	Credit Agreement, dated as of March 8, 2002, among the Company, the Lenders named therein, The Bank of Nova Scotia and Bayerische Landesbank Girozentrale, as lead arrangers and bookrunners, Salomon Smith Barney Inc. and Deutsche Banc Alex. Brown Inc., as lead arrangers and bookrunners, Bank of America, National Association, and Credit Suisse First Boston, Cayman Islands Branch, as lead arrangers and syndication agents, TD Securities (USA) Inc., as lead arranger, The Bank of Nova Scotia, as joint administrative agent and funding agent, and Citicorp USA, Inc., as joint administrative agent(f)	
 	*10.10	 	 	First Amendment to Credit Agreement, dated as of May 9, 2002, among the Company, The Bank of Nova Scotia, as Joint Administrative Agent and Funding Agent, Citicorp USA, Inc., as Joint Administrative Agent, and the Lenders named therein(e)	
 	*10.11	 	 	Increase in Term B Loan Commitment Amount Notice, effective as of May 31, 2002, by The Bank of Nova Scotia and Citicorp USA, Inc., as Administrative Agents (y)	
 	+10.12	 	 	Second Amendment to Credit Agreement, dated as of May 23, 2003, among the Company, The Bank of Nova Scotia, as Joint Administrative Agent and Funding Agent, Citicorp USA, Inc., as Joint Administrative Agent, and the Lenders named therein	
 	+10.13	 	 	Third Amendment to Credit Agreement, dated as of June 16, 2003, among the Company, The Bank of Nova Scotia, as Joint Administrative Agent and Funding Agent, Citicorp USA, Inc., as Joint Administrative Agent, and the Lenders named therein	
 	+99.1	 	 	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 Registration Statement on Form S-3 (Registration No. 333-40652), filed with the SEC on June 30, 2000.	
 		
(b)	Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2000, filed with the SEC on March 15, 2001.	
 		
(c)	Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3 (Registration No. 333-66078), filed with the SEC on July 27, 2001.	
 		
(d)	Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated March 31, 2001, filed with the SEC on May 15, 2001.	
 		
(e)	Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated March 31, 2002, filed with the SEC on May 15, 2002.	
 		
(f)	Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2001, filed with the SEC on March 29, 2002.	
 		
(g)	Incorporated by reference to Calpine Corporation’s Current Report on Form 8-K dated July 25, 2000, filed with the SEC on August 9, 2000.	
 		
(h)	Incorporated by reference to Calpine Corporation’s Registration Statement on Form S-3 (Registration No. 333-76880), filed with the SEC on January 17, 2002.	
 		
(i)	Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated September 30, 2002, filed with the SEC on November 14, 2002.	
 		
(j)	Incorporated by reference to Calpine Corporation’s Annual Report on Form 10-K for the year ended December 31, 2002, filed with the SEC on March 31, 2003.	
 		
(k)	Incorporated by reference to Calpine Corporation’s Quarterly Report on Form 10-Q dated June 30, 2002, filed with the SEC on August 12, 2002.	
69
 
EXHIBIT 10.7
EXECUTION COPY
SIXTH AMENDMENT
SIXTH AMENDMENT, dated as of May 23, 2003 (this "Amendment"), to the Second Amended and Restated Credit Agreement, dated as of May 23, 2000 (as amended, the "Credit Agreement"), among CALPINE CORPORATION, a Delaware corporation (the "Borrower"), the various financial institutions as are or may become parties thereto (the "Lenders") and THE BANK OF NOVA SCOTIA, as administrative agent (in such capacity, the "Agent").
WHEREAS pursuant to the Credit Agreement, the Lenders have made extensions of credit to the Borrower; and
WHEREAS the Borrower has requested that a provision of the Credit Agreement be modified in the manner provided for in this Amendment, and the Lenders are willing to agree to such modification as provided for in this Amendment.
NOW, THEREFORE, the parties hereto hereby agree as follows:
1. Defined Terms. Capitalized terms used and not defined herein shall have the meanings given to them in the Credit Agreement, as amended hereby.
2. Amendment to Credit Agreement. The definition of "Commitment Termination Date" in Section 1.1 of the Credit Agreement is hereby amended by deleting clause (a) thereof in its entirety and by substituting in lieu thereof the following: "(a) June 16, 2003;".
3. Representations and Warranties. The Borrower hereby represents and warrants to the Agent and the Lenders that, as of the date hereof and after giving effect to the amendment contained herein:
(a) No Default or Event of Default has occurred and is continuing.
(b) The execution, delivery and performance by the Borrower of this Amendment has been duly authorized by all necessary corporate and other action and does not and will not require any registration with, consent or approval of, notice to or action by, any person in order to be effective and enforceable. Each of this Amendment and the Credit Agreement as amended by this Amendment constitutes the legal, valid and binding obligation of the Borrower, enforceable against each in accordance with its terms, subject to applicable bankruptcy, insolvency, fraudulent conveyance, reorganization, moratorium or other laws affecting creditors' rights generally and subject to general principles of equity, regardless of whether considered in a proceeding in equity or at law.
(c) All representations and warranties of each Obligor set forth in the Loan Documents as amended hereby are true and correct in all material respects.
4. Covenants. The Borrower hereby agrees that during the period commencing on the date hereof up to and including June 16, 2003 (the "Extension Period"), the Borrower shall not take any action which could, directly or indirectly, have a material adverse effect upon
2
(i) the financial condition, operations, assets (including power projects), business or prospects of the Borrower and its Subsidiaries taken as a whole; or
(ii) the ability of the Borrower or any other Obligor to perform under any Loan Document. Without prejudice to the foregoing, the Borrower shall ensure that, during the Extension Period, (1) no Indebtedness is incurred, created, assumed or suffered to exist by the Borrower or any of its Subsidiaries (except (A) Indebtedness under the Loan Documents and the Loan Documents (as defined in the 2002 Credit Agreement), (B) unsecured Indebtedness incurred in the ordinary course of business, other than Indebtedness of the type described in (1) clauses
(a), (c) or (f) of the definition of "Indebtedness" and (2) clauses (b) and (g) of the definition of "Indebtedness" with respect to any Indebtedness described in clause (1) above, (C) other unsecured Indebtedness or Non-Recourse Debt (as defined in the Senior Note Indentures) incurred in the ordinary course of business in connection with Indebtedness existing or contractually committed to be made available as of the date hereof, and (D) Indebtedness outstanding on the date hereof), and no guarantee, collateral or other credit support is provided, and no Lien on the properties of the Borrower or any of its Subsidiaries is created, incurred, assumed or granted, in each case in support of (x) any Indebtedness (other than Indebtedness permitted above) or (y) any obligation relating to any synthetic lease transaction of the Borrower or any Subsidiary of the Borrower; (2) no amendment, modification or supplement is made to any agreement or instrument evidencing any Indebtedness, other than amendments, modifications or supplements entered into in the ordinary course of business in respect of (A) the Credit Agreement or the 2002 Credit Agreement, (B) any agreement or instrument evidencing Non-Recourse Debt (as defined in the Senior Note Indentures) of a Subsidiary of the Borrower, or (C) any agreement or instrument evidencing Indebtedness other than Indebtedness of the type described in (1) clauses (a), (c) or (f) of the definition of "Indebtedness" and (2) clauses (b) and (g) of the definition of "Indebtedness" with respect to any Indebtedness described in clause (1) above (the Indebtedness described in clauses (B) and (C) being collectively referred to as "Excluded Indebtedness");
(3) no optional prepayment is made on, or purchase or optional redemption is executed of, any Indebtedness other than Excluded Indebtedness (including, without limitation, any buy-back or defeasance of any outstanding bonds, puttable convertible bonds or other securities of the Borrower or any of its Subsidiaries), it being understood and agreed that, during the Extension Period, neither the Borrower or any of its Subsidiaries shall obtain or receive any such Indebtedness (or instruments evidencing same) in consideration of the sale or other transfer of any assets or properties thereof; (4) no Investment is made by the Borrower or any of its Subsidiaries in any other Person (except (A) Investments by the Borrower in the ordinary course of business in Subsidiaries the equity in which has been pledged to the Lenders, and each of their respective Subsidiaries, (B) Investments by the Borrower in other Persons pursuant to contractual commitments existing as of the date hereof, and (C) Investments by the Borrower in CES in support of transactions entered into by CES in the ordinary course of CES's business, consistent with historical practices); and (5) all transactions between any one or more of the Borrower and its Affiliates entered into during the Extension Period are on terms that are fair and reasonable and similar to those found in a comparable arm's length transaction with a Person that is not an Affiliate of the Borrower. Notwithstanding the foregoing, it is agreed that (x) the Borrower and its Subsidiaries may effectuate the transactions referred to in Schedule I attached to the letter from the Borrower to the Lenders dated May 20, 2003 and (y) none of the prohibitions contained in this Section 4 shall be applicable insofar as they would otherwise constitute an encumbrance or restriction in violation of
Section 3.5 of the Pre-2000 Indentures (as defined in the 2002 Credit Agreement). The provisions of this Section 4 may be amended,
3
modified or waived, if such amendment, modification or waiver is in writing and consented to by the Borrower and Lenders owed or holding at least 51% of the aggregate Revolving Loan Commitments and Commitments under the 2002 Credit Agreement and the Credit Agreement, respectively (it being understood, however, that no such amendment, modification or waiver shall amend, modify or waive the provisions of the Credit Agreement unless such amendment, modification or waiver satisfies the requirements of Section 11.1 of the Credit Agreement).
5. Conditions Precedent to Effectiveness. This Amendment shall become effective as of the date hereof upon (i) the Agent having received counterparts hereof duly executed and delivered by the Borrower and each Lender and (ii) the Second Amendment, dated as of the date hereof, to the 2002 Credit Agreement becoming effective in accordance with its terms.
6. No Other Amendments. Except as expressly amended hereby, the provisions of the Credit Agreement are and shall remain in full force and effect.
7. Expenses. The Borrower agrees to pay or reimburse the Agent for its out-of-pocket expenses in connection with this Amendment, including the reasonable fees, charges and disbursements of counsel to the Agent.
8. Governing Law; Counterparts. (a) This Amendment and the rights and obligations of the parties hereto shall be governed by, and construed and interpreted in accordance with, the laws of the State of New York.
(b) This Amendment may be executed by one or more of the parties to this Amendment on any number of separate counterparts, and all of said counterparts taken together shall be deemed to constitute one and the same instrument. This Amendment may be delivered by facsimile transmission of the relevant signature pages hereof.
IN WITNESS WHEREOF, the Borrower and the Lenders have caused this Amendment to be duly executed by their respective authorized officers as of the day and year first above written.
CALPINE CORPORATION

By   /s/ ROBERT D. KELLY
   -----------------------------------------
   Name: Robert D. Kelly
   Title: Chief Financial Officer	

THE BANK OF NOVA SCOTIA, as Agent
and Lender

By   /s/ DENIS P. O'MEARA
   -----------------------------------------
   Name: Denis P. O'Meara
   Title: Managing Director	

Signature page to the Sixth Amendment, dated as of May 23, 2003, to the Second Amended and Restated Credit Agreement, dated as of May 23, 2000, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto and The Bank of Nova Scotia, as administrative agent.
BAYERISCHE LANDESBANK
CAYMAN ISLANDS BRANCH

By   /s/ OLIVER HILDENBRAND
   -----------------------------------------
   Name: Oliver Hildenbrand
   Title: First Vice President

By   /s/ JAMES H. BOYLE
   -----------------------------------------
   Name: James H. Boyle
   Title: Vice President	

Signature page to the Sixth Amendment, dated as of May 23, 2003, to the Second Amended and Restated Credit Agreement, dated as of May 23, 2000, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto and The Bank of Nova Scotia, as administrative agent.
BANK OF AMERICA, NA

By   /s/ EILEEN C. HIGGINS
   -----------------------------------------
   Name: Eileen C. Higgins
   Title: Principal	

Signature page to the Sixth Amendment, dated as of May 23, 2003, to the Second Amended and Restated Credit Agreement, dated as of May 23, 2000, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto and The Bank of Nova Scotia, as administrative agent.
ING CAPITAL LLC

By   /s/ ERWIN THOMET
   -----------------------------------------
   Name: Erwin Thomet
   Title: Managing Director

By   /s/ NICK BELLAMY
   -----------------------------------------
   Name: Nick Bellamy
   Title: Director	

Signature page to the Sixth Amendment, dated as of May 23, 2003, to the Second Amended and Restated Credit Agreement, dated as of May 23, 2000, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto and The Bank of Nova Scotia, as administrative agent.
CIBC INC.

By   /s/ M. SANJEEVA SENANAYAKE
   -----------------------------------------
   Name: M. Sanjeeva Senanayake
   Title: Executive Director	

CIBC World Markets Corp. As Agent
Signature page to the Sixth Amendment, dated as of May 23, 2003, to the Second Amended and Restated Credit Agreement, dated as of May 23, 2000, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto and The Bank of Nova Scotia, as administrative agent.
DRESDNER BANK AG, NEW YORK 
and GRAND CAYMAN BRANCHES

By   /s/ FRED THURSTON
   -----------------------------------------
   Name: Fred Thurston
   Title: Vice President

By   /s/ THOMAS R. BRADY
   -----------------------------------------
   Name: Thomas R. Brady
   Title: Director	

Signature page to the Sixth Amendment, dated as of May 23, 2003, to the Second Amended and Restated Credit Agreement, dated as of May 23, 2000, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto and The Bank of Nova Scotia, as administrative agent.
UNION BANK OF CALIFORNIA, N.A.

By   /s/ BRYAN READ
   -----------------------------------------
   Name: Bryan Read
   Title: Vice President	

Signature page to the Sixth Amendment, dated as of May 23, 2003, to the Second Amended and Restated Credit Agreement, dated as of May 23, 2000, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto and The Bank of Nova Scotia, as administrative agent.
BAYERISCHE HYPO-UND
VEREINSBSBANK, AG, NY BRANCH

By   /s/ PAUL J. COLATRELLA
   -----------------------------------------
   Name: Paul J. Colatrella
   Title: Director

By   /s/ ANDREW G. MATHEWS
   -----------------------------------------
   Name: Andrew G. Mathews
   Title: Managing Director	

Signature page to the Sixth Amendment, dated as of May 23, 2003, to the Second Amended and Restated Credit Agreement, dated as of May 23, 2000, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto and The Bank of Nova Scotia, as administrative agent.
FORTIS CAPITAL CORP.

By   /s/ EDDIE MATTHEWS
   -----------------------------------------
   Name: Eddie Matthews
   Title: Senior Vice President

By   /s/ MOHAMMED ALAM
   -----------------------------------------
   Name: Mohammed Alam
   Title: Vice President	

Signature page to the Sixth Amendment, dated as of May 23, 2003, to the Second Amended and Restated Credit Agreement, dated as of May 23, 2000, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto and The Bank of Nova Scotia, as administrative agent.
CREDIT LYONNAIS NEW YORK BRANCH

By   /s/ MARTIN C. LIVINGSTON
   -----------------------------------------
   Name: Martin C. Livingston
   Title: Vice President	

Signature page to the Sixth Amendment, dated as of May 23, 2003, to the Second Amended and Restated Credit Agreement, dated as of May 23, 2000, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto and The Bank of Nova Scotia, as administrative agent.
FLEET NATIONAL BANK

By   /s/ ANTHONY D. HEALEY
   -----------------------------------------
   Name: Anthony D. Healey
   Title: Authorized Signer	

Signature page to the Sixth Amendment, dated as of May 23, 2003, to the Second Amended and Restated Credit Agreement, dated as of May 23, 2000, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto and The Bank of Nova Scotia, as administrative agent.
CREDIT SUISSE FIRST BOSTON

By   /s/ JAMES P. MORAN
   -----------------------------------------
   Name: James P. Moran
   Title: Director

By   /s/ BRIAN T. CALDWELL
   -----------------------------------------
   Name: Brian T. Caldwell
   Title: Director	

Signature page to the Sixth Amendment, dated as of May 23, 2003, to the Second Amended and Restated Credit Agreement, dated as of May 23, 2000, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto and The Bank of Nova Scotia, as administrative agent.
TORONTO DOMINION (TEXAS) INC.

By   /s/ DEBORAH GRAVINESE
   -----------------------------------------
   Name: Deborah Gravinese
   Title: Managing Director	

EXHIBIT 10.8
EXECUTION COPY
SEVENTH AMENDMENT
SEVENTH AMENDMENT, dated as of June 16, 2003 (this "Amendment"), to the Second Amended and Restated Credit Agreement, dated as of May 23, 2000 (as amended, the "Credit Agreement"), among CALPINE CORPORATION, a Delaware corporation (the "Borrower"), the various financial institutions as are or may become parties thereto (the "Lenders") and THE BANK OF NOVA SCOTIA, as administrative agent (in such capacity, the "Agent").
WHEREAS pursuant to the Credit Agreement, the Lenders have made extensions of credit to the Borrower; and
WHEREAS the Borrower has requested that a provision of the Credit Agreement be modified in the manner provided for in this Amendment, and the Lenders are willing to agree to such modification as provided for in this Amendment.
NOW, THEREFORE, the parties hereto hereby agree as follows:
1. Defined Terms. Capitalized terms used and not defined herein shall have the meanings given to them in the Credit Agreement, as amended hereby.
2. Amendment to Credit Agreement. The definition of "Commitment Termination Date" in Section 1.1 of the Credit Agreement is hereby amended by deleting clause (a) thereof in its entirety and by substituting in lieu thereof the following: "(a) July 16, 2003;"; provided, that if, by 5:00
p.m. (New York time) on June 24, 2003, the Agent shall not have received a consent letter, in form and substance satisfactory to the Agent, from the Borrower and each Lender with respect to a new term sheet for the extension of the revolving credit facilities (the date, if any, on which the Agent shall have received such consent letters, the "Term Sheet Agreement Date"), the foregoing extension shall automatically cease to be in effect and the reference to July 16, 2003 set forth herein shall automatically become a reference to June 24, 2003.
3. Representations and Warranties. The Borrower hereby represents and warrants to the Agent and the Lenders that, as of the date hereof and after giving effect to the amendment contained herein:
(a) No Default or Event of Default has occurred and is continuing.
(b) The execution, delivery and performance by the Borrower of this Amendment has been duly authorized by all necessary corporate and other action and does not and will not require any registration with, consent or approval of, notice to or action by, any person in order to be effective and enforceable. Each of this Amendment and the Credit Agreement as amended by this Amendment constitutes the legal, valid and binding obligation of the Borrower, enforceable against each in accordance with its terms, subject to applicable bankruptcy, insolvency, fraudulent conveyance, reorganization, moratorium or other laws
2
affecting creditors' rights generally and subject to general principles of equity, regardless of whether considered in a proceeding in equity or at law.
(c) All representations and warranties of each Obligor set forth in the Loan Documents as amended hereby are true and correct in all material respects.
4. Covenants. The Borrower hereby agrees that during the period commencing on the date hereof up to and including July 16, 2003 (the "Extension Period"), the Borrower shall not take any action which could, directly or indirectly, have a material adverse effect upon (i) the financial condition, operations, assets (including power projects), business or prospects of the Borrower and its Subsidiaries taken as a whole; or (ii) the ability of the Borrower or any other Obligor to perform under any Loan Document. Without prejudice to the foregoing, the Borrower shall ensure that, during the Extension Period, (1) no Indebtedness is incurred, created, assumed or suffered to exist by the Borrower or any of its Subsidiaries (except (A) Indebtedness under the Loan Documents and the Loan Documents (as defined in the 2002 Credit Agreement), (B) unsecured Indebtedness incurred in the ordinary course of business, other than Indebtedness of the type described in (1) clauses (a), (c) or (f) of the definition of "Indebtedness" and (2) clauses (b) and (g) of the definition of "Indebtedness" with respect to any Indebtedness described in clause (1) above,
(C) other unsecured Indebtedness or Non-Recourse Debt (as defined in the Senior Note Indentures) incurred in the ordinary course of business in connection with Indebtedness existing or contractually committed to be made available as of the date hereof, and (D) Indebtedness outstanding on the date hereof), and no guarantee, collateral or other credit support is provided, and no Lien on the properties of the Borrower or any of its Subsidiaries is created, incurred, assumed or granted, in each case in support of (x) any Indebtedness (other than Indebtedness permitted above) or (y) any obligation relating to any synthetic lease transaction of the Borrower or any Subsidiary of the Borrower; (2) no amendment, modification or supplement is made to any agreement or instrument evidencing any Indebtedness, other than amendments, modifications or supplements entered into in the ordinary course of business in respect of (A) the Credit Agreement or the 2002 Credit Agreement, (B) any agreement or instrument evidencing Non-Recourse Debt (as defined in the Senior Note Indentures) of a Subsidiary of the Borrower, or (C) any agreement or instrument evidencing Indebtedness other than Indebtedness of the type described in (1) clauses (a),
(c) or (f) of the definition of "Indebtedness" and (2) clauses (b) and (g) of the definition of "Indebtedness" with respect to any Indebtedness described in clause (1) above (the Indebtedness described in clauses (B) and (C) being collectively referred to as "Excluded Indebtedness"); (3) no optional prepayment is made on, or purchase or optional redemption is executed of, any Indebtedness other than Excluded Indebtedness (including, without limitation, any buy-back or defeasance of any outstanding bonds, puttable convertible bonds or other securities of the Borrower or any of its Subsidiaries), it being understood and agreed that, during the Extension Period, neither the Borrower or any of its Subsidiaries shall obtain or receive any such Indebtedness (or instruments evidencing same) in consideration of the sale or other transfer of any assets or properties thereof; provided, that notwithstanding anything to the contrary contained herein or in the Credit Agreement, at any time after the Term Sheet Agreement Date, the Borrower shall be permitted to repurchase notes issued by Calpine Canada Energy Finance II, ULC for an aggregate purchase amount not to exceed US$50,000,000; (4) no Investment is made by the Borrower or any of its Subsidiaries in any other Person (except (A) Investments by the Borrower in the ordinary course of business in Subsidiaries the equity in which has been pledged to the Lenders, and each of their respective Subsidiaries, (B)
3
Investments by the Borrower in other Persons pursuant to contractual commitments existing as of the date hereof, and (C) Investments by the Borrower in CES in support of transactions entered into by CES in the ordinary course of CES's business, consistent with historical practices); and (5) all transactions between any one or more of the Borrower and its Affiliates entered into during the Extension Period are on terms that are fair and reasonable and similar to those found in a comparable arm's length transaction with a Person that is not an Affiliate of the Borrower. Notwithstanding the foregoing, it is agreed that
(x) the Borrower and its Subsidiaries may effectuate the transactions referred to in Schedule I attached to the letter from the Borrower to the Lenders dated May 20, 2003 and (y) none of the prohibitions contained in this Section 4 shall be applicable insofar as they would otherwise constitute an encumbrance or restriction in violation of Section 3.5 of the Pre-2000 Indentures (as defined in the 2002 Credit Agreement). The provisions of this Section 4 may be amended, modified or waived, if such amendment, modification or waiver is in writing and consented to by the Borrower and Lenders owed or holding at least 51% of the aggregate Revolving Loan Commitments and Commitments under the 2002 Credit Agreement and the Credit Agreement, respectively (it being understood, however, that no such amendment, modification or waiver shall amend, modify or waive the provisions of the Credit Agreement unless such amendment, modification or waiver satisfies the requirements of Section 11.1 of the Credit Agreement).
5. Conditions Precedent to Effectiveness. This Amendment shall become effective as of the date hereof upon (i) the Agent having received counterparts hereof duly executed and delivered by the Borrower and each Lender and (ii) the Third Amendment, dated as of the date hereof, to the 2002 Credit Agreement becoming effective in accordance with its terms.
6. No Other Amendments. Except as expressly amended hereby, the provisions of the Credit Agreement are and shall remain in full force and effect.
7. Expenses. The Borrower agrees to pay or reimburse the Agent for its out-of-pocket expenses in connection with this Amendment, including the reasonable fees, charges and disbursements of counsel to the Agent.
8. Governing Law; Counterparts. (a) This Amendment and the rights and obligations of the parties hereto shall be governed by, and construed and interpreted in accordance with, the laws of the State of New York.
(b) This Amendment may be executed by one or more of the parties to this Amendment on any number of separate counterparts, and all of said counterparts taken together shall be deemed to constitute one and the same instrument. This Amendment may be delivered by facsimile transmission of the relevant signature pages hereof.
IN WITNESS WHEREOF, the Borrower and the Lenders have caused this Amendment to be duly executed by their respective authorized officers as of the day and year first above written.
CALPINE CORPORATION

By   /s/ ROBERT D. KELLY
   -----------------------------------------
   Name: Robert D. Kelly
   Title: Chief Financial Officer	

THE BANK OF NOVA SCOTIA, as Agent and Lender

By   /s/ DENIS P. O'MEARA
   -----------------------------------------
   Name: Denis P. O'Meara
   Title: Managing Director	

Signature page to the Seventh Amendment, dated as of June 16, 2003, to the Second Amended and Restated Credit Agreement, dated as of May 23, 2000, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto and The Bank of Nova Scotia, as administrative agent.
BANK OF AMERICA, NA

By   /s/ THOMAS BIAGGI
   -----------------------------------------
   Name: Thomas Biaggi
   Title: Managing Director	

Signature page to the Seventh Amendment, dated as of June 16, 2003, to the Second Amended and Restated Credit Agreement, dated as of May 23, 2000, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto and The Bank of Nova Scotia, as administrative agent.
BAYERISCHE LANDESBANK
Cayman Islands Branch

By   /s/ DIETMAR RIEG
   -----------------------------------------
   Name: Dietmar Rieg
   Title: First Vice President

By   /s/ JAMES H. BOYLE
   -----------------------------------------
   Name: James H. Boyle
   Title: Vice President	

Signature page to the Seventh Amendment, dated as of June 16, 2003, to the Second Amended and Restated Credit Agreement, dated as of May 23, 2000, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto and The Bank of Nova Scotia, as administrative agent.
CIBC INC.

By   /s/ M. SANJEEVA SENANAYAKE
   -----------------------------------------
   Name: M. Sanjeeva Senanayake
   Title: Executive Director
       CIBC World Markets Corp. As Agent	

Signature page to the Seventh Amendment, dated as of June 16, 2003, to the Second Amended and Restated Credit Agreement, dated as of May 23, 2000, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto and The Bank of Nova Scotia, as administrative agent.
CREDIT LYONNAIS NEW YORK BRANCH

By   /s/ MARTIN C. LIVINGSTON
   -----------------------------------------
   Name: Martin C. Livingston
   Title: Vice President	

Signature page to the Seventh Amendment, dated as of June 16, 2003, to the Second Amended and Restated Credit Agreement, dated as of May 23, 2000, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto and The Bank of Nova Scotia, as administrative agent.
CREDIT SUISSE FIRST BOSTON

By   /s/ JAMES P. MORAN
   -----------------------------------------
   Name: James P. Moran
   Title: Director

By   /s/ JAY CHALL
   -----------------------------------------
   Name: Jay Chall
   Title: Director	

Signature page to the Seventh Amendment, dated as of June 16, 2003, to the Second Amended and Restated Credit Agreement, dated as of May 23, 2000, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto and The Bank of Nova Scotia, as administrative agent.
DRESDNER BANK AG, NEW YORK 
and GRAND CAYMAN BRANCHES

By   /s/ FRED THURSTON
   -----------------------------------------
   Name: Fred Thurston
   Title: Vice President

By   /s/ THOMAS R. BRADY
   -----------------------------------------
   Name: Thomas R. Brady
   Title: Director	

Signature page to the Seventh Amendment, dated as of June 16, 2003, to the Second Amended and Restated Credit Agreement, dated as of May 23, 2000, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto and The Bank of Nova Scotia, as administrative agent.
FLEET NATIONAL BANK

By   /s/ ANTHONY D. HEALEY
   -----------------------------------------
   Name: Anthony D. Healey
   Title: Authorized Signer	

Signature page to the Seventh Amendment, dated as of June 16, 2003, to the Second Amended and Restated Credit Agreement, dated as of May 23, 2000, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto and The Bank of Nova Scotia, as administrative agent.
FORTIS CAPITAL CORP.

By   /s/ HENDRIK VROEGO
   -----------------------------------------
   Name: Hendrik Vroego
   Title: Managing Director

By   /s/ JIM TROUSDALE
   -----------------------------------------
   Name: Jim Trousdale
   Title: Assistant Vice President	

Signature page to the Seventh Amendment, dated as of June 16, 2003, to the Second Amended and Restated Credit Agreement, dated as of May 23, 2000, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto and The Bank of Nova Scotia, as administrative agent.
BAYERISCHE HYPO-UND
VEREINSBSBANK, AG NY BRANCH

By   /s/ ANDREW G. MATHEWS
   -----------------------------------------
   Name: Andrew G. Mathews
   Title: Managing Director

By   /s/ PAUL J. COLATRELLA
   -----------------------------------------
   Name: Paul J. Colatrella
   Title: Director	

Signature page to the Seventh Amendment, dated as of June 16, 2003, to the Second Amended and Restated Credit Agreement, dated as of May 23, 2000, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto and The Bank of Nova Scotia, as administrative agent.
ING CAPITAL LLC

By   /s/ STEPHEN E. FISCHER
   -----------------------------------------
   Name: Stephen E. Fischer
   Title: Managing Director

By   /s/ G.D. BELLAMY, JR.
   --------------------------------
   Name: G.D. Bellamy, Jr.
   Title: Director	

Signature page to the Seventh Amendment, dated as of June 16, 2003, to the Second Amended and Restated Credit Agreement, dated as of May 23, 2000, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto and The Bank of Nova Scotia, as administrative agent.
THE TORONTO DOMINION (TEXAS) INC.

By   /s/ LYNN CHASIN
   -----------------------------------------
   Name: Lynn Chasin
   Title: Vice President	

Signature page to the Seventh Amendment, dated as of June 16, 2003, to the Second Amended and Restated Credit Agreement, dated as of May 23, 2000, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto and The Bank of Nova Scotia, as administrative agent.
UNION BANK OF CALIFORNIA, N.A.

By   /s/ BRYAN READ
   -----------------------------------------
   Name: Bryan Read
   Title: Vice President	

EXHIBIT 10.12
EXECUTION COPY
SECOND AMENDMENT
SECOND AMENDMENT, dated as of May 23, 2003 (this "Amendment"), to the Credit Agreement, dated as of March 8, 2002 (as amended, the "Credit Agreement"), among CALPINE CORPORATION, a Delaware corporation (the "Borrower"), the various financial institutions as are or may become parties thereto (the "Lenders"), THE BANK OF NOVA SCOTIA, as joint administrative agent and funding agent (in such capacity, the "Agent") and CITICORP USA, INC., as joint administrative agent.
WHEREAS pursuant to the Credit Agreement, the Lenders have made extensions of credit to the Borrower; and
WHEREAS the Borrower has requested that certain provisions of the Credit Agreement be modified in the manner provided for in this Amendment, and the Lenders are willing to agree to such modifications as provided for in this Amendment.
NOW, THEREFORE, the parties hereto hereby agree as follows:
1. Defined Terms. Capitalized terms used and not defined herein shall have the meanings given to them in the Credit Agreement, as amended hereby.
2. Amendments to Credit Agreement. The definitions of "Revolving Loan Commitment Termination Date" and "Stated Maturity Date" in
Section 1.1 of the Credit Agreement and Section 2.7(a) of the Credit Agreement are hereby amended by deleting the reference to "May 24, 2003" in such definitions and such Section 2.7(a) and by substituting in lieu thereof in each case "June 16, 2003".
3. Representations and Warranties. The Borrower hereby represents and warrants to the Agent and the Lenders that, as of the date hereof and after giving effect to the amendment contained herein:
(a) No Default or Event of Default has occurred and is continuing.
(b) The execution, delivery and performance by the Borrower of this Amendment has been duly authorized by all necessary corporate and other action and does not and will not require any registration with, consent or approval of, notice to or action by, any person in order to be effective and enforceable. Each of this Amendment and the Credit Agreement as amended by this Amendment constitutes the legal, valid and binding obligation of the Borrower, enforceable against each in accordance with its terms, subject to applicable bankruptcy, insolvency, fraudulent conveyance, reorganization, moratorium or other laws affecting creditors' rights generally and subject to general principles of equity, regardless of whether considered in a proceeding in equity or at law.
(c) All representations and warranties of each Obligor set forth in the Loan Documents as amended hereby are true and correct in all material respects.
2
4. Covenants. The Borrower hereby agrees that during the period commencing on the date hereof up to and including June 16, 2003 (the "Extension Period"), the Borrower shall not take any action which could, directly or indirectly, have a material adverse effect upon (i) the financial condition, operations, assets (including power projects), business or prospects of the Borrower and its Subsidiaries taken as a whole; or (ii) the ability of the Borrower or any other Obligor to perform under any Loan Document. Without prejudice to the foregoing, the Borrower shall ensure that, during the Extension Period, (1) no Indebtedness is incurred, created, assumed or suffered to exist by the Borrower or any of its Subsidiaries (except (A) Indebtedness under the Loan Documents and the Loan Documents (as defined in the Existing Credit Agreement), (B) unsecured Indebtedness incurred in the ordinary course of business, other than Indebtedness of the type described in (1) clauses (a), (c) or (f) of the definition of "Indebtedness" and (2) clauses (b) and (g) of the definition of "Indebtedness" with respect to any Indebtedness described in clause (1) above, (C) other unsecured Indebtedness or Non-Recourse Debt (as defined in the Senior Note Indentures) incurred in the ordinary course of business in connection with Indebtedness existing or contractually committed to be made available as of the date hereof, and (D) Indebtedness outstanding on the date hereof), and no guarantee, collateral or other credit support is provided, and no Lien on the properties of the Borrower or any of its Subsidiaries is created, incurred, assumed or granted, in each case in support of (x) any Indebtedness (other than Indebtedness permitted above) or (y) any obligation relating to any synthetic lease transaction of the Borrower or any Subsidiary of the Borrower; (2) no amendment, modification or supplement is made to any agreement or instrument evidencing any Indebtedness, other than amendments, modifications or supplements entered into in the ordinary course of business in respect of (A) the Credit Agreement or the Existing Credit Agreement, (B) any agreement or instrument evidencing Non-Recourse Debt (as defined in the Senior Note Indentures) of a Subsidiary of the Borrower, or (C) any agreement or instrument evidencing Indebtedness other than Indebtedness of the type described in (1) clauses (a), (c) or (f) of the definition of "Indebtedness" and (2) clauses (b) and (g) of the definition of "Indebtedness" with respect to any Indebtedness described in clause (1) above (the Indebtedness described in clauses (B) and (C) being collectively referred to as "Excluded Indebtedness");
(3) no optional prepayment is made on, or purchase or optional redemption is executed of, any Indebtedness other than Excluded Indebtedness (including, without limitation, any buy-back or defeasance of any outstanding bonds, puttable convertible bonds or other securities of the Borrower or any of its Subsidiaries), it being understood and agreed that, during the Extension Period, neither the Borrower or any of its Subsidiaries shall obtain or receive any such Indebtedness (or instruments evidencing same) in consideration of the sale or other transfer of any assets or properties thereof; (4) no Investment is made by the Borrower or any of its Subsidiaries in any other Person (except (A) Investments by the Borrower in the ordinary course of business in Subsidiaries the equity in which has been pledged to the Lenders, and each of their respective Subsidiaries, (B) Investments by the Borrower in other Persons pursuant to contractual commitments existing as of the date hereof, and (C) Investments by the Borrower in CES in support of transactions entered into by CES in the ordinary course of CES's business, consistent with historical practices); and (5) all transactions between any one or more of the Borrower and its Affiliates entered into during the Extension Period are on terms that are fair and reasonable and similar to those found in a comparable arm's length transaction with a Person that is not an Affiliate of the Borrower. Notwithstanding the foregoing, it is agreed that (x) the Borrower and its Subsidiaries may effectuate the transactions referred to in Schedule I attached to the letter from the Borrower to the Lenders dated May 20, 2003 and (y) none of the
3
prohibitions contained in this Section 4 shall be applicable insofar as they would otherwise constitute an encumbrance or restriction in violation of Section 3.5 of the Pre-2000 Indentures. The provisions of this Section 4 may be amended, modified or waived, if such amendment, modification or waiver is in writing and consented to by the Borrower and Lenders owed or holding at least 51% of the aggregate Revolving Loan Commitments and Commitments under the Credit Agreement and the Existing Credit Agreement, respectively (it being understood, however, that no such amendment, modification or waiver shall amend, modify or waive the provisions of the Credit Agreement unless such amendment, modification or waiver satisfies the requirements of Section 11.1 of the Credit Agreement).
5. Conditions Precedent to Effectiveness. This Amendment shall become effective as of the date hereof upon (i) the Agent having received counterparts hereof duly executed and delivered by the Borrower, the Required Lenders and each Revolving Lender and (ii) the Sixth Amendment, dated as of the date hereof, to the Existing Credit Agreement becoming effective in accordance with its terms.
6. No Other Amendments. Except as expressly amended hereby, the provisions of the Credit Agreement are and shall remain in full force and effect.
7. Expenses. The Borrower agrees to pay or reimburse the Agent for its out-of-pocket expenses in connection with this Amendment, including the reasonable fees, charges and disbursements of counsel to the Agent.
8. Governing Law; Counterparts. (a) This Amendment and the rights and obligations of the parties hereto shall be governed by, and construed and interpreted in accordance with, the laws of the State of New York.
(b) This Amendment may be executed by one or more of the parties to this Amendment on any number of separate counterparts, and all of said counterparts taken together shall be deemed to constitute one and the same instrument. This Amendment may be delivered by facsimile transmission of the relevant signature pages hereof.
IN WITNESS WHEREOF, the Borrower and the Lenders have caused this Amendment to be duly executed by their respective authorized officers as of the day and year first above written.
CALPINE CORPORATION

By   /s/ ROBERT D. KELLY
   -----------------------------------------
   Name: Robert D. Kelly
   Title: Chief Financial Officer	

THE BANK OF NOVA SCOTIA, as Agent
and Lender

By   /s/ DENIS P. O'MEARA
   -----------------------------------------
   Name: Denis P. O'Meara
   Title: Managing Director	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
CREDIT SUISSE FIRST BOSTON

By   /s/ JAMES P. MORAN
   -----------------------------------------
   Name: James P. Moran
   Title:  Director

By   /s/ BRIAN T. CALDWELL
   -----------------------------------------
   Name: Brian T. Caldwell
   Title:  Director	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
BAYERISCHE LANDESBANK
Cayman Islands Branch

By   /s/ OLIVER HILDENBRAND
   -----------------------------------------
      Name: Oliver Hildenbrand
      Title: First Vice President

By   /s/ JAMES H. BOYLE
   -----------------------------------------
   Name: James H. Boyle
   Title: Vice President	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
BANK OF AMERICA, NA

By   /s/ EILEEN C. HIGGINS
   ---------------------------
   Name: Eileen C. Higgins
   Title: Principal	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
ING CAPITAL LLC

By   /s/ ERWIN THOMET
   -----------------------------------------
   Name: Erwin Thomet
   Title: Managing Director

By   /s/ NICK BELLAMY
   -----------------------------------------
   Name: Nick Bellamy
   Title: Director	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
CITICORP USA, INC.

By   /s/ ANTHONY MURPHY
   -----------------------------------------
   Name: Anthony Murphy
   Title: Managing Director	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
DEUTSCHE BANK TRUST COMPANY AMERICAS

By   /s/ MARCUS M. TARKINGTON
   -----------------------------------------
   Name: Marcus M. Tarkington
   Title: Director	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
TORONTO DOMINION (TEXAS) INC.

By   /s/ DEBORAH GRAVINESE
   -----------------------------------------
   Name: Deborah Gravinese
   Title: Managing Director	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
MERRILL LYNCH PRIME RATE PORTFOLIO
 By: Merrill Lynch Investment Managers, L.P.
as Investment Advisor

By   /s/ JAIMIN PATEL
   -------------------------------------
   Name: Jaimin Patel
   Title: Authorized Signatory	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
MERRILL LYNCH GLOBAL INVESTMENT SERIES:
INCOME STRATEGIES PORTFOLIO
 By: Merrill Lynch Investment Managers, L.P.
as Investment Advisor

By   /s/ JAIMIN PATEL
   -------------------------------------
   Name: Jaimin Patel
   Title: Authorized Signatory	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
MERRILL LYNCH GLOBAL INVESTMENT SERIES:
BANK LOAN INCOME PORTFOLIO
 By: Merrill Lynch Investment Managers, L.P.
as Investment Advisor

By   /s/ JAIMIN PATEL
   -------------------------------------
   Name: Jaimin Patel
   Title: Authorized Signatory	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
MASTER SENIOR FLOATING RATE TRUST

By   /s/ JAIMIN PATEL
   -----------------------------------------
   Name: Jaimin Patel
   Title: Authorized Signatory	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
SENIOR HIGH INCOME PORTFOLIO, INC.

By   /s/ JAIMIN PATEL
   -----------------------------------------
   Name: Jaimin Patel
   Title: Authorized Signatory	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
LONGHORN CDO II, LTD.
 By: Merrill Lynch Investment Managers, L.P.
as Investment Advisor

By   /s/ JAIMIN PATEL
   -----------------------------------------
   Name: Jaimin Patel
   Title: Authorized Signatory	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
LONGHORN CDO (CAYMAN) LTD
 By: Merrill Lynch Investment Managers, L.P.
as Investment Advisor

By   /s/ JAIMIN PATEL
   -----------------------------------------
   Name: Jaimin Patel
   Title: Authorized Signatory	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
Longhorn CDO III, LTD.

By: Merrill Lynch Investment Managers, L.P.
as Investment Advisor

By   /s/ JAIMIN PATEL
   -----------------------------------------
   Name: Jaimin Patel
   Title: Authorized Signatory	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
DEBT STRATEGIES FUND, INC.

By   /s/ JAIMIN PATEL
   -----------------------------------------
   Name: Jaimin Patel
   Title: Authorized Signatory	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
ENDURANCE CLO I, LTD.
 By: ING Capital Advisors LLC,
as Collateral Manager

By   /s/ GORDON R. COOK
   -----------------------------------------
   Name: Gordon R. Cook
   Title: Managing Director	

ARCHIMEDES FUNDING III, LTD.
 By: ING Capital Advisors LLC,
as Collateral Manager

By   /s/ GORDON R. COOK
   -----------------------------------------
   Name: Gordon R. Cook
   Title: Managing Director	

ARCHIMEDES FUNDING IV (CAYMAN), LTD.
 By: ING Capital Advisors LLC,
as Collateral Manager

By   /s/ GORDON R. COOK
   -----------------------------------------
   Name: Gordon R. Cook
   Title: Managing Director	

BALANCED HIGH-YIELD FUND II, LTD.
 By: ING Capital Advisors LLC,
as Collateral Manager

By   /s/ GORDON R. COOK
   -----------------------------------------
   Name: Gordon R. Cook
   Title: Managing Director	

SEQUILS-ING I (HBDGM), LTD.
 By: ING Capital Advisors LLC,
as Collateral Manager

By   /s/ GORDON R. COOK
   -----------------------------------------
   Name: Gordon R. Cook
   Title: Managing Director	

NEMEAN CLO, LTD.
 By: ING Capital Advisors LLC,
as Collateral Manager

By   /s/ GORDON R. COOK
   -----------------------------------------
   Name: Gordon R. Cook
   Title: Managing Director	

ING-ORYX CLO, LTD.
 By: ING Capital Advisors LLC,
as Collateral Manager

By   /s/ GORDON R. COOK
   -----------------------------------------
   Name: Gordon R. Cook
   Title: Managing Director	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
CITADEL JACKSON INVESTMENT FUND LTD.
 By: Citadel Limited Partnership,
its Portfolio Manager
By: GLB Partners, L.P., its General Partner
By: Citadel Investment Group, LLC,
its General Partner

By   /s/ BRAD COURI
   -----------------------------------------
   Name: Brad Couri
   Title: Senior Managing Director	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
CITADEL EQUITY FUND LTD.
 By: Citadel Limited Partnership,
its Portfolio Manager
By: GLB Partners, L.P., its General Partner
By: Citadel Investment Group, LLC,
its General Partner

By   /s/ BRAD COURI
   -----------------------------------------
   Name: Brad Couri
   Title: Senior Managing Director	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
AIMCO CDO SERIES 2000-A

By   /s/ CHRIS GOERGEN
   -----------------------------------------
   Name: Chris Goergen
   Title: Authorized Signatory

By   /s/ PATRICIA W. WILSON
   -----------------------------------------
   Name: Patricia W. Wilson
   Title: Authorized Signatory	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
AIMCO CLO SERIES 2001-A

By   /s/ CHRIS GOERGEN
   -----------------------------------------
   Name: Chris Goergen
   Title: Authorized Signatory

By   /s/ PATRICIA W. WILSON
   -----------------------------------------
   Name: Patricia W. Wilson
   Title: Authorized Signatory	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
HARCH CLO I LTD.

By   /s/ MICHAEL E. LEWITT
   -----------------------------------------
   Name: Michael E. Lewitt
   Title: Authorized Signatory	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
GALAXY CLO 1999-1, LTD.

By   /s/ W. JEFFREY BAXTER
   -----------------------------------------
   Name: W. Jeffrey Baxter
   Title: Authorized Agent	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
SUNAMERICA LIFE INSURANCE COMPANY

By   /s/ W. JEFFREY BAXTER
   -----------------------------------------
   Name: W. Jeffrey Baxter
   Title: Authorized Agent	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
KZH CNC LLC

By   /s/ ROWENA SMITH
   -----------------------------------------
   Name: Rowena Smith
   Title: Authorized Agent	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
KZH PENDVIEW LLC

By   /s/ ROWENA SMITH
   -----------------------------------------
   Name: Rowena Smith
   Title: Authorized Agent	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
KZH RIVERSIDE LLC

By   /s/ ROWENA SMITH
   -----------------------------------------
   Name: Rowena Smith
   Title: Authorized Agent	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
KZH SOLEIL LLC

By   /s/ ROWENA SMITH
   -----------------------------------------
   Name: Rowena Smith
   Title: Authorized Agent	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
KZH SOLEIL-2 LLC

By   /s/ ROWENA SMITH
   -----------------------------------------
   Name: Rowena Smith
   Title: Authorized Agent	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
KZH WATERSIDE LLC

By   /s/ ROWENA SMITH
   -----------------------------------------
   Name: Rowena Smith
   Title: Authorized Agent	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
LANDMARK CDO LIMITED
 By: Aladdin Capital Management LLC,
as Manager

By   /s/ JOSEPH MORONEY
   -----------------------------------------
   Name: Joseph Moroney
   Title: Authorized Signatory	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
LANDMARK II CDO LIMITED
 By: Aladdin Capital Management LLC,
as Manager

By   /s/ JOSEPH MORONEY
   -----------------------------------------
   Name: Joseph Moroney
   Title: Authorized Signatory	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
INDOSUEZ CAPITAL FUNDING VI, LIMITED
 By: Indosuez Capital as Collateral Manager

By   /s/ JACK C. HENRY
   -----------------------------------------
   Name: Jack C. Henry
   Title: Principal	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
AMMC CDO I, LIMITED
 By: American Money Management Corp.,
as Collateral Manager

By   /s/ DAVID P. MEYER
   -----------------------------------------
   Name: David P. Meyer
   Title: Vice President	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
AMMC CDO II, LIMITED
 By: American Money Management Corp.,
as Collateral Manager

By   /s/ DAVID P. MEYER
   -----------------------------------------
   Name: David P. Meyer
   Title: Vice President	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
EAST WEST BANK

By   /s/ NANCY A. MOORE
   -----------------------------------------
   Name: Nancy A. Moore
   Title: Senior Vice President	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
JUPITER FUNDING TRUST

By   /s/ ANN E. MORRIS
   -----------------------------------------
   Name: Ann E. Morris
   Title: Authorized Agent	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
RIVIERA FUNDING LLC

By   /s/ ANN E. MORRIS
   -----------------------------------------
   Name: Ann E. Morris
   Title: Asst. Vice President	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
SRF TRADING, INC.

By   /s/ ANN E. MORRIS
   -----------------------------------------
   Name: Ann E. Morris
   Title: Asst. Vice President	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
STANWICH LOAN FUNDING LLC

By   /s/ ANN E. MORRIS
   -----------------------------------------
   Name: Ann E. Morris
   Title: Asst. Vice President	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
WINGED FOOT FUNDING TRUST

By   /s/ ANN E. MORRIS
   -----------------------------------------
   Name: Ann E. Morris
   Title: Asst. Vice President	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
SRF 2000, INC.

By   /s/ ANN E. MORRIS
   -----------------------------------------
   Name: Ann E. Morris
   Title: Asst. Vice President	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
STEIN ROE FLOATING RATE
LIMITED LIABILITY COMPANY
 By: Columbia Management Advisors, Inc.
(f/k/a Stein Roe & Farnham
Incorporated), As Advisor

By   /s/ JAMES R. FELLOWS
   -----------------------------------------
   Name: James R. Fellows
   Title: Sr. Vice President & Portfolio
          Manager	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
LIBERTY FLOATING RATE
ADVANTAGE FUND
 By: Columbia Management Advisors, Inc.
(f/k/a Stein Roe & Farnham
Incorporated), As Advisor

By   /s/ JAMES R. FELLOWS
   -----------------------------------------
   Name: James R. Fellows
   Title: Sr. Vice President & Portfolio
          Manager	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
STEIN ROE & FARNHAM CLO I LTD.
 By: Columbia Management Advisors, Inc.
(f/k/a Stein Roe & Farnham
Incorporated), As Advisor

By   /s/ JAMES R. FELLOWS
   -----------------------------------------
   Name: James R. Fellows
   Title: Sr. Vice President & Portfolio
          Manager	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
AURUM CLO 2002-1 LTD.
 By: Columbia Management Advisors, Inc.
(f/k/a Stein Roe & Farnham
Incorporated), As Advisor

By   /s/ JAMES R. FELLOWS
   -----------------------------------------
   Name: James R. Fellows
   Title: Sr. Vice President & Portfolio
          Manager	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
GALLATIN FUNDING I LTD.
 By: Bear Stearns Asset Management Inc.
as its Collateral Manager

By   /s/ JUSTIN DRISCOLL
   -----------------------------------------
   Name: Justin Driscoll
   Title: Managing Director	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
GRAYSTON CLO 2001-01 LTD.
 By: Bear Stearns Asset Management Inc.
as its Collateral Manager

By   /s/ JUSTIN DRISCOLL
   -----------------------------------------
   Name: Justin Driscoll
   Title: Managing Director	

Signature page to the Second Amendment, dated as of May 23, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
SAGAMORE HILL HUB FUND
 By: Sagamore Hill Capital

By   /s/ LEON ZALTZMAN
   -----------------------------------------
   Name: Leon Zaltzman
   Title:	

EXHIBIT 10.13
EXECUTION COPY
THIRD AMENDMENT
THIRD AMENDMENT, dated as of June 16, 2003 (this "Amendment"), to the Credit Agreement, dated as of March 8, 2002 (as amended, the "Credit Agreement"), among CALPINE CORPORATION, a Delaware corporation (the "Borrower"), the various financial institutions as are or may become parties thereto (the "Lenders"), THE BANK OF NOVA SCOTIA, as joint administrative agent and funding agent (in such capacity, the "Agent") and CITICORP USA, INC., as joint administrative agent.
WHEREAS pursuant to the Credit Agreement, the Lenders have made extensions of credit to the Borrower; and
WHEREAS the Borrower has requested that certain provisions of the Credit Agreement be modified in the manner provided for in this Amendment, and the Lenders are willing to agree to such modifications as provided for in this Amendment.
NOW, THEREFORE, the parties hereto hereby agree as follows:
1. Defined Terms. Capitalized terms used and not defined herein shall have the meanings given to them in the Credit Agreement, as amended hereby.
2. Amendments to Credit Agreement. The definitions of "Revolving Loan Commitment Termination Date" and "Stated Maturity Date" in
Section 1.1 of the Credit Agreement and Section 2.7(a) of the Credit Agreement are hereby amended by deleting the reference to "June 16, 2003" in such definitions and such Section 2.7(a) and by substituting in lieu thereof in each case "July 16, 2003"; provided, that if, by 5:00 p.m. (New York time) on June 24, 2003, the Agent shall not have received a consent letter, in form and substance satisfactory to the Agent, from the Borrower and each Revolving Lender with respect to a new term sheet for the extension of the revolving credit facilities (the date, if any, on which the Agent shall have received such consent letters, the "Term Sheet Agreement Date"), the foregoing extension shall automatically cease to be in effect and the reference to July 16, 2003 set forth herein shall automatically become a reference to June 24, 2003.
3. Representations and Warranties. The Borrower hereby represents and warrants to the Agent and the Lenders that, as of the date hereof and after giving effect to the amendment contained herein:
(a) No Default or Event of Default has occurred and is continuing.
(b) The execution, delivery and performance by the Borrower of this Amendment has been duly authorized by all necessary corporate and other action and does not and will not require any registration with, consent or approval of, notice to or action by, any person in order to be effective and enforceable. Each of this Amendment and the Credit Agreement as amended by this Amendment constitutes the legal, valid and binding obligation of the Borrower, enforceable against each in accordance with its terms, subject to applicable bankruptcy, insolvency, fraudulent conveyance, reorganization, moratorium or other laws affecting creditors'
2
rights generally and subject to general principles of equity, regardless of whether considered in a proceeding in equity or at law.
(c) All representations and warranties of each Obligor set forth in the Loan Documents as amended hereby are true and correct in all material respects.
4. Covenants. The Borrower hereby agrees that during the period commencing on the date hereof up to and including July 16, 2003 (the "Extension Period"), the Borrower shall not take any action which could, directly or indirectly, have a material adverse effect upon (i) the financial condition, operations, assets (including power projects), business or prospects of the Borrower and its Subsidiaries taken as a whole; or (ii) the ability of the Borrower or any other Obligor to perform under any Loan Document. Without prejudice to the foregoing, the Borrower shall ensure that, during the Extension Period, (1) no Indebtedness is incurred, created, assumed or suffered to exist by the Borrower or any of its Subsidiaries (except (A) Indebtedness under the Loan Documents and the Loan Documents (as defined in the Existing Credit Agreement), (B) unsecured Indebtedness incurred in the ordinary course of business, other than Indebtedness of the type described in (1) clauses (a), (c) or (f) of the definition of "Indebtedness" and (2) clauses (b) and (g) of the definition of "Indebtedness" with respect to any Indebtedness described in clause (1) above, (C) other unsecured Indebtedness or Non-Recourse Debt (as defined in the Senior Note Indentures) incurred in the ordinary course of business in connection with Indebtedness existing or contractually committed to be made available as of the date hereof, and (D) Indebtedness outstanding on the date hereof), and no guarantee, collateral or other credit support is provided, and no Lien on the properties of the Borrower or any of its Subsidiaries is created, incurred, assumed or granted, in each case in support of (x) any Indebtedness (other than Indebtedness permitted above) or (y) any obligation relating to any synthetic lease transaction of the Borrower or any Subsidiary of the Borrower; (2) no amendment, modification or supplement is made to any agreement or instrument evidencing any Indebtedness, other than amendments, modifications or supplements entered into in the ordinary course of business in respect of (A) the Credit Agreement or the Existing Credit Agreement, (B) any agreement or instrument evidencing Non-Recourse Debt (as defined in the Senior Note Indentures) of a Subsidiary of the Borrower, or (C) any agreement or instrument evidencing Indebtedness other than Indebtedness of the type described in (1) clauses (a), (c) or (f) of the definition of "Indebtedness" and (2) clauses (b) and (g) of the definition of "Indebtedness" with respect to any Indebtedness described in clause (1) above (the Indebtedness described in clauses (B) and (C) being collectively referred to as "Excluded Indebtedness");
(3) no optional prepayment is made on, or purchase or optional redemption is executed of, any Indebtedness other than Excluded Indebtedness (including, without limitation, any buy-back or defeasance of any outstanding bonds, puttable convertible bonds or other securities of the Borrower or any of its Subsidiaries), it being understood and agreed that, during the Extension Period, neither the Borrower or any of its Subsidiaries shall obtain or receive any such Indebtedness (or instruments evidencing same) in consideration of the sale or other transfer of any assets or properties thereof; provided, that notwithstanding anything to the contrary contained herein or in the Credit Agreement, at any time after the Term Sheet Agreement Date, the Borrower shall be permitted to repurchase notes issued by Calpine Canada Energy Finance II, ULC for an aggregate purchase amount not to exceed US$50,000,000; (4) no Investment is made by the Borrower or any of its Subsidiaries in any other Person (except (A) Investments by the Borrower in the ordinary course of business in Subsidiaries the equity in which has been pledged to the Lenders, and each of their respective Subsidiaries, (B)
3
Investments by the Borrower in other Persons pursuant to contractual commitments existing as of the date hereof, and (C) Investments by the Borrower in CES in support of transactions entered into by CES in the ordinary course of CES's business, consistent with historical practices); and (5) all transactions between any one or more of the Borrower and its Affiliates entered into during the Extension Period are on terms that are fair and reasonable and similar to those found in a comparable arm's length transaction with a Person that is not an Affiliate of the Borrower. Notwithstanding the foregoing, it is agreed that
(x) the Borrower and its Subsidiaries may effectuate the transactions referred to in Schedule I attached to the letter from the Borrower to the Lenders dated May 20, 2003 and (y) none of the prohibitions contained in this Section 4 shall be applicable insofar as they would otherwise constitute an encumbrance or restriction in violation of Section 3.5 of the Pre-2000 Indentures. The provisions of this Section 4 may be amended, modified or waived, if such amendment, modification or waiver is in writing and consented to by the Borrower and Lenders owed or holding at least 51% of the aggregate Revolving Loan Commitments and Commitments under the Credit Agreement and the Existing Credit Agreement, respectively (it being understood, however, that no such amendment, modification or waiver shall amend, modify or waive the provisions of the Credit Agreement unless such amendment, modification or waiver satisfies the requirements of Section 11.1 of the Credit Agreement).
5. Conditions Precedent to Effectiveness. This Amendment shall become effective as of the date hereof upon (i) the Agent having received counterparts hereof duly executed and delivered by the Borrower, the Required Lenders and each Revolving Lender and (ii) the Seventh Amendment, dated as of the date hereof, to the Existing Credit Agreement becoming effective in accordance with its terms.
6. No Other Amendments. Except as expressly amended hereby, the provisions of the Credit Agreement are and shall remain in full force and effect.
7. Expenses. The Borrower agrees to pay or reimburse the Agent for its out-of-pocket expenses in connection with this Amendment, including the reasonable fees, charges and disbursements of counsel to the Agent.
8. Governing Law; Counterparts. (a) This Amendment and the rights and obligations of the parties hereto shall be governed by, and construed and interpreted in accordance with, the laws of the State of New York.
(b) This Amendment may be executed by one or more of the parties to this Amendment on any number of separate counterparts, and all of said counterparts taken together shall be deemed to constitute one and the same instrument. This Amendment may be delivered by facsimile transmission of the relevant signature pages hereof.
IN WITNESS WHEREOF, the Borrower and the Lenders have caused this Amendment to be duly executed by their respective authorized officers as of the day and year first above written.
CALPINE CORPORATION

By   /s/ ROBERT D. KELLY
   -----------------------------------------
   Name: Robert D. Kelly
   Title: Chief Financial Officer	

THE BANK OF NOVA SCOTIA, as Agent and Lender

By   /s/ DENIS P. O'MEARA
   -----------------------------------------
   Name: Denis P. O'Meara
   Title: Managing Director	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
BANK OF AMERICA, NA

By   /s/ THOMAS BIAGGI
   --------------------------------
   Name: Thomas Biaggi
   Title: Managing Director	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
CREDIT SUISSE FIRST BOSTON

By /s/ JAMES P. MORAN
   -----------------------------------------
   Name: James P. Moran
   Title: Director

By /s/ JAY CHALL
   -----------------------------------------
   Name: Jay Chall
   Title: Director	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
BAYERISCHE LANDESBANK
Cayman Islands Branch

By   /s/ DIETMAR RIEG
   -----------------------------------------
   Name: Dietmar Rieg
   Title: First Vice President

By   /s/ JAMES H. BOYLE
   --------------------------------
   Name: James H. Boyle
   Title: Vice President	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
CITICORP USA, INC.

By   /s/ ANTHONY MURPHY
   -----------------------------------------
   Name: Anthony Murphy
   Title: Managing Director	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
DEUTSCHE BANK TRUST COMPANY AMERICAS

By   /s/ MARCUS TARKINGTON
   -----------------------------------------
   Name: Marcus Tarkington
   Title: Director	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
ING CAPITAL LLC

By   /s/ STEPHEN E. FISCHER
   -----------------------------------------
   Name: Stephen E. Fischer
   Title: Managing Director

By   /s/ G.D. BELLAMY, JR.
   -----------------------------------------
   Name: G.D. Bellamy, Jr.
   Title: Director	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
TORONTO DOMINION (TEXAS) INC.

By   /s/ LYNN CHASIN
   --------------------------------
   Name: Lynn Chasin
   Title: Vice President	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
LANDMARK CDO LIMITED
 By: Aladdin Capital Management LLC,
as Manager

By   /s/ JOSEPH MORONEY
   -----------------------------------------
   Name: Joseph Moroney, CFA
   Title: Authorized Signatory	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
LANDMARK II CDO LIMITED
 By: Aladdin Capital Management LLC,
as Manager

By   /s/ JOSEPH MORONEY
   -----------------------------------------
   Name: Joseph Moroney, CFA
   Title: Authorized Signatory	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
AMMC CDO I, LIMITED
 By: American Money Management Corp.,
as Collateral Manager

By   /s/ DAVID P. MEYER
   -----------------------------------------
   Name: David P. Meyer
   Title: Vice President	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
AMMC CDO II, LIMITED
 By: American Money Management Corp.,
as Collateral Manager

By   /s/ DAVID P. MEYER
   -----------------------------------------
   Name: David P. Meyer
   Title: Vice President	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
WINGED FOOT FUNDING TRUST

By   /s/ DIANA M. HIMES
   -----------------------------------------
   Name: Diana M. Himes
   Title: Authorized Agent	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
JUPITER FUNDING TRUST

By   /s/ DIANA M. HIMES
   -----------------------------------------
   Name: Diana M. Himes
   Title: Authorized Agent	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
SRF 2000, INC.

By   /s/ DIANA M. HIMES
   -----------------------------------------
   Name: Diana M. Himes
   Title: Assistant Vice President	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
SRF TRADING, INC.

By   /s/ DIANA M. HIMES
   -----------------------------------------
   Name: Diana M. Himes
   Title: Assistant Vice President	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
STANWICH LOAN FUNDING LLC

By   /s/ DIANA M. HIMES
   -----------------------------------------
   Name: Diana M. Himes
   Title: Assistant Vice President	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
RIVIERA FUNDING LLC

By   /s/ DIANA M. HIMES
   -----------------------------------------
   Name: Diana M. Himes
   Title: Assistant Vice President	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
BH FINANCE LLC

By   /s/ MARK D. MILLARD
   -----------------------------------------
   Name: Mark D. Millard
   Title: Authorized Signatory	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
FIRST DOMINION FUNDING I

By   /s/ DAVID H. LERNER
   -----------------------------------------
   Name: David H. Lerner
   Title: Authorized Signatory	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
FIRST DOMINION FUNDING II

By   /s/ DAVID H. LERNER
   -----------------------------------------
   Name: David H. Lerner
   Title: Authorized Signatory	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
FIRST DOMINION FUNDING III

By   /s/ DAVID H. LERNER
   -----------------------------------------
   Name: David H. Lerner
   Title: Authorized Signatory	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
CSAM FUNDING I

By   /s/ DAVID H. LERNER
   -----------------------------------------
   Name: David H. Lerner
   Title: Authorized Signatory	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
CSAM FUNDING II

By   /s/ DAVID H. LERNER
   -----------------------------------------
   Name: David H. Lerner
   Title: Authorized Signatory	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
ATRIUM CDO

By   /s/ DAVID H. LERNER
   -----------------------------------------
   Name: David H. Lerner
   Title: Authorized Signatory	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
CONNECTICUT GENERAL LIFE
INSURANCE COMPANY
 By: CIGNA Investments, Inc.

By   /s/ JOHN P. CONNOR
   -----------------------------------------
   Name: John P. Connor
   Title: Managing Director	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
GOLDMAN SACHS CREDIT
PARTNERS, L.P.

By   /s/ SANDRA STULBERGER
   --------------------------------
   Name: Sandra Stulberger
   Title: Authorized Signatory	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
INDOSUEZ CAPITAL FUNDING VI, LIMITED
 By: Indosuez Capital as Collateral Manager

By   /s/ CHARLES KOBAYASHI
   -----------------------------------------
   Name: Charles Kobayashi
   Title: Principal and Portfolio Manager	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
ENDURANCE CLO I, LTD.
 By: ING Capital Advisors LLC,
as Collateral Manager

By   /s/ GORDON R. COOK
   -----------------------------------------
   Name: Gordon R. Cook
   Title: Managing Director	

ARCHIMEDES FUNDING III, LTD.
 By: ING Capital Advisors LLC,
as Collateral Manager

By   /s/ GORDON R. COOK
   -----------------------------------------
   Name: Gordon R. Cook
   Title: Managing Director	

ARCHIMEDES FUNDING IV (CAYMAN)
LTD.
 By: ING Capital Advisors LLC,
as Collateral Manager

By   /s/ GORDON R. COOK
   -----------------------------------------
   Name: Gordon R. Cook
   Title: Managing Director	

BALANCED HIGH-YIELD FUND II
LTD.
 By: ING Capital Advisors LLC,
as Asset Manager

By   /s/ GORDON R. COOK
   -----------------------------------------
   Name: Gordon R. Cook
   Title: Managing Director	

SEQUILS-ING I (HBDGM), LTD.
 By: ING Capital Advisors LLC,
as Collateral Manager

By   /s/ GORDON R. COOK
   -----------------------------------------
   Name: Gordon R. Cook
   Title: Managing Director	

NEMEAN CLO, LTD.
 By: ING Capital Advisors LLC,
as Investment Manager

By   /s/ GORDON R. COOK
   -----------------------------------------
   Name: Gordon R. Cook
   Title: Managing Director	

ING-ORYX CLO, LTD.
 By: ING Capital Advisors LLC,
as Collateral Manager

By   /s/ GORDON R. COOK
   -----------------------------------------
   Name: Gordon R. Cook
   Title: Managing Director	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
KZH CNC LLC

By   /s/ DORIAN HERRERA
   -----------------------------------------
   Name: Dorian Herrera
   Title: Authorized Agent	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
KZH PONDVIEW LLC

By   /s/ DORIAN HERRERA
   -----------------------------------------
   Name: Dorian Herrera
   Title: Authorized Agent	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
KZH RIVERSIDE LLC

By   /s/ DORIAN HERRERA
   -----------------------------------------
   Name: Dorian Herrera
   Title: Authorized Agent	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
KZH SOLEIL LLC

By   /s/ DORIAN HERRERA
   -----------------------------------------
   Name: Dorian Herrera
   Title: Authorized Agent	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
KZH SOLEIL-2 LLC

By   /s/ DORIAN HERRERA
   -----------------------------------------
   Name: Dorian Herrera
   Title: Authorized Agent	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
KZH WATERSIDE LLC

By   /s/ DORIAN HERRERA
   -----------------------------------------
   Name: Dorian Herrera
   Title: Authorized Agent	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
MASTER SENIOR FLOATING RATE TRUST

By   /s/ JAIMIN PATEL
   -----------------------------------------
   Name: Jaimin Patel
   Title: Authorized Signatory	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
SENIOR HIGH INCOME PORTFOLIO, INC.

By   /s/ JAIMIN PATEL
   -----------------------------------------
   Name: Jaimin Patel
   Title: Authorized Signatory	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
MERRILL LYNCH PRIME RATE PORTFOLIO
 By: Merrill Lynch Investment Managers, L.P.
as Investment Advisor

By   /s/ JAIMIN PATEL
   -----------------------------------------
   Name: Jaimin Patel
   Title: Authorized Signatory	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
DEBT STRATEGIES FUND, INC.

By   /s/ JAIMIN PATEL
   -----------------------------------------
   Name: Jaimin Patel
   Title: Authorized Signatory	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
LONGHORN CDO II, LTD.
 By: Merrill Lynch Investment Managers, L.P.
as Investment Manager

By   /s/ JAIMIN PATEL
   -----------------------------------------
   Name: Jaimin Patel
   Title: Authorized Signatory	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
LONGHORN CDO (Cayman) LTD
 By: Merrill Lynch Investment Managers, L.P.
as Investment Advisor

By   /s/ JAIMIN PATEL
   -----------------------------------------
   Name: Jaimin Patel
   Title: Authorized Signatory	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
LONGHORN CDO III, LTD.
 By: Merrill Lynch Investment Managers, L.P.
as Investment Advisor

By   /s/ JAIMIN PATEL
   -----------------------------------------
   Name: Jaimin Patel
   Title: Authorized Signatory	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
MERRILL LYNCH GLOBAL INVESTMENT SERIES:
INCOME STRATEGIES PORTFOLIO
 By: Merrill Lynch Investment Managers, L.P.
as Investment Advisor

By   /s/ JAIMIN PATEL
   -----------------------------------------
   Name: Jaimin Patel
   Title: Authorized Signatory	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
MERRILL LYNCH GLOBAL INVESTMENT SERIES:
BANK LOAN INCOME PORTFOLIO
 By: Merrill Lynch Investment Managers, L.P.
as Investment Advisor

By   /s/ JAIMIN PATEL
   -----------------------------------------
   Name: Jaimin Patel
   Title: Authorized Signatory	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
MORGAN STANLEY SENIOR FUNDING, INC.

By   /s/ JAMES MORGAN
   -----------------------------------------
   Name: James Morgan
   Title: Vice President	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
STEIN ROE FLOATING RATE
LIMITED LIABILITY COMPANY
 By: Columbia Management Advisors, Inc.
(f/k/a Stein Roe & Farnham
Incorporated), As Advisor

By   /s/ JAMES R. FELLOWS
   -----------------------------------------
   Name: James R. Fellows
   Title: Sr. Vice President & Portfolio
          Manager	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
LIBERTY FLOATING RATE
ADVANTAGE FUND
 By: Columbia Management Advisors, Inc.
(f/k/a Stein Roe & Farnham
Incorporated), As Advisor

By   /s/ JAMES R. FELLOWS
   -----------------------------------------
   Name: James R. Fellows
   Title: Sr. Vice President & Portfolio
          Manager	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
STEIN ROE & FARNHAM CLO I LTD.
 By: Columbia Management Advisors, Inc.
(f/k/a Stein Roe & Farnham
Incorporated), As Advisor

By   /s/ JAMES R. FELLOWS
   -----------------------------------------
   Name: James R. Fellows
   Title: Sr. Vice President & Portfolio
          Manager	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
AURUM CLO 2002-1 LTD.
 By: Columbia Management Advisors, Inc.
(f/k/a Stein Roe & Farnham
Incorporated), As Advisor

By       /s/ JAMES R. FELLOWS
   -----------------------------------------
   Name: James R. Fellows
   Title: Sr. Vice President & Portfolio
          Manager	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
GALAXY CLO 1999-1, LTD.

By   /s/ W. JEFFREY BAXTER
   -----------------------------------------
   Name: W. Jeffrey Baxter
   Title: Vice President	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
SUNAMERICA LIFE INSURANCE COMPANY

By   /s/ W. JEFFREY BAXTER
   -----------------------------------------
   Name: W. Jeffrey Baxter
   Title: Vice President	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
SUNTRUST BANK

By   /s/ PETER C. VAKY
   --------------------------------
   Name: Peter C. Vaky
   Title: Managing Director	

Signature page to the Third Amendment, dated as of June 16, 2003, to the Credit Agreement, dated as of March 8, 2002, as amended, among Calpine Corporation, the various financial institutions as are or may become parties thereto, The Bank of Nova Scotia and Citicorp USA, Inc., as joint administrative agents.
TRUMBULL, THC, LTD.

By   /s/ STACEY MALEK
   -----------------------------------------
   Name: Stacey Malek
   Title: Attorney in fact	

EXHIBIT 99.1
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of Calpine Corporation (the "Company") on Form 10-Q for the period ending March 31, 2003, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), each of the undersigned does hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of his knowledge, based upon a review of the Report:
(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operation of the Company.

/s/ Peter Cartwright                   /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: June 30, 2003	

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.